Algonquin Power & Utilities (AQN) 40-F 5 Mar 21 2020 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2020shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Entity File Number	001-37946
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	354 Davis Road
Entity Address, City or Town	Oakville
Entity Address, State or Province	ON
Entity Address, Postal Zip Code	L6J 2X1
Entity Address, Country	CA
City Area Code	905
Local Phone Number	465-4500
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	597,142,219
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Entity Central Index Key	0001174169
Amendment Flag	false
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078
Entity Information [Line Items]
Title of 12(b) Security	6.875% Fixed-to-Floating Subordinated Notes – Series 2018-A due October 17, 2078
Trading Symbol	AQNA
Security Exchange Name	NYSE
6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079
Entity Information [Line Items]
Title of 12(b) Security	6.20% Fixed-to-Floating Subordinated Notes – Series 2019-A due July 1, 2079
Trading Symbol	AQNB
Security Exchange Name	NYSE
Common shares
Entity Information [Line Items]
Title of 12(b) Security	Common shares, no par value
Trading Symbol	AQN
Security Exchange Name	NYSE
Business Contact
Entity Information [Line Items]
Entity Address, Address Line One	111 Eighth Avenue
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10011
City Area Code	212
Local Phone Number	894-8940
Contact Personnel Name	CT Corporation System

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue
Total revenue	$ 1,677,058	$ 1,626,392
Expenses
Expenses	520,452	471,989
Administrative expenses	59,490	56,802
Depreciation and amortization	314,123	284,304
Loss (gain) on foreign exchange	(2,108)	3,146
Costs and Expenses, Total	1,292,965	1,259,545
Operating income	384,093	366,847
Interest expense	(181,934)	(181,488)
Income from long-term investments	664,671	397,621
Other net losses (note 19)	(61,311)	(26,694)
Pension and other post-employment non-service costs (note 10)	(14,072)	(17,332)
Gain on derivative financial instruments (note 24(b)(iv))	964	16,113
Nonoperating Income (Expense)	408,318	188,220
Earnings before income taxes	792,411	555,067
Income tax expense (note 18)
Current	(4,888)	(16,431)
Deferred	(59,695)	(53,686)
Income tax expense	(64,583)	(70,117)
Net earnings	727,828	484,950
Non-controlling interests	67,286	62,416
Non-controlling interests held by related party (note 16(b))	(12,651)	(16,482)
Net Income (Loss) Attributable To Noncontrolling Interest, Net Of Related Party	54,635	45,934
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	782,463	530,884
Series A and D Preferred shares dividend (note 15)	8,401	8,486
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$ 774,062	$ 522,398
Basic net earnings per share (USD per share)	$ 1.38	$ 1.05
Diluted net earnings per share (USD per share)	$ 1.37	$ 1.04
Regulated electricity distribution
Revenue
Total revenue	$ 777,577	$ 784,396
Expenses
Expenses	227,509	247,417
Regulated gas distribution
Revenue
Total revenue	456,267	439,153
Expenses
Expenses	144,271	170,487
Regulated water reclamation and distribution
Revenue
Total revenue	154,995	130,488
Expenses
Expenses	12,583	8,142
Non-regulated energy sales
Revenue
Total revenue	255,955	246,601
Expenses
Expenses	16,645	17,258
Other revenue
Revenue
Total revenue	$ 32,264	$ 25,754

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net earnings	$ 727,828	$ 484,950
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax recovery of $1,526 and of $289, respectively (notes 24(b)(iii) and 24(b)(iv))	28,406	7,795
Change in fair value of cash flow hedges, net of tax recovery of $9,046 and tax expense of $3,862 respectively (note 24(b)(ii))	(24,282)	10,580
Change in pension and other post-employment benefits, net of tax recovery of $6,881 and $2,735, respectively (note 10)	(17,561)	(6,509)
Other comprehensive income (loss), net of tax	(13,437)	11,866
Comprehensive income	714,391	496,816
Comprehensive loss attributable to the non-controlling interests	(55,326)	(43,506)
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$ 769,717	$ 540,322

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, tax (recovery) and expense	$ 1,526	$ 289
Change in fair value of cash flow hedge, tax (recovery) and expense	9,046	3,862
Change in unrealized pension and other post-employment expense, tax expense and (recovery)	$ 6,881	$ 2,735

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 101,614	$ 62,485
Change in pension and other post-employment benefits, net of tax recovery of $6,881 and $2,735, respectively (note 10)	325,644	259,144
Fuel and natural gas in storage	30,567	30,804
Supplies and consumables inventory	104,078	60,295
Regulatory assets (note 7)	63,042	50,213
Prepaid expenses	49,640	29,003
Derivative instruments (note 24)	13,106	13,483
Other assets (note 11)	7,266	7,764
Assets, current, total	694,957	513,191
Property, plant and equipment, net (note 5)	8,241,838	7,240,980
Intangible assets, net (note 6)	114,913	47,616
Goodwill (note 6)	1,208,390	1,031,696
Regulatory assets (note 7)	782,429	509,674
Long-term investments
Investments carried at fair value	1,837,429	1,294,147
Other long-term investments	214,583	121,968
Derivative instruments	39,001	72,221
Deferred income taxes (note 18)	21,880	30,585
Other assets (note 11)	68,486	58,708
Assets	13,223,906	10,920,786
Current liabilities:
Accounts payable	192,160	150,336
Accrued liabilities	369,530	307,952
Dividends payable (note 15)	92,720	73,945
Regulatory liabilities (note 7)	38,483	41,683
Long-term debt (note 9)	139,874	225,013
Other long-term liabilities (note 12)	72,505	57,939
Derivative instruments (note 24)	41,980	5,898
Other liabilities	7,901	9,300
Liabilities, current, total	955,153	872,066
Long-term debt (note 9)	4,398,596	3,706,855
Regulatory liabilities (note 7)	563,035	565,695
Deferred income taxes (note 18)	568,644	491,538
Derivative instruments (note 24)	68,430	78,766
Pension and other post-employment benefits obligation (note 10)	341,502	224,094
Other long-term liabilities (note 12)	339,181	243,401
Liabilities	7,234,541	6,182,415
Redeemable non-controlling interests
Redeemable non-controlling interest, held by related party (note 16(b))	306,316	305,863
Redeemable non-controlling interests	20,859	25,913
Redeemable non-controlling interests, total	327,175	331,776
Equity:
Preferred shares	184,299	184,299
Common shares	4,935,304	4,017,044
Additional paid-in capital	60,729	50,579
Retained earnings (deficit)	45,753	(367,107)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(22,507)	(9,761)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,203,578	3,875,054
Non-controlling interests	399,487	457,834
Non-controlling interest, held by related party (note 16(c))	59,125	73,707
Non-controlling interests, total	458,612	531,541
Total equity	5,662,190	4,406,595
Commitments and contingencies (note 22)
Liabilities and equity, total	$ 13,223,906	$ 10,920,786

Consolidated Statement of Equit

Consolidated Statement of Equity $ in Thousands, $ in Thousands	USD ($)	CAD ($)	Cumulative Effect, Period of Adoption, AdjustmentUSD ($)	Common sharesUSD ($)	Preferred sharesUSD ($)	Additional paid-in capitalUSD ($)	Additional paid-in capitalCAD ($)	Retained earnings (deficit)USD ($)	Retained earnings (deficit)Cumulative Effect, Period of Adoption, AdjustmentUSD ($)	Accumulated OCIUSD ($)	Accumulated OCICumulative Effect, Period of Adoption, AdjustmentUSD ($)	Non- controlling interestsUSD ($)
Beginning Balance at Dec. 31, 2018	$ 3,697,522		$ 0	$ 3,562,418	$ 184,299	$ 45,553		$ (595,259)	$ (186)	$ (19,385)	$ 186	$ 519,896
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	484,950							530,884				(45,934)
Effect of redeemable non-controlling interests not included in equity (note 17)	(7,476)											(7,476)
Other comprehensive income (loss)	11,866									9,438		2,428
Dividends declared and distributions to non-controlling interests	(255,155)							(217,464)				(37,691)
Dividends and issuance of shares under dividend reinvestment plan	0			68,856				(68,856)
Contributions received from non-controlling interests	100,318											100,318
Common shares issued upon conversion of convertible debentures	148			148
Common shares issued upon public offering, net of cost	364,211			364,211
Common shares issued under employee share purchase plan	2,853			2,853
Share-based compensation	12,974					12,974
Common shares issued pursuant to share-based awards		$ (5,616)		18,558			$ (7,948)	(16,226)
Ending Balance at Dec. 31, 2019	$ 4,406,595			4,017,044	184,299	50,579		(367,107)		(9,761)		531,541
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Accounting Standards Update [Extensible List]	us-gaap:AccountingStandardsUpdate201712Member	us-gaap:AccountingStandardsUpdate201712Member
Net earnings (loss)	$ 727,828							782,463				(54,635)
Effect of redeemable non-controlling interests not included in equity (note 17)	(5,696)											(5,696)
Other comprehensive income (loss)	(13,437)									(12,746)		(691)
Dividends declared and distributions to non-controlling interests	(307,726)							(281,977)				(25,749)
Dividends and issuance of shares under dividend reinvestment plan	0			70,830				(70,830)
Contributions received from non-controlling interests	3,371											3,371
Common shares issued upon conversion of convertible debentures	48			48
Common shares issued upon public offering, net of cost	823,891			823,891
Common shares issued under employee share purchase plan	4,327			4,327
Share-based compensation	25,859					25,859
Common shares issued pursuant to share-based awards	(11,591)			19,164		(13,959)		(16,796)
Acquisition of redeemable non-controlling interest, net (note 3(b))	8,721					(1,750)						10,471
Ending Balance at Dec. 31, 2020	$ 5,662,190			$ 4,935,304	$ 184,299	$ 60,729		$ 45,753		$ (22,507)		$ 458,612

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating Activities
Net earnings	$ 727,828	$ 484,950
Adjustments and items not affecting cash:
Depreciation and amortization	314,123	284,304
Deferred taxes	59,695	53,686
Unrealized gain on derivative financial instruments	(2,124)	(15,237)
Share-based compensation expense	24,637	11,042
Cost of equity funds used for construction purposes	(2,219)	(4,896)
Change in value of investments carried at fair value	(559,701)	(276,458)
Pension and post-employment expense in excess of (lower than) contributions	2,182	(8,952)
Distributions received from equity investments, net of income	3,869	7,487
Others	14,406	15,031
Changes in non-cash operating items	(77,479)	60,303
Net Cash Provided by (Used in) Operating Activities, Total	505,217	611,260
Financing Activities
Increase in long-term debt	3,471,740	3,614,758
Decrease in long-term debt	(3,160,523)	(3,048,008)
Issuance of common shares, net of costs	820,767	362,364
Cash dividends on common shares	(253,762)	(196,391)
Dividends on preferred shares	(8,401)	(8,486)
Contributions from non-controlling interests, related party	0	96,752
Contributions from non-controlling interests and redeemable non-controlling interests (note 17)	3,717	3,403
Production-based cash contributions from non-controlling interest	3,371	3,565
Distributions to non-controlling interests, related party (note 16(b) and (c))	(27,447)	(38,718)
Distributions to non-controlling interests	(11,417)	(12,251)
Payments upon settlement of derivatives	0	(8,732)
Shares surrendered to fund withholding taxes on exercised share options	(5,274)	(5,282)
Repurchase of non-controlling interest	(76,046)	0
Increase in other long-term liabilities	18,342	10,175
Decrease in other long-term liabilities	(8,208)	(39,783)
Net Cash Provided by (Used in) Financing Activities, Total	766,859	733,366
Investing Activities
Additions to property, plant and equipment and intangible assets	(786,030)	(581,332)
Increase in long-term investments	(279,188)	(669,832)
Acquisitions of operating entities (note 3)	(402,784)	(308,423)
Increase in other assets	(21,419)	(16,690)
Receipt of principal on development loans receivable	244,285	251,118
Distributions received from equity investments	14,818	1,000
Proceeds from sale of long-lived assets	415	0
Net Cash Provided by (Used in) Investing Activities, Total	(1,229,903)	(1,324,159)
Effect of exchange rate differences on cash and restricted cash	573	1,032
Increase in cash, cash equivalents and restricted cash	42,746	21,499
Cash, cash equivalents and restricted cash, beginning of year	87,272	65,773
Cash, cash equivalents and restricted cash, end of year	130,018	87,272
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	190,942	171,548
Cash paid during the year for income taxes	5,603	14,543
Cash received during the year for distributions from equity investments	121,506	131,492
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	74,505	98,231
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	94,321	87,414
Sale of property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	27,611	57,753
Convertible Debentures
Non-cash financing and investing activities:
Issuance of common shares upon conversion of convertible debentures	$ 50	$ 155

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Notes to the Consolidated Financial Statements	Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity under the Canada Business Corporations Act

Significant accounting policies

Significant accounting policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Significant accounting policies	Significant accounting policies (a) Basis of preparation The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission. (b) Basis of consolidation The accompanying consolidated financial statements of AQN include the accounts of AQN, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)). (c) Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company's customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company's electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized. As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN's Chilean operating company, Empresa de Servicios de Los Lagos S.A. (“ESSAL”), which was acquired in October 2020. The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover ESSAL's specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations. The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the Regulator and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation. (e) Cash and cash equivalents Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less. (f) Restricted cash Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN. (g) Accounts receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers. 1. Significant accounting policies (continued) (h) Fuel and natural gas in storage Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(g)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company. (i) Supplies and consumables inventory Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value. (j) Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest . The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2020 2019 2020 2019 Generation 3 - 60 3 - 60 33 33 Distribution 1 - 100 5 - 100 40 42 Equipment 5 - 50 5 - 44 11 10 The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. (k) Commonly owned facilities The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. (l) Impairment of long-lived assets AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount. Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. (m) Variable interest entities The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8). 1. Significant accounting policies (continued) (m) Variable interest entities (continued) The Company has equity and notes receivable interests in two power generating facilities and one water pipeline project. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. The key decisions that affect the water pipeline investment entity's performance relate to any future investments and loans to the project, administering its rights as lender to the project, and the distribution of any interest or dividends received from the project. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary. Total net book value of assets and long-term debt of these facilities amounts to $59,521 (2019 - $60,230) and $20,328 (2019 - 21,754), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,116 (2019 - 17,108), operating expenses and amortization of $5,400 (2019 - $4,930) and interest expense of $2,119 (2019 - $2,340). (n) Long-term investments and notes receivable Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee. Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured. If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. 1. Significant accounting policies (continued) (o) Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations. (p) Asset retirement obligations The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation. (q) Leases The Company accounts for leases in accordance with ASC Topic 842, Leases . The Company leases land, buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842. The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company's right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company's lease balances as at December 31, 2020 and its expected lease payments for the next five years and thereafter are not significant. 1. Significant accounting policies (continued) (r) Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; a restricted share unit (“RSU”) and a performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares. (s) Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period. Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification. (t) Recognition of revenue Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, "Segmented information" for details of revenue disaggregation by business units. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Regulated Services Group revenue Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water. Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant. Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, "Segmented information" and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset. Renewable Energy Group revenue Renewable Energy Group's revenue consists primarily of the sale of electricity, capacity, and renewable energy credits. Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Renewable Energy Group revenue (continued) Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized a

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2020
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently issued accounting pronouncements	Recently adopted accounting pronouncements The FASB issued accounting standards update (“ASU”) 2018-08 Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The adoption of this update in 2020 did not have an impact on the consolidated financial statements. The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The adoption of this update in 2020 did not have an impact on the consolidated financial statements. The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the amendments in this update, the impairment loss will be measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The Company will follow the pronouncements prospectively for goodwill impairment testing. The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The adoption of this topic in 2020 did not have a significant impact on the consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The amendments in this update are effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently assessing the impact of this update. The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The amendments in this update are effective for all entities as of March 12, 2020 through December 31, 2022. The FASB issued an update to Topic 848 in ASU 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition. The Company is currently assessing the impact of the reference rate reform and this update.

Business acquisitions and devel

Business acquisitions and development projects	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Business acquisitions and development projects	Business acquisitions and development projects (a) Acquisition of Ascendant Group Limited On November 9, 2020, the Company completed the acquisition of Ascendant Group Limited (“Ascendant”), parent company of Bermuda Electric Light Company Limited (“BELCO”). BELCO is the sole electric utility providing regulated electrical generation, transmission and distribution services to Bermuda's residents and businesses. The purchase price was $364,468 for the acquisition of Ascendant. The costs related to this acquisition have been expensed through the consolidated statement of operations. The following table summarizes the preliminary allocation of the acquisition price to the assets acquired and liabilities assumed at the acquisition date: Working capital $ 71,948 Property, plant and equipment 417,947 Intangible assets 27,315 Goodwill 93,202 Regulatory assets 9,859 Other assets 4,992 Long-term debt (159,682) Pension and other post-employment benefits (58,746) Derivative instruments (12,748) Other liabilities (29,619) Total net assets acquired $ 364,468 Cash and cash equivalents acquired 42,920 Total net assets acquired, net of cash and cash equivalents $ 321,548 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Due to the timing of the acquisition, the Company has not finalized the fair value measurements. In particular, the assignment of goodwill to the reporting units has not been completed. The Company will continue to review information and perform further analysis prior to finalizing the fair value of assets acquired and liabilities assumed. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost savings in the delivery of certain shared administrative and other services. Property, plant and equipment, exclusive of computer software, are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of Ascendant's assets is 29 years. 3. Business acquisitions and development projects (continued) (b) Acquisition of ESSAL The Company acquired 51% of ESSAL on October 13, 2020 for $87,975 and an additional 43% for $74,111 on October 17, 2020, resulting in AQN acquiring in total 94% of the outstanding shares of ESSAL. The remaining 6% of ESSAL is recorded as non-controlling interest by AQN. Subsequent to year-end, the Company sold a 32% interest in Eco Acquisitionco SpA (the holding company through which AQN's interest in ESSAL is held) to a third party for total consideration of $51,750. This portion will be reflected as additional non-controlling interest in 2021. Following this transaction, AQN owns approximately 64% of the outstanding shares of ESSAL. ESSAL is a vertically integrated, regional water and wastewater provider in Southern Chile. The Company controls and consolidates ESSAL. Acquisition costs related to this acquisition have been expensed through the consolidated statement of operations. The following table summarizes the preliminary allocation of the acquisition price of $87,975, when control was obtained, to the assets acquired and liabilities assumed at the initial acquisition date. The purchase of the second tranche reduced non-controlling interest by $74,111 in October 2020. Working capital $ 11,278 Property, plant and equipment 238,504 Intangible assets 37,095 Goodwill 70,382 Other assets 22 Long-term debt (139,534) Other post-employment benefits (2,292) Deferred tax liabilities, net (28,074) Other liabilities (14,881) Non-controlling interest (84,525) Total net assets acquired $ 87,975 Cash and cash equivalents acquired 6,983 Total net assets acquired, net of cash and cash equivalents $ 80,992 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Due to the timing of the acquisitions, the Company has not finalized the fair value measurements. In particular, the fair value of certain long-term liabilities and the assignment of goodwill to the reporting units has not been completed. The Company will continue to review information and perform further analysis prior to finalizing the fair value of assets acquired and liabilities assumed. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group Segment. Property, plant and equipment, exclusive of computer software, are amortized over the estimated useful life of the assets using the straight-line method. The weighted average useful life of ESSAL's assets is 40 years. (c) Acquisition of Enbridge Gas New Brunswick Limited Partnership & St. Lawrence Gas Company, Inc. The Company completed the acquisition of Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas”) on October 1, 2019, and St. Lawrence Gas Company, Inc. (“St. Lawrence Gas”) on November 1, 2019. New Brunswick Gas is a regulated utility that provides natural gas. The purchase price recorded in 2019 was $256,011 (C$339,036). A closing adjustment of $1,213 (C$1,884) was made in 2020 to reduce goodwill. St. Lawrence Gas is a regulated utility that provides natural gas in northern New York State. The total purchase price recorded in 2019 for the transaction was $61,820. A closing adjustment of $3,207 was made in 2020 to increase goodwill. 3. Business acquisitions and development projects (continued) (d) Acquisition of Mid-West Wind Development Project In 2019, The Empire District Electric Company ("Empire Electric System"), a wholly owned subsidiary of the Company, entered into purchase agreements to acquire, once completed, three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri ("Missouri Wind Projects") and in Neosho County, Kansas ("Kansas Wind Project"). These assets, net of third-party tax equity investment, are expected to be included in the rate base of the Empire Electric System. In November 2019, Liberty Utilities Co., a wholly owned subsidiary of the Company, acquired an interest in the entities that own North Fork Ridge and Kings Point, the two Missouri Wind Projects and, in partnership with a third-party developer, continued development and construction of such projects until they are acquired by the Empire Electric System following completion. The Company accounted for its interest in these two projects using the equity method (note 8(e)). In November 2019, a tax equity agreement was executed for the Kansas Wind Project and in December 2020, tax equity agreements were executed for the Missouri Wind Projects. The Class A partnership units will be owned by third-party tax equity investors who have committed to fund on a future date. With their interests, the tax equity investors will receive the majority of the tax attributes associated with the Wind Projects. Concurrent with the execution of the tax equity agreements in December 2020, the North Fork Ridge Wind project reached commercial operation and the tax equity investors provided initial funding of $29,446. Subsequent to year-end, the Empire Electric System acquired the North Fork Ridge project for total consideration of $288,066; the tax equity investor provided additional funding of $84,926; and, North Fork Ridge's third party construction loan of $193,506 was repaid. As a result of obtaining control of the facility, the transaction will be treated as an asset acquisition. The remaining Missouri Wind Project and the Kansas Wind Project are expected to achieve commercial operation in March 2021. (e) Acquisition of Turquoise Solar Facility Liberty Utilities (Turquoise Holdings) LLC (“Turquoise Holdings”) is owned by Liberty Utilities (Calpeco Electric) LLC ("Calpeco Electric System"). The 10 MWac solar generating facility is located in Washoe County, Nevada ("Turquoise Solar Facility"). On December 31, 2019, as the Turquoise Solar Facility was placed in service, Turquoise Holdings obtained control of the property, plant and equipment for a total purchase price of $20,830. The Class A partnership units are owned by a third-party tax equity investor who funded $3,403 in 2019 and the final installments of $3,717 in 2020. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Turquoise Solar Facility. Because the Class A tax equity investor has the right to withdraw from Turquoise Holdings and require the Company to redeem its remaining interests for cash, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets (note 17). Redemption is not considered probable as of December 31, 2020. (f) Great Bay Solar II Facility The Great Bay Solar II Facility is a 40 MWac solar powered generating facility in Somerset County, Maryland. Commercial operations as defined by the power purchase agreement were reached for all sites during the year. Liberty Utilities (America) Holdco Inc., a subsidiary of AQN, is the tax equity investor for the facility and contributed initial funding of $11,281 in 2019. Additional funding of $15,268 was made in 2020. The facility generated an investment tax credit of $10,717 in 2020 (2019 - $8,526), which was recorded by the AQN as a reduction to income tax expense in the consolidated statement of operations.

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivable Accounts receivable as of December 31, 2020 include unbilled revenue of $91,295 (December 31, 2019 - $80,295 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2020 are presented net of allowance for doubtful accounts of $29,506 (December 31, 2019 - $4,939 ).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2020 Cost Accumulated depreciation Net book value Generation $ 2,918,692 $ 633,210 $ 2,285,482 Distribution and transmission 5,766,885 661,786 5,105,099 Land 114,847 — 114,847 Equipment 99,722 51,979 47,743 Construction in progress Generation 136,424 — 136,424 Distribution and transmission 552,243 — 552,243 $ 9,588,813 $ 1,346,975 $ 8,241,838 2019 Cost Accumulated depreciation Net book value Generation $ 2,816,611 $ 540,118 $ 2,276,493 Distribution and transmission 4,997,613 598,449 4,399,164 Land 74,517 — 74,517 Equipment 94,583 47,541 47,042 Construction in progress Generation 140,235 — 140,235 Distribution and transmission 303,529 — 303,529 $ 8,427,088 $ 1,186,108 $ 7,240,980 Generation assets include cost of $111,806 (2019 - $109,653) and accumulated depreciation of $43,444 (2019 - $39,638) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,708 (2019 - $1,615). Distribution and transmission assets include the following: • Cost of $885,087 (2019 - $1,125,062) and accumulated depreciation of $28,779 (2019 - $81,480) related to regulated generation assets. In 2020, the Asbury plant ceased operations and net book value was transferred to a regulatory asset (note 7(a)). • Cost of $531,191 (2019 - $514,709) and accumulated depreciation of $50,919 (2019 - $31,349) related to commonly owned facilities (note 1(k)). Total expenditures incurred on these facilities for the year ended December 31, 2020 were $61,827 (2019 - $69,210). • Cost of $3,076 (2019 - $3,076) and accumulated depreciation of $1,321 (2019 - $1,003) related to assets under finance lease. • Expansion costs of $1,000 (2019 - $1,000) on which the Company does not currently earn a return. For the year ended December 31, 2020, contributions received in aid of construction of $4,214 (2019 - $7,137) have been credited to the cost of the assets. 5. Property, plant and equipment (continued) Interest and AFUDC capitalized to the cost of the assets in 2020 and 2019 are as follows: 2020 2019 Interest capitalized on non-regulated property $ 9,359 $ 4,538 AFUDC capitalized on regulated property: Allowance for borrowed funds 3,475 2,745 Allowance for equity funds 2,219 4,896 $ 15,053 $ 12,179

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2020 Cost Accumulated amortization Net book value Power sales contracts $ 57,943 $ 41,184 $ 16,759 Customer relationships (note 3) 83,342 10,967 72,375 Interconnection agreements 15,028 1,458 13,570 Other (a) 12,209 — 12,209 $ 168,522 $ 53,609 $ 114,913 (a) Other includes brand names, water rights and miscellaneous intangibles (note 3) 2019 Cost Accumulated amortization Net book value Power sales contracts $ 56,206 $ 38,931 $ 17,275 Customer relationships 26,797 10,104 16,693 Interconnection agreements 14,827 1,179 13,648 $ 97,830 $ 50,214 $ 47,616 Estimated amortization expense for intangible assets for the next year is $4,353, $4,194 in year two, $4,194 in year three, $4,194 in year four and $4,194 in year five. All goodwill pertains to the Regulated Services Group. 2020 2019 Opening balance $ 1,031,696 $ 954,282 Business acquisitions (note 3) 167,209 76,313 Foreign exchange 9,485 1,101 Closing balance $ 1,208,390 $ 1,031,696

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory matters	Regulatory matters The operating companies within the Regulated Services Group are subject to regulation by the respective authorities of the jurisdictions in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. Except for ESSAL, these utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980, Regulated Operations . Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process. At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed: Utility State Regulatory proceeding type Annual revenue increase (decrease) Effective date New England Natural Gas System Massachusetts General System Enhancement Plan $2,679 May 1, 2020 Energy North Gas System New Hampshire Cast Iron/Bare Steel Replacement Program Results $1,613 July 1, 2020 Granite State Electric System New Hampshire General Rate Review $5,474 July 1, 2020. The regulator also approved a one-time recoupment of $1,836 for the difference between the final rates and temporary rate increase of $2,093 granted on July 1, 2019. Empire Electric System (Missouri) Missouri General Rate Review $992 September 16, 2020 Peach State Gas System Georgia General Rate Review $1,566 August 1, 2020 Calpeco Electric System California General Rate Review $5,277 Retroactive to January 1, 2019 Various Various General Rate Review ($283) 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2020 December 31, 2019 Regulatory assets Retired generating plant (a) $ 194,192 $ — Pension and post-employment benefits (b) 178,403 143,292 Rate adjustment mechanism (c) 99,853 69,121 Environmental remediation (d) 87,308 82,300 Income taxes (e) 77,730 71,506 Debt premium (f) 35,688 42,150 Fuel and commodity cost adjustments (g) 18,094 23,433 Clean energy and other customer programs (h) 26,400 25,859 Deferred capitalized costs (i) 34,398 38,833 Asset retirement obligation (j) 26,546 23,841 Wildfire mitigation and vegetation management (k) 22,736 5,043 Long-term maintenance contract (l) 14,405 13,264 Rate review costs (m) 8,054 7,205 Other 21,664 14,040 Total regulatory assets $ 845,471 $ 559,887 Less: current regulatory assets (63,042) (50,213) Non-current regulatory assets $ 782,429 $ 509,674 Regulatory liabilities Income taxes (e) $ 322,317 $ 321,960 Cost of removal (n) 200,739 205,739 Pension and post-employment benefits (b) 26,311 22,256 Fuel and commodity costs adjustments (g) 20,136 17,729 Rate adjustment mechanism (c) 5,214 10,446 Clean energy and other customer programs (h) 10,440 6,871 Rate base offset (o) 6,874 8,719 Other 9,487 13,658 Total regulatory liabilities $ 601,518 $ 607,378 Less: current regulatory liabilities (38,483) (41,683) Non-current regulatory liabilities $ 563,035 $ 565,695 (a) Retired generating plant On March 1, 2020, the Company's 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The ultimate valuation of the regulatory asset will be determined in future commission orders. The Company is also assessing the decommissioning requirements associated with the retirement of the facility. Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on rates for consideration in the next rate case. The Company expects to defer such amounts collected from customers until new rates become effective. The accrual for this estimated amount includes revenues collected related to Asbury that will be subject to a future rate review proceeding and possible refund to customers. The ultimate resolution of this matter is uncertain. 7. Regulatory matters (continued) (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems' and St. Lawrence Gas system's pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods. (c) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 26 years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. (d) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (e) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. (f) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (g) Fuel and commodity cost adjustments The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. (h) Clean energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. 7. Regulatory matters (continued) (i) Deferred capitalized costs Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years. During the year, Empire Electric made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits Empire Electric to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable weighted average cost of capital (“WACC”) on certain property, plant, and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state, and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates. The regulatory asset associated with PISA as at December 31, 2020 is not material. (j) Asset retirement obligation Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates. (k) Wildfire mitigation and vegetation management The regulatory asset for vegetation management includes wildfire insurance in the Company's California operations as well as spending related to dead trees program, to prevent future forest fires and general vegetation management. (l) Long-term maintenance contract To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. (m) Rate review costs The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (n) Cost of removal Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability tracks the amounts that have been collected from customers net of costs incurred to date. (o) Rate base offset The regulators imposed a rate base offset that will reduce the revenue requirements at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years. As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate review costs.

Long-term investments

Long-term investments	12 Months Ended
	Dec. 31, 2020
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: December 31, 2020 December 31, 2019 Long-term investments carried at fair value Atlantica (a) $ 1,706,900 $ 1,178,581 Atlantica share subscription agreement (b) 20,015 — Atlantica Yield Energy Solutions Canada Inc. (c) 110,514 88,494 San Antonio Water System (d) — 27,072 $ 1,837,429 $ 1,294,147 Other long-term investments Equity-method investees (e), (f) $ 186,452 $ 82,111 Development loans receivable from equity-method investees (f) 22,912 36,204 Other 5,219 3,653 $ 214,583 $ 121,968 Income (loss) from long-term investments from the years ended December 31 is as follows: Year ended December 31, 2020 2019 Fair value gain (loss) on investments carried at fair value Atlantica $ 519,297 $ 290,740 Atlantica share subscription agreement 20,015 — Atlantica Yield Energy Solutions Canada Inc. 20,272 (6,649) San Antonio Water System 117 (6,007) $ 559,701 $ 278,084 Dividend and interest income from investments carried at fair value Atlantica $ 74,604 $ 69,307 Atlantica Yield Energy Solutions Canada Inc. 14,731 25,572 San Antonio Water System 2,113 6,007 $ 91,448 $ 100,886 Other long-term investments Equity method income (loss) 209 (9,108) Interest and other income 13,313 27,759 $ 664,671 $ 397,621 (a) Investment in Atlantica AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 44.2% (2019 - 44.2%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The shares were purchased at a cost of $1,036,414. The Company accounts for its investment in Atlantica at fair value, with changes in fair value reflected in the consolidated statements of operations. 8. Long-term investments (continued) (b) Atlantica share subscription agreement On December 9, 2020, the Company entered into a subscription agreement to purchase additional ordinary shares of Atlantica at $33.00 per share in order to maintain its 44.2% ownership interest pursuant to a treasury share issuance by Atlantica. The contract is accounted for as a derivative under ASC 815, Derivatives and Hedging and had a fair value of $20,015 as at December 31, 2020. Subsequent to year-end, on January 7, 2021, the subscription closed and the Company paid $132,688 for 4,020,860 shares of Atlantica. (c) Investment in AYES Canada On May 24, 2019, AQN and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. ("AYES Canada"), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. ("Windlectric"). AQN invested $91,918 (C$123,603) and Atlantica invested C$4,834 (C$6,500) in AYES Canada, which in turn invested those funds in Amherst Island Partnership ("AIP"), the holding company of Windlectric. AQN controls and consolidates AIP and Windlectric. The investment of $96,752 (C$130,103) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. For the year ended December 31, 2020, the Company incurred non-controlling interest calculated using the HLBV method of accounting of $nil (2019 - $nil) and recorded distributions of $16,064 (2019 - $26,465) during the year. AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment (note 24(a)). For the year ended December 31, 2020, AQN recorded dividend income of $14,731 (2019 - $25,572) and a fair value gain of $20,272 (2019 - loss of $6,649) on its investment in AYES Canada. As at December 31, 2020, the Company's maximum exposure to loss is $110,514 (2019 - $88,494), which represents the fair value of the investment. (d) San Antonio Water System On December 30, 2019, the Company and a third party each contributed C$1,500 to the capital of a new joint venture, created for the purpose of investing in infrastructure opportunities. The Company sold its investment in Abengoa Water USA, LLC to the joint venture in exchange for a note receivable of $30,293 and has elected the fair value option under ASC 825, Financial Instruments to account for its investment in the joint venture, with changes in fair value reflected in the consolidated statements of operations. On July 2, 2020, AQN acquired the third-party developer's 50% interest in the joint venture for C$1,581. As a result, the Company consolidates Abengoa Water USA, LLC and its 20% interest in the San Antonio Water System (“SAWS”). The Company accounts for its 20% interest in SAWS using the equity method. (e) Equity-method investees The Company has non-controlling interests in various corporations, partnerships and joint ventures with a total carrying value of $186,452 (2019 - $82,111) including investments in VIEs of $174,685 (2019 - $59,091). 8. Long-term investments (continued) (e) Equity-method investees (continued) Subsequent to year-end, the Company acquired a 51% interest in three wind facilities from a portfolio of four wind facilities located in Texas for $227,556. The facilities have achieved commercial operations. The acquisition of the last facility is expected to close after achieving commercial operation for approximately $103,642. Commercial operation is expected to occur in March 2021. The Company is not considered the primary beneficiary of the entity and therefore will account for its 51% interest using the equity method. The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. AQN exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method. The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa S.A. (“Abengoa”) in 2018; Sugar Creek, a 202 MW wind power project in Logan County, Illinois; Maverick Creek, a 492 MW wind power project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia; Blue Hill, a 175 MW wind power project located between Herbert and Neidpath, Saskatchewan; and North Fork Ridge and Kings Point, two approximately 150 MW wind projects in southwestern Missouri. During the year, the Blue Hill wind project net assets of $20,029 (C$27,205) were transferred into a joint venture entity in exchange for 50% equity interests in the joint venture. During the year, the Sugar Creek and North Fork Ridge wind facilities reached commercial operations and Maverick Creek commissioned 111 of its 127 total turbines. Subsequent to year-end, the Company acquired the remaining 50% equity interest in each of Sugar Creek and Maverick Creek for $43,796 and as a result, obtained control of the facilities. As at December 31, 2020, the net book value of property, plant and equipment of the joint ventures was $1,009,709 while the third-party construction debt was $837,026 which are expected to be repaid in the first quarter of 2021. Subsequent to year-end, the Empire Electric System acquired North Fork Ridge from Liberty Utilities Co. and the third-party developer (note 3(d)). On October 21, 2020, AQN paid $1,500 to Abengoa for a 12-month exclusive, transferable, and irrevocable option to purchase all of Abengoa's interests in Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V."), AAGES Development Canada Inc., and AAGES Development Spain, S.A. During the term of the option, the Company is obligated to provide cash advances in an aggregate amount not exceeding $7,233 in any calendar year to be used only in accordance with the baseline operating budget. Summarized combined information for AQN's investments in significant partnerships and joint ventures as at December 31 is as follows: 2020 2019 Total assets $ 3,201,967 $ 833,791 Total liabilities 2,913,188 697,751 Net assets $ 288,779 $ 136,040 AQN's ownership interest in the entities 141,666 63,624 Difference between investment carrying amount and underlying equity in net assets (a) 44,786 18,487 AQN's investment carrying amount for the entities $ 186,452 $ 82,111 (a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs. 8. Long-term investments (continued) (e) Equity-method investees (continued) Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2020, the Company had issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as at December 31, 2020 amounts to $12,273 (2019 - $9,446). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2020 2019 AQN's maximum exposure in regards to VIEs Carrying amount $ 174,685 $ 59,091 Development loans receivable (e) 21,804 35,000 Performance guarantees and other commitments on behalf of VIEs 965,291 1,364,871 $ 1,161,780 $ 1,458,962 The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements. (f) Development loans receivable from equity investees The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans generally mature between the fifth and tenth anniversary of the commercial operation date.

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-term debt	Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value December 31, 2020 December 31, 2019 Senior unsecured revolving credit facilities (a) — 2021-2024 N/A $ 223,507 $ 141,577 Senior unsecured bank credit facilities (b) — 2021-2031 N/A 152,338 75,000 Commercial paper (c) — 2021 N/A 122,000 218,000 U.S. dollar borrowings Senior unsecured notes (d) 3.46 % 2022-2047 $ 1,700,000 1,688,390 1,219,579 Senior unsecured utility notes (e) 6.34 % 2023-2035 $ 142,000 157,212 233,686 Senior secured utility bonds (f) 4.71 % 2026-2044 $ 556,229 561,494 672,337 Canadian dollar borrowings Senior unsecured notes (g) 4.28 % 2021-2050 C$ 1,150,669 899,710 728,679 Senior secured project notes 10.21 % 2027 C$ 25,882 20,315 21,961 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds (h) 4.29 % 2028-2040 CLF 1,868 92,183 — $ 3,917,149 $ 3,310,819 Subordinated U.S. dollar borrowings Subordinated unsecured notes (i) 6.50 % 2078-2079 $ 637,500 621,321 621,049 $ 4,538,470 $ 3,931,868 Less: current portion (139,874) (225,013) $ 4,398,596 $ 3,706,855 Short-term obligations of $194,478 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities. Recent financing activities: (a) Senior unsecured revolving credit facilities On November 8, 2020 in connection with the acquisition of Ascendant (note 3(a)), the Company assumed $62,654 of debt outstanding under its revolving credit facility that matures on June 30, 2021. On February 24, 2020, the Renewable Energy Group increased its uncommitted letter of credit facility to $350,000 and extended the maturity to June 30, 2021. On July 12, 2019, the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024. The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread. 9. Long-term debt (continued) Recent financing activities (continued): (a) Senior unsecured revolving credit facilities (continued) Given the uncertainty caused by the COVID-19 pandemic, the Company secured, in the second quarter of 2020, additional liquidity as an additional margin of safety intended to ensure the Company could continue to move forward with its 2020 capital expenditure program and committed acquisitions independent of the state of the capital markets. The additional liquidity was in the form of three new senior unsecured delayed draw non-revolving credit facilities for a total of $1,600,000 maturing in April 2021. On October 5, 2020, these facilities were replaced with two new syndicated revolving credit facilities for a total of $1,600,000 maturing December 31, 2021. (b) Senior unsecured bank credit facilities On November 8, 2020, in connection with the acquisition of Ascendant (note 3(a)), the Company assumed $97,029 of debt outstanding under two term loan facilities that mature on June 29, 2023 and December 26, 2031. Amounts of $4,655 were repaid under these two facilities prior to December 31, 2020. On October 13, 2020, in connection with the acquisition of ESSAL (note 3(b)), the Company assumed $55,786 (CLP 44,408,558) of debt outstanding under seven credit facilities that mature between March 29, 2021 and November 18, 2022. Amounts of $2,474 (CLP 1,759,423) were repaid under these facilities prior to December 31, 2020. On June 27, 2019, the Regulated Services Group extended the maturity of its C$135,000 term loan to July 6, 2020. Upon maturity, the term loan was fully repaid. (c) Commercial paper On July 1, 2019, the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group's revolving bank credit facility. (d) Senior unsecured notes On September 23, 2020, the Regulated Services Group's debt financing entity issued $600,000 senior unsecured notes bearing interest at 2.05% with a maturity date of September 15, 2030. On July 31, 2020, the Company repaid, upon its maturity, a $25,000 unsecured note. On April 30, 2020, the Company repaid, upon its maturity, a $100,000 unsecured note. (e) Senior unsecured utility notes During 2020, the Regulated Services Group repaid two utility notes upon their maturities in the amount of $45,000 and $30,000. (f) Senior secured utility bonds On February 15, 2020 and June 1, 2020, the Company repaid, upon its maturity, a $6,500 and a $100,000 secured utility bond, respectively. (g) Canadian dollar senior unsecured notes On February 14, 2020, the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050. The debentures are redeemable at the option of the Company at a price based on a make-whole provision. On January 29, 2019, the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C$135,000 (note 24(b)(ii)). 9. Long-term debt (continued) Recent financing activities (continued) (h) Chilean Unidad de Fomento senior unsecured bonds On October 13, 2020, in connection with the acquisition of ESSAL (note 3(b)), the Company assumed two senior unsecured bonds (series B and series C) of $82,320 (CLF 1,926). The series B bonds bear interest at 6% and mature on June 1, 2028 while the series C bonds bear interest at 2.8% and mature on October 15, 2040. In December 2020, the Company repaid $1,550 (CLF 58) of obligations under the series B bonds. (i) Subordinated unsecured notes In 2019, the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes ("subordinated notes") maturing on July 1, 2079. Concurrent with the offering, the Company entered into cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars. Beginning on July 1, 2024, and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01%, payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029, and on every interest reset date until July 1, 2049, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26%, payable in arrears. Beginning on July 1, 2049, and on every interest reset date until July 1, 2079, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01%, payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. As of December 31, 2020, the Company had accrued $50,486 in interest expense (2019 - $44,229). Interest expense on the long-term debt, net of capitalized interest, in 2020 was $175,358 (2019 - $175,664). Principal payments due in the next five years and thereafter are as follows: 2021 2022 2023 2024 2025 Thereafter Total $ 334,352 $ 422,609 $ 111,427 $ 240,151 $ 45,451 $ 3,380,045 $ 4,534,035

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Pension and other post-retirement benefits	Pension and other post-employment benefits The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2020 were $9,672 (2019 - $8,798). In conjunction with the utility acquisitions, the Company assumes defined benefit pension, SERP and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its U.S. water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2020 2019 2020 2019 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 564,970 $ 484,707 $ 219,217 $ 168,325 Projected benefit obligation assumed from business combination 195,231 20,196 44,950 11,646 Modifications to plans (191) (7,705) — — Service cost 15,450 12,351 6,175 4,587 Interest cost 19,281 20,222 7,695 7,575 Actuarial loss 76,618 65,443 34,507 33,605 Contributions from retirees 171 — 2,037 1,913 Medicare Part D — — 377 414 Benefits paid (37,020) (30,244) (8,434) (8,848) Foreign exchange 403 — — — Projected benefit obligation, end of year $ 834,913 $ 564,970 $ 306,524 $ 219,217 Change in plan assets Fair value of plan assets, beginning of year 407,074 339,099 158,873 115,542 Plan assets acquired in business combination 179,600 8,004 — 15,688 Actual return on plan assets 52,876 68,025 21,219 25,464 Employer contributions 26,099 22,190 2,583 8,628 Contributions from retirees 171 — 1,998 1,913 Medicare Part D subsidy receipts — — 377 414 Benefits paid (37,020) (30,244) (8,434) (8,776) Foreign exchange 357 — — — Fair value of plan assets, end of year $ 629,157 $ 407,074 $ 176,616 $ 158,873 Unfunded status $ (205,756) $ (157,896) $ (129,908) $ (60,344) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 488 — 10,174 8,437 Current liabilities (1,989) (1,415) (2,835) (1,168) Non-current liabilities (204,255) (156,481) (137,247) (67,613) Net amount recognized $ (205,756) $ (157,896) $ (129,908) $ (60,344) The accumulated benefit obligation for the pension plans was $1,080,685 and $526,517 as of December 31, 2020 and 2019, respectively. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation (continued) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2020 2019 2020 2019 Accumulated benefit obligation $ 727,981 $ 504,403 $ 288,594 $ 202,422 Fair value of plan assets $ 578,143 $ 407,074 $ 148,496 $ 133,711 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2020 2019 2020 2019 Projected benefit obligation $ 833,846 $ 564,971 $ 288,594 $ 202,422 Fair value of plan assets $ 627,601 $ 407,074 $ 148,496 $ 133,711 In 2019, the Company merged the Empire pension plan into the Company's cash balance plan and defined benefit plans, and changed benefits for certain Empire participants. The total impact of these plan amendments resulted in a decrease to the projected benefit obligation of $7,798, which was recorded as a prior service credit in OCI. (b) Pension and post-employment actuarial changes Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2019 $ 34,257 $ (6,221) $ (13,888) $ (208) Additions to AOCI 17,905 (7,705) 14,871 — Amortization in current period (3,530) 784 409 208 Reclassification to regulatory accounts (10,122) 6,962 (10,538) — Balance, December 31, 2019 $ 38,510 $ (6,180) $ (9,146) $ — Additions to AOCI 50,026 (191) 22,036 — Amortization in current period (5,430) 1,609 (509) — Reclassification to regulatory accounts (25,875) (544) (16,680) — Balance, December 31, 2020 $ 57,231 $ (5,306) $ (4,299) $ — The movements in AOCI for Empire's and St. Lawrence Gas' pension and OPEB plans are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(b)). 10. Pension and other post-employment benefits (continued) (c) Assumptions Weighted average assumptions used to determine net benefit obligation for 2020 and 2019 were as follows: Pension benefits OPEB 2020 2019 2020 2019 Discount rate 2.49 % 3.19 % 2.58 % 3.29 % Interest crediting rate (for cash balance plans) 4.15 % 4.48 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.00 % 6.125 % Age 65 and after 6.00 % 6.125 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031 The mortality assumption for December 31, 2020 uses the Pri-2012 mortality table and the projected generationally scale MP-2020, adjusted to reflect the ultimate improvement rates in the 2020 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31, 2020 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B. In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate. The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations. Weighted average assumptions used to determine net benefit cost for 2020 and 2019 were as follows: Pension benefits OPEB 2020 2019 2020 2019 Discount rate 3.19 % 4.19 % 3.29 % 4.25 % Expected return on assets 6.85 % 6.87 % 5.57 % 6.51 % Rate of compensation increase 3.96 % 4.00 % N/A N/A Health care cost trend rate Before Age 65 6.125 % 6.25 % Age 65 and after 6.125 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031 10. Pension and other post-employment benefits (continued) (d) Benefit costs The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2020 2019 2020 2019 Service cost $ 15,450 $ 12,351 $ 6,175 $ 4,587 Non-service costs Interest cost 19,281 20,222 7,695 7,575 Expected return on plan assets (26,285) (20,485) (8,748) (6,725) Amortization of net actuarial loss (gain) 5,430 3,530 509 (409) Amortization of prior service credits (1,609) (784) — (208) Amortization of regulatory accounts 16,272 12,082 1,527 2,534 $ 13,089 $ 14,565 $ 983 $ 2,767 Net benefit cost $ 28,539 $ 26,916 $ 7,158 $ 7,354 (e) Plan assets The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due. The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 47 % 30% -100% Debt securities 43 % 20% - 60% Other 10 % 0% - 20% 100 % The fair values of investments as of December 31, 2020, by asset category, are as follows: Asset class 2020 Percentage Equity securities $ 479,506 59 % Debt securities 255,975 32 % Other 70,292 9 % $ 805,773 100 % As of December 31, 2020, the funds do not hold any material investments in AQN. 10. Pension and other post-employment benefits (continued) (e) Plan assets (continued) All investments as of December 31, 2020 were valued using level 1 inputs except for $7,745 of institutional private equity investments using level 3 fair value measurement. These private equity funds invest in the private equity secondary market and in the credit markets. These funds are not traded in the open market, and are valued based on the underlying securities within the funds. The underlying securities are valued at fair value by the fund managers by using securities exchange quotations, pricing services, obtaining broker-dealer quotations, reflecting valuations provided in the most recent financial reports, or at a good faith estimate using fair market value principles. The following table summarizes the changes fair value of these level 3 assets as of December 31: Level 3 Balance, January 1, 2020 $ — Contributions into funds 6,726 Unrealized gains 1,188 Distributions (169) Balance, December 31, 2020 $ 7,745 (f) Cash flows The Company expects to contribute $28,104 to its pension plans and $11,398 to its post-employment benefit plans in 2021. The expected benefit payments over the next ten years are as follows: 2021 2022 2023 2024 2025 2026 — 2030 Pension plan $ 46,858 $ 44,993 $ 46,358 $ 47,028 $ 48,197 $ 241,151 OPEB 10,414 11,033 11,601 12,165 12,687 68,826

Other assets

Other assets	12 Months Ended
	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2020 2019 Restricted cash $ 28,404 $ 24,787 OPEB plan assets (note 10(a)) 10,662 8,437 Atlantica related prepaid amount — 8,844 Long-term deposits 13,459 6,319 Income taxes recoverable 4,717 4,416 Deferred financing costs 6,774 5,477 Other 11,736 8,192 $ 75,752 $ 66,472 Less: current portion (7,266) (7,764) $ 68,486 $ 58,708

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2020 2019 Advances in aid of construction (a) $ 79,864 $ 60,828 Environmental remediation obligation (b) 69,383 58,061 Asset retirement obligations (c) 79,968 53,879 Customer deposits (d) 31,939 31,946 Unamortized investment tax credits (e) 17,893 18,234 Deferred credits (f) 21,156 18,952 Preferred shares, Series C (g) 13,698 13,793 Hook up fees (h) 17,704 9,610 Lease liabilities (note 1(q)) 14,288 9,695 Contingent development support obligations (i) 12,273 9,446 Note payable to related party (j) 30,493 — Other 23,027 16,896 $ 411,686 $ 301,340 Less: current portion (72,505) (57,939) $ 339,181 $ 243,401 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2020, $1,994 (2019 - $5,465) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. With the acquisition of Ascendant on November 9, 2020 (note 3(a)), the Company assumed additional environmental remediation obligations with respect to the decommissioning and remediation of a power station. This remediation approach involves excavation, treatment and reuse, with most of the work expected to occur in 2023. The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $60,803 (2019 - $58,484), which at discount rates ranging from 0.8% to 3.4% represents the recorded accrual of $69,383 as of December 31, 2020 (2019 - $58,061). Approximately $43,995 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years. 12. Other long-term liabilities (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2020 2019 Opening balance $ 58,061 $ 55,621 Remediation activities (5,130) (1,678) Accretion 436 1,065 Changes in cash flow estimates 3,828 981 Revision in assumptions 3,402 2,072 Obligation assumed from business acquisition 8,786 — Closing balance $ 69,383 $ 58,061 The Regulator for the New England gas system and Energy North gas system provide for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2020, the Company has reflected a regulatory asset of $87,308 (2019 - $82,300) for the MGP and related sites (note 7(d)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls ("PCB") contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities. Changes in the asset retirement obligations are as follows: 2020 2019 Opening balance $ 53,879 $ 43,291 Obligation assumed from business acquisition and constructed projects 20,420 3,226 Retirement activities (1,724) (443) Accretion 2,674 2,148 Change in cash flow estimates 4,719 5,657 Closing balance $ 79,968 $ 53,879 As the cost of retirement of utility assets in the United States, liability accretion and asset depreciation expense are expected to be recovered through rates, a corresponding regulatory asset is recorded (note 7(j)). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. 12. Other long-term liabilities (continued) (f) Deferred credits In 2019, the Company settled $29,100 of contingent consideration related to the Company's investment in Atlantica (note 8(a)), and recorded an additional $5,000 contingent consideration related to the Company's investment in the San Antonio Water System (note 8(d)). (g) Preferred shares, Series C AQN has 100 redeemable Series C preferred shares issued and outstanding. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share. As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2021 $ 1,075 2022 1,097 2023 1,324 2024 1,536 2025 1,552 Thereafter to 2031 7,693 Redemption amount 4,195 $ 18,472 Less: amounts representing interest (4,774) $ 13,698 Less current portion (1,075) $ 12,623 (h) Hook up fees Hook up fees result from the collection from customers of funds for installation and connection to the utility's infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement. (i) Contingent development support obligations The Company provides credit support necessary for the continued development and construction of its equity investees' wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(e)). (j) Note payable to related party In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project (note 8(e)). Following the closing of the construction financing facility for the Altatvista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually and has a maturity date of March 31, 2021.

Shareholders' capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2020 2019 Common shares, beginning of year 524,223,323 488,851,433 Public offering 66,130,063 28,009,341 Dividend reinvestment plan 5,217,071 6,068,465 Exercise of share-based awards (b) 1,565,537 1,274,655 Conversion of convertible debentures 6,225 19,429 Common shares, end of year 597,142,219 524,223,323 Authorized AQN is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of AQN to receive pro rata the remaining property and assets of AQN, subject to the rights of any shares having priority over the common shares. The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2022. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan. (i) Public offering On July 17, 2020, AQN issued 57,465,500 common shares at $12.60 (C$17.10) per share pursuant to agreements with a syndicate of underwriters and an institutional investor for gross proceeds of $723,926 (C$982,660) before issuance costs of $25,268 (C$34,299). For ward contracts were used to manage the Canadian dollar risk (note 24(b)(iv)). In October 2019, AQN issued 26,252,542 common shares at $13.50 per share pursuant to a public offering for proceeds of $354,409 before issuance costs of $14,418. (ii) At-the-market equity program AQN has established an at-the-market equity program (“ATM program”) that allows the Company to issue up to $500,000 of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. During the year ended December 31, 2020, the Company issued 8,664,563 common shares under the ATM program at an average price of $13.92 per common share for gross proceeds of $120,634 ($119,126 net of commissions). Other related costs, primarily related to the re-establishment of the ATM program, were $1,346. Since the initial launch of the ATM program in February 2019, the Company has issued an aggregate of 10,421,362 common shares under the ATM program at an average price of $13.69 per share for gross proceeds of $142,668 ($140,885 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishment of the ATM program, were $3,413. 13. Shareholders’ capital (continued) (a) Common shares (continued) (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by AQN at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, AQN issued an addition al 1,403,635 co mmon shares under the dividend reinvestment plan. (b) Preferred shares AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2020 and 2019: Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $ Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463 Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836 $ 184,299 The holders of Series A preferred shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 will be an annual amount of C$1.2905 per share. The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A preferred shares are redeemable at C$25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter. The holders of Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.25 per share for each year up to, but excluding, March 31, 2019. The dividend for the five-year period from and including March 31, 2019 to, but excluding, March 31, 2024 will be C$1.2728. The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D preferred shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter. The holders of Series D preferred shares had the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2019, respectively, and every fifth year thereafter. None of the Series B preferred shares were converted on March 31, 2019. The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(g)). (c) Share-based compensation For the year ended December 31, 2020, AQN recorded $24,637 (2019 - $11,042) in total share-based compensation expense as follows: 2020 2019 Share options $ 1,743 $ 1,288 Director deferred share units 870 798 Employee share purchase 511 322 Performance and restricted share units 21,513 8,634 Total share-based compensation $ 24,637 $ 11,042 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) The compensation expense is recorded with payroll expenses in the consolidated statements of operations, except for $12,639 related to management succession and executive retirement expenses discussed below, which was recorded in other net losses (note 19(b)) for the year ended December 31, 2020. The portion of share-based compensation costs capitalized as cost of construction is insignificant. As of December 31, 2020, total unrecognized compensation costs related to non-vested share-based awards was $12,063 and is expected to be recognized over a period of 1.71 years. (i) Management succession and executive retirements The Company had announced succession plans for the role of Chief Executive Officer (“CEO”) and the retirements of the Chief Financial Officer (“CFO”) and Vice Chair who retired on July 17, 2020, September 18, 2020, and November 30, 2020, respectively (collectively, the "retiring executives"). Retirement RSUs were granted to the retiring executives. The retirement RSUs vested on each executive’s respective retirement date and settle at various times between the first and fifth anniversary of the day of grant. The compensation cost is recorded over the period from the effective date of the retirement agreement to the retirement date. For the year ended December 31, 2020, the Company recorded compensation cost of $5,466 in other net losses (note 19(b)). All unvested PSUs held by the retiring executive will remain outstanding. All options held by the executive will continue to vest and be exercisable as if the executive were still employed until such options otherwise expire in accordance with their terms and conditions. The fair value of these PSUs and options is being recognized over their vesting period. As a result of the retirement agreement, the recognition of the compensation cost is accelerated and recorded over the period from the effective date of the retirement agreement to the retirement date. For the year ended December 31, 2020, the Company recorded accelerated compensation expense of $4,591 in other net losses (note 19(b)). For the year ended December 31, 2020, the Company recorded other succession and retirement expense of $2,582 in other net losses (note 19(b)). (ii) Share option plan The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted. The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company's clawback policy. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (ii) Share option plan (continued) The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN shares. The following assumptions were used in determining the fair value of share options granted: 2020 2019 Risk-free interest rate 1.2 % 1.9 % Expected volatility 24 % 20 % Expected dividend yield 4.1 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.72 C$ 1.66 Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2019 6,292,642 C$ 11.61 5.75 C$ 13,342 Granted 1,113,775 14.96 8.00 — Exercised (3,882,505) 11.23 4.45 6,225 Balance, December 31, 2019 3,523,912 C$ 13.09 5.87 C$ 18,609 Granted 999,962 16.78 7.27 — Exercised (2,386,275) 12.52 5.16 18,465 Forfeited (27,151) 14.96 — — Balance, December 31, 2020 2,110,448 C$ 15.45 6.55 C$ 11,604 Exercisable, December 31, 2020 1,710,662 C$ 15.22 6.44 C$ 9,798 (iii) Employee share purchase plan Under the Company’s ESPP, eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by AQN under the ESPP shall not exceed 4,000,000 common shares. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (iii) Employee share purchase plan (continued) The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2020, a total of 302,727 common shares (2019 - 253,538) were issued to employees under the ESPP. (iv) Director's deferred share units Under the Company’s deferred share unit plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2020, 544,493 (2019 - 460,418) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by AQN under the DSU plan shall not exceed 1,000,000 common shares. (v) Performance and restricted share units The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.5% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by AQN under the PSU and RSU Plan shall not exceed 7,000,000 common shares. Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (v) Performance and restricted share units (continued) A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2019 1,392,132 C$ 12.75 1.60 C$ 19,114 Granted, including dividends 1,471,442 14.69 2.00 16,302 Exercised (344,340) 11.55 — 5,148 Forfeited (107,191) 13.84 — — Balance, December 31, 2019 2,412,043 C$ 14.00 1.86 C$ 44,309 Granted, including dividends 1,313,171 19.31 2.00 24,966 Exercised (968,470) 14.45 — 20,105 Forfeited (35,537) 15.62 — 745 Balance, December 31, 2020 2,721,207 C$ 16.58 0.93 C$ 44,289 Exercisable, December 31, 2020 707,630 C$ 12.70 — C$ 14,825 (vi) Bonus deferral RSUs Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. These RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. The RSUs granted are 100% vested and therefore, compensation expense associated with these RSUs is recognized immediately upon issuance. During the year ended December, 31, 2020, 135,409 bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 13,778 bonus deferral RSUs in exchange for 6,401 common shares issued from treasury, and 7,377 RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs.

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss) AOCI consists of the following balances, net of tax: Foreign currency cumulative translation Unrealized gain on cash flow hedges Pension and post-employment actuarial changes Total Balance, January 1, 2019 $ (74,189) $ 64,333 $ (9,529) $ (19,385) Adoption of ASU 2017-12 on hedging — 186 — 186 Other comprehensive income (loss) 4,267 19,177 (7,999) 15,445 Amounts reclassified from AOCI to the consolidated statement of operations 3,528 (8,597) 1,490 (3,579) Net current period OCI $ 7,795 $ 10,580 $ (6,509) $ 11,866 OCI attributable to the non-controlling interests (2,428) — — (2,428) Net current period OCI attributable to shareholders of AQN $ 5,367 $ 10,580 $ (6,509) $ 9,438 Balance, December 31, 2019 $ (68,822) $ 75,099 $ (16,038) $ (9,761) Other comprehensive income (loss) 25,643 (13,418) (20,964) (8,739) Amounts reclassified from AOCI to the consolidated statement of operations 2,763 (10,864) 3,403 (4,698) Net current period OCI $ 28,406 $ (24,282) $ (17,561) $ (13,437) OCI attributable to the non-controlling interests 691 — — 691 Net current period OCI attributable to shareholders of AQN $ 29,097 $ (24,282) $ (17,561) $ (12,746) Balance, December 31, 2020 $ (39,725) $ 50,817 $ (33,599) $ (22,507) Amounts reclassified from AOCI for foreign currency cumulative translation affected interest expense and derivative gain (loss); those for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales, interest expense and derivative gain (loss) while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs (note 24(b)).

Dividends

Dividends	12 Months Ended
	Dec. 31, 2020
Disclosure Cash Dividends [Abstract]
Dividends	Dividends All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared were as follows: 2020 2019 Dividend Dividend per share Dividend Dividend per share Common shares $ 344,382 $ 0.6063 $ 277,835 $ 0.5512 Series A preferred shares C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Series D preferred shares C$ 5,091 C$ 1.2728 C$ 5,068 C$ 1.2671

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related party transactions	Related party transactions (a) Equity-method investments The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2020, the Company charged its equity-method investees $25,829 (2019 - $16,248). Additionally, one of the equity-method investees provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $26,015 (2019 - $3,924). In 2020, the Company issued a promissory note of $30,493 payable to Altavista, an equity investee of the Company (note 12(j)). On December 30, 2019, the Company and a third party each contributed C$1,500 to the capital of a new joint venture, created for the purpose of investing in infrastructure opportunities. The Company sold its investment in Abengoa Water USA, LLC to the joint venture in exchange for a note receivable of $30,293 (note 8(d)). No gain or loss was recognized on the sale. In 2019, AQN recorded interest income of $6,007, and a fair value loss of $6,007 on its investment in the joint venture. On July 2, 2020, AQN acquired the third-party developer's 50% interest in the joint venture for C$1,581. During 2019, the Company sold the Sugar Creek Wind Project to AAGES Sugar Creek in exchange for a note receivable of $21,107, subject to certain adjustments. No gain was recorded on deconsolidation of the Sugar Creek net assets. However, an amount of $15,765, or $11,412, net of tax, was reclassified from AOCI into earnings as a result of the discontinuation of hedge accounting on energy derivatives put in place early in the development of Sugar Creek. The novation and transfer of the derivative contract was subject to counterparty approval, which was received in the first quarter of 2020. Upon approval, the contract was transferred to AAGES Sugar Creek in exchange for a note receivable of $15,765 (note 24(b)(ii)). During 2019, the Company entered into an enhanced cooperation agreement with Atlantica to, among other things, provide a framework for evaluating mutually advantageous transactions. For a period of one year from the date of the agreement, Atlantica had an exclusive right of first offer for interests in certain Renewable Energy assets. The right expired in 2020. (b) Redeemable non-controlling interest held by related party On November 28, 2018, AAGES B.V., an equity investee of the Company, obtained a three-year secured credit facility in the amount of $306,500 and subscribed to a $305,000 preference share ownership interest in AY Holdings. The AAGES B.V. secured credit facility is collateralized through a pledge of Atlantica shares held by AY Holdings. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica stock to eliminate the collateral shortfall. The AAGES B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company. AQN reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest held by related party. Redemption is not considered probable as at December 31, 2020. During the year ended December 31, 2020, the Company incurred non-controlling interest attributable to AAGES B.V. of $12,651 (2019 - $16,482) and recorded distributions of $12,198 (2019 - $18,241) (note 17). (c) Non-controlling interest held by related party Non-controlling interest held by related party represents an interest in AIP, a consolidated subsidiary of the Company, acquired by AYES Canada in May 2019 for $96,752 (C$130,103) (note 8(c)). During the year ended December 31, 2020, the Company recorded distributions to AYES of $16,064 (2019 - $26,465). The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Non-controlling Interests and R

Non-controlling Interests and Redeemable non-controlling Interest	12 Months Ended
	Dec. 31, 2020
Noncontrolling Interest [Abstract]
Non-controlling Interests and Redeemable non-controlling Interest	Non-controlling interests and redeemable non-controlling interests Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2020 2019 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 63,080 $ 55,963 Non-controlling interests - redeemable tax equity partnership units 6,955 9,006 Other net earnings attributable to: Non-controlling interests (2,749) (2,553) $ 67,286 $ 62,416 Redeemable non-controlling interest, held by related party (12,651) (16,482) Net effect of non-controlling interests $ 54,635 $ 45,934 The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s). Non-controlling interests As of December 31, 2020, non-controlling interests of $399,487 (2019 - $457,834) include partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $388,253 (2019 - $457,000) and other non-controlling interests of $11,234 (2019 - $834). Non-controlling interest held by related party Non-controlling interest was issued to AYES Canada in May 2019 for $96,752 (note 8(c)). The balance as of December 31, 2020 was $59,125 (2019 - $73,707). Redeemable non-controlling interests Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2020. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2020 2019 2020 2019 Opening balance $ 305,863 $ 307,622 $ 25,913 $ 33,364 Net effect from operations 12,651 16,482 (6,955) (9,006) Contributions, net of costs — — 3,717 3,403 Dividends and distributions declared (12,198) (18,241) (951) (1,848) Repurchase of non-controlling interest — — (865) — Closing balance $ 306,316 $ 305,863 $ 20,859 $ 25,913 The Turquoise Solar Facility, a 10 MWac solar generating facility located in Washoe County, Nevada, was placed in service on December 31, 2019. The Class A partnership units are owned by a third-party tax equity investor who funded $3,403 in 2019 and final installments of $3,717 in 2020.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income taxes	Income taxes The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate o f 26.5% (2019 - 26.5%). The differences are as follows: 2020 2019 Expected income tax expense at Canadian statutory rate $ 209,989 $ 147,093 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,082) (27,703) Adjustments from investments carried at fair value (87,058) (60,730) Non-controlling interests share of income 18,243 16,991 Non-deductible acquisition costs 3,223 2,500 Tax credits (40,185) (9,332) Adjustment relating to prior periods (4,228) (1,240) Amortization and settlement of excess deferred income tax (12,392) (2,554) Other 4,073 5,092 Income tax expense $ 64,583 $ 70,117 On April 8, 2020, the IRS issued final regulations with respect to rules regarding certain Hybrid arrangements as a result of U.S. Tax Reform. As a result of the final regulations, the Company has recorded a one-time income tax expense of $9,300 to reverse the benefit of the deductions taken in the prior year. For the years ended December 31, 2020 and 2019, earnings before income taxes consist of the following: 2020 2019 Canada (1) $ 626,980 $ 351,908 U.S. 165,431 203,159 $ 792,411 $ 555,067 (1) Inclusive of fair value gain (loss) on investments carried at fair value (note 8) Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2020 Canada $ 6,336 $ 61,440 $ 67,776 United States (1,448) (1,745) (3,193) $ 4,888 $ 59,695 $ 64,583 Year ended December 31, 2019 Canada $ 6,695 $ 17,607 $ 24,302 United States 9,736 36,079 45,815 $ 16,431 $ 53,686 $ 70,117 18. Income taxes (continued) The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2020 and 2019 are presented below: 2020 2019 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 531,353 $ 382,448 Pension and OPEB 66,826 54,113 Environmental obligation 16,145 15,541 Regulatory liabilities 168,054 160,200 Other 65,787 59,103 Total deferred income tax assets $ 848,165 $ 671,405 Less: valuation allowance (29,824) (29,447) Total deferred tax assets $ 818,341 $ 641,958 Deferred tax liabilities: Property, plant and equipment $ 733,211 $ 707,185 Outside basis differentials 406,429 235,063 Regulatory accounts 212,937 145,852 Other 12,528 14,811 Total deferred tax liabilities $ 1,365,105 $ 1,102,911 Net deferred tax liabilities $ (546,764) $ (460,953) Consolidated balance sheets classification: Deferred tax assets $ 21,880 $ 30,585 Deferred tax liabilities (568,644) (491,538) Net deferred tax liabilities $ (546,764) $ (460,953) The valuation allowance for deferred tax assets as at December 31, 2020 was $29,824 (2019 - $29,447). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment. As of December 31, 2020, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows: Non-capital loss carryforward and credits 2021-2026 2027+ Total Canada $ 58 $ 552,506 $ 552,564 US 13,427 912,589 926,016 Total non-capital loss carryforward $ 13,485 $ 1,465,095 $ 1,478,580 Tax credits $ 3,624 $ 72,849 $ 76,473 The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximate ly $504,149 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

Other net losses

Other net losses	12 Months Ended
	Dec. 31, 2020
Other Income and Expenses [Abstract]
Other net losses	Other net losses Other net losses consist of the following: 2020 2019 Acquisition and transition-related costs $ 14,104 $ 11,609 Tax reform (a) 11,728 — Management succession and executive retirement (b) 12,639 — Other (c) 22,840 15,085 $ 61,311 $ 26,694 (a) Tax reform As a result of the Tax Cuts and Jobs Act enacted in 2017, regulators in the states where the Regulated Services Group operates contemplated the rate making implications of federal tax rates from the legacy 35% tax rate and the new 21% federal statutory income tax rate effective January 2018. On July 1, 2020, the Company received an order from the Public Service Commission of the State of Missouri that requires Empire to refund to customers over five years the revenue requirement collected at the higher tax rate between January 1, 2018 and August 31, 2018 before new rates came into effect. Therefore, an accounting loss was recognized for $11,728 in 2020. (b) Management succession and executive retirement The Company announced succession plans for the role of CEO, and the retirements of the CFO and Vice Chair. As part of the Retirement Agreements, the Company recorded $12,639, for the year ended December 31, 2020, of expenses in relation to these executives’ share-based compensation agreements (note 13(c)(i)). (c) Other

Basic and diluted net earnings

Basic and diluted net earnings per share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share, Basic and Diluted [Abstract]
Basic and diluted net earnings per share	Basic and diluted net earnings per shareBasic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options and additional shares issued subsequent to year-end under the dividend reinvestment plan. The convertible debentures are convertible into common shares at any time prior to maturity or redemption by the Company. The shares issuable upon conversion of the convertible debentures are included in diluted earnings per share. 20. Basic and diluted net earnings per share (continued) The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2020 2019 Net earnings attributable to shareholders of AQN $ 782,463 $ 530,884 Series A preferred shares dividend 4,611 4,666 Series D preferred shares dividend 3,790 3,820 Net earnings attributable to common shareholders of AQN – basic and diluted $ 774,062 $ 522,398 Weighted average number of shares Basic 559,633,275 499,910,876 Effect of dilutive securities 4,740,561 4,828,678 Diluted 564,373,836 504,739,554

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segmented information	Segmented information The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company. The Regulated Services Group, the Company's regulated operating unit, owns and operates a portfolio of electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States, Canada, Chile and Bermuda; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates a diversified portfolio of renewable and thermal electric generation assets in North America and internationally. For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group, while interest income from San Antonio Water System is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate. 21. Segmented information (continued) Year ended December 31, 2020 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,405,136 $ 270,398 $ 1,524 $ 1,677,058 Fuel, power and water purchased 384,363 16,645 — 401,008 Net revenue 1,020,773 253,753 1,524 1,276,050 Operating expenses 445,459 74,981 12 520,452 Administrative expenses 34,141 24,719 630 59,490 Depreciation and amortization 219,089 92,890 2,144 314,123 Gain on foreign exchange — — (2,108) (2,108) Operating income 322,084 61,163 846 384,093 Interest expense (99,161) (52,656) (30,117) (181,934) Income from long-term investments 7,753 96,652 560,266 664,671 Other (40,128) (6,537) (27,754) (74,419) Earnings before income taxes $ 190,548 $ 98,622 $ 503,241 $ 792,411 Property, plant and equipment $ 5,757,532 $ 2,451,706 $ 32,600 $ 8,241,838 Investments carried at fair value — 1,837,429 — 1,837,429 Equity-method investees 74,673 111,779 — 186,452 Total assets 8,528,172 4,589,521 106,213 13,223,906 Capital expenditures $ 690,792 $ 80,746 $ 14,492 $ 786,030 (1) Renewable Energy Group revenue includes $28,586 related to net hedging gains from energy derivative contracts and availability credits for the year ended December 31, 2020 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $24,928 related to alternative revenue programs for the year ended December 31, 2020 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2019 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,368,411 $ 256,510 $ 1,471 $ 1,626,392 Fuel and power purchased 426,046 17,258 — 443,304 Net revenue 942,365 239,252 1,471 1,183,088 Operating expenses 397,092 74,676 221 471,989 Administrative expenses 36,667 19,366 769 56,802 Depreciation and amortization 194,766 88,557 981 284,304 Loss on foreign exchange — — 3,146 3,146 Operating income 313,840 56,653 (3,646) 366,847 Interest expense (101,518) (61,039) (18,931) (181,488) Income from long-term investments 9,334 104,025 284,262 397,621 Other (32,297) 15,951 (11,567) (27,913) Earnings before income taxes $ 189,359 $ 115,590 $ 250,118 $ 555,067 Property, plant and equipment $ 4,763,689 $ 2,444,382 $ 32,909 $ 7,240,980 Investments carried at fair value 27,072 1,267,075 — 1,294,147 Equity-method investees 29,827 52,284 — 82,111 Total assets 6,825,379 4,014,067 81,340 10,920,786 Capital expenditures $ 478,936 $ 102,396 $ — $ 581,332 (1) Renewable Energy Group revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has sought to mitigate its credit risk by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue. 21. Segmented information (continued) AQN operates in the independent power and utility industries in the United States, Canada and other regions. Information on operations by geographic area is as follows: 2020 2019 Revenue United States $ 1,475,087 $ 1,537,695 Canada 153,569 88,697 Other regions 48,402 — $ 1,677,058 $ 1,626,392 Property, plant and equipment United States $ 6,666,015 $ 6,488,964 Canada 884,195 752,016 Other regions 691,628 — $ 8,241,838 $ 7,240,980 Intangible assets United States $ 24,825 $ 23,821 Canada 23,123 23,795 Other regions 66,965 — $ 114,913 $ 47,616 Revenue is attributed to the regions based on the location of the underlying generating and utility facilities.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies (a) Contingencies AQN and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider AQN’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable. Claim by Gaia Power Inc. On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against AQN and certain of its subsidiaries, initially claiming damages of not less than C$345,000 and punitive damages in the sum of C$25,000. On November 28, 2020, Gaia served the Company with an amended notice of arbitration to, among other things, lower the value of its damages claim to C$108,500 and lower the value of its punitive damages claim to C$10,000. The action arises from Gaia’s 2010 sale, to a subsidiary of AQN, of Gaia’s interest in certain proposed wind farm projects in Canada. Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets. The parties have agreed to arbitrate the dispute, with the evidentiary portion of the hearing having occurred during the week of February 22, 2021 and closing arguments scheduled for March 16 and 17, 2021. The likelihood of success in this lawsuit cannot be reasonably predicted; however, AQN intends to continue to vigorously defend it. Condemnation expropriation proceedings Liberty Utilities (Apple Valley Ranchos Water) Corp. is the subject of a condemnation lawsuit filed by the town of Apple Valley. A court will determine the necessity of the taking by Apple Valley and, if established, a jury will determine the fair market value of the assets being condemned. The evidentiary portion of the right-to-take condemnation trial finished on July 15, 2020 and a decision is expected from the Court in the first half of 2021. Any taking by government entities would legally require fair compensation to be paid; however, there is no assurance that the value received as a result of the condemnation will be sufficient to recover the Company's net book value of the utility assets taken. Mountain View fire On November 17, 2020, a wildfire now known as the Mountain View fire occurred in the territory of Liberty Utilities (CalPeco Electric) LLC. The cause of the fire is undetermined at this time, and CAL FIRE has not yet issued a report. To date, four lawsuits have been filed against subsidiaries of the Company in connection with the Mountain View fire. The likelihood of success in these lawsuits cannot be reasonably predicted; however, Liberty Utilities (CalPeco Electric) LLC intends to vigorously defend them. (b) Commitments In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2020. AQN has outstanding purchase commitments for power purchases, gas supply and service agreements, service agreements, capital project commitments and land easements. 22. Commitments and contingencies (continued) (b) Commitments (continued) Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 45,083 $ 27,310 $ 26,178 $ 26,236 $ 26,472 $ 167,380 $ 318,659 Gas supply and service agreements (ii) 89,034 62,781 48,427 42,174 37,699 144,885 425,000 Service agreements 56,828 46,817 50,223 48,671 45,766 248,540 496,845 Capital projects 654,399 — — — — — 654,399 Land easements 6,747 6,783 6,874 6,958 7,036 194,995 229,393 Total $ 852,091 $ 143,691 $ 131,702 $ 124,039 $ 116,973 $ 755,800 $ 2,124,296 (i) Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2020. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: AQN’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Non-cash operating items

Non-cash operating items	12 Months Ended
	Dec. 31, 2020
Disclosure Changes In Non Cash Operating Items [Abstract]
Non-cash operating items	Non-cash operating items The changes in non-cash operating items consist of the following: 2020 2019 Accounts receivable $ (52,778) $ (20,857) Fuel and natural gas in storage 237 13,985 Supplies and consumables inventory 1,058 (6,028) Income taxes recoverable (3,440) 17,796 Prepaid expenses (15,411) (7,501) Accounts payable 40,885 63,854 Accrued liabilities (29,150) 8,872 Current income tax liability 3,818 (5,016) Asset retirements and environmental obligations 3,562 (2,494) Net regulatory assets and liabilities (26,260) (2,308) $ (77,479) $ 60,303

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments December 31, 2020 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,837,429 $ 1,837,429 $ 1,706,900 $ 20,015 $ 110,514 Development loans and other receivables 23,804 31,088 — 31,088 — Derivative instruments: Energy contracts designated as a cash flow hedge 51,525 51,525 — — 51,525 Energy contracts not designated as cash flow hedge 388 388 — — 388 Commodity contracts for regulated operations 194 194 — 194 — Total derivative instruments 52,107 52,107 — 194 51,913 Total financial assets $ 1,913,340 $ 1,920,624 $ 1,706,900 $ 51,297 $ 162,427 Long-term debt $ 4,538,470 $ 5,140,059 $ 2,316,586 $ 2,823,473 $ — Notes payable to related party 30,493 30,493 — 30,493 — Convertible debentures 295 623 623 — — Preferred shares, Series C 13,698 15,565 — 15,565 — Derivative instruments: Energy contracts designated as a cash flow hedge 5,597 5,597 — — 5,597 Energy contracts not designated as a cash flow hedge 332 332 — — 332 Cross-currency swap designated as a net investment hedge 84,543 84,543 — 84,543 — Interest rate swaps designated as a hedge 19,324 19,324 — 19,324 — Commodity contracts for regulated operations 614 614 — 614 — Total derivative instruments 110,410 110,410 — 104,481 5,929 Total financial liabilities $ 4,693,366 $ 5,297,150 $ 2,317,209 $ 2,974,012 $ 5,929 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2019 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,294,147 $ 1,294,147 $ 1,178,581 $ 27,072 $ 88,494 Development loans and other receivables 37,050 37,984 — 37,984 — Derivative instruments: Energy contracts designated as a cash flow hedge 65,304 65,304 — — 65,304 Energy contracts not designated as a cash flow hedge 20,384 20,384 — — 20,384 Commodity contracts for regulatory operations 16 16 — 16 — Total derivative instruments 85,704 85,704 — 16 85,688 Total financial assets $ 1,416,901 $ 1,417,835 $ 1,178,581 $ 65,072 $ 174,182 Long-term debt $ 3,931,868 $ 4,284,068 $ 1,495,153 $ 2,788,915 $ — Convertible debentures 342 623 623 — — Preferred shares, Series C 13,793 15,120 — 15,120 — Derivative instruments: Energy contracts designated as a cash flow hedge 789 789 — — 789 Energy contracts not designated as a cash flow hedge 38 38 — — 38 Cross-currency swap designated as a net investment hedge 81,765 81,765 — 81,765 — Commodity contracts for regulated operations 2,072 2,072 — 2,072 — Total derivative instruments 84,664 84,664 — 83,837 827 Total financial liabilities $ 4,030,667 $ 4,384,475 $ 1,495,776 $ 2,887,872 $ 827 The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2020 and 2019 du e to the short-term maturity of these instruments. The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange. 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The Company’s level 1 fair value of long-term debt is measured at the closing price on the New York Stock Exchange and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates. The Company's level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of AQN's common shares on a converted basis. The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights, subscription agreements and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves, which are observable in the marketplace. The Company’s level 3 instruments consist of energy contracts for electricity sales and the fair value of the Company's investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $13.64 to $98.05 with a weighted average of $22.96 as of December 31, 2020. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of the Company's AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.25% to 8.75% with a weighted average of 8.67%, and the expected volatility of Atlantica's share price ranging from 22% to 46% as of December 31, 2020. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement. The increase in value and volatility of the Atlantica shares during the year resulted in a significant increase in the fair value measurement. (b) Derivative instruments Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period. (i) Commodity derivatives – regulated accounting The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas and electric service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers. The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts: 2020 Financial contracts: Swaps 1,830,852 Options 479,692 Forward contracts 1,500,000 3,810,544 The accounting for these derivative instruments is subject to guidance for rate regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(g)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact. 24. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts on the consolidated balance sheets: 2020 2019 Regulatory assets: Swap contracts $ 228 $ 28 Option contracts 50 38 Forward contracts $ 693 $ 1,830 Regulatory liabilities: Swap contracts $ 271 $ 743 Option contracts $ 76 $ — (ii) Cash flow hedges The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities and the Shady Oaks II development project by entering into the following long-term energy derivative contracts. Notional quantity Expiry Receive average Pay floating price 2,479,234 December 2031 $23.50 NI HUB 642,280 December 2028 $34.02 PJM Western HUB 2,953,751 December 2027 $24.76 NI HUB 2,330,995 December 2027 $36.46 ERCOT North HUB The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility is expected to provide a portion of the energy required to service these customers, AQN anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy. The Company designated a contract with a notional quantity of 81,408 MW-hours, a price of $38.95 per MW-hr and expiring in February 2022 as a hedge to the price of energy purchases. The Company also mitigates the risk by using short-term financial forward energy purchase contracts. These short-term derivatives are not accounted for as hedges and changes in fair value are recorded in earnings as they occur (note 24(b)(iv)). In November 2020, upon the acquisition of Ascendant (note 3(a)), the Company redesignated two interest rate swap contracts as cash flow hedges to mitigate the risk that LIBOR-based interest rates will increase over the life of Ascendant's term loan facilities. Under the terms of the interest rate swap contracts, the Company has fixed its LIBOR interest rate expense on $87,627 and $8,875 to 3.28% and 3.02%, respectively, on its two term loan facilities. In January 2019, the Company entered into a long-term energy derivative contract to reduce the price risk on the expected future sale of power generation at the Sugar Creek Wind Project. On September 30, 2019, the Company sold the derivative contract together with 100% of its ownership interest in Sugar Creek Wind Project to AAGES Sugar Creek Wind, LLC. The novation and transfer of the derivative contract was subject to counterparty approval, which was received in the first quarter of 2020. As a result, the hedge relationship for the Sugar Creek Wind Project energy derivative was discontinued in 2019. Amounts in AOCI of $15,765 and related tax were reclassified from AOCI into earnings in 2019. In September 2019, the Company entered into a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the $350,000 subordinated unsecured notes. The Company designated the entire notional amount of the three pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes. 24. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) The Company was party to a 10-year forward-starting interest rate swap in order to reduce the interest rate risk related to the probable issuance of a 10-year C$135,000 bond. In 2019, the Company settled the forward-starting interest rate swap contract as it issued C$300,000 10-year senior unsecured notes with an interest rate of 4.60% (note 9(g)). The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2020 2019 Effective portion of cash flow hedge $ (13,418) $ 19,177 Amortization of cash flow hedge (1,248) (33) Amounts reclassified from AOCI (9,616) (8,564) OCI attributable to shareholders of AQN $ (24,282) $ 10,580 The Company expects $8,624, $483 and $1,215 of unrealized gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales, interest expense and derivative gains, respectively, within the next 12 months, as the underlying hedged transactions settle. (iii) Foreign exchange hedge of net investment in foreign operation The functional currency of most of AQN's operations is the U.S. dollar. Effective January 1, 2020, the functional currency of AQN, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts, taking into consideration its operating, financing and investing activities. As a result of that entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk. The Company designates obligations denominated in Canadian dollars as a hedge of the foreign currency exposure of its net investment in its Canadian investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of $656 for the year ended December 31, 2020 (2019 - $nil) was recorded in OCI. On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes, to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. Upon the change in functional currency of AQN to the U.S. dollar on January 1, 2020, this hedge was dedesignated. The OCI related to this hedge will be amortized into earnings in the period that future interest payments affect earnings over the remaining life of the original hedge. The Company redesignated this swap as a hedge of AQN's net investment in its Canadian subsidiaries. The related foreign currency transaction gain or loss designated as a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The fair value of the derivative on the redesignation date will be amortized over the remaining life of the original hedge. A foreign currency loss of $13,256 for the year ended December 31, 2020 (2019 - $nil) was recorded in OCI. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iii) Foreign exchange hedge of net investment in foreign operation (continued) Canadian operations The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases. The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of $3,581 for the year ended December 31, 2020 (2019 - gain of $35,277) was recorded in OCI. The Company is party to C$650,000 cross currency swaps to effectively convert Canadian dollar debentures (note 9) into U.S. dollars. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $18,875 for the year ended December 31, 2020 (2019 - gain of $15,946) was recorded in OCI. Chilean operations The Company is exposed to currency fluctuations from its Chilean-based operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency. Chilean long-term debt used to finance the operations is denominated in Chilean Unidad de Fomento. (iv) Other derivatives Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. During the year, the Company executed on currency forward contracts to purchase in total $682,500 for approximately C$923,243 in order to manage the currency exposure to the Canadian dollar shares issuance (note 13(a)). A foreign currency gain of $2,363 was recorded as a result of the settlement. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives (continued) The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2020 2019 Change in unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (901) $ 530 Currency forward contract — (904) Total change in unrealized gain (loss) on derivative financial instruments $ (901) $ (374) Realized gain (loss) on derivative financial instruments: Energy derivative contracts (1,145) (227) Currency forward contract 2,363 147 Total realized gain (loss) on derivative financial instruments $ 1,218 $ (80) Gain (loss) on derivative financial instruments not accounted for as hedges 317 (454) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,009 15,810 $ 3,326 $ 15,356 Amounts recognized in the consolidated statements of operations consist of: Gain on derivative financial instruments $ 964 $ 16,113 Gain (loss) on foreign exchange 2,362 (757) $ 3,326 $ 15,356 (c) Risk management In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks. Credit risk Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the accounts receivable to be significant as 91% of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days. 24. Financial instruments (continued) (c) Risk management (continued) Credit risk (continued) The remaining revenue is primarily earned by the Regulated Services Group, which consists of water and wastewater, electric and gas utilities in the United States, Canada, Chile and Bermuda. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $266,225 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, most of the regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers. As of December 31, 2020, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2020 Cash and cash equivalents and restricted cash $ 130,018 Accounts receivable 355,151 Allowance for doubtful accounts (29,506) Notes receivable 23,804 $ 479,467 In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Liquidity risk Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2020, in addition to cash on hand of $101,614, the Company had $2,675,735 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn. The Company’s liabilities mature as follows: Due less Due 2 to 3 Due 4 to 5 Due after Total Long-term debt obligations $ 334,352 $ 821,535 $ 285,600 $ 3,092,544 $ 4,534,031 Interest on long-term debt 195,876 337,199 267,112 1,084,022 1,884,209 Purchase obligations 561,690 — — — 561,690 Environmental obligation 16,955 26,409 1,251 21,518 66,133 Advances in aid of construction 1,236 — — 78,628 79,864 Derivative financial instruments: Cross-currency swap 37,338 29,999 19,875 (2,670) 84,542 Interest rate swaps 2,725 4,346 4,369 7,885 19,325 Energy derivative and commodity contracts 1,917 (233) 919 3,940 6,543 Other obligations 79,219 6,601 5,232 125,209 216,261 Total obligations $ 1,231,308 $ 1,225,856 $ 584,358 $ 4,411,076 $ 7,452,598

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Comparative figures	Comparative figuresCertain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event Subsequent to year-end, in February 2021, the Company’s operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (the "Midwest Extreme Weather Event"). Despite the extreme weather conditions, the Regulated Services Group’s mid-west electric and gas systems performed well through the extreme conditions delivering new system peaks. In line with other Southwest Power Pool utilities, limited and short lived load shedding was required to meet broader system requirements. The Company incurred incremental commodity costs during a period of record pricing and elevated consumption. The incremental commodity costs incurred by the Company are expected to be substantially recovered from customers over a timeframe to be agreed with its regulators. However, the Company expects it will have sufficient liquidity to fund these costs in the interim. The Midwest Extreme Weather Event caused ice and freezing conditions, which restricted electricity production at certain of the Renewable Energy Group’s Texas-based wind facilities. The Company operates two facilities in Texas: the Senate Wind Facility in north-east Texas and the Maverick Creek Wind Facility in central Texas. Starting in 2021, the Company also has a 51% interest in the Stella, Cranell and East Raymond Texas Coastal Wind Facilities. The most significantly impacted facility was the Senate Wind Facility, which has a financial hedge in place that imposes an obligation to deliver energy. Due to icing, the facility was unable to produce the required energy to satisfy the quantities required to be delivered under the hedge, and was required to settle in the market at elevated pricing. The impacts to the Company's other Texas wind facilities were marginal. The Maverick Creek Wind Facility has two unit contingent power purchase agreements and as a result was not negatively subjected to the elevated market pricing. The Texas Coastal Wind Facilities experienced marginal impacts of the weather in aggregate.

Significant accounting polici_2

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of preparation	Basis of preparationThe accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.
Basis of consolidation	Basis of consolidationThe accompanying consolidated financial statements of AQN include the accounts of AQN, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).
Business combinations, intangible assets and goodwill	Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company's customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company's electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized. As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
Accounting for rate regulated operations	Accounting for rate regulated operations The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN's Chilean operating company, Empresa de Servicios de Los Lagos S.A. (“ESSAL”), which was acquired in October 2020. The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover ESSAL's specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations. The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the Regulator and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.
Cash and cash equivalents	Cash and cash equivalentsCash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
Restricted cash	Restricted cashRestricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.
Accounts receivable	Accounts receivableTrade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.1.Significant accounting policies (continued)
Fuel and natural gas in storage	Fuel and natural gas in storageFuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(g)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.
Supplies and consumables inventory	Supplies and consumables inventorySupplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.
Property, plant and equipment	Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest . The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2020 2019 2020 2019 Generation 3 - 60 3 - 60 33 33 Distribution 1 - 100 5 - 100 40 42 Equipment 5 - 50 5 - 44 11 10 The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.
Commonly owned facilities	Commonly owned facilitiesThe Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense.
Impairment of long-lived assets	Impairment of long-lived assets AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount. Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.
Variable interest entities	Variable interest entitiesThe Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8). 1. Significant accounting policies (continued) (m) Variable interest entities (continued) The Company has equity and notes receivable interests in two power generating facilities and one water pipeline project. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. The key decisions that affect the water pipeline investment entity's performance relate to any future investments and loans to the project, administering its rights as lender to the project, and the distribution of any interest or dividends received from the project. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary.
Long-term investments and notes receivable	Long-term investments and notes receivable Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee. Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured. If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. 1. Significant accounting policies (continued)
Pension and other post-employment plans	Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.
Asset retirement obligations	Asset retirement obligationsThe Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.
Leases	Leases The Company accounts for leases in accordance with ASC Topic 842, Leases . The Company leases land, buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842. The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company's right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company's lease balances as at December 31, 2020 and its expected lease payments for the next five years and thereafter are not significant.
Share-based compensation	Share-based compensationThe Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; a restricted share unit (“RSU”) and a performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.
Non-controlling interests	Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period. Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.
Recognition of revenue	Recognition of revenue Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, "Segmented information" for details of revenue disaggregation by business units. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Regulated Services Group revenue Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water. Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant. Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, "Segmented information" and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset. Renewable Energy Group revenue Renewable Energy Group's revenue consists primarily of the sale of electricity, capacity, and renewable energy credits. Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Renewable Energy Group revenue (continued) Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses. The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Renewable Energy Group contracts. The Company does not disclose the value of unsatisfied performance obligations for these contracts as revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.
Foreign currency translation	Foreign currency translation AQN’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with "CLP", in Chilean Unidad de Fomento with "CLF", and in Bermudian dollars with "BMD" immediately prior to the stated amounts. Effective January 1, 2020, the functional currency of AQN, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk.
Income taxes	Income taxesIncome taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises. 1. Significant accounting policies (continued) (v) Income taxes (continued) The organizational structure of AQN and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
Financial instruments and derivatives	Financial instruments and derivatives Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts. Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument. The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity. For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings. Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption. 1. Significant accounting policies (continued)
Fair value measurements	Fair value measurements The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels: • Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. • Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.
Commitments and contingencies	Commitments and contingenciesLiabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.
Use of estimates	Use of estimatesThe preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
COVID-19 pandemic	COVID-19 pandemic The ongoing outbreak of the novel strain of coronavirus (“COVID-19”) has resulted in business suspensions and shutdowns that have changed consumption patterns of residential, commercial and industrial customers across all three modalities of utility services, including decreased consumption among certain commercial and industrial customers. In each of the jurisdictions where the Company's major renewable energy construction projects are located, construction of new renewable energy generation has been considered an essential activity exempt from government-mandated business shutdowns. As a result, construction activities have proceeded at all of the Company's major renewable energy construction projects throughout the COVID-19 pandemic. In the second quarter of 2020, the U.S. Internal Revenue Service extended by one year the “continuity safe harbor” deadline by which renewable projects must be placed in service to qualify for the maximum permissible U.S. federal tax credits.
Recently adopted accounting pronouncements	Recently adopted accounting pronouncements The FASB issued accounting standards update (“ASU”) 2018-08 Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The adoption of this update in 2020 did not have an impact on the consolidated financial statements. The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The adoption of this update in 2020 did not have an impact on the consolidated financial statements. The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the amendments in this update, the impairment loss will be measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The Company will follow the pronouncements prospectively for goodwill impairment testing. The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The adoption of this topic in 2020 did not have a significant impact on the consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The amendments in this update are effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently assessing the impact of this update. The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The amendments in this update are effective for all entities as of March 12, 2020 through December 31, 2022. The FASB issued an update to Topic 848 in ASU 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition. The Company is currently assessing the impact of the reference rate reform and this update.

Significant accounting polici_3

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Estimated Useful Lives of Depreciable Assets	The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2020 2019 2020 2019 Generation 3 - 60 3 - 60 33 33 Distribution 1 - 100 5 - 100 40 42 Equipment 5 - 50 5 - 44 11 10

Business acquisitions and dev_2

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2020
Bermuda Electric Light Company
Business Acquisition [Line Items]
Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary allocation of the acquisition price to the assets acquired and liabilities assumed at the acquisition date: Working capital $ 71,948 Property, plant and equipment 417,947 Intangible assets 27,315 Goodwill 93,202 Regulatory assets 9,859 Other assets 4,992 Long-term debt (159,682) Pension and other post-employment benefits (58,746) Derivative instruments (12,748) Other liabilities (29,619) Total net assets acquired $ 364,468 Cash and cash equivalents acquired 42,920 Total net assets acquired, net of cash and cash equivalents $ 321,548
ESSAL
Business Acquisition [Line Items]
Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary allocation of the acquisition price of $87,975, when control was obtained, to the assets acquired and liabilities assumed at the initial acquisition date. The purchase of the second tranche reduced non-controlling interest by $74,111 in October 2020. Working capital $ 11,278 Property, plant and equipment 238,504 Intangible assets 37,095 Goodwill 70,382 Other assets 22 Long-term debt (139,534) Other post-employment benefits (2,292) Deferred tax liabilities, net (28,074) Other liabilities (14,881) Non-controlling interest (84,525) Total net assets acquired $ 87,975 Cash and cash equivalents acquired 6,983 Total net assets acquired, net of cash and cash equivalents $ 80,992

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment consist of the following: 2020 Cost Accumulated depreciation Net book value Generation $ 2,918,692 $ 633,210 $ 2,285,482 Distribution and transmission 5,766,885 661,786 5,105,099 Land 114,847 — 114,847 Equipment 99,722 51,979 47,743 Construction in progress Generation 136,424 — 136,424 Distribution and transmission 552,243 — 552,243 $ 9,588,813 $ 1,346,975 $ 8,241,838 2019 Cost Accumulated depreciation Net book value Generation $ 2,816,611 $ 540,118 $ 2,276,493 Distribution and transmission 4,997,613 598,449 4,399,164 Land 74,517 — 74,517 Equipment 94,583 47,541 47,042 Construction in progress Generation 140,235 — 140,235 Distribution and transmission 303,529 — 303,529 $ 8,427,088 $ 1,186,108 $ 7,240,980
Capitalization of Interest	Interest and AFUDC capitalized to the cost of the assets in 2020 and 2019 are as follows: 2020 2019 Interest capitalized on non-regulated property $ 9,359 $ 4,538 AFUDC capitalized on regulated property: Allowance for borrowed funds 3,475 2,745 Allowance for equity funds 2,219 4,896 $ 15,053 $ 12,179

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible assets consist of the following: 2020 Cost Accumulated amortization Net book value Power sales contracts $ 57,943 $ 41,184 $ 16,759 Customer relationships (note 3) 83,342 10,967 72,375 Interconnection agreements 15,028 1,458 13,570 Other (a) 12,209 — 12,209 $ 168,522 $ 53,609 $ 114,913 (a) Other includes brand names, water rights and miscellaneous intangibles (note 3) 2019 Cost Accumulated amortization Net book value Power sales contracts $ 56,206 $ 38,931 $ 17,275 Customer relationships 26,797 10,104 16,693 Interconnection agreements 14,827 1,179 13,648 $ 97,830 $ 50,214 $ 47,616
Goodwill	All goodwill pertains to the Regulated Services Group. 2020 2019 Opening balance $ 1,031,696 $ 954,282 Business acquisitions (note 3) 167,209 76,313 Foreign exchange 9,485 1,101 Closing balance $ 1,208,390 $ 1,031,696

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	The following regulatory proceedings were recently completed: Utility State Regulatory proceeding type Annual revenue increase (decrease) Effective date New England Natural Gas System Massachusetts General System Enhancement Plan $2,679 May 1, 2020 Energy North Gas System New Hampshire Cast Iron/Bare Steel Replacement Program Results $1,613 July 1, 2020 Granite State Electric System New Hampshire General Rate Review $5,474 July 1, 2020. The regulator also approved a one-time recoupment of $1,836 for the difference between the final rates and temporary rate increase of $2,093 granted on July 1, 2019. Empire Electric System (Missouri) Missouri General Rate Review $992 September 16, 2020 Peach State Gas System Georgia General Rate Review $1,566 August 1, 2020 Calpeco Electric System California General Rate Review $5,277 Retroactive to January 1, 2019 Various Various General Rate Review ($283) 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2020 December 31, 2019 Regulatory assets Retired generating plant (a) $ 194,192 $ — Pension and post-employment benefits (b) 178,403 143,292 Rate adjustment mechanism (c) 99,853 69,121 Environmental remediation (d) 87,308 82,300 Income taxes (e) 77,730 71,506 Debt premium (f) 35,688 42,150 Fuel and commodity cost adjustments (g) 18,094 23,433 Clean energy and other customer programs (h) 26,400 25,859 Deferred capitalized costs (i) 34,398 38,833 Asset retirement obligation (j) 26,546 23,841 Wildfire mitigation and vegetation management (k) 22,736 5,043 Long-term maintenance contract (l) 14,405 13,264 Rate review costs (m) 8,054 7,205 Other 21,664 14,040 Total regulatory assets $ 845,471 $ 559,887 Less: current regulatory assets (63,042) (50,213) Non-current regulatory assets $ 782,429 $ 509,674 Regulatory liabilities Income taxes (e) $ 322,317 $ 321,960 Cost of removal (n) 200,739 205,739 Pension and post-employment benefits (b) 26,311 22,256 Fuel and commodity costs adjustments (g) 20,136 17,729 Rate adjustment mechanism (c) 5,214 10,446 Clean energy and other customer programs (h) 10,440 6,871 Rate base offset (o) 6,874 8,719 Other 9,487 13,658 Total regulatory liabilities $ 601,518 $ 607,378 Less: current regulatory liabilities (38,483) (41,683) Non-current regulatory liabilities $ 563,035 $ 565,695 (a) Retired generating plant On March 1, 2020, the Company's 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The ultimate valuation of the regulatory asset will be determined in future commission orders. The Company is also assessing the decommissioning requirements associated with the retirement of the facility. Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on rates for consideration in the next rate case. The Company expects to defer such amounts collected from customers until new rates become effective. The accrual for this estimated amount includes revenues collected related to Asbury that will be subject to a future rate review proceeding and possible refund to customers. The ultimate resolution of this matter is uncertain. 7. Regulatory matters (continued) (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems' and St. Lawrence Gas system's pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods. (c) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 26 years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. (d) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (e) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. (f) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (g) Fuel and commodity cost adjustments The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. (h) Clean energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. 7. Regulatory matters (continued) (i) Deferred capitalized costs Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years. During the year, Empire Electric made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits Empire Electric to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable weighted average cost of capital (“WACC”) on certain property, plant, and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state, and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates. The regulatory asset associated with PISA as at December 31, 2020 is not material. (j) Asset retirement obligation Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates. (k) Wildfire mitigation and vegetation management The regulatory asset for vegetation management includes wildfire insurance in the Company's California operations as well as spending related to dead trees program, to prevent future forest fires and general vegetation management. (l) Long-term maintenance contract To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. (m) Rate review costs The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (n) Cost of removal Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability tracks the amounts that have been collected from customers net of costs incurred to date. (o) Rate base offset The regulators imposed a rate base offset that will reduce the revenue requirements at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term Investments	Long-term investments consist of the following: December 31, 2020 December 31, 2019 Long-term investments carried at fair value Atlantica (a) $ 1,706,900 $ 1,178,581 Atlantica share subscription agreement (b) 20,015 — Atlantica Yield Energy Solutions Canada Inc. (c) 110,514 88,494 San Antonio Water System (d) — 27,072 $ 1,837,429 $ 1,294,147 Other long-term investments Equity-method investees (e), (f) $ 186,452 $ 82,111 Development loans receivable from equity-method investees (f) 22,912 36,204 Other 5,219 3,653 $ 214,583 $ 121,968
Income from Long-term Investments	Income (loss) from long-term investments from the years ended December 31 is as follows: Year ended December 31, 2020 2019 Fair value gain (loss) on investments carried at fair value Atlantica $ 519,297 $ 290,740 Atlantica share subscription agreement 20,015 — Atlantica Yield Energy Solutions Canada Inc. 20,272 (6,649) San Antonio Water System 117 (6,007) $ 559,701 $ 278,084 Dividend and interest income from investments carried at fair value Atlantica $ 74,604 $ 69,307 Atlantica Yield Energy Solutions Canada Inc. 14,731 25,572 San Antonio Water System 2,113 6,007 $ 91,448 $ 100,886 Other long-term investments Equity method income (loss) 209 (9,108) Interest and other income 13,313 27,759 $ 664,671 $ 397,621 (a) Investment in Atlantica AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 44.2% (2019 - 44.2%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The shares were purchased at a cost of $1,036,414. The Company accounts for its investment in Atlantica at fair value, with changes in fair value reflected in the consolidated statements of operations. 8. Long-term investments (continued) (b) Atlantica share subscription agreement On December 9, 2020, the Company entered into a subscription agreement to purchase additional ordinary shares of Atlantica at $33.00 per share in order to maintain its 44.2% ownership interest pursuant to a treasury share issuance by Atlantica. The contract is accounted for as a derivative under ASC 815, Derivatives and Hedging and had a fair value of $20,015 as at December 31, 2020. Subsequent to year-end, on January 7, 2021, the subscription closed and the Company paid $132,688 for 4,020,860 shares of Atlantica. (c) Investment in AYES Canada On May 24, 2019, AQN and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. ("AYES Canada"), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. ("Windlectric"). AQN invested $91,918 (C$123,603) and Atlantica invested C$4,834 (C$6,500) in AYES Canada, which in turn invested those funds in Amherst Island Partnership ("AIP"), the holding company of Windlectric. AQN controls and consolidates AIP and Windlectric. The investment of $96,752 (C$130,103) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. For the year ended December 31, 2020, the Company incurred non-controlling interest calculated using the HLBV method of accounting of $nil (2019 - $nil) and recorded distributions of $16,064 (2019 - $26,465) during the year. AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment (note 24(a)). For the year ended December 31, 2020, AQN recorded dividend income of $14,731 (2019 - $25,572) and a fair value gain of $20,272 (2019 - loss of $6,649) on its investment in AYES Canada. As at December 31, 2020, the Company's maximum exposure to loss is $110,514 (2019 - $88,494), which represents the fair value of the investment. (d) San Antonio Water System On December 30, 2019, the Company and a third party each contributed C$1,500 to the capital of a new joint venture, created for the purpose of investing in infrastructure opportunities. The Company sold its investment in Abengoa Water USA, LLC to the joint venture in exchange for a note receivable of $30,293 and has elected the fair value option under ASC 825, Financial Instruments to account for its investment in the joint venture, with changes in fair value reflected in the consolidated statements of operations. On July 2, 2020, AQN acquired the third-party developer's 50% interest in the joint venture for C$1,581. As a result, the Company consolidates Abengoa Water USA, LLC and its 20% interest in the San Antonio Water System (“SAWS”). The Company accounts for its 20% interest in SAWS using the equity method. (e) Equity-method investees The Company has non-controlling interests in various corporations, partnerships and joint ventures with a total carrying value of $186,452 (2019 - $82,111) including investments in VIEs of $174,685 (2019 - $59,091). 8. Long-term investments (continued) (e) Equity-method investees (continued) Subsequent to year-end, the Company acquired a 51% interest in three wind facilities from a portfolio of four wind facilities located in Texas for $227,556. The facilities have achieved commercial operations. The acquisition of the last facility is expected to close after achieving commercial operation for approximately $103,642. Commercial operation is expected to occur in March 2021. The Company is not considered the primary beneficiary of the entity and therefore will account for its 51% interest using the equity method. The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. AQN exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method. The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa S.A. (“Abengoa”) in 2018; Sugar Creek, a 202 MW wind power project in Logan County, Illinois; Maverick Creek, a 492 MW wind power project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia; Blue Hill, a 175 MW wind power project located between Herbert and Neidpath, Saskatchewan; and North Fork Ridge and Kings Point, two approximately 150 MW wind projects in southwestern Missouri. During the year, the Blue Hill wind project net assets of $20,029 (C$27,205) were transferred into a joint venture entity in exchange for 50% equity interests in the joint venture. During the year, the Sugar Creek and North Fork Ridge wind facilities reached commercial operations and Maverick Creek commissioned 111 of its 127 total turbines. Subsequent to year-end, the Company acquired the remaining 50% equity interest in each of Sugar Creek and Maverick Creek for $43,796 and as a result, obtained control of the facilities. As at December 31, 2020, the net book value of property, plant and equipment of the joint ventures was $1,009,709 while the third-party construction debt was $837,026 which are expected to be repaid in the first quarter of 2021. Subsequent to year-end, the Empire Electric System acquired North Fork Ridge from Liberty Utilities Co. and the third-party developer (note 3(d)). On October 21, 2020, AQN paid $1,500 to Abengoa for a 12-month exclusive, transferable, and irrevocable option to purchase all of Abengoa's interests in Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V."), AAGES Development Canada Inc., and AAGES Development Spain, S.A. During the term of the option, the Company is obligated to provide cash advances in an aggregate amount not exceeding $7,233 in any calendar year to be used only in accordance with the baseline operating budget. Summarized combined information for AQN's investments in significant partnerships and joint ventures as at December 31 is as follows: 2020 2019 Total assets $ 3,201,967 $ 833,791 Total liabilities 2,913,188 697,751 Net assets $ 288,779 $ 136,040 AQN's ownership interest in the entities 141,666 63,624 Difference between investment carrying amount and underlying equity in net assets (a) 44,786 18,487 AQN's investment carrying amount for the entities $ 186,452 $ 82,111 (a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs. 8. Long-term investments (continued) (e) Equity-method investees (continued) Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2020, the Company had issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as at December 31, 2020 amounts to $12,273 (2019 - $9,446). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2020 2019 AQN's maximum exposure in regards to VIEs Carrying amount $ 174,685 $ 59,091 Development loans receivable (e) 21,804 35,000 Performance guarantees and other commitments on behalf of VIEs 965,291 1,364,871 $ 1,161,780 $ 1,458,962 The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.
Investments in Partnerships and Joint Ventures	Summarized combined information for AQN's investments in significant partnerships and joint ventures as at December 31 is as follows: 2020 2019 Total assets $ 3,201,967 $ 833,791 Total liabilities 2,913,188 697,751 Net assets $ 288,779 $ 136,040 AQN's ownership interest in the entities 141,666 63,624 Difference between investment carrying amount and underlying equity in net assets (a) 44,786 18,487 AQN's investment carrying amount for the entities $ 186,452 $ 82,111 (a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs. 8. Long-term investments (continued) (e) Equity-method investees (continued)
Schedule of Variable Interest Entities	Summarized combined information for AQN's VIEs as at December 31 is as follows: 2020 2019 AQN's maximum exposure in regards to VIEs Carrying amount $ 174,685 $ 59,091 Development loans receivable (e) 21,804 35,000 Performance guarantees and other commitments on behalf of VIEs 965,291 1,364,871 $ 1,161,780 $ 1,458,962

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long Term Debt	Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value December 31, 2020 December 31, 2019 Senior unsecured revolving credit facilities (a) — 2021-2024 N/A $ 223,507 $ 141,577 Senior unsecured bank credit facilities (b) — 2021-2031 N/A 152,338 75,000 Commercial paper (c) — 2021 N/A 122,000 218,000 U.S. dollar borrowings Senior unsecured notes (d) 3.46 % 2022-2047 $ 1,700,000 1,688,390 1,219,579 Senior unsecured utility notes (e) 6.34 % 2023-2035 $ 142,000 157,212 233,686 Senior secured utility bonds (f) 4.71 % 2026-2044 $ 556,229 561,494 672,337 Canadian dollar borrowings Senior unsecured notes (g) 4.28 % 2021-2050 C$ 1,150,669 899,710 728,679 Senior secured project notes 10.21 % 2027 C$ 25,882 20,315 21,961 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds (h) 4.29 % 2028-2040 CLF 1,868 92,183 — $ 3,917,149 $ 3,310,819 Subordinated U.S. dollar borrowings Subordinated unsecured notes (i) 6.50 % 2078-2079 $ 637,500 621,321 621,049 $ 4,538,470 $ 3,931,868 Less: current portion (139,874) (225,013) $ 4,398,596 $ 3,706,855 Short-term obligations of $194,478 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities. Recent financing activities: (a) Senior unsecured revolving credit facilities On November 8, 2020 in connection with the acquisition of Ascendant (note 3(a)), the Company assumed $62,654 of debt outstanding under its revolving credit facility that matures on June 30, 2021. On February 24, 2020, the Renewable Energy Group increased its uncommitted letter of credit facility to $350,000 and extended the maturity to June 30, 2021. On July 12, 2019, the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024. The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread. 9. Long-term debt (continued) Recent financing activities (continued): (a) Senior unsecured revolving credit facilities (continued) Given the uncertainty caused by the COVID-19 pandemic, the Company secured, in the second quarter of 2020, additional liquidity as an additional margin of safety intended to ensure the Company could continue to move forward with its 2020 capital expenditure program and committed acquisitions independent of the state of the capital markets. The additional liquidity was in the form of three new senior unsecured delayed draw non-revolving credit facilities for a total of $1,600,000 maturing in April 2021. On October 5, 2020, these facilities were replaced with two new syndicated revolving credit facilities for a total of $1,600,000 maturing December 31, 2021. (b) Senior unsecured bank credit facilities On November 8, 2020, in connection with the acquisition of Ascendant (note 3(a)), the Company assumed $97,029 of debt outstanding under two term loan facilities that mature on June 29, 2023 and December 26, 2031. Amounts of $4,655 were repaid under these two facilities prior to December 31, 2020. On October 13, 2020, in connection with the acquisition of ESSAL (note 3(b)), the Company assumed $55,786 (CLP 44,408,558) of debt outstanding under seven credit facilities that mature between March 29, 2021 and November 18, 2022. Amounts of $2,474 (CLP 1,759,423) were repaid under these facilities prior to December 31, 2020. On June 27, 2019, the Regulated Services Group extended the maturity of its C$135,000 term loan to July 6, 2020. Upon maturity, the term loan was fully repaid. (c) Commercial paper On July 1, 2019, the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group's revolving bank credit facility. (d) Senior unsecured notes On September 23, 2020, the Regulated Services Group's debt financing entity issued $600,000 senior unsecured notes bearing interest at 2.05% with a maturity date of September 15, 2030. On July 31, 2020, the Company repaid, upon its maturity, a $25,000 unsecured note. On April 30, 2020, the Company repaid, upon its maturity, a $100,000 unsecured note. (e) Senior unsecured utility notes During 2020, the Regulated Services Group repaid two utility notes upon their maturities in the amount of $45,000 and $30,000. (f) Senior secured utility bonds On February 15, 2020 and June 1, 2020, the Company repaid, upon its maturity, a $6,500 and a $100,000 secured utility bond, respectively. (g) Canadian dollar senior unsecured notes On February 14, 2020, the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050. The debentures are redeemable at the option of the Company at a price based on a make-whole provision. On January 29, 2019, the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C$135,000 (note 24(b)(ii)). 9. Long-term debt (continued) Recent financing activities (continued) (h) Chilean Unidad de Fomento senior unsecured bonds On October 13, 2020, in connection with the acquisition of ESSAL (note 3(b)), the Company assumed two senior unsecured bonds (series B and series C) of $82,320 (CLF 1,926). The series B bonds bear interest at 6% and mature on June 1, 2028 while the series C bonds bear interest at 2.8% and mature on October 15, 2040. In December 2020, the Company repaid $1,550 (CLF 58) of obligations under the series B bonds. (i) Subordinated unsecured notes In 2019, the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes ("subordinated notes") maturing on July 1, 2079. Concurrent with the offering, the Company entered into cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars. Beginning on July 1, 2024, and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01%, payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029, and on every interest reset date until July 1, 2049, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26%, payable in arrears. Beginning on July 1, 2049, and on every interest reset date until July 1, 2079, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01%, payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
Schedule of Maturities of Long-term Debt	Principal payments due in the next five years and thereafter are as follows: 2021 2022 2023 2024 2025 Thereafter Total $ 334,352 $ 422,609 $ 111,427 $ 240,151 $ 45,451 $ 3,380,045 $ 4,534,035

Pension and other post-retire_2

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Benefit Obligations Fair Value of Plan Assets and Funded Status	The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2020 2019 2020 2019 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 564,970 $ 484,707 $ 219,217 $ 168,325 Projected benefit obligation assumed from business combination 195,231 20,196 44,950 11,646 Modifications to plans (191) (7,705) — — Service cost 15,450 12,351 6,175 4,587 Interest cost 19,281 20,222 7,695 7,575 Actuarial loss 76,618 65,443 34,507 33,605 Contributions from retirees 171 — 2,037 1,913 Medicare Part D — — 377 414 Benefits paid (37,020) (30,244) (8,434) (8,848) Foreign exchange 403 — — — Projected benefit obligation, end of year $ 834,913 $ 564,970 $ 306,524 $ 219,217 Change in plan assets Fair value of plan assets, beginning of year 407,074 339,099 158,873 115,542 Plan assets acquired in business combination 179,600 8,004 — 15,688 Actual return on plan assets 52,876 68,025 21,219 25,464 Employer contributions 26,099 22,190 2,583 8,628 Contributions from retirees 171 — 1,998 1,913 Medicare Part D subsidy receipts — — 377 414 Benefits paid (37,020) (30,244) (8,434) (8,776) Foreign exchange 357 — — — Fair value of plan assets, end of year $ 629,157 $ 407,074 $ 176,616 $ 158,873 Unfunded status $ (205,756) $ (157,896) $ (129,908) $ (60,344) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 488 — 10,174 8,437 Current liabilities (1,989) (1,415) (2,835) (1,168) Non-current liabilities (204,255) (156,481) (137,247) (67,613) Net amount recognized $ (205,756) $ (157,896) $ (129,908) $ (60,344) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2020 2019 2020 2019 Accumulated benefit obligation $ 727,981 $ 504,403 $ 288,594 $ 202,422 Fair value of plan assets $ 578,143 $ 407,074 $ 148,496 $ 133,711 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2020 2019 2020 2019 Projected benefit obligation $ 833,846 $ 564,971 $ 288,594 $ 202,422 Fair value of plan assets $ 627,601 $ 407,074 $ 148,496 $ 133,711
Amounts Recognized in Other Comprehensive Loss	Pension and post-employment actuarial changes Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2019 $ 34,257 $ (6,221) $ (13,888) $ (208) Additions to AOCI 17,905 (7,705) 14,871 — Amortization in current period (3,530) 784 409 208 Reclassification to regulatory accounts (10,122) 6,962 (10,538) — Balance, December 31, 2019 $ 38,510 $ (6,180) $ (9,146) $ — Additions to AOCI 50,026 (191) 22,036 — Amortization in current period (5,430) 1,609 (509) — Reclassification to regulatory accounts (25,875) (544) (16,680) — Balance, December 31, 2020 $ 57,231 $ (5,306) $ (4,299) $ —
Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2020 and 2019 were as follows: Pension benefits OPEB 2020 2019 2020 2019 Discount rate 2.49 % 3.19 % 2.58 % 3.29 % Interest crediting rate (for cash balance plans) 4.15 % 4.48 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.00 % 6.125 % Age 65 and after 6.00 % 6.125 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031
Effect of One Percent Change in Assumed Health Care Cost Trend Rates (HCCTR)	Weighted average assumptions used to determine net benefit cost for 2020 and 2019 were as follows: Pension benefits OPEB 2020 2019 2020 2019 Discount rate 3.19 % 4.19 % 3.29 % 4.25 % Expected return on assets 6.85 % 6.87 % 5.57 % 6.51 % Rate of compensation increase 3.96 % 4.00 % N/A N/A Health care cost trend rate Before Age 65 6.125 % 6.25 % Age 65 and after 6.125 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses	The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2020 2019 2020 2019 Service cost $ 15,450 $ 12,351 $ 6,175 $ 4,587 Non-service costs Interest cost 19,281 20,222 7,695 7,575 Expected return on plan assets (26,285) (20,485) (8,748) (6,725) Amortization of net actuarial loss (gain) 5,430 3,530 509 (409) Amortization of prior service credits (1,609) (784) — (208) Amortization of regulatory accounts 16,272 12,082 1,527 2,534 $ 13,089 $ 14,565 $ 983 $ 2,767 Net benefit cost $ 28,539 $ 26,916 $ 7,158 $ 7,354
Target Asset Allocation	The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 47 % 30% -100% Debt securities 43 % 20% - 60% Other 10 % 0% - 20% 100 % The fair values of investments as of December 31, 2020, by asset category, are as follows: Asset class 2020 Percentage Equity securities $ 479,506 59 % Debt securities 255,975 32 % Other 70,292 9 % $ 805,773 100 %
Schedule of Changes in Fair Value of Plan Assets	The following table summarizes the changes fair value of these level 3 assets as of December 31: Level 3 Balance, January 1, 2020 $ — Contributions into funds 6,726 Unrealized gains 1,188 Distributions (169) Balance, December 31, 2020 $ 7,745
Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2021 2022 2023 2024 2025 2026 — 2030 Pension plan $ 46,858 $ 44,993 $ 46,358 $ 47,028 $ 48,197 $ 241,151 OPEB 10,414 11,033 11,601 12,165 12,687 68,826

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other Assets	Other assets consist of the following: 2020 2019 Restricted cash $ 28,404 $ 24,787 OPEB plan assets (note 10(a)) 10,662 8,437 Atlantica related prepaid amount — 8,844 Long-term deposits 13,459 6,319 Income taxes recoverable 4,717 4,416 Deferred financing costs 6,774 5,477 Other 11,736 8,192 $ 75,752 $ 66,472 Less: current portion (7,266) (7,764) $ 68,486 $ 58,708

Other long-term liabilities and

Other long-term liabilities and deferred credits (Tables)	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Other Long Term Liabilities	Other long-term liabilities consist of the following: 2020 2019 Advances in aid of construction (a) $ 79,864 $ 60,828 Environmental remediation obligation (b) 69,383 58,061 Asset retirement obligations (c) 79,968 53,879 Customer deposits (d) 31,939 31,946 Unamortized investment tax credits (e) 17,893 18,234 Deferred credits (f) 21,156 18,952 Preferred shares, Series C (g) 13,698 13,793 Hook up fees (h) 17,704 9,610 Lease liabilities (note 1(q)) 14,288 9,695 Contingent development support obligations (i) 12,273 9,446 Note payable to related party (j) 30,493 — Other 23,027 16,896 $ 411,686 $ 301,340 Less: current portion (72,505) (57,939) $ 339,181 $ 243,401 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2020, $1,994 (2019 - $5,465) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. With the acquisition of Ascendant on November 9, 2020 (note 3(a)), the Company assumed additional environmental remediation obligations with respect to the decommissioning and remediation of a power station. This remediation approach involves excavation, treatment and reuse, with most of the work expected to occur in 2023. The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $60,803 (2019 - $58,484), which at discount rates ranging from 0.8% to 3.4% represents the recorded accrual of $69,383 as of December 31, 2020 (2019 - $58,061). Approximately $43,995 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years. 12. Other long-term liabilities (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2020 2019 Opening balance $ 58,061 $ 55,621 Remediation activities (5,130) (1,678) Accretion 436 1,065 Changes in cash flow estimates 3,828 981 Revision in assumptions 3,402 2,072 Obligation assumed from business acquisition 8,786 — Closing balance $ 69,383 $ 58,061 The Regulator for the New England gas system and Energy North gas system provide for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2020, the Company has reflected a regulatory asset of $87,308 (2019 - $82,300) for the MGP and related sites (note 7(d)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls ("PCB") contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities. Changes in the asset retirement obligations are as follows: 2020 2019 Opening balance $ 53,879 $ 43,291 Obligation assumed from business acquisition and constructed projects 20,420 3,226 Retirement activities (1,724) (443) Accretion 2,674 2,148 Change in cash flow estimates 4,719 5,657 Closing balance $ 79,968 $ 53,879 As the cost of retirement of utility assets in the United States, liability accretion and asset depreciation expense are expected to be recovered through rates, a corresponding regulatory asset is recorded (note 7(j)). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. 12. Other long-term liabilities (continued) (f) Deferred credits In 2019, the Company settled $29,100 of contingent consideration related to the Company's investment in Atlantica (note 8(a)), and recorded an additional $5,000 contingent consideration related to the Company's investment in the San Antonio Water System (note 8(d)). (g) Preferred shares, Series C AQN has 100 redeemable Series C preferred shares issued and outstanding. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share. As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2021 $ 1,075 2022 1,097 2023 1,324 2024 1,536 2025 1,552 Thereafter to 2031 7,693 Redemption amount 4,195 $ 18,472 Less: amounts representing interest (4,774) $ 13,698 Less current portion (1,075) $ 12,623 (h) Hook up fees Hook up fees result from the collection from customers of funds for installation and connection to the utility's infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement. (i) Contingent development support obligations The Company provides credit support necessary for the continued development and construction of its equity investees' wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(e)). (j) Note payable to related party In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project (note 8(e)). Following the closing of the construction financing facility for the Altatvista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually and has a maturity date of March 31, 2021.

Shareholders' capital (Tables)

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Number of Common Shares	Number of common shares 2020 2019 Common shares, beginning of year 524,223,323 488,851,433 Public offering 66,130,063 28,009,341 Dividend reinvestment plan 5,217,071 6,068,465 Exercise of share-based awards (b) 1,565,537 1,274,655 Conversion of convertible debentures 6,225 19,429 Common shares, end of year 597,142,219 524,223,323
Schedule of Shares Issued and Outstanding	The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2020 and 2019: Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $ Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463 Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836 $ 184,299
Share-based Compensation Expense	For the year ended December 31, 2020, AQN recorded $24,637 (2019 - $11,042) in total share-based compensation expense as follows: 2020 2019 Share options $ 1,743 $ 1,288 Director deferred share units 870 798 Employee share purchase 511 322 Performance and restricted share units 21,513 8,634 Total share-based compensation $ 24,637 $ 11,042
Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2020 2019 Risk-free interest rate 1.2 % 1.9 % Expected volatility 24 % 20 % Expected dividend yield 4.1 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.72 C$ 1.66
Stock Option Activity	Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2019 6,292,642 C$ 11.61 5.75 C$ 13,342 Granted 1,113,775 14.96 8.00 — Exercised (3,882,505) 11.23 4.45 6,225 Balance, December 31, 2019 3,523,912 C$ 13.09 5.87 C$ 18,609 Granted 999,962 16.78 7.27 — Exercised (2,386,275) 12.52 5.16 18,465 Forfeited (27,151) 14.96 — — Balance, December 31, 2020 2,110,448 C$ 15.45 6.55 C$ 11,604 Exercisable, December 31, 2020 1,710,662 C$ 15.22 6.44 C$ 9,798
Performance Stock Units	A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2019 1,392,132 C$ 12.75 1.60 C$ 19,114 Granted, including dividends 1,471,442 14.69 2.00 16,302 Exercised (344,340) 11.55 — 5,148 Forfeited (107,191) 13.84 — — Balance, December 31, 2019 2,412,043 C$ 14.00 1.86 C$ 44,309 Granted, including dividends 1,313,171 19.31 2.00 24,966 Exercised (968,470) 14.45 — 20,105 Forfeited (35,537) 15.62 — 745 Balance, December 31, 2020 2,721,207 C$ 16.58 0.93 C$ 44,289 Exercisable, December 31, 2020 707,630 C$ 12.70 — C$ 14,825

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated other comprehensive income (loss)	AOCI consists of the following balances, net of tax: Foreign currency cumulative translation Unrealized gain on cash flow hedges Pension and post-employment actuarial changes Total Balance, January 1, 2019 $ (74,189) $ 64,333 $ (9,529) $ (19,385) Adoption of ASU 2017-12 on hedging — 186 — 186 Other comprehensive income (loss) 4,267 19,177 (7,999) 15,445 Amounts reclassified from AOCI to the consolidated statement of operations 3,528 (8,597) 1,490 (3,579) Net current period OCI $ 7,795 $ 10,580 $ (6,509) $ 11,866 OCI attributable to the non-controlling interests (2,428) — — (2,428) Net current period OCI attributable to shareholders of AQN $ 5,367 $ 10,580 $ (6,509) $ 9,438 Balance, December 31, 2019 $ (68,822) $ 75,099 $ (16,038) $ (9,761) Other comprehensive income (loss) 25,643 (13,418) (20,964) (8,739) Amounts reclassified from AOCI to the consolidated statement of operations 2,763 (10,864) 3,403 (4,698) Net current period OCI $ 28,406 $ (24,282) $ (17,561) $ (13,437) OCI attributable to the non-controlling interests 691 — — 691 Net current period OCI attributable to shareholders of AQN $ 29,097 $ (24,282) $ (17,561) $ (12,746) Balance, December 31, 2020 $ (39,725) $ 50,817 $ (33,599) $ (22,507)

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure Cash Dividends [Abstract]
Dividends	Dividends declared were as follows: 2020 2019 Dividend Dividend per share Dividend Dividend per share Common shares $ 344,382 $ 0.6063 $ 277,835 $ 0.5512 Series A preferred shares C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Series D preferred shares C$ 5,091 C$ 1.2728 C$ 5,068 C$ 1.2671

Non-controlling Interests and_2

Non-controlling Interests and Redeemable non-controlling Interest (Tables)	12 Months Ended
	Dec. 31, 2020
Noncontrolling Interest [Abstract]
Net Loss Attributable to Non-controlling Interests	Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2020 2019 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 63,080 $ 55,963 Non-controlling interests - redeemable tax equity partnership units 6,955 9,006 Other net earnings attributable to: Non-controlling interests (2,749) (2,553) $ 67,286 $ 62,416 Redeemable non-controlling interest, held by related party (12,651) (16,482) Net effect of non-controlling interests $ 54,635 $ 45,934 Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2020 2019 2020 2019 Opening balance $ 305,863 $ 307,622 $ 25,913 $ 33,364 Net effect from operations 12,651 16,482 (6,955) (9,006) Contributions, net of costs — — 3,717 3,403 Dividends and distributions declared (12,198) (18,241) (951) (1,848) Repurchase of non-controlling interest — — (865) — Closing balance $ 306,316 $ 305,863 $ 20,859 $ 25,913

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The differences are as follows: 2020 2019 Expected income tax expense at Canadian statutory rate $ 209,989 $ 147,093 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,082) (27,703) Adjustments from investments carried at fair value (87,058) (60,730) Non-controlling interests share of income 18,243 16,991 Non-deductible acquisition costs 3,223 2,500 Tax credits (40,185) (9,332) Adjustment relating to prior periods (4,228) (1,240) Amortization and settlement of excess deferred income tax (12,392) (2,554) Other 4,073 5,092 Income tax expense $ 64,583 $ 70,117
Income (Loss) Before Taxes	For the years ended December 31, 2020 and 2019, earnings before income taxes consist of the following: 2020 2019 Canada (1) $ 626,980 $ 351,908 U.S. 165,431 203,159 $ 792,411 $ 555,067
Income Tax Expenses (Recovery) Attributable to Income (Loss)	Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2020 Canada $ 6,336 $ 61,440 $ 67,776 United States (1,448) (1,745) (3,193) $ 4,888 $ 59,695 $ 64,583 Year ended December 31, 2019 Canada $ 6,695 $ 17,607 $ 24,302 United States 9,736 36,079 45,815 $ 16,431 $ 53,686 $ 70,117 18. Income taxes (continued)
Tax Effect of Temporary Difference Between Assets and Liability	The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2020 and 2019 are presented below: 2020 2019 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 531,353 $ 382,448 Pension and OPEB 66,826 54,113 Environmental obligation 16,145 15,541 Regulatory liabilities 168,054 160,200 Other 65,787 59,103 Total deferred income tax assets $ 848,165 $ 671,405 Less: valuation allowance (29,824) (29,447) Total deferred tax assets $ 818,341 $ 641,958 Deferred tax liabilities: Property, plant and equipment $ 733,211 $ 707,185 Outside basis differentials 406,429 235,063 Regulatory accounts 212,937 145,852 Other 12,528 14,811 Total deferred tax liabilities $ 1,365,105 $ 1,102,911 Net deferred tax liabilities $ (546,764) $ (460,953) Consolidated balance sheets classification: Deferred tax assets $ 21,880 $ 30,585 Deferred tax liabilities (568,644) (491,538) Net deferred tax liabilities $ (546,764) $ (460,953)
Non Capital Losses Carry Forwards	As of December 31, 2020, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows: Non-capital loss carryforward and credits 2021-2026 2027+ Total Canada $ 58 $ 552,506 $ 552,564 US 13,427 912,589 926,016 Total non-capital loss carryforward $ 13,485 $ 1,465,095 $ 1,478,580 Tax credits $ 3,624 $ 72,849 $ 76,473

Other net losses (Tables)

Other net losses (Tables)	12 Months Ended
	Dec. 31, 2020
Other Income and Expenses [Abstract]
Schedule of Other Net Losses	Other net losses consist of the following: 2020 2019 Acquisition and transition-related costs $ 14,104 $ 11,609 Tax reform (a) 11,728 — Management succession and executive retirement (b) 12,639 — Other (c) 22,840 15,085 $ 61,311 $ 26,694 (a) Tax reform As a result of the Tax Cuts and Jobs Act enacted in 2017, regulators in the states where the Regulated Services Group operates contemplated the rate making implications of federal tax rates from the legacy 35% tax rate and the new 21% federal statutory income tax rate effective January 2018. On July 1, 2020, the Company received an order from the Public Service Commission of the State of Missouri that requires Empire to refund to customers over five years the revenue requirement collected at the higher tax rate between January 1, 2018 and August 31, 2018 before new rates came into effect. Therefore, an accounting loss was recognized for $11,728 in 2020. (b) Management succession and executive retirement The Company announced succession plans for the role of CEO, and the retirements of the CFO and Vice Chair. As part of the Retirement Agreements, the Company recorded $12,639, for the year ended December 31, 2020, of expenses in relation to these executives’ share-based compensation agreements (note 13(c)(i)). (c) Other

Basic and diluted net earning_2

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share, Basic and Diluted [Abstract]
Reconciliation of Net Income and Weighted Average Shares Used in Computation of Basic and Diluted Earnings per Share	The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2020 2019 Net earnings attributable to shareholders of AQN $ 782,463 $ 530,884 Series A preferred shares dividend 4,611 4,666 Series D preferred shares dividend 3,790 3,820 Net earnings attributable to common shareholders of AQN – basic and diluted $ 774,062 $ 522,398 Weighted average number of shares Basic 559,633,275 499,910,876 Effect of dilutive securities 4,740,561 4,828,678 Diluted 564,373,836 504,739,554

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Results of Operations and Assets for Segments	Year ended December 31, 2020 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,405,136 $ 270,398 $ 1,524 $ 1,677,058 Fuel, power and water purchased 384,363 16,645 — 401,008 Net revenue 1,020,773 253,753 1,524 1,276,050 Operating expenses 445,459 74,981 12 520,452 Administrative expenses 34,141 24,719 630 59,490 Depreciation and amortization 219,089 92,890 2,144 314,123 Gain on foreign exchange — — (2,108) (2,108) Operating income 322,084 61,163 846 384,093 Interest expense (99,161) (52,656) (30,117) (181,934) Income from long-term investments 7,753 96,652 560,266 664,671 Other (40,128) (6,537) (27,754) (74,419) Earnings before income taxes $ 190,548 $ 98,622 $ 503,241 $ 792,411 Property, plant and equipment $ 5,757,532 $ 2,451,706 $ 32,600 $ 8,241,838 Investments carried at fair value — 1,837,429 — 1,837,429 Equity-method investees 74,673 111,779 — 186,452 Total assets 8,528,172 4,589,521 106,213 13,223,906 Capital expenditures $ 690,792 $ 80,746 $ 14,492 $ 786,030 (1) Renewable Energy Group revenue includes $28,586 related to net hedging gains from energy derivative contracts and availability credits for the year ended December 31, 2020 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $24,928 related to alternative revenue programs for the year ended December 31, 2020 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2019 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,368,411 $ 256,510 $ 1,471 $ 1,626,392 Fuel and power purchased 426,046 17,258 — 443,304 Net revenue 942,365 239,252 1,471 1,183,088 Operating expenses 397,092 74,676 221 471,989 Administrative expenses 36,667 19,366 769 56,802 Depreciation and amortization 194,766 88,557 981 284,304 Loss on foreign exchange — — 3,146 3,146 Operating income 313,840 56,653 (3,646) 366,847 Interest expense (101,518) (61,039) (18,931) (181,488) Income from long-term investments 9,334 104,025 284,262 397,621 Other (32,297) 15,951 (11,567) (27,913) Earnings before income taxes $ 189,359 $ 115,590 $ 250,118 $ 555,067 Property, plant and equipment $ 4,763,689 $ 2,444,382 $ 32,909 $ 7,240,980 Investments carried at fair value 27,072 1,267,075 — 1,294,147 Equity-method investees 29,827 52,284 — 82,111 Total assets 6,825,379 4,014,067 81,340 10,920,786 Capital expenditures $ 478,936 $ 102,396 $ — $ 581,332 (1) Renewable Energy Group revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers.
Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2020 2019 Revenue United States $ 1,475,087 $ 1,537,695 Canada 153,569 88,697 Other regions 48,402 — $ 1,677,058 $ 1,626,392 Property, plant and equipment United States $ 6,666,015 $ 6,488,964 Canada 884,195 752,016 Other regions 691,628 — $ 8,241,838 $ 7,240,980 Intangible assets United States $ 24,825 $ 23,821 Canada 23,123 23,795 Other regions 66,965 — $ 114,913 $ 47,616

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Estimates of Future Commitments	Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 45,083 $ 27,310 $ 26,178 $ 26,236 $ 26,472 $ 167,380 $ 318,659 Gas supply and service agreements (ii) 89,034 62,781 48,427 42,174 37,699 144,885 425,000 Service agreements 56,828 46,817 50,223 48,671 45,766 248,540 496,845 Capital projects 654,399 — — — — — 654,399 Land easements 6,747 6,783 6,874 6,958 7,036 194,995 229,393 Total $ 852,091 $ 143,691 $ 131,702 $ 124,039 $ 116,973 $ 755,800 $ 2,124,296 (i) Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2020. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: AQN’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Non-cash operating items (Table

Non-cash operating items (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure Changes In Non Cash Operating Items [Abstract]
Changes in Non-Cash Operating Items	The changes in non-cash operating items consist of the following: 2020 2019 Accounts receivable $ (52,778) $ (20,857) Fuel and natural gas in storage 237 13,985 Supplies and consumables inventory 1,058 (6,028) Income taxes recoverable (3,440) 17,796 Prepaid expenses (15,411) (7,501) Accounts payable 40,885 63,854 Accrued liabilities (29,150) 8,872 Current income tax liability 3,818 (5,016) Asset retirements and environmental obligations 3,562 (2,494) Net regulatory assets and liabilities (26,260) (2,308) $ (77,479) $ 60,303

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair value of financial instruments December 31, 2020 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,837,429 $ 1,837,429 $ 1,706,900 $ 20,015 $ 110,514 Development loans and other receivables 23,804 31,088 — 31,088 — Derivative instruments: Energy contracts designated as a cash flow hedge 51,525 51,525 — — 51,525 Energy contracts not designated as cash flow hedge 388 388 — — 388 Commodity contracts for regulated operations 194 194 — 194 — Total derivative instruments 52,107 52,107 — 194 51,913 Total financial assets $ 1,913,340 $ 1,920,624 $ 1,706,900 $ 51,297 $ 162,427 Long-term debt $ 4,538,470 $ 5,140,059 $ 2,316,586 $ 2,823,473 $ — Notes payable to related party 30,493 30,493 — 30,493 — Convertible debentures 295 623 623 — — Preferred shares, Series C 13,698 15,565 — 15,565 — Derivative instruments: Energy contracts designated as a cash flow hedge 5,597 5,597 — — 5,597 Energy contracts not designated as a cash flow hedge 332 332 — — 332 Cross-currency swap designated as a net investment hedge 84,543 84,543 — 84,543 — Interest rate swaps designated as a hedge 19,324 19,324 — 19,324 — Commodity contracts for regulated operations 614 614 — 614 — Total derivative instruments 110,410 110,410 — 104,481 5,929 Total financial liabilities $ 4,693,366 $ 5,297,150 $ 2,317,209 $ 2,974,012 $ 5,929 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2019 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,294,147 $ 1,294,147 $ 1,178,581 $ 27,072 $ 88,494 Development loans and other receivables 37,050 37,984 — 37,984 — Derivative instruments: Energy contracts designated as a cash flow hedge 65,304 65,304 — — 65,304 Energy contracts not designated as a cash flow hedge 20,384 20,384 — — 20,384 Commodity contracts for regulatory operations 16 16 — 16 — Total derivative instruments 85,704 85,704 — 16 85,688 Total financial assets $ 1,416,901 $ 1,417,835 $ 1,178,581 $ 65,072 $ 174,182 Long-term debt $ 3,931,868 $ 4,284,068 $ 1,495,153 $ 2,788,915 $ — Convertible debentures 342 623 623 — — Preferred shares, Series C 13,793 15,120 — 15,120 — Derivative instruments: Energy contracts designated as a cash flow hedge 789 789 — — 789 Energy contracts not designated as a cash flow hedge 38 38 — — 38 Cross-currency swap designated as a net investment hedge 81,765 81,765 — 81,765 — Commodity contracts for regulated operations 2,072 2,072 — 2,072 — Total derivative instruments 84,664 84,664 — 83,837 827 Total financial liabilities $ 4,030,667 $ 4,384,475 $ 1,495,776 $ 2,887,872 $ 827
Summary of Commodity Volumes Associated with Derivative Contracts	The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts: 2020 Financial contracts: Swaps 1,830,852 Options 479,692 Forward contracts 1,500,000 3,810,544
Impact of Change in Fair Value of Natural Gas Derivative Contracts	The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts on the consolidated balance sheets: 2020 2019 Regulatory assets: Swap contracts $ 228 $ 28 Option contracts 50 38 Forward contracts $ 693 $ 1,830 Regulatory liabilities: Swap contracts $ 271 $ 743 Option contracts $ 76 $ —
Long-Term Energy Derivative Contracts	The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities and the Shady Oaks II development project by entering into the following long-term energy derivative contracts. Notional quantity Expiry Receive average Pay floating price 2,479,234 December 2031 $23.50 NI HUB 642,280 December 2028 $34.02 PJM Western HUB 2,953,751 December 2027 $24.76 NI HUB 2,330,995 December 2027 $36.46 ERCOT North HUB
Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Consolidated Statement of Operations	The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2020 2019 Effective portion of cash flow hedge $ (13,418) $ 19,177 Amortization of cash flow hedge (1,248) (33) Amounts reclassified from AOCI (9,616) (8,564) OCI attributable to shareholders of AQN $ (24,282) $ 10,580
Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges	The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2020 2019 Change in unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (901) $ 530 Currency forward contract — (904) Total change in unrealized gain (loss) on derivative financial instruments $ (901) $ (374) Realized gain (loss) on derivative financial instruments: Energy derivative contracts (1,145) (227) Currency forward contract 2,363 147 Total realized gain (loss) on derivative financial instruments $ 1,218 $ (80) Gain (loss) on derivative financial instruments not accounted for as hedges 317 (454) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,009 15,810 $ 3,326 $ 15,356 Amounts recognized in the consolidated statements of operations consist of: Gain on derivative financial instruments $ 964 $ 16,113 Gain (loss) on foreign exchange 2,362 (757) $ 3,326 $ 15,356
Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2020, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2020 Cash and cash equivalents and restricted cash $ 130,018 Accounts receivable 355,151 Allowance for doubtful accounts (29,506) Notes receivable 23,804 $ 479,467
Liabilities Maturity Profile	The Company’s liabilities mature as follows: Due less Due 2 to 3 Due 4 to 5 Due after Total Long-term debt obligations $ 334,352 $ 821,535 $ 285,600 $ 3,092,544 $ 4,534,031 Interest on long-term debt 195,876 337,199 267,112 1,084,022 1,884,209 Purchase obligations 561,690 — — — 561,690 Environmental obligation 16,955 26,409 1,251 21,518 66,133 Advances in aid of construction 1,236 — — 78,628 79,864 Derivative financial instruments: Cross-currency swap 37,338 29,999 19,875 (2,670) 84,542 Interest rate swaps 2,725 4,346 4,369 7,885 19,325 Energy derivative and commodity contracts 1,917 (233) 919 3,940 6,543 Other obligations 79,219 6,601 5,232 125,209 216,261 Total obligations $ 1,231,308 $ 1,225,856 $ 584,358 $ 4,411,076 $ 7,452,598

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements - Narrative (Details)	12 Months Ended
	Dec. 31, 2020businessUnit
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business units	2

Significant accounting polici_4

Significant accounting policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)waterUtilityfacility	Dec. 31, 2019USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities | facility	3
Number of power generating facilities | facility	2
Number of water pipeline projects | waterUtility	1
Generating assets of Long Sault	$ 13,223,906	$ 10,920,786
Long-term debt of Long Sault	7,234,541	6,182,415
Non-regulated energy sales	1,677,058	1,626,392
Interest expense on long-term debt and others	181,934	181,488
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	59,521	60,230
Long-term debt of Long Sault	20,328	21,754
Operating expenses and amortization	5,400	4,930
Interest expense on long-term debt and others	$ 2,119	2,340
Minimum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities	7.52%
Lease renewal term	1 year
Maximum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities	60.00%
Lease renewal term	5 years
Power sales contracts | Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	6 years
Power sales contracts | Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	25 years
Interconnection agreements
Significant Accounting Policies [Line Items]
Intangible asset, useful life	40 years
Customer Relationships | Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	25 years
Customer Relationships | Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	40 years
Non-regulated energy sales
Significant Accounting Policies [Line Items]
Non-regulated energy sales	$ 255,955	246,601
Non-regulated energy sales | Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Non-regulated energy sales	$ 17,116	$ 17,108

Significant accounting polici_5

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Generation | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years	3 years
Generation | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	60 years	60 years
Generation | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	33 years	33 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	1 year	5 years
Distribution | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	100 years	100 years
Distribution | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	40 years	42 years
Equipment and other | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Equipment and other | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years	44 years
Equipment and other | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	11 years	10 years

Business acquisitions (Details)

Business acquisitions (Details) $ in Thousands, $ in Thousands	Nov. 09, 2020USD ($)	Oct. 17, 2020USD ($)	Oct. 13, 2020USD ($)	Dec. 31, 2019USD ($)MWac	Nov. 01, 2019USD ($)	Oct. 01, 2019USD ($)	Oct. 01, 2019CAD ($)	Nov. 30, 2019windProject	Mar. 04, 2021USD ($)	Dec. 31, 2020USD ($)MWac	Dec. 31, 2020CAD ($)MWac	Dec. 31, 2019USD ($)windProjectMWac	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Goodwill				$ 1,031,696						$ 1,208,390		$ 1,031,696	$ 954,282
Non-controlling interest		$ (84,525)
Number of wind projects | windProject												3
Turquoise Solar Facility
Business Acquisition [Line Items]
Total purchase price				$ 20,830
Solar power capacity (megawatt ac) | MWac				10						10	10
Turquoise Solar Facility | Partnership
Business Acquisition [Line Items]
Partnership agreement, funded amount										$ 3,717		$ 3,403
Great Bay Solar II Facility
Business Acquisition [Line Items]
Solar power capacity (megawatt ac) | MWac										40	40
Tax equity funding				$ 11,281						$ 15,268		11,281
Investment tax credit										10,717		$ 8,526
North Fork Ridge Wind Project
Business Acquisition [Line Items]
Tax equity funding										$ 29,446
Empire Electric System | North Fork Ridge Wind Project | Subsequent Event
Business Acquisition [Line Items]
Total purchase price									$ 288,066
Tax equity funding									84,926
Construction loan repaid									$ 193,506
Ascendant
Business Acquisition [Line Items]
Total purchase price	$ 364,468
Working capital	71,948
Property, plant and equipment	417,947
Intangible assets	27,315
Goodwill	93,202
Regulatory assets	9,859
Other assets	4,992
Long-term debt	(159,682)
Pension and other post-employment benefits	(58,746)
Derivative instruments	(12,748)
Other liabilities	(29,619)
Total net assets acquired	364,468
Cash and cash equivalents acquired	42,920
Total net assets acquired, net of cash and cash equivalents	$ 321,548
Weighted average useful life of assets	29 years
ESSAL
Business Acquisition [Line Items]
Total purchase price		$ 74,111	$ 87,975
Ownership interest acquired (percent)		43.00%	51.00%
Cumulative ownership interest acquired (percent)		94.00%
Working capital		$ 11,278
Property, plant and equipment		238,504
Intangible assets		37,095
Goodwill		70,382
Other assets		22
Long-term debt		(139,534)
Pension and other post-employment benefits		(2,292)
Deferred tax liabilities, net		(28,074)
Other liabilities		(14,881)
Total net assets acquired		87,975
Cash and cash equivalents acquired		6,983
Total net assets acquired, net of cash and cash equivalents		$ 80,992
Weighted average useful life of assets		40 years
ESSAL | Subsequent Event
Business Acquisition [Line Items]
Ownership interest sold (percent)									32.00%
Ownership interest after transaction (percent)									64.00%
ESSAL | APUC
Business Acquisition [Line Items]
Non-controlling interest (percent)										6.00%
ESSAL | Third Party | Subsequent Event
Business Acquisition [Line Items]
Ownership interest sold									$ 51,750
New Brunswick Gas
Business Acquisition [Line Items]
Total purchase price						$ 256,011	$ 339,036
Increase (decrease) in goodwill										$ (1,213)	$ (1,884)
St. Lawrence Gas Company, Inc.
Business Acquisition [Line Items]
Total purchase price					$ 61,820
Increase (decrease) in goodwill										$ 3,207
Mid-west Wind Development Project
Business Acquisition [Line Items]
Wind power capacity (megawatt AC) | MWac												600
Southwestern Missouri Wind Projects
Business Acquisition [Line Items]
Number of wind projects | windProject								2

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 29,506	$ 4,939
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 91,295	$ 80,295

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Cost	$ 9,588,813	$ 8,427,088
Accumulated depreciation	1,346,975	1,186,108
Net book value	8,241,838	7,240,980
Land
Property, Plant and Equipment [Line Items]
Cost	114,847	74,517
Accumulated depreciation	0	0
Net book value	114,847	74,517
Equipment
Property, Plant and Equipment [Line Items]
Cost	99,722	94,583
Accumulated depreciation	51,979	47,541
Net book value	47,743	47,042
Generation
Property, Plant and Equipment [Line Items]
Cost	2,918,692	2,816,611
Accumulated depreciation	633,210	540,118
Net book value	2,285,482	2,276,493
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	136,424	140,235
Accumulated depreciation	0	0
Net book value	136,424	140,235
Distribution and Transmission
Property, Plant and Equipment [Line Items]
Cost	5,766,885	4,997,613
Accumulated depreciation	661,786	598,449
Net book value	5,105,099	4,399,164
Distribution and Transmission | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	552,243	303,529
Accumulated depreciation	0	0
Net book value	$ 552,243	$ 303,529

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 531,191	$ 514,709
Accumulated depreciation related to commonly owned facilities	50,919	31,349
Expenditures	61,827	69,210
Contribution received	4,214	7,137
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	111,806	109,653
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	43,444	39,638
Depreciation expense	1,708	1,615
Distribution and Transmission
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	885,087	1,125,062
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	28,779	81,480
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	1,321	1,003
Expansion costs	$ 1,000	$ 1,000

Property, plant and equipment_3

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Capitalization [Line Items]
Total	$ 15,053	$ 12,179
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	9,359	4,538
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	3,475	2,745
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	$ 2,219	$ 4,896

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Cost	$ 168,522	$ 97,830
Accumulated amortization	53,609	50,214
Net book value	114,913	47,616
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	57,943	56,206
Accumulated amortization	41,184	38,931
Net book value	16,759	17,275
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	83,342	26,797
Accumulated amortization	10,967	10,104
Net book value	72,375	16,693
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	15,028	14,827
Accumulated amortization	1,458	1,179
Net book value	13,570	$ 13,648
Other
Finite-Lived Intangible Assets [Line Items]
Cost	12,209
Accumulated amortization	0
Net book value	$ 12,209

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Detail) $ in Thousands	Dec. 31, 2020USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 4,353
Estimated amortization expense for intangibles in year 2	4,194
Estimated amortization expense for intangibles in year 3	4,194
Estimated amortization expense for intangibles in year 4	4,194
Estimated amortization expense for intangibles in year 5	$ 4,194

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 1,031,696	$ 954,282
Business acquisitions	167,209	76,313
Foreign exchange	9,485	1,101
Goodwill end of the period	$ 1,208,390	$ 1,031,696

Regulatory matters - Approved A

Regulatory matters - Approved Annual Revenue Increases (Details) - USD ($) $ in Thousands	Sep. 16, 2020	Aug. 01, 2020	Jul. 01, 2020	May 01, 2020	Jul. 01, 2019	Jan. 01, 2019	Dec. 31, 2020
New England Natural Gas System
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)				$ 2,679
Energy North Gas System
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)			$ 1,613
Granite State Electric System
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)			5,474
Recoupment of difference between final and temporary rates			$ 1,836
Temporary revenue increase					$ 2,093
Empire Electric System (Missouri)
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)	$ 992
Peach State Gas System
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)		$ 1,566
Calpeco Electric System
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)						$ 5,277
Various
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)							$ (283)

Regulatory matters - Regulatory

Regulatory matters - Regulatory Assets and Liabilities (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)	Mar. 01, 2020MWac	Dec. 31, 2019USD ($)
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 845,471		$ 559,887
Less: current regulatory assets	(63,042)		(50,213)
Non-current regulatory assets	782,429		509,674
Total regulatory liabilities	601,518		607,378
Less: current regulatory liabilities	(38,483)		(41,683)
Non-current regulatory liabilities	$ 563,035		565,695
Capital expenditure shortfall refundable to customers (percent)	80.00%
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 322,317		321,960
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	200,739		205,739
Pension and Postremployment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	26,311		22,256
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20,136		17,729
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5,214		10,446
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10,440		6,871
Rate base offset
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 6,874		8,719
Rate base offset | Minimum
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	10 years
Rate base offset | Maximum
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	16 years
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 9,487		13,658
Retired generating plant
Regulatory Liabilities [Line Items]
Total regulatory assets	194,192		0
Coal generation capacity (MW) | MWac		200
Pension and Postremployment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 178,403		143,292
Future service years of employees	10 years
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 99,853		69,121
Retroactive rate adjustment collection period	24 months
Regulatory asset, amortization period	26 years
Environmental remediation
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 87,308		82,300
Environmental remediation, rate recovery period	7 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 77,730		71,506
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets	35,688		42,150
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory assets	18,094		23,433
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets	26,400		25,859
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 34,398		38,833
Regulatory asset, amortization period	20 years
Capitalized operating and maintenance costs, recovery rate, (percent)	2.43%
Capitalized operating and maintenance costs, recovery period	29 years
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 26,546		23,841
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Total regulatory assets	22,736		5,043
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets	14,405		13,264
Rate review costs
Regulatory Liabilities [Line Items]
Total regulatory assets	8,054		7,205
Other
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 21,664		$ 14,040

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,837,429	$ 1,294,147
Noncontrolling interest in partnerships and joint ventures	186,452	82,111
Other	5,219	3,653
Long-term investments	214,583	121,968
Notes Receivable | Development loans
Schedule of Equity Method Investments [Line Items]
Development loans receivable from equity-method investees (f)	22,912	36,204
Atlantica
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	1,706,900	1,178,581
Atlantica share subscription agreement
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	20,015	0
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	110,514	88,494
San Antonio Water System
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 0	$ 27,072

Long-term investments - Income

Long-term investments - Income from Long-term Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments	$ 559,701	$ 278,084
Dividend and interest income from investments carried at fair value	91,448	100,886
Equity method income (loss)	209	(9,108)
Interest and other income	13,313	27,759
Income from long-term investments	664,671	397,621
Atlantica
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments	519,297	290,740
Dividend and interest income from investments carried at fair value	74,604	69,307
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments	20,272	(6,649)
Dividend and interest income from investments carried at fair value	14,731	25,572
Atlantica share subscription agreement
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments	20,015	0
San Antonio Water System
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments	117	(6,007)
Dividend and interest income from investments carried at fair value	$ 2,113	$ 6,007

Long-term investments - Additio

Long-term investments - Additional Information (Detail) $ in Thousands	Dec. 09, 2020USD ($)$ / instrument	Oct. 21, 2020USD ($)	May 31, 2020shares	Dec. 31, 2020USD ($)$ / MWhturbinewindProjectMWac	Dec. 31, 2019USD ($)	Mar. 31, 2021USD ($)	Mar. 04, 2021USD ($)windProject	Jan. 07, 2021USD ($)shares	Dec. 31, 2020CAD ($)$ / MWhwindProjectMWac	Jul. 02, 2020CAD ($)	Dec. 30, 2019USD ($)	May 31, 2019USD ($)	May 31, 2019CAD ($)	May 24, 2019USD ($)	May 24, 2019CAD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments				$ 186,452,000	$ 82,111,000
Non-controlling interest held by related party				458,612,000	531,541,000
Non-controlling interest calculated using the HLBV method of accounting				(67,286,000)	(62,416,000)
Interest income				91,448,000	100,886,000
Fair value loss				559,701,000	278,084,000
Investments carried at fair value				1,837,429,000	1,294,147,000
Noncontrolling interest in partnerships and joint ventures				186,452,000	82,111,000
Fair value of support provided				12,273,000	9,446,000
Obligation to provide cash advances under purchase option agreement				2,124,296,000
Short-term debt				$ 194,478,000
San Antonio Water System
Schedule of Equity Method Investments [Line Items]
Equity interest				20.00%					20.00%
Interest income				$ 2,113,000	6,007,000
Fair value loss				117,000	(6,007,000)
Investments carried at fair value				$ 0	27,072,000
San Antonio Water System, Joint Venture
Schedule of Equity Method Investments [Line Items]
Investments in joint venture					1,500,000					$ 1,581
Ownership interest acquired (percent)										50.00%
San Antonio Water System, Joint Venture | Third party
Schedule of Equity Method Investments [Line Items]
Investments in joint venture					1,500,000
AWUSA | AIP
Schedule of Equity Method Investments [Line Items]
Interest income					6,007,000
Fair value loss					(6,007,000)
Exchange of notes receivable											$ 30,293,000
Atlantica
Schedule of Equity Method Investments [Line Items]
Equity interest				44.20%					44.20%
Equity method investments				$ 1,036,414,000
Interest income				74,604,000	69,307,000
Fair value loss				519,297,000	290,740,000
Investments carried at fair value				$ 1,706,900,000	1,178,581,000
Atlantica | Maximum
Schedule of Equity Method Investments [Line Items]
Equity interest				48.50%					48.50%
Atlantica | Subscription Share Purchase Agreement
Schedule of Equity Method Investments [Line Items]
Subscription purchase agreement, share price (in USD) | $ / instrument	33
Derivative financial instruments, liabilities	$ 20,015,000
Windlectric
Schedule of Equity Method Investments [Line Items]
Equity method investments														$ 91,918,000	$ 123,603
Windlectric | AYES Canada
Schedule of Equity Method Investments [Line Items]
Equity method investments														4,834,000	6,500
AYES Canada
Schedule of Equity Method Investments [Line Items]
Non-controlling interest held by related party				$ 59,125,000	73,707,000							$ 96,752,000
Option to exchange shares | shares			3,500,000
Interest income				14,731,000	25,572,000
Fair value loss				20,272,000	(6,649,000)
Investments carried at fair value				110,514,000	88,494,000
AYES Canada | AIP
Schedule of Equity Method Investments [Line Items]
Non-controlling interest held by related party												$ 96,752,000	$ 130,103	$ 96,752,000	$ 130,103
Non-controlling interest calculated using the HLBV method of accounting				0	0
Distribution from interest in noncontrolling interest				$ 16,064,000	$ 26,465,000
Texas Wind Farms | Forecast
Schedule of Equity Method Investments [Line Items]
Equity method investments						$ 103,642,000
Red Lily I
Schedule of Equity Method Investments [Line Items]
Equity interest				75.00%					75.00%
Wind facility capacity (megawatt AC) | $ / MWh				26.4					26.4
Other Development Projects
Schedule of Equity Method Investments [Line Items]
Equity interest				50.00%					50.00%
Option to acquire remaining equity interest (percent)				50.00%					50.00%
Sugar Creek
Schedule of Equity Method Investments [Line Items]
Wind facility capacity (megawatt ac) | MWac				202					202
Maverick
Schedule of Equity Method Investments [Line Items]
Wind facility capacity (megawatt ac) | MWac				492					492
Sugar Creek and North Fork Ridge
Schedule of Equity Method Investments [Line Items]
Number of turbines commissioned | turbine				111
Total number of turbines | turbine				127
Altavista
Schedule of Equity Method Investments [Line Items]
Solar power capacity (megawatt ac) | MWac				80
Blue Hill
Schedule of Equity Method Investments [Line Items]
Wind facility capacity (megawatt ac) | MWac				175					175
Blue Hill | Joint Venture
Schedule of Equity Method Investments [Line Items]
Equity interest				50.00%					50.00%
Investments in joint venture				$ 20,029,000					$ 27,205
Southwestern Missouri Wind Projects
Schedule of Equity Method Investments [Line Items]
Number of wind development projects | windProject				2					2
Wind facility capacity (megawatt ac) | MWac				150					150
Abengoa Investments
Schedule of Equity Method Investments [Line Items]
Payment for option to purchase investments		$ 1,500,000
Term of option to purchase investment		12 months
Obligation to provide cash advances under purchase option agreement		$ 7,233,000
Subsequent Event | Atlantica
Schedule of Equity Method Investments [Line Items]
Equity method investments								$ 132,688,000
Equity method investment, shares acquired (shares) | shares								4,020,860
Subsequent Event | Texas Wind Farms
Schedule of Equity Method Investments [Line Items]
Equity interest							51.00%
Equity method investments							$ 227,556,000
Number of wind development projects acquired | windProject							3
Number of wind development projects | windProject							4
Subsequent Event | Sugar Creek
Schedule of Equity Method Investments [Line Items]
Ownership interest acquired (percent)							50.00%
Subsequent Event | Maverick
Schedule of Equity Method Investments [Line Items]
Ownership interest acquired (percent)							50.00%
Subsequent Event | Sugar Creek and Maverick
Schedule of Equity Method Investments [Line Items]
Investments in joint venture							$ 43,796,000
Subsequent Event | Sugar Creek and Maverick | Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Investments in joint venture							1,009,709,000
Subsequent Event | Sugar Creek and Maverick | Construction Loan Payable
Schedule of Equity Method Investments [Line Items]
Short-term debt							$ 837,026,000
Subsequent Event | North Fork Ridge
Schedule of Equity Method Investments [Line Items]
Ownership interest acquired (percent)							50.00%

Long-term investments - Investm

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Assets	$ 13,223,906	$ 10,920,786
Liabilities	7,234,541	6,182,415
AQN's investment carrying amount for the entities	186,452	82,111
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Assets	3,201,967	833,791
Liabilities	2,913,188	697,751
Net assets	288,779	136,040
Investments in Significant Partnerships and Joint Ventures | APUC
Schedule of Equity Method Investments [Line Items]
Net assets	141,666	63,624
Difference between investment carrying amount and underlying equity in net assets(a)	44,786	18,487
AQN's investment carrying amount for the entities	$ 186,452	$ 82,111

Long-term investments -Combined

Long-term investments -Combined Information for APUC's interest in VIE's (Details) - Variable Interest Entity, Not Primary Beneficiary - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity [Line Items]
Carrying amount	$ 174,685	$ 59,091
Development loans receivable (e)	21,804	35,000
Performance guarantees and other commitments on behalf of VIEs	965,291	1,364,871
APUC's maximum exposure in regard to VIE's	$ 1,161,780	$ 1,458,962

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail)	Dec. 31, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020CLP ($)	Sep. 23, 2020USD ($)	Dec. 31, 2019USD ($)	May 23, 2019USD ($)	Jan. 29, 2019CAD ($)
Debt Instrument [Line Items]
Long-term debt	$ 4,538,470,000				$ 3,931,868,000
Less: current portion	(139,874,000)				(225,013,000)
Long-term debt, excluding current portion	$ 4,398,596,000				3,706,855,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	3.46%	3.46%	3.46%
Par value	$ 1,700,000,000			$ 600,000,000
Long-term debt	$ 1,688,390,000				1,219,579,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Utility Notes
Debt Instrument [Line Items]
Weighted average coupon	6.34%	6.34%	6.34%
Par value	$ 142,000,000
Long-term debt	$ 157,212,000				233,686,000
Senior Unsecured Notes | U.S Dollar Senior Secured Utility Bonds
Debt Instrument [Line Items]
Weighted average coupon	4.71%	4.71%	4.71%
Par value	$ 556,229,000
Long-term debt	$ 561,494,000				672,337,000
Senior Unsecured Notes | Canadian Dollar Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	4.28%	4.28%	4.28%
Par value		$ 1,150,669,000					$ 300,000,000
Long-term debt	$ 899,710,000				728,679,000
Senior Unsecured Notes | Canadian Dollar Senior Secured Project Notes
Debt Instrument [Line Items]
Weighted average coupon	10.21%	10.21%	10.21%
Par value		$ 25,882,000
Long-term debt	$ 20,315,000				21,961,000
Senior Unsecured Notes | Chilean Unidad de Fomento borrowings
Debt Instrument [Line Items]
Weighted average coupon	4.29%	4.29%	4.29%
Par value			$ 1,868,000
Long-term debt	$ 92,183,000				0
Senior Unsecured Notes | Senior Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 3,917,149,000				3,310,819,000
Senior Unsecured Notes | U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	6.50%	6.50%	6.50%
Par value	$ 637,500,000				350,000,000	$ 350,000,000
Long-term debt	621,321,000				621,049,000
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Revolving Credit Facilities
Debt Instrument [Line Items]
Long-term debt	223,507,000				141,577,000
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Bank Credit Facilities
Debt Instrument [Line Items]
Long-term debt	152,338,000				75,000,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial Paper
Debt Instrument [Line Items]
Long-term debt	$ 122,000,000				$ 218,000,000

Long-term debt - Narrative (Det

Long-term debt - Narrative (Detail)

Oct. 13, 2020USD ($)unsecuredBondcreditFacility

Jul. 31, 2020USD ($)

Jun. 01, 2020USD ($)

Apr. 30, 2020USD ($)

Feb. 15, 2020USD ($)

Jul. 01, 2019USD ($)

Dec. 31, 2020USD ($)

Dec. 31, 2020CLP ($)

Dec. 31, 2020USD ($)

Dec. 31, 2020USD ($)

Dec. 31, 2020CLP ($)

Dec. 31, 2020USD ($)utilityNote

Dec. 31, 2019USD ($)businessUnit

Dec. 31, 2020CAD ($)

Dec. 31, 2020CLP ($)

Nov. 08, 2020USD ($)termLoanFacility

Oct. 13, 2020CLP ($)creditFacility

Oct. 05, 2020creditFacility

Sep. 23, 2020USD ($)

Jun. 30, 2020USD ($)creditFacility

Feb. 24, 2020USD ($)

Feb. 14, 2020CAD ($)

Dec. 31, 2019CAD ($)

Sep. 30, 2019USD ($)

Jul. 12, 2019USD ($)

Jun. 27, 2019CAD ($)

May 23, 2019USD ($)

Jan. 29, 2019USD ($)

Jan. 29, 2019CAD ($)

Debt Instrument [Line Items]

Short-term debt

$ 194,478,000

$ 194,478,000

$ 194,478,000

$ 194,478,000

Interest on long-term debt

50,486,000

50,486,000

50,486,000

50,486,000

$ 44,229,000

Interest expense during the year on long-term liabilities

175,358,000

$ 175,664,000

Revolving Credit Facility | Commercial Paper

Debt Instrument [Line Items]

Par value

$ 500,000,000

Maximum maturity of amounts drawn under the commercial paper program

270 days

Senior Unsecured Bank Credit Facilities | Line of Credit

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 135,000,000

U.S. Dollar Subordinated Unsecured Notes | Interest rate swaps

Debt Instrument [Line Items]

Derivative notional amount

$ 350,000,000

Senior Unsecured Debt

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 25,000,000

$ 100,000,000

$ 100,000,000

$ 6,500,000

Senior Unsecured Debt | Interest rate swaps

Debt Instrument [Line Items]

Interest rate (percent)

4.60%

4.60%

Derivative notional amount

$ 300,000,000

Senior Unsecured Debt | U.S. Dollar Senior Unsecured Notes

Debt Instrument [Line Items]

Par value

1,700,000,000

1,700,000,000

1,700,000,000

1,700,000,000

$ 600,000,000

Interest rate (percent)

2.05%

Senior Unsecured Debt | Senior Unsecured Bank Credit Facilities | Revolving Credit Facility | Ascendant

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 97,029,000

Number of new credit facilities | termLoanFacility

2

Repayments of unsecured debt

4,655,000

Senior Unsecured Debt | Senior Unsecured Bank Credit Facilities | Revolving Credit Facility | ESSAL

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 55,786,000

$ 44,408,558,000

Number of new credit facilities | creditFacility

7

7

Repayments of unsecured debt

2,474,000

$ 1,759,423,000

Senior Unsecured Debt | Senior Unsecured Bank Credit Facilities | Line of Credit

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 1,600,000,000

Number of new credit facilities | creditFacility

2

3

Senior Unsecured Debt | Senior Unsecured Revolving Credit Facilities | Letter of Credit

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 350,000,000

Senior Unsecured Debt | Senior Unsecured Revolving Credit Facilities | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

Senior Unsecured Debt | Senior Unsecured Revolving Credit Facilities | Revolving Credit Facility | Ascendant

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 62,654,000

Senior Unsecured Debt | Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 200,000,000

Interest rate (percent)

3.315%

Senior Unsecured Debt | Canadian Dollar Senior Unsecured Notes

Debt Instrument [Line Items]

Par value

$ 1,150,669,000

$ 300,000,000

Interest rate (percent)

4.60%

4.60%

Senior Unsecured Debt | Canadian Dollar Senior Unsecured Notes | Interest rate swaps

Debt Instrument [Line Items]

Derivative notional amount

$ 135,000,000

Senior Unsecured Debt | Chilean Unidad de Fomento borrowings

Debt Instrument [Line Items]

Par value

$ 1,868,000

Number of debt instruments repaid | unsecuredBond

2

Senior Unsecured Debt | Chilean Unidad de Fomento borrowings | ESSAL

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 82,320,000

$ 1,926,000

Senior Unsecured Debt | Chilean Senior Unsecured Utility Notes, Series B | ESSAL

Debt Instrument [Line Items]

Repayments of unsecured debt

1,550,000

$ 58,000

Interest rate (percent)

6.00%

6.00%

Senior Unsecured Debt | Chilean Senior Unsecured Utility Notes, Series C | ESSAL

Debt Instrument [Line Items]

Interest rate (percent)

2.80%

2.80%

Senior Unsecured Debt | U.S. Dollar Subordinated Unsecured Notes

Debt Instrument [Line Items]

Par value

$ 637,500,000

$ 637,500,000

$ 637,500,000

$ 637,500,000

$ 350,000,000

$ 350,000,000

Interest rate (percent)

6.20%

6.20%

Available interest deferral period | businessUnit

5

Redemption price (percent)

100.00%

Senior Unsecured Debt | U.S. Dollar Subordinated Unsecured Notes | Interest Rate Reset, Period One

Debt Instrument [Line Items]

Basis spread on variable rate

4.01%

Senior Unsecured Debt | U.S. Dollar Subordinated Unsecured Notes | Interest Rate Reset, Period Two

Debt Instrument [Line Items]

Basis spread on variable rate

4.26%

Senior Unsecured Debt | U.S. Dollar Subordinated Unsecured Notes | Interest Rate Reset, Period Three

Debt Instrument [Line Items]

Basis spread on variable rate

5.01%

Senior Secured Utility Bonds

Debt Instrument [Line Items]

Number of debt instruments repaid | utilityNote

2

Senior Secured Utility Bonds | Senior Unsecured Utility Note One

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 45,000,000

Senior Secured Utility Bonds | Senior Unsecured Utility Note Two

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 30,000,000

Long-term debt - Principal Paym

Long-term debt - Principal Payments (Detail) $ in Thousands	Dec. 31, 2020USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2021	$ 334,352
2022	422,609
2023	111,427
2024	240,151
2025	45,451
Thereafter	3,380,045
Total, including adjustment	$ 4,534,035

Pension and other post-retire_3

Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Non-service costs
Defined Benefit Plan, Non-service Costs, Total	$ 14,072	$ 17,332
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	15,450	12,351
Non-service costs
Interest cost	19,281	20,222
Expected return on plan assets	(26,285)	(20,485)
Amortization of net actuarial loss	5,430	3,530
Amortization of prior service credits	(1,609)	(784)
Amortization of regulatory assets/liabilities	16,272	12,082
Defined Benefit Plan, Non-service Costs, Total	13,089	14,565
Net benefit cost	28,539	26,916
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	6,175	4,587
Non-service costs
Interest cost	7,695	7,575
Expected return on plan assets	(8,748)	(6,725)
Amortization of net actuarial loss	509	(409)
Amortization of prior service credits	0	(208)
Amortization of regulatory assets/liabilities	1,527	2,534
Defined Benefit Plan, Non-service Costs, Total	983	2,767
Net benefit cost	$ 7,158	$ 7,354

Pension and other post-retire_4

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	$ 9,672	$ 8,798
Accumulated benefit obligation for pension plan	1,080,685	526,517
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit)		$ (7,798)
Pension Plans
Employee Benefits Disclosure [Line Items]
Expected employer contributions for next year	28,104
Other Postretirement Benefit Plans, Defined Benefit
Employee Benefits Disclosure [Line Items]
Expected employer contributions for next year	$ 11,398

Pension and other post-retire_5

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in plan assets
Non-current assets (note 11)	$ 10,662	$ 8,437
Pension Plans
Change in projected benefit obligation
Projected benefit obligation, beginning of year	564,970	484,707
Projected benefit obligation assumed from business combination	195,231	20,196
Modifications to plans	(191)	(7,705)
Service cost	15,450	12,351
Interest cost	19,281	20,222
Actuarial (gain) loss	76,618	65,443
Contributions from retirees	171	0
Medicare Part D	0	0
Benefits paid	(37,020)	(30,244)
Foreign exchange	403	0
Projected benefit obligation, end of year	834,913	564,970
Change in plan assets
Fair value of plan assets, beginning of year	407,074	339,099
Plan assets acquired in business combination	179,600	8,004
Actual return on plan assets	52,876	68,025
Employer contributions	26,099	22,190
Contributions from retirees	171	0
Medicare Part D subsidy receipts	0	0
Benefits paid	(37,020)	(30,244)
Foreign exchange	357	0
Fair value of plan assets, end of year	629,157	407,074
Unfunded status	(205,756)	(157,896)
Non-current assets (note 11)	488	0
Current liabilities	(1,989)	(1,415)
Non-current liabilities	(204,255)	(156,481)
Net amount recognized	(205,756)	(157,896)
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation
Projected benefit obligation, beginning of year	219,217	168,325
Projected benefit obligation assumed from business combination	44,950	11,646
Modifications to plans	0	0
Service cost	6,175	4,587
Interest cost	7,695	7,575
Actuarial (gain) loss	34,507	33,605
Contributions from retirees	2,037	1,913
Medicare Part D	377	414
Benefits paid	(8,434)	(8,848)
Foreign exchange	0	0
Projected benefit obligation, end of year	306,524	219,217
Change in plan assets
Fair value of plan assets, beginning of year	158,873	115,542
Plan assets acquired in business combination	0	15,688
Actual return on plan assets	21,219	25,464
Employer contributions	2,583	8,628
Contributions from retirees	1,998	1,913
Medicare Part D subsidy receipts	377	414
Benefits paid	(8,434)	(8,776)
Foreign exchange	0	0
Fair value of plan assets, end of year	176,616	158,873
Unfunded status	(129,908)	(60,344)
Non-current assets (note 11)	10,174	8,437
Current liabilities	(2,835)	(1,168)
Non-current liabilities	(137,247)	(67,613)
Net amount recognized	$ (129,908)	$ (60,344)

Pension and other post-retire_6

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 727,981	$ 504,403
Fair value of plan assets	578,143	407,074
Projected benefit obligation	833,846	564,971
Fair value of plan assets	627,601	407,074
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	288,594	202,422
Fair value of plan assets	148,496	133,711
Projected benefit obligation	288,594	202,422
Fair value of plan assets	$ 148,496	$ 133,711

Pension and other post-retire_7

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	$ 38,510	$ 34,257
Additions to AOCI	50,026	17,905
Amortization in current period	(5,430)	(3,530)
Reclassification to regulatory accounts	(25,875)	(10,122)
Ending balance, December 31	57,231	38,510
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	(6,180)	(6,221)
Additions to AOCI	(191)	(7,705)
Amortization in current period	1,609	784
Reclassification to regulatory accounts	(544)	6,962
Ending balance, December 31	(5,306)	(6,180)
Other Postretirement Benefit Plans, Defined Benefit
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	(9,146)	(13,888)
Additions to AOCI	22,036	14,871
Amortization in current period	(509)	409
Reclassification to regulatory accounts	(16,680)	(10,538)
Ending balance, December 31	(4,299)	(9,146)
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	0	(208)
Additions to AOCI	0	0
Amortization in current period	0	208
Reclassification to regulatory accounts	0	0
Ending balance, December 31	$ 0	$ 0

Pension and other post-retire_8

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.49%	3.19%
Interest crediting rate (for cash balance plans)	4.15%	4.48%
Rate of compensation increase	4.00%	4.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.58%	3.29%
Health care cost trend rate
Before age 65	6.00%	6.125%
Age 65 and after	6.00%	6.125%
Assumed ultimate medical inflation rate	4.75%	4.75%
Year in which ultimate rate is reached	2031	2031

Pension and other post-retire_9

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.19%	4.19%
Expected return on assets	6.85%	6.87%
Rate of compensation increase	3.96%	4.00%
Health care cost trend rate
Before Age 65	6.125%	6.25%
Age 65 and after	6.125%	6.25%
Assumed Ultimate Medical Inflation Rate	4.75%	4.75%
Year in which Ultimate Rate is reached	2031	2031
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.29%	4.25%
Expected return on assets	5.57%	6.51%

Pension and other post-retir_10

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	47.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	43.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	10.00%
Minimum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	30.00%
Minimum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	20.00%
Minimum | Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	0.00%
Maximum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100.00%
Maximum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	60.00%
Maximum | Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	20.00%

Pension and other post-retir_11

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) - Level 1 $ in Thousands	Dec. 31, 2020USD ($)
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	100.00%
Fair value of plan assets	$ 805,773
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	59.00%
Fair value of plan assets	$ 479,506
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	32.00%
Fair value of plan assets	$ 255,975
Other
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	9.00%
Fair value of plan assets	$ 70,292

Pension and other post-retir_12

Pension and other post-retirement benefits- Change in Plan Assets (Details) - Private Equity Funds $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets, end of year	$ 7,745
Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets, beginning of year	0
Contributions into funds	6,726
Unrealized gains	1,188
Distributions	$ (169)

Pension and other post-retir_13

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2020USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2021	$ 46,858
2022	44,993
2023	46,358
2024	47,028
2025	48,197
2026—2030	241,151
Post-Employment Benefit Payments
Defined Benefit Plan Disclosure [Line Items]
2021	10,414
2022	11,033
2023	11,601
2024	12,165
2025	12,687
2026—2030	$ 68,826

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	$ 28,404	$ 24,787
OPEB plan assets	10,662	8,437
Atlantica related prepaid amount	0	8,844
Long-term deposits	13,459	6,319
Income taxes recoverable	4,717	4,416
Deferred financing costs	6,774	5,477
Other	11,736	8,192
Total other assets	75,752	66,472
Less: current portion	(7,266)	(7,764)
Other assets, noncurrent	$ 68,486	$ 58,708

Other long-term liabilities - S

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Long-term Liabilities
Advances in aid of construction	$ 79,864	$ 60,828
Environmental remediation obligation	69,383	58,061	$ 55,621
Asset retirement obligations	79,968	53,879	$ 43,291
Customer deposits	31,939	31,946
Unamortized investment tax credits	17,893	18,234
Deferred credits	21,156	18,952
Preferred shares, Series C	13,698	13,793
Hook up fees	17,704	9,610
Lease liabilities	14,288	9,695
Contingent development support obligations	12,273	9,446
Note payable to related party	30,493	0
Other	23,027	16,896
Other long-term liabilities	411,686	301,340
Less: current portion	(72,505)	(57,939)
Other long-term liabilities, excluding current	339,181	243,401
Transfers from advances in aid of construction to contributions in aid of construction	1,994	5,465
Undiscounted, unescalated cost of environmental cleanup activities	60,803	58,484
Accrual for environmental loss contingencies to be incurred over next four years	43,995
Regulatory assets	$ 845,471	559,887
Note payable to related party
Other Long-term Liabilities
Interest rate (percent)	0.675%
Atlantica
Other Long-term Liabilities
Contingent consideration related to prior acquisition		29,100
San Antonio Water System
Other Long-term Liabilities
Additional deferred credits related to investment in San Antonio Water System		5,000
Environmental costs
Other Long-term Liabilities
Environmental remediation, rate recovery period	7 years
Regulatory assets	$ 87,308	$ 82,300
Minimum
Other Long-term Liabilities
Other liability repayment period	5 years
Accrual for environmental cleanup, discount rate (percent)	0.80%
Maximum
Other Long-term Liabilities
Other liability repayment period	40 years
Accrual for environmental cleanup, discount rate (percent)	3.40%

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 58,061	$ 55,621
Remediation activities	(5,130)	(1,678)
Accretion	436	1,065
Changes in cash flow estimates	3,828	981
Revision in assumptions	3,402	2,072
Obligation assumed from business acquisition	8,786	0
Closing balance	$ 69,383	$ 58,061

Other long-term liabilities - A

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 53,879	$ 43,291
Obligation assumed from business acquisition and constructed projects	20,420	3,226
Retirement activities	(1,724)	(443)
Accretion	2,674	2,148
Change in cash flow estimates	4,719	5,657
Closing balance	$ 79,968	$ 53,879

Other long-term liabilities - P

Other long-term liabilities - Preferred Shares, Series C (Details) $ in Thousands	Dec. 31, 2020USD ($)shares	Dec. 31, 2020$ / shares	Dec. 31, 2019USD ($)
Class of Stock [Line Items]
2021	$ 334,352
2022	422,609
2023	111,427
2024	240,151
2025	45,451
Thereafter to 2031	3,380,045
Total Preferred shares series C	$ 13,698		$ 13,793
Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares | shares	100
Preferred stock redemption price per share (in CAD per share) | $ / shares		$ 53,400
Series C Preferred Stock | Dividends Payable
Class of Stock [Line Items]
2021	$ 1,075
2022	1,097
2023	1,324
2024	1,536
2025	1,552
Thereafter to 2031	7,693
Redemption amount	4,195
Estimated dividend and redemption payments	18,472
Less amounts representing interest	(4,774)
Total Preferred shares series C	13,698
Less current portion	(1,075)
Preferred shares series C, noncurrent	$ 12,623

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Common Shares Rollforward
Beginning balance (in shares)	524,223,323	488,851,433
Public offering and subscription receipts (in shares)	66,130,063	28,009,341
Dividend reinvestment plan (in shares)	5,217,071	6,068,465
Exercise of share-based awards	1,565,537	1,274,655
Conversion of convertible debentures (in shares)	6,225	19,429
Ending balance (in shares)	597,142,219	524,223,323

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands	Jul. 17, 2020USD ($)$ / sharesshares	Jul. 17, 2020CAD ($)shares	Mar. 31, 2019shares	Mar. 30, 2019$ / shares	Oct. 31, 2019USD ($)$ / sharesshares	Mar. 04, 2021shares	Dec. 31, 2020USD ($)shares	Dec. 31, 2020USD ($)rightvote$ / sharesshares	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2019USD ($)shares	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2020CAD ($)$ / sharesshares	Jul. 17, 2020$ / shares
Stockholders Equity Note [Line Items]
Number of entitled votes per common share | vote								1
Number of voting rights per share | right								1
Discount rate on share purchases (percent)								50.00%
Discount rate on share purchases under dividend reinvestment plan (percent)								5.00%
Carrying amount | $							$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000
Share-based compensation expense | $								24,637,000		$ 11,042,000
Unrecognized compensation costs, non-vested awards | $							$ 12,063,000	$ 12,063,000	$ 12,063,000			$ 12,063,000
Unrecognized compensation costs, non-vested options, period of recognition								1 year 8 months 15 days
Succession and retirement expense | $								$ 2,582,000
Options granted (in shares)								999,962		1,113,775
Options granted (CAD per share) | $ / shares									$ 16.78		$ 14.96
Options exercised (in shares)								2,386,275		3,882,505
Options exercised (CAD per share) | $ / shares									$ 12.52		11.23
Total share-based compensation expense | $								$ 24,637,000		$ 11,042,000
Company Match, First $5,000 Contributed by Employee
Stockholders Equity Note [Line Items]
Employer matching contribution (percent)								20.00%
Company Match, Employee Contributions $5,001 to $10,000
Stockholders Equity Note [Line Items]
Employer matching contribution (percent)								10.00%
Minimum
Stockholders Equity Note [Line Items]
Percentage of outstanding stock to be purchased to acquire discount (or more)								20.00%
Common shares
Stockholders Equity Note [Line Items]
Options settled at cash value for payment of the exercise price and for tax withholdings (in shares)							7,377
Treasury Stock, Common
Stockholders Equity Note [Line Items]
Shares issued from treasury for option exercise (in shares)								6,401,000
Retirement Restricted Share Units
Stockholders Equity Note [Line Items]
Awards vested (percent)								100.00%
Performance Share Units
Stockholders Equity Note [Line Items]
Maximum aggregate number of shares reserved for future issuance (in shares)							7,000,000	7,000,000	7,000,000			7,000,000	7,000,000
Award vesting period								3 years
Performance Share Units | Minimum
Stockholders Equity Note [Line Items]
Percentage of shares issued on number of PSU grants (percent)								2.50%
Performance Share Units | Maximum
Stockholders Equity Note [Line Items]
Percentage of shares issued on number of PSU grants (percent)								237.00%
Bonus Deferral Restricted Stock Units
Stockholders Equity Note [Line Items]
Shares issued during period (in shares)								135,409
Deferred Share Units
Stockholders Equity Note [Line Items]
Common stock, shares issued (in shares)							13,778,000	13,778,000	13,778,000			13,778,000	13,778,000
Maximum aggregate number of shares reserved for future issuance (in shares)							1,000,000	1,000,000	1,000,000			1,000,000	1,000,000
Shares issued during period (in shares)								544,493		460,418
Employee Stock Option
Stockholders Equity Note [Line Items]
Share-based compensation expense | $								$ 1,743,000		$ 1,288,000
Percentage of shares reserved under the plan (must not exceed)								8.00%
Total share-based compensation expense | $								$ 1,743,000		$ 1,288,000
ESPP
Stockholders Equity Note [Line Items]
Vesting period of matching contribution shares								1 year
Maximum aggregate number of shares reserved for future issuance (in shares)							4,000,000	4,000,000	4,000,000			4,000,000	4,000,000
Shares issued during period (in shares)								302,727		253,538
Subsequent Event | Common shares
Stockholders Equity Note [Line Items]
Dividend reinvestment plan shares issued (in shares)						1,403,635
ATM Equity Program
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)								8,664,563				10,421,362
Cash proceeds from issuance of shares | $								$ 120,634,000				$ 142,668,000
Treasury atock, amount reserved for issuance under the plan | $							$ 500,000,000	$ 500,000,000	$ 500,000,000			$ 500,000,000
Sale of stock, average price per share (in USD) | $ / shares								$ 13.92				$ 13.69
Gross proceeds from sale of stock, net of commissions | $								$ 119,126,000				$ 140,885,000
Sale of stock, other related costs | $								$ 1,346,000				$ 3,413,000
Series A Preferred Stock
Stockholders Equity Note [Line Items]
Shares issued, price per share (USD and CAD per share) | $ / shares													$ 25
Preferred stock issued (in shares)							4,800,000	4,800,000	4,800,000			4,800,000	4,800,000
Carrying amount							$ 100,463,000	$ 100,463,000	$ 100,463,000			$ 100,463,000	$ 116,546
Dividend declared per preferred share (CAD per share) | (per share)								$ 1.2905			1.2905
Preferred dividend rate reset period								5 years
Basis spread on five-year Government of Canada Bond Yield (percent)								2.94%
Series D Preferred Stock
Stockholders Equity Note [Line Items]
Shares issued, price per share (USD and CAD per share) | $ / shares													$ 25
Preferred stock issued (in shares)							4,000,000	4,000,000	4,000,000			4,000,000	4,000,000
Carrying amount							$ 83,836,000	$ 83,836,000	$ 83,836,000			$ 83,836,000	$ 97,259
Dividend declared per preferred share (CAD per share) | (per share)				$ 1.25				$ 1.2728			$ 1.2671
Preferred dividend rate reset period								5 years
Preferred dividend, initial period			5 years
Basis spread on five-year Government of Canada Bond Yield (percent)								3.28%
Series B Preferred Stock
Stockholders Equity Note [Line Items]
Convertible preferred stock, shares issued upon conversion			0
Series C Preferred Stock
Stockholders Equity Note [Line Items]
Redeemable preferred stock issued (in shares)							100	100	100			100	100
Public Stock Offering | Common shares
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)	57,465,500	57,465,500			26,252,542
Shares issued, price per share (USD and CAD per share) | (per share)	$ 12.60				$ 13.50									$ 17.10
Cash proceeds from issuance of shares	$ 723,926,000	$ 982,660			$ 354,409,000
Issuance costs	$ 25,268,000	$ 34,299			$ 14,418,000
Other Net Losses
Stockholders Equity Note [Line Items]
Share-based compensation expense | $								$ 12,639,000
Total share-based compensation expense | $								12,639,000
Other Net Losses | Retirement Restricted Share Units
Stockholders Equity Note [Line Items]
Share-based compensation expense | $								5,466,000
Total share-based compensation expense | $								5,466,000
Other Net Losses | Performance Share Units
Stockholders Equity Note [Line Items]
Share-based compensation expense | $								4,591,000
Total share-based compensation expense | $								$ 4,591,000

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 24,637	$ 11,042
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	1,743	1,288
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	870	798
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	511	322
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 21,513	$ 8,634

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Risk-free interest rate	1.20%	1.90%
Expected volatility	24.00%	20.00%
Expected dividend yield	4.10%	4.30%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (CAD per share)	$ 2.72	$ 1.66

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of awards
Beginning balance (in shares)	3,523,912	6,292,642
Granted (in shares)	999,962	1,113,775
Exercised (in shares)	(2,386,275)	(3,882,505)
Forfeited (in shares)	(27,151)
Ending balance (in shares)	2,110,448	3,523,912	6,292,642
Exercisable (in shares)	1,710,662
Weighted average exercise price
Beginning balance (CAD per share)	$ 13.09	$ 11.61
Granted (CAD per share)	16.78	14.96
Exercised (CAD per share)	12.52	11.23
Forfeited (CAD per share)	14.96
Ending balance (CAD per share)	15.45	$ 13.09	$ 11.61
Exercisable (CAD per share)	$ 15.22
Additional Disclosures
Outstanding shares, weighted average remaining contractual term	6 years 6 months 18 days	5 years 10 months 13 days	5 years 9 months
Granted, weighted average remaining contractual term	7 years 3 months 7 days	8 years
Exercised shares, weighted average remaining contractual term	5 years 1 month 28 days	4 years 5 months 12 days
Exercisable , weighted average remaining contractual term	6 years 5 months 8 days
Beginning balance, aggregate intrinsic value	$ 18,609	$ 13,342
Granted, aggregate intrinsic value	0	0
Exercised, aggregate intrinsic value	18,465	6,225
Ending balance, aggregate intrinsic value	11,604	$ 18,609	$ 13,342
Exercisable, aggregate intrinsic value	$ 9,798

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - Performance and restricted share units - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Number of awards
Beginning balance (in shares)	2,412,043	1,392,132
Granted, including dividends (in shares)	1,313,171	1,471,442
Exercised (in shares)	(968,470)	(344,340)
Forfeited (in shares)	(35,537)	(107,191)
Ending balance (in shares)	2,721,207	2,412,043	1,392,132
Exercisable (in shares)	707,630
Weighted average grant-date fair value
Beginning balance (CAD per share)	$ 14	$ 12.75
Granted, including dividends (CAD per share)	19.31	14.69
Exercised (CAD per share)	14.45	11.55
Forfeited (CAD per share)	15.62	13.84
Ending balance (CAD per share)	16.58	$ 14	$ 12.75
Exercisable (CAD per share)	$ 12.70
Additional Disclosures
Outstanding, Weighted average remaining contractual term	11 months 4 days	1 year 10 months 9 days	1 year 7 months 6 days
Granted, including dividends, Weighted average remaining contractual term	2 years	2 years
Outstanding, aggregate intrinsic value	$ 44,289	$ 44,309	$ 19,114
Granted, including dividends, aggregate intrinsic value	24,966	16,302
Exercised, aggregate intrinsic value	20,105	5,148
Forfeited, aggregate intrinsic value	745	$ 0
Exercisable, aggregate intrinsic value	$ 14,825

Accumulated other comprehensi_3

Accumulated other comprehensive income (loss) - Schedule of Accumulated Other Comprehensive Income (loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 4,406,595	$ 3,697,522
Other comprehensive income (loss)	(8,739)	15,445
Amounts reclassified from AOCI to the consolidated statement of operations	(4,698)	(3,579)
Other comprehensive income (loss), net of tax	(13,437)	11,866
OCI attributable to the non-controlling interests	691	(2,428)
Net current period OCI attributable to shareholders of AQN	(12,746)	9,438
Ending Balance	5,662,190	4,406,595
Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		0
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(68,822)	(74,189)
Other comprehensive income (loss)	25,643	4,267
Amounts reclassified from AOCI to the consolidated statement of operations	2,763	3,528
Other comprehensive income (loss), net of tax	28,406	7,795
OCI attributable to the non-controlling interests	691	(2,428)
Net current period OCI attributable to shareholders of AQN	29,097	5,367
Ending Balance	(39,725)	(68,822)
Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	75,099	64,333
Other comprehensive income (loss)	(13,418)	19,177
Amounts reclassified from AOCI to the consolidated statement of operations	(10,864)	(8,597)
Other comprehensive income (loss), net of tax	(24,282)	10,580
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	(24,282)	10,580
Ending Balance	50,817	75,099
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(16,038)	(9,529)
Other comprehensive income (loss)	(20,964)	(7,999)
Amounts reclassified from AOCI to the consolidated statement of operations	3,403	1,490
Other comprehensive income (loss), net of tax	(17,561)	(6,509)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	(17,561)	(6,509)
Ending Balance	(33,599)	(16,038)
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(9,761)	(19,385)
Ending Balance	$ (22,507)	(9,761)
Adoption of ASU 2017-12 on hedging | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		186
Adoption of ASU 2017-12 on hedging | Foreign currency cumulative translation | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		0
Adoption of ASU 2017-12 on hedging | Unrealized gain on cash flow hedges | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		186
Adoption of ASU 2017-12 on hedging | Pension and post-employment actuarial changes | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		$ 0

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	Mar. 30, 2019$ / shares	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2020CAD ($)	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2019CAD ($)$ / shares
Dividends [Line Items]
Dividend declared for common share holders		$ 344,382		$ 277,835
Cash dividend declared per common share (USD per share) | $ / shares		$ 0.6063		$ 0.5512
Series A Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders			$ 6,194		$ 6,194
Dividend declared per preferred share (CAD per share) | (per share)		1.2905			$ 1.2905
Series D Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders			$ 5,091		$ 5,068
Dividend declared per preferred share (CAD per share) | (per share)	$ 1.25	$ 1.2728			$ 1.2671

Related party transactions (Det

Related party transactions (Detail) $ in Thousands	Dec. 30, 2019USD ($)	Nov. 28, 2018USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jul. 02, 2020CAD ($)	May 31, 2019USD ($)	May 31, 2019CAD ($)	May 24, 2019USD ($)	May 24, 2019CAD ($)
Transactions with Third Party [Line Items]
Note payable to related party			$ 30,493,000	$ 0
Interest income			91,448,000	100,886,000
Fair value loss			(559,701,000)	(278,084,000)
Amount reclassified from AOCI into earnings, net of tax			4,698,000	3,579,000
Contributions from redeemable non-controlling interests			3,717,000	3,403,000
Non-controlling interest incurred			(6,955,000)	(9,006,000)
Distribution to redeemable non-controlling interest			951,000	1,848,000
Non-controlling interests			458,612,000	531,541,000
San Antonio Water System, Joint Venture
Transactions with Third Party [Line Items]
Investments in joint venture				1,500,000	$ 1,581
Ownership interest acquired (percent)					50.00%
AYES Canada
Transactions with Third Party [Line Items]
Interest income			14,731,000	25,572,000
Fair value loss			(20,272,000)	6,649,000
Non-controlling interests			59,125,000	73,707,000		$ 96,752,000
Redeemable Non-Controlling Interest
Transactions with Third Party [Line Items]
Contributions from redeemable non-controlling interests		$ 305,000,000
Non-controlling interest incurred			12,651,000	16,482,000
Distribution to redeemable non-controlling interest			12,198,000	18,241,000
Redeemable Non-Controlling Interest | Secured Credit Facility
Transactions with Third Party [Line Items]
Debt instrument, term		3 years
Secured credit facility, maximum borrowing capacity		$ 306,500,000
Related Party
Transactions with Third Party [Line Items]
Distribution from interest in noncontrolling interest			16,064,000	26,465,000
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses			25,829,000	16,248,000
Development fees charged to the Company			(26,015,000)	(3,924,000)
Equity Method Investee | Sugar Creek
Transactions with Third Party [Line Items]
Exchange of notes receivable				21,107,000
Amount reclassified from AOCI into earnings, before tax				15,765,000
Amount reclassified from AOCI into earnings, net of tax				11,412,000
Third party | San Antonio Water System, Joint Venture
Transactions with Third Party [Line Items]
Investments in joint venture				1,500,000
Related Party | AWUSA
Transactions with Third Party [Line Items]
Exchange of notes receivable	$ 30,293,000
Gain (loss) on sale of investments	$ 0
Interest income				6,007,000
Fair value loss				6,007,000
Related Party | AYES Canada
Transactions with Third Party [Line Items]
Non-controlling interests						$ 96,752,000	$ 130,103	$ 96,752,000	$ 130,103
Distribution from interest in noncontrolling interest			$ 16,064,000	$ 26,465,000

Non-controlling Interests and_3

Non-controlling Interests and Redeemable non-controlling Interest - Net Loss Attributable to Non-Controlling Interest (Details) $ in Thousands	Dec. 31, 2019USD ($)MWac	Dec. 31, 2020USD ($)MWac	Dec. 31, 2019USD ($)	May 31, 2019USD ($)
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests		$ 67,286	$ 62,416
Non-controlling interests - redeemable tax equity partnership units		6,955	9,006
Redeemable non-controlling interest, held by related party		(12,651)	(16,482)
Net effect of non-controlling interests		54,635	45,934
Non-controlling interests	$ 457,834	399,487	457,834
Non-controlling interests	531,541	458,612	531,541
Non-controlling interest attributable to subsidiary		12,651	16,482
Contributions from redeemable non-controlling interests		3,717	3,403
AYES Canada
Noncontrolling Interest [Line Items]
Non-controlling interests	73,707	59,125	73,707	$ 96,752
Other Noncontrolling Interests
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests		(2,749)	(2,553)
Non-controlling interests	834	11,234	834
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests		63,080	55,963
Non-controlling interests - redeemable tax equity partnership units		6,955	9,006
Non-controlling interests	$ 457,000	$ 388,253	457,000
Turquoise Solar Facility
Noncontrolling Interest [Line Items]
Solar power capacity (megawatt ac) | MWac	10	10
Contributions from redeemable non-controlling interests		$ 3,717	$ 3,403

Non-controlling Interests and_4

Non-controlling Interests and Redeemable non-controlling Interest - Change in Redeemable non-controlling Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 25,913	$ 33,364
Net effect from operations	(6,955)	(9,006)
Contributions, net of costs	3,717	3,403
Dividends and distributions declared	(951)	(1,848)
Repurchase of non-controlling interest	(865)	0
Closing balance	20,859	25,913
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	305,863	307,622
Net effect from operations	12,651	16,482
Contributions, net of costs	0	0
Dividends and distributions declared	(12,198)	(18,241)
Repurchase of non-controlling interest	0	0
Closing balance	$ 306,316	$ 305,863

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	Apr. 08, 2020	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Canadian enacted statutory rate (percent)		26.50%	26.50%
U.S. Tax reform and related deferred tax adjustments	$ 9,300
Valuation allowance for deferred tax assets		$ 29,824	$ 29,447
Undistributed earnings of foreign subsidiaries		$ 504,149

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Expected income tax expense at Canadian statutory rate	$ 209,989	$ 147,093
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(27,082)	(27,703)
Adjustments from investments carried at fair value	(87,058)	(60,730)
Non-controlling interests share of income	18,243	16,991
Non-deductible acquisition costs	3,223	2,500
Tax credits	(40,185)	(9,332)
Adjustment relating to prior periods	(4,228)	(1,240)
Amortization and settlement of excess deferred income tax	(12,392)	(2,554)
Other	4,073	5,092
Income tax expense	$ 64,583	$ 70,117

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 792,411	$ 555,067
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	626,980	351,908
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 165,431	$ 203,159

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Expenses [Line Items]
Income tax expenses, current	$ 4,888	$ 16,431
Deferred Income Tax Expense (Benefit)	59,695	53,686
Income tax expense	64,583	70,117
Canada
Income Tax Expenses [Line Items]
Income tax expenses, current	6,336	6,695
Deferred Income Tax Expense (Benefit)	61,440	17,607
Income tax expense	67,776	24,302
United States
Income Tax Expenses [Line Items]
Income tax expenses, current	(1,448)	9,736
Deferred Income Tax Expense (Benefit)	(1,745)	36,079
Income tax expense	$ (3,193)	$ 45,815

Income taxes - Tax Effect on Si

Income taxes - Tax Effect on Significant Portions of Deferred Tax Assets and Deferred Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 531,353	$ 382,448
Pension and OPEB	66,826	54,113
Environmental obligation	16,145	15,541
Regulatory liabilities	168,054	160,200
Other	65,787	59,103
Total deferred income tax assets	848,165	671,405
Less: valuation allowance	(29,824)	(29,447)
Total deferred tax assets	818,341	641,958
Deferred tax liabilities:
Property, plant and equipment	733,211	707,185
Outside basis in partnership	406,429	235,063
Regulatory accounts	212,937	145,852
Other	12,528	14,811
Total deferred tax liabilities	1,365,105	1,102,911
Net deferred tax liabilities	(546,764)	(460,953)
Deferred tax assets	21,880	30,585
Deferred tax liabilities	$ (568,644)	$ (491,538)

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2020USD ($)
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	$ 1,478,580
Tax credits	76,473
Canada
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	552,564
U.S.
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	926,016
Tax Years 2021-2026
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	13,485
Tax credits	3,624
Tax Years 2021-2026 | Canada
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	58
Tax Years 2021-2026 | U.S.
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	13,427
Tax Years 2027 and after
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	1,465,095
Tax credits	72,849
Tax Years 2027 and after | Canada
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	552,506
Tax Years 2027 and after | U.S.
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	$ 912,589

Other net losses Other Losses (

Other net losses Other Losses (Details) - USD ($) $ in Thousands	Jul. 01, 2020	Dec. 31, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Acquisition and transition-related costs		$ 14,104	$ 11,609
Tax reform		11,728	0
Management succession and executive retirement expense		12,639	0
Other		22,840	15,085
Other losses		61,311	$ 26,694
Period for refund of taxes collected at the higher rate	5 years
Abandonment loss		$ 5,876

Basic and diluted net earning_3

Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Class of Stock [Line Items]
Net earnings attributable to shareholders of AQN	$ 782,463	$ 530,884
Series A and D Preferred shares dividend	8,401	8,486
Net earnings attributable to common shareholders of AQN – basic and diluted	$ 774,062	$ 522,398
Weighted average number of shares
Basic (in shares)	559,633,275	499,910,876
Effect of dilutive securities (in shares)	4,740,561	4,828,678
Diluted (in shares)	564,373,836	504,739,554
Series A Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,611	$ 4,666
Series D Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 3,790	$ 3,820

Basic and diluted net earning_4

Basic and diluted net earnings per share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures (in shares)	479,836	1,113,775

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2020businessUnitsegment
Segment Reporting [Abstract]
Number of business units | businessUnit	2
Number of reportable segments | segment	2

Segmented information - Results

Segmented information - Results of Operations and Assets for Segments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue
Revenue	$ 1,677,058	$ 1,626,392
Fuel, power and water purchased	401,008	443,304
Net revenue	1,276,050	1,183,088
Operating expenses	520,452	471,989
Administrative expenses	59,490	56,802
Depreciation and amortization	314,123	284,304
Gain (loss) on foreign exchange	(2,108)	3,146
Operating income	384,093	366,847
Interest expense	(181,934)	(181,488)
Income from long-term investments	664,671	397,621
Other	(74,419)	(27,913)
Earnings before income taxes	792,411	555,067
Property, plant and equipment	8,241,838	7,240,980
Investments carried at fair value	1,837,429	1,294,147
Equity-method investees	186,452	82,111
Total assets	13,223,906	10,920,786
Capital expenditures	786,030	581,332
Revenue related to net hedging gains, not recognized as revenue from contract with customers	28,586	22,282
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	24,928	(4,405)
Regulated Services Group
Revenue
Revenue	1,405,136	1,368,411
Fuel, power and water purchased	384,363	426,046
Net revenue	1,020,773	942,365
Operating expenses	445,459	397,092
Administrative expenses	34,141	36,667
Depreciation and amortization	219,089	194,766
Gain (loss) on foreign exchange	0	0
Operating income	322,084	313,840
Interest expense	(99,161)	(101,518)
Income from long-term investments	7,753	9,334
Other	(40,128)	(32,297)
Earnings before income taxes	190,548	189,359
Property, plant and equipment	5,757,532	4,763,689
Investments carried at fair value	0	27,072
Equity-method investees	74,673	29,827
Total assets	8,528,172	6,825,379
Capital expenditures	690,792	478,936
Renewable Energy Group
Revenue
Revenue	270,398	256,510
Fuel, power and water purchased	16,645	17,258
Net revenue	253,753	239,252
Operating expenses	74,981	74,676
Administrative expenses	24,719	19,366
Depreciation and amortization	92,890	88,557
Gain (loss) on foreign exchange	0	0
Operating income	61,163	56,653
Interest expense	(52,656)	(61,039)
Income from long-term investments	96,652	104,025
Other	(6,537)	15,951
Earnings before income taxes	98,622	115,590
Property, plant and equipment	2,451,706	2,444,382
Investments carried at fair value	1,837,429	1,267,075
Equity-method investees	111,779	52,284
Total assets	4,589,521	4,014,067
Capital expenditures	80,746	102,396
Corporate
Revenue
Revenue	1,524	1,471
Fuel, power and water purchased	0	0
Net revenue	1,524	1,471
Operating expenses	12	221
Administrative expenses	630	769
Depreciation and amortization	2,144	981
Gain (loss) on foreign exchange	(2,108)	3,146
Operating income	846	(3,646)
Interest expense	(30,117)	(18,931)
Income from long-term investments	560,266	284,262
Other	(27,754)	(11,567)
Earnings before income taxes	503,241	250,118
Property, plant and equipment	32,600	32,909
Investments carried at fair value	0	0
Equity-method investees	0	0
Total assets	106,213	81,340
Capital expenditures	$ 14,492	$ 0

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenue	$ 1,677,058	$ 1,626,392
Property, plant and equipment	8,241,838	7,240,980
Intangible assets	114,913	47,616
Canada
Segment Reporting Information [Line Items]
Revenue	153,569	88,697
Property, plant and equipment	884,195	752,016
Intangible assets	23,123	23,795
International
Segment Reporting Information [Line Items]
Revenue	48,402	0
Property, plant and equipment	691,628	0
Intangible assets	66,965	0
United States
Segment Reporting Information [Line Items]
Revenue	1,475,087	1,537,695
Property, plant and equipment	6,666,015	6,488,964
Intangible assets	$ 24,825	$ 23,821

Commitments and contingencies -

Commitments and contingencies - Estimates of Future Commitments (Detail) $ in Thousands, $ in Thousands	Nov. 28, 2018CAD ($)	Oct. 30, 2018CAD ($)	Mar. 04, 2021lawsuit	Dec. 31, 2020USD ($)
Commitments Disclosure [Line Items]
Year 1				$ 852,091
Year 2				143,691
Year 3				131,702
Year 4				124,039
Year 5				116,973
Thereafter				755,800
Total				2,124,296
Power purchase
Commitments Disclosure [Line Items]
Year 1				45,083
Year 2				27,310
Year 3				26,178
Year 4				26,236
Year 5				26,472
Thereafter				167,380
Total				318,659
Gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1				89,034
Year 2				62,781
Year 3				48,427
Year 4				42,174
Year 5				37,699
Thereafter				144,885
Total				425,000
Service agreements
Commitments Disclosure [Line Items]
Year 1				56,828
Year 2				46,817
Year 3				50,223
Year 4				48,671
Year 5				45,766
Thereafter				248,540
Total				496,845
Capital projects
Commitments Disclosure [Line Items]
Year 1				654,399
Year 2				0
Year 3				0
Year 4				0
Year 5				0
Thereafter				0
Total				654,399
Land easements
Commitments Disclosure [Line Items]
Year 1				6,747
Year 2				6,783
Year 3				6,874
Year 4				6,958
Year 5				7,036
Thereafter				194,995
Total				$ 229,393
Gaia Power Inc. vs APUC
Commitments Disclosure [Line Items]
Damages claimed by other party in lawsuit	$ 108,500	$ 345,000
Punitive damages claimed by other party in lawsuit	$ 10,000	$ 25,000
Mountain View Fire | Subsequent Event
Commitments Disclosure [Line Items]
Number of lawsuits filed | lawsuit			4

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ (52,778)	$ (20,857)
Fuel and natural gas in storage	237	13,985
Supplies and consumables inventory	1,058	(6,028)
Income taxes recoverable	(3,440)	17,796
Prepaid expenses	(15,411)	(7,501)
Accounts payable	40,885	63,854
Accrued liabilities	(29,150)	8,872
Current income tax liability	3,818	(5,016)
Asset retirements and environmental obligations	3,562	(2,494)
Net regulatory assets and liabilities	(26,260)	(2,308)
Changes in non-cash operating items	$ (77,479)	$ 60,303

Financial instruments - Fair Va

Financial instruments - Fair Value of Financial Instruments (Detail) $ in Thousands, $ in Thousands	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)
Fair Value of Financial Instruments [Line Items]
Note payable to related party	$ 30,493	$ 0
Cross currency swap
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	84,542
Interest rate swaps
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	19,325
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,706,900		$ 1,178,581
Total financial assets	1,706,900	1,178,581
Long-term debt	2,316,586	1,495,153
Convertible debentures	623	623
Total financial liabilities	2,317,209	1,495,776
Level 2
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	20,015		27,072
Development loans and other receivables	31,088	37,984
Derivative Asset	194	16
Total financial assets	51,297	65,072
Long-term debt	2,823,473	2,788,915
Note payable to related party	30,493
Convertible debentures	0
Derivative financial instruments, liabilities	104,481	83,837
Total financial liabilities	2,974,012	2,887,872
Level 2 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	194	16
Derivative financial instruments, liabilities	614	2,072
Level 2 | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	84,543	81,765
Level 2 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	19,324
Level 2 | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	15,565	15,120
Level 3
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	110,514		$ 88,494
Development loans and other receivables	0	0
Derivative Asset	51,913	85,688
Total financial assets	162,427	174,182
Derivative financial instruments, liabilities	5,929	827
Total financial liabilities	5,929	827
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	51,525	65,304
Derivative financial instruments, liabilities	5,597	789
Level 3 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	388
Derivative financial instruments, liabilities	332
Level 3 | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		20,384
Derivative financial instruments, liabilities		38
Level 3 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	0
Carrying amount
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,837,429	1,294,147
Development loans and other receivables	23,804	37,050
Derivative Asset	52,107	85,704
Total financial assets	1,913,340	1,416,901
Long-term debt	4,538,470	3,931,868
Convertible debentures	295	342
Derivative financial instruments, liabilities	110,410	84,664
Total financial liabilities	4,693,366	4,030,667
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	51,525	65,304
Derivative financial instruments, liabilities	5,597	789
Carrying amount | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	388
Derivative financial instruments, liabilities	332
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		20,384
Derivative financial instruments, liabilities		38
Carrying amount | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	194	16
Derivative financial instruments, liabilities	614	2,072
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	84,543	81,765
Carrying amount | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	19,324
Carrying amount | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	13,698	13,793
Fair value
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,837,429	1,294,147
Development loans and other receivables	31,088	37,984
Derivative Asset	52,107	85,704
Total financial assets	1,920,624	1,417,835
Long-term debt	5,140,059	4,284,068
Note payable to related party	30,493
Convertible debentures	623	623
Derivative financial instruments, liabilities	110,410	84,664
Total financial liabilities	5,297,150	4,384,475
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	51,525	65,304
Derivative financial instruments, liabilities	5,597	789
Fair value | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	388
Derivative financial instruments, liabilities	332
Fair value | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		20,384
Derivative financial instruments, liabilities		38
Fair value | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	194	16
Derivative financial instruments, liabilities	614	2,072
Fair value | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	84,543	81,765
Fair value | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	19,324
Fair value | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	$ 15,565	$ 15,120

Financial instruments - Additio

Financial instruments - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Nov. 30, 2020USD ($)termLoanFacilityderivativeContract	Dec. 31, 2020USD ($)$ / MWhMWh	Dec. 31, 2019USD ($)	Dec. 31, 2020CAD ($)$ / MWh	Jul. 17, 2020USD ($)	Jul. 17, 2020CAD ($)	Dec. 31, 2019CAD ($)	Sep. 30, 2019USD ($)instrument	May 23, 2019USD ($)
Derivative [Line Items]
Number of term loan facilities | termLoanFacility	2
Number of pay-variable and receive-fixed interest rate swaps | instrument								3
Foreign currency gain (loss)		$ 28,406,000	$ 7,795,000
Revenue collection period		45 days
Cash on hand		$ 101,614,000
Available to be drawn on senior debt facilities		$ 2,675,735,000
Accounts Receivable | Credit Concentration Risk
Derivative [Line Items]
Percentage of revenue contributed by large utility customers		91.00%
Ascendant
Derivative [Line Items]
Number of interest rate swaps redesignated as cash flow hedges | derivativeContract	2
Liberty Power Group
Derivative [Line Items]
Foreign currency gain (loss)		$ (18,875,000)	$ (15,946,000)
Bonds
Derivative [Line Items]
Debt instrument, term			10 years
Senior Unsecured Notes | Senior Unsecured Notes Due January 2029
Derivative [Line Items]
Debt instrument, term			10 years
Senior Unsecured Notes | U.S. Dollar Subordinated Unsecured Notes
Derivative [Line Items]
Interest rate (percent)			6.20%				6.20%
Par value		637,500,000	$ 350,000,000						$ 350,000,000
Interest rate swaps | U.S. Dollar Subordinated Unsecured Notes
Derivative [Line Items]
Derivative notional amount								$ 350,000,000
Interest rate swaps | Bonds
Derivative [Line Items]
Derivative notional amount							$ 135,000,000
Interest rate swaps | Senior Unsecured Notes
Derivative [Line Items]
Derivative notional amount							$ 300,000,000
Interest rate (percent)			4.60%				4.60%
Interest Rate Swap One | Ascendant
Derivative [Line Items]
Derivative notional amount	$ 87,627,000
Derivative, fixed interest rate (percent)	3.28%
Interest Rate Swap Two | Ascendant
Derivative [Line Items]
Derivative notional amount	$ 8,875,000
Derivative, fixed interest rate (percent)	3.02%
Currency Swap
Derivative [Line Items]
Derivative notional amount				$ 650,000,000
Foreign currency gain (loss)		13,256,000	$ 0
Foreign exchange contract
Derivative [Line Items]
Foreign currency gain (loss)		3,581,000	(35,277,000)
Currency forward contract
Derivative [Line Items]
Derivative notional amount					$ 682,500,000	$ 923,243,000
Foreign currency gain on settlement of derivative		2,363,000
Non-regulated Energy Sales
Derivative [Line Items]
Unrealized gains in AOCI to be reclassified		8,624,000
Interest expense
Derivative [Line Items]
Unrealized gains in AOCI to be reclassified		483,000
Derivative gains
Derivative [Line Items]
Unrealized gains in AOCI to be reclassified		1,215,000
Sugar Creek
Derivative [Line Items]
Amount reclassified from AOCI to earnings			15,765,000
Canadian Investments and Subsidiaries
Derivative [Line Items]
Foreign currency gain (loss)		$ 656,000	$ 0
Minimum
Derivative [Line Items]
Forward price | $ / MWh		13.64		13.64
Minimum | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0825		0.0825
Minimum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.22		0.22
Maximum
Derivative [Line Items]
Forward price | $ / MWh		98.05		98.05
Maximum | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0875		0.0875
Maximum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.46		0.46
Weighted Average
Derivative [Line Items]
Forward price | $ / MWh		22.96		22.96
Weighted Average | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0867		0.0867
Cash flow hedge | Interest rate swaps
Derivative [Line Items]
Term of forward-starting interest rate swap			10 years
Cash flow hedge | ISO NE Spot Rate contract expiring February 2022
Derivative [Line Items]
Number of Megawatt hours | MWh		81,408
Cost per Megawatt Hour | $ / MWh		38.95

Financial instruments - Summary

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2020MMBTU
Derivative [Line Items]
Commodity volumes, Gas	3,810,544
Swap
Derivative [Line Items]
Commodity volumes, Gas	1,830,852
Options
Derivative [Line Items]
Commodity volumes, Gas	479,692
Forward contracts
Derivative [Line Items]
Commodity volumes, Gas	1,500,000

Financial instruments - Impact

Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Regulatory Assets	$ 845,471	$ 559,887
Regulatory liabilities, natural gas derivative contracts	601,518	607,378
Swap
Derivative [Line Items]
Regulatory Assets	228	28
Regulatory liabilities, natural gas derivative contracts	271	743
Options
Derivative [Line Items]
Regulatory Assets	50	38
Regulatory liabilities, natural gas derivative contracts	76	0
Forward contracts
Derivative [Line Items]
Regulatory Assets	$ 693	$ 1,830

Financial instruments - Long-te

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2020MWh$ / MWh$ / MWh
PJM Western HUB
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	642,280
Receive average prices (per MW-hr) | $ / MWh	34.02
NI HUB, Expiry December 2031
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,479,234
Receive average prices (per MW-hr) | $ / MWh	23.50
NI HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,953,751
Receive average prices (per MW-hr) | $ / MWh	24.76
ERCOT North HUB
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,330,995
Receive average prices (per MW-hr) | $ / MWh	36.46

Financial instruments - Derivat

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge	$ (13,418)	$ 19,177
Amortization of cash flow hedge	(1,248)	(33)
Amounts reclassified from AOCI	(9,616)	(8,564)
OCI attributable to shareholders of AQN	$ (24,282)	$ 10,580

Financial instruments - Effects

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain (loss) on derivative financial instruments	$ 2,124	$ 15,237
Total realized gain (loss) on derivative financial instruments	2,362	(757)
Gain on derivative financial instruments	964	16,113
Gain (loss) on derivative instruments	3,326	15,356
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain (loss) on derivative financial instruments	(901)	(374)
Total realized gain (loss) on derivative financial instruments	1,218	(80)
Gain (loss) on derivative financial instruments not accounted for as hedges	317	(454)
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain (loss) on derivative financial instruments	(901)	530
Total realized gain (loss) on derivative financial instruments	(1,145)	(227)
Not Designated as Hedging Instrument | Foreign exchange forward
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain (loss) on derivative financial instruments	0	(904)
Total realized gain (loss) on derivative financial instruments	2,363	147
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Amortization of AOCI gains frozen as a result of hedge dedesignation	$ 3,009	$ 15,810

Financial instruments - Maximum

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2020 $ in Thousands	USD ($)	CAD ($)
Segment Reporting Information [Line Items]
Cash and cash equivalents and restricted cash	$ 130,018
Accounts receivable	355,151
Allowance for doubtful accounts	(29,506)
Notes receivable	23,804
Maximum exposure to credit risk for financial instruments	479,467
Regulated Services Group
Segment Reporting Information [Line Items]
Accounts receivable	$ 266,225

Financial instruments - Liabili

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Long-term debt obligations	$ 4,534,031
Interest on long-term debt	1,884,209
Purchase obligations	561,690
Environmental obligation	66,133
Advances in aid of construction	79,864	$ 60,828
Other obligations	216,261
Total obligations	7,452,598
Cross currency swap
Derivative [Line Items]
Derivative financial instruments, liabilities	84,542
Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	19,325
Energy derivative and commodity contracts
Derivative [Line Items]
Derivative financial instruments, liabilities	6,543
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	334,352
Interest on long-term debt	195,876
Purchase obligations	561,690
Environmental obligation	16,955
Advances in aid of construction	1,236
Other obligations	79,219
Total obligations	1,231,308
Due less than 1 year | Cross currency swap
Derivative [Line Items]
Derivative financial instruments, liabilities	37,338
Due less than 1 year | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	2,725
Due less than 1 year | Energy derivative and commodity contracts
Derivative [Line Items]
Derivative financial instruments, liabilities	1,917
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	821,535
Interest on long-term debt	337,199
Purchase obligations	0
Environmental obligation	26,409
Advances in aid of construction	0
Other obligations	6,601
Total obligations	1,225,856
Due 2 to 3 years | Cross currency swap
Derivative [Line Items]
Derivative financial instruments, liabilities	29,999
Due 2 to 3 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	4,346
Due 2 to 3 years | Energy derivative and commodity contracts
Derivative [Line Items]
Derivative financial instruments, liabilities	(233)
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	285,600
Interest on long-term debt	267,112
Purchase obligations	0
Environmental obligation	1,251
Advances in aid of construction	0
Other obligations	5,232
Total obligations	584,358
Due 4 to 5 years | Cross currency swap
Derivative [Line Items]
Derivative financial instruments, liabilities	19,875
Due 4 to 5 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	4,369
Due 4 to 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Derivative financial instruments, liabilities	919
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	3,092,544
Interest on long-term debt	1,084,022
Purchase obligations	0
Environmental obligation	21,518
Advances in aid of construction	78,628
Other obligations	125,209
Total obligations	4,411,076
Due after 5 years | Cross currency swap
Derivative [Line Items]
Derivative financial instruments, liabilities	(2,670)
Due after 5 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	7,885
Due after 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Derivative financial instruments, liabilities	$ 3,940

Subsequent Events (Details)

Subsequent Events (Details)	2 Months Ended	12 Months Ended
	Mar. 04, 2021windProjectunitContingentPPA	Dec. 31, 2019windProject
Subsequent Event [Line Items]
Number of wind projects		3
Subsequent Event | Texas Wind Farms
Subsequent Event [Line Items]
Number of wind projects	2
Equity interest	51.00%
Subsequent Event | Stella, Cranell and East Raymond Texas Coastal Wind Facilities
Subsequent Event [Line Items]
Equity interest	51.00%
Subsequent Event | Maverick
Subsequent Event [Line Items]
Number of Unit Contingent PPAs | unitContingentPPA	2