Algonquin Power & Utilities (AQN) 40-F 3 Mar 22 2021 FY Annual report (Canada) Financial data

Cover Page

Cover Page - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Common Stock, Shares, Outstanding	671,960,276	597,142,219	524,223,323
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	2021
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
Corporate Units
Entity Information [Line Items]
Title of 12(b) Security	Corporate Units
Trading Symbol	AQNU
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

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Toronto, Canada
Auditor Firm ID	1263

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue
Other revenue	$ 2,285,479	$ 1,676,991
Expenses
Administrative expenses	66,726	63,122
Depreciation and amortization	402,963	314,123
Loss (gain) on foreign exchange	4,371	(2,108)
Costs and expenses, total	1,895,288	1,292,965
Gain on sale of renewable assets (note 8(c))	29,063	0
Operating income	419,254	384,026
Interest expense	(209,554)	(181,934)
Income (loss) from long-term investments (note 8)	(26,457)	664,738
Other net losses (note 19)	(22,949)	(61,311)
Pension and other post-employment non-service costs (note 10)	(16,313)	(14,072)
Gain (loss) on derivative financial instruments (note 24(b)(iv))	(1,749)	964
Earnings before income taxes	142,232	792,411
Income tax recovery (expense) (note 18)
Current	(7,237)	(4,888)
Deferred	50,662	(59,695)
Income tax expense	43,425	(64,583)
Net earnings	185,657	727,828
Non-controlling interests	89,637	67,286
Non-controlling interests held by related party	(10,435)	(12,651)
Net effect of non-controlling interests	79,202	54,635
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	264,859	782,463
Preferred shares, Series A and preferred shares, Series D dividend (note 15)	9,003	8,401
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$ 255,856	$ 774,062
Basic net earnings per share (USD per share)	$ 0.41	$ 1.38
Diluted net earnings per share (USD per share)	$ 0.41	$ 1.37
Operating expenses
Expenses
Expenses	$ 702,128	$ 516,820
Regulated electricity distribution
Revenue
Other revenue	1,183,399	776,309
Expenses
Expenses	475,764	227,509
Regulated gas distribution
Revenue
Other revenue	525,897	454,743
Expenses
Expenses	194,174	144,271
Regulated water reclamation and distribution
Revenue
Other revenue	234,875	154,995
Expenses
Expenses	12,664	12,583
Non-regulated energy sales
Revenue
Other revenue	267,970	255,955
Expenses
Expenses	36,498	16,645
Other revenue
Revenue
Other revenue	$ 73,338	$ 34,989

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net earnings	$ 185,657	$ 727,828
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax recovery of $3,219 and $1,526, respectively (notes 24(b)(iii) and 24(b)(iv))	(30,270)	28,406
Change in fair value of cash flow hedges, net of tax recovery of $22,077 and $9,046, respectively (note 24(b)(ii))	(54,331)	(24,282)
Change in pension and other post-employment benefits, net of tax expense of $9,176 and recovery of $6,881, respectively (note 10)	42,051	(17,561)
OCI, net of tax	(42,550)	(13,437)
Comprehensive income	143,107	714,391
Comprehensive loss attributable to the non-controlling interests	(78,953)	(55,326)
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$ 222,060	$ 769,717

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, tax (recovery) and expense	$ (3,219)	$ 1,526
Change in fair value of cash flow hedge, tax (recovery) and expense	(22,077)	(9,046)
Change in unrealized pension and other post-employment expense, tax expense and (recovery)	$ (9,176)	$ (6,881)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 125,157	$ 101,614
Trade and other receivables, net (note 4)	403,426	324,839
Fuel and natural gas in storage	74,209	44,498
Supplies and consumables inventory	103,552	90,147
Regulatory assets (note 7)	158,212	64,090
Prepaid expenses	54,548	49,640
Derivative instruments (note 24)	3,486	13,106
Other assets (note 11)	16,153	7,266
Assets, current, total	938,743	695,200
Property, plant and equipment, net (note 5)	11,042,446	8,241,838
Intangible assets, net (note 6)	105,116	114,913
Goodwill (note 6)	1,201,244	1,208,390
Regulatory assets (note 7)	1,009,413	782,429
Long-term investments (note 8)
Investments carried at fair value	1,848,456	1,839,212
Other long-term investments	495,826	214,583
Derivative instruments (note 24)	17,136	39,001
Deferred income taxes (note 18)	31,595	21,880
Other assets (note 11)	95,861	66,703
Assets	16,785,836	13,224,149
Current liabilities:
Accounts payable	185,291	192,160
Accrued liabilities	428,733	369,530
Dividends payable (note 15)	114,544	92,720
Regulatory liabilities (note 7)	65,809	38,483
Long-term debt (note 9)	356,397	139,874
Other long-term liabilities (note 12)	167,908	72,748
Derivative instruments (note 24)	38,569	41,980
Other liabilities	7,461	7,901
Liabilities, current, total	1,364,712	955,396
Long-term debt (note 9)	5,854,978	4,398,596
Regulatory liabilities (note 7)	510,380	563,035
Deferred income taxes (note 18)	530,187	568,644
Derivative instruments (note 24)	81,676	68,430
Pension and other post-employment benefits obligation (note 10)	226,387	341,502
Other long-term liabilities (note 12)	515,911	339,181
Liabilities	9,084,231	7,234,784
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party (note 16(b))	306,537	306,316
Redeemable non-controlling interests	12,989	20,859
Redeemable non-controlling interests, total	319,526	327,175
Equity:
Preferred shares	184,299	184,299
Common shares (note 13(a))	6,032,792	4,935,304
Additional paid-in capital	2,007	60,729
Retained earnings (deficit)	(288,424)	45,753
Accumulated other comprehensive loss (“AOCI”) (note 14)	(71,677)	(22,507)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,858,997	5,203,578
Non-controlling interests	1,441,924	399,487
Non-controlling interest, held by related party (note 16(c))	81,158	59,125
Non-controlling interests, total	1,523,082	458,612
Total equity	7,382,079	5,662,190
Commitments and contingencies (note 22)
Liabilities and equity, total	$ 16,785,836	$ 13,224,149

Consolidated Statement of Equit

Consolidated Statement of Equity - USD ($) $ in Thousands	Total	Common shares	Preferred shares	Additional paid-in capital	Retained earnings (deficit)	AOCI	Non- controlling interests
Beginning 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]
Net earnings	(727,828)				(782,463)
Net income, non-controlling interests	54,635						(54,635)
Effect of redeemable non-controlling interests not included in equity (note 17)	(5,696)						(5,696)
OCI	(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 (note 3)	3,371						3,371
Common shares issued upon public offering, net of tax effected cost	823,891	823,891
Common shares issued under employee share purchase plan	4,327	4,327
Common shares issued upon conversion of convertible debentures	48	48
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	(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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	(185,657)				(264,859)
Net income, non-controlling interests	79,202						(79,202)
Effect of redeemable non-controlling interests not included in equity (note 17)	(4,866)						(4,866)
OCI	(42,550)					(42,799)	249
Dividends declared and distributions to non-controlling interests	(370,140)				(339,531)		(30,609)
Dividends and issuance of shares under dividend reinvestment plan	0	92,495			(92,495)
Contributions received from non-controlling interests (note 3)	1,150,305			6,919		(6,371)	1,149,757
Common shares issued upon public offering, net of tax effected cost	988,886	988,886		0	0
Contract adjustment payments (note 7(a))	(222,378)			(62,240)	(160,138)
Common shares issued under employee share purchase plan	5,108	5,108
Common shares issued upon conversion of convertible debentures	16	16
Share-based compensation	10,036			10,036
Common shares issued pursuant to share-based awards	(9,326)	10,983		(13,437)	(6,872)
Non-controlling interest assumed on asset acquisition (note 3(b))	29,141						29,141
Ending Balance at Dec. 31, 2021	$ 7,382,079	$ 6,032,792	$ 184,299	$ 2,007	$ (288,424)	$ (71,677)	$ 1,523,082

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Operating Activities
Net earnings	$ 185,657	$ 727,828
Adjustments and items not affecting cash:
Depreciation and amortization	402,963	314,123
Deferred taxes	(50,662)	59,695
Unrealized gain on derivative financial instruments	(5,609)	(2,124)
Share-based compensation expense	8,395	24,637
Cost of equity funds used for construction purposes	(637)	(2,219)
Change in value of investments carried at fair value	122,419	(559,701)
Pension and post-employment expense in excess of (lower than) contributions	(14,146)	2,182
Distributions received from equity investments, net of income	29,818	3,869
Other	1,290	14,406
Net change in non-cash operating items (note 23)	(522,022)	(77,479)
Net Cash Provided by (Used in) Operating Activities, Total	157,466	505,217
Financing Activities
Increase in long-term debt	12,834,047	3,471,740
Repayments of long-term debt	(12,895,091)	(3,160,523)
Issuance of common shares, net of costs	985,619	820,767
Cash dividends on common shares	(307,115)	(253,762)
Dividends on preferred shares	(9,003)	(8,401)
Contributions from non-controlling interests and redeemable non-controlling interests (note 3)	1,125,548	3,717
Production-based cash contributions from non-controlling interest	4,832	3,371
Distributions to non-controlling interests, related party (note 16(b) and (c))	(28,007)	(27,447)
Distributions to non-controlling interests	(12,830)	(11,417)
Payments upon settlement of derivatives	(33,782)	0
Shares surrendered to fund withholding taxes on exercised share options	(3,372)	(5,274)
Repurchase of non-controlling interest	0	(76,046)
Increase in other long-term liabilities	62,000	18,342
Decrease in other long-term liabilities	(49,130)	(8,208)
Net Cash Provided by (Used in) Financing Activities, Total	1,673,716	766,859
Investing Activities
Additions to property, plant and equipment and intangible assets	(1,345,045)	(786,030)
Increase in long-term investments	(622,320)	(279,188)
Acquisitions of operating entities	0	(402,784)
Increase in other assets	(43,306)	(21,419)
Receipt of principal on development loans receivable	206,319	244,285
Distributions received from equity investments	220	14,818
Other proceeds	6,023	415
Net Cash Provided by (Used in) Investing Activities, Total	(1,798,109)	(1,229,903)
Effect of exchange rate differences on cash and restricted cash	(1,702)	573
Increase in cash, cash equivalents and restricted cash	31,371	42,746
Cash, cash equivalents and restricted cash, beginning of year	130,018	87,272
Cash, cash equivalents and restricted cash, end of year	161,389	130,018
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	219,025	190,942
Cash paid during the year for income taxes	5,019	5,603
Cash received during the year for distributions from equity investments	124,143	121,506
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	103,427	74,505
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	108,586	94,321
Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	90,821	27,611
Convertible Debentures
Non-cash financing and investing activities:
Issuance of common shares upon conversion of convertible debentures	$ 0	$ 50

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2021
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, 2021
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 applicable Regulator(s) 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(a)). 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(c)) 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 2021 2020 2021 2020 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 40 Equipment 5-50 5-50 11 11 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. 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. 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 $59,877 (2020 - $59,521) and $18,344 (2020 - 20,328), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $16,772 (2020 - 17,116), operating expenses and amortization of $5,410 (2020 - $5,400) and interest expense of $2,055 (2020 - $2,119). (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, 2021 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; and a restricted share unit (“RSU”) and 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 revenue derives primarily from 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 derives primarily from 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. Revenue related to the sale of capacity is 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 applies the invoicing expedient to the electricity and capacity in the Renewabl

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently issued accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The Financial Accounting Standards Board (“FASB”) issued ASU 2020-01, Investments — Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to address the diversity in practice associated with accounting for certain equity securities upon the application or discontinuation of the equity method of accounting and certain scope considerations for forward contracts and purchased options. The adoption of this update did not have an impact on the consolidated financial statements. The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes to reduce complexity in the accounting standards generally. The update removed certain exceptions to the general principles of Topic 740, Income Taxes and made certain amendments to improve consistent application of other areas of Topic 740. The adoption of this update did not have an impact on the consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. 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 2020-06, 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 at 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, 2021
Business Combination and Asset Acquisition [Abstract]
Business acquisitions and development projects	Business acquisitions and development projects (a) Acquisition of New York American Water Company, Inc. Subsequent to year end, effective January 1, 2022, the Company completed the acquisition of New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)) for a purchase price of approximately $608,000. Liberty NY Water is a Merrick, New York based regulated water and wastewater utility company, serving customers in seven counties in southeastern New York. Due to the timing of the acquisition, the Company has not completed the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the allocation of the consideration paid to the fair value of the asset acquired and liabilities assumed. (b) Agreement to Acquire Kentucky Power Company and AEP Kentucky Transmission Company On October 26, 2021, the Company entered into an agreement with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2,846,000, including the assumption of approximately $1,221,000 in debt (the “Kentucky Power Transaction”). Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility operating within the Commonwealth of Kentucky under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of the Pennsylvania – New Jersey – Maryland regional transmission organization, PJM. Kentucky Power and Kentucky TransCo are both regulated by FERC. Closing of the Kentucky Power Transaction is subject to receipt of certain regulatory and governmental approvals, including the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, clearance of the Kentucky Power Transaction by the Committee on Foreign Investment in the United States, the approval by each of the Kentucky Public Service Commission and FERC, and the approval of the Public Service Commission of West Virginia with respect to the termination and replacement of the existing operating agreement for the Mitchell coal generating facility (in which Kentucky Power owns a 50% interest, representing 780 MW), and the satisfaction of other customary closing conditions. If the acquisition agreement is terminated in certain circumstances, including due to a failure to receive required regulatory approvals (other than the approval of the Kentucky Public Service Commission, FERC or the Public Service Commission of West Virginia for the termination and replacement of the existing operating agreement for the Mitchell Plant), the Company may be required to pay a termination fee of $65,000. The Kentucky Power Transaction is expected to close in mid-2022. (c) Acquisition of Mid-West Wind Facilities 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, and in Neosho County, Kansas (collectively, the “Mid-West Wind Facilities”). 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 acquisition by the Empire Electric System following completion. The Company accounted for its interest in these two projects using the equity method (note 8(c)). In November 2019, a tax equity agreement was executed for Neosho Ridge, the Kansas wind project, and in December 2020, tax equity agreements were executed for North Fork Ridge and Kings Point. Under these agreements, the Class A partnership units are owned by third-party tax equity investors who receive the majority of the tax attributes associated with the Mid-West Wind Facilities. Concurrent with the execution of the tax equity agreements in December 2020, the North Fork Ridge Wind Facility reached commercial operation and the tax equity investors provided initial funding of $29,446. The Kings Point Wind and Neosho Ridge Wind Facilities reached commercial operation in 2021. 3. Business acquisitions and development projects (continued) (c) Acquisition of Mid-West Wind Facilities (continued) The Empire Electric System acquired each of the Mid-West Wind Facilities in 2021 for total consideration to third-party developers of $97,760 and obtained control of the facilities. Subsequent to acquisition, the tax equity investors provided additional funding of $530,880 and third-party construction loans of $789,923 were repaid. The Company accounted for these transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets. The following table summarizes the allocation of the aggregate assets acquired and liabilities assumed at the acquisition dates. Mid-West Wind Working capital $ (28,630) Property, plant and equipment 1,141,884 Long-term debt (789,804) Asset retirement obligation (27,053) Deferred tax liability (4,566) Other liabilities (104,129) Non-controlling interest (tax equity investors) (29,141) Total net assets acquired 158,561 Cash and cash equivalents 15,860 Net assets acquired, net of cash and cash equivalents $ 142,701 (d) Altavista Solar Facility Up to April 2021, the Company held a 50% interest in Altavista Solar SponsorCo, LLC, an entity that indirectly owns an 80 MW solar power facility located in Campbell County, Virginia. In April 2021, the Company acquired the remaining 50% interest in Altavista Solar SponsorCo, LLC for $6,735 and as a result, obtained control of the facility. Subsequent to acquisition, the third-party construction loan of $122,024 was repaid. The Company accounted for the transaction as an asset acquisition since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date of the solar facility. Altavista Solar Working capital $ 870 Property, plant and equipment 138,343 Long-term debt (122,024) Deferred tax liability (421) Asset retirement obligation (3,332) Total net assets acquired 13,436 Cash and cash equivalents 33 Net assets acquired, net of cash and cash equivalents $ 13,403 3. Business acquisitions and development projects (continued) (e) Maverick Creek Wind Facility and Sugar Creek Wind Facility Up to January 2021, the Company held 50% equity interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC (note 8). The two entities indirectly own 492 MW and 202 MW wind development projects in the state of Texas and Illinois (“Maverick Creek Wind Facility” and “Sugar Creek Wind Facility”), respectively. In January 2021, the Company acquired the remaining 50% interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC for $43,797 in aggregate and obtained control of the facilities. An amount of $18,641 was withheld from the consideration for the acquisition of AAGES Sugar Creek Wind, LLC and remains payable upon the satisfaction of certain conditions. The Company accounted for the transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date of the two wind facilities. The existing loans between the Company and the partnerships of $87,035 were treated as additional consideration incurred to acquire the partnerships. Maverick Creek and Sugar Creek Working capital $ (15,557) Property, plant and equipment 1,062,613 Long-term debt (855,409) Asset retirement obligation (23,402) Deferred tax liability (337) Derivative instruments 7,575 Total net assets acquired 175,483 Cash and cash equivalents 4,241 Net assets acquired, net of cash and cash equivalents $ 171,242 Tax equity investors provided funding of $147,914 and $380,829 to the Sugar Creek Wind Facility and Maverick Creek Wind Facility, respectively, in 2021 and third-party construction loans of $284,829 and $570,579, respectively, were repaid subsequent to the acquisition of the remaining 50% interests in the facilities. 3. Business acquisitions and development projects (continued) (f) Acquisition of Ascendant Group Limited On November 9, 2020, the Company completed the acquisition of Liberty Group Limited (formerly 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 final 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. 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) (g) Acquisition of ESSAL The Company acquired 51% of ESSAL on October 13, 2020 for $87,975. 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 final allocation of the acquisition price of $87,975 to the assets acquired and liabilities assumed when control was obtained. Working capital $ 10,575 Property, plant and equipment 238,504 Intangible assets 37,095 Goodwill 75,917 Other assets 1,394 Long-term debt (144,335) Other post-employment benefits (2,292) Deferred tax liabilities, net (29,477) 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. During 2021, adjustments to the preliminary allocation performed in 2020 were made to the fair value of other assets, accruals and long-term debt, resulting in a net increase of goodwill by $5,535, net of tax. These adjustments are reflected in the table above. 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. AQN acquired an additional 43% of ESSAL for $74,111 on October 17, 2020, resulting in AQN acquiring in total 94% of the outstanding shares of ESSAL. The purchase of the second tranche reduced non-controlling interest by $74,111. In January 2021, 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 consideration of $51,750. This represents an interest of 30% in the aggregate interest in ESSAL, which was reflected by a corresponding increase in non-controlling interest. This transaction resulted in no gain or loss. Following this transaction, AQN owns approximately 64% of the outstanding shares of ESSAL and continues to consolidate ESSAL's operations.

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivableAccounts receivable as of December 31, 2021 include unbilled revenue of $102,693 (December 31, 2020 - $91,538) from the Company’s regulated utilities. Accounts receivable as of December 31, 2021 are presented net of allowance for doubtful accounts of $19,327 (December 31, 2020 - $19,628).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2021 Cost Accumulated depreciation Net book value Generation $ 4,187,197 $ 751,219 $ 3,435,978 Distribution and transmission 7,468,236 780,537 6,687,699 Land 114,821 — 114,821 Equipment 101,971 56,464 45,507 Construction in progress Generation 148,302 — 148,302 Distribution and transmission 610,139 — 610,139 $ 12,630,666 $ 1,588,220 $ 11,042,446 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 Generation assets include cost of $114,868 (2020 - $111,806) and accumulated depreciation of $46,649 (2020 - $43,444) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,716 (2020 - $1,708). Distribution and transmission assets include the following: • Cost of $2,018,039 (2020 - $885,087) and accumulated depreciation of $72,484 (2020 - $28,779) related to regulated generation assets. In 2020, the Asbury plant ceased operations and net book value was transferred to a regulatory asset (note 7(b)). • Cost of $557,954 (2020 - $531,191) and accumulated depreciation of $59,857 (2020 - $50,919) related to commonly owned facilities (note 1(k)). Total expenditures incurred on these facilities for the year ended December 31, 2021 were $143,255 (2020 - $61,827). • Cost of $3,076 (2020 - $3,076) and accumulated depreciation of $1,665 (2020 - $1,321) related to assets under finance lease. For the year ended December 31, 2021, contributions received in aid of construction of $6,376 (2020 - $4,214) 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 2021 and 2020 are as follows: 2021 2020 Interest capitalized on non-regulated property $ 3,313 $ 9,359 AFUDC capitalized on regulated property: Allowance for borrowed funds 3,208 3,475 Allowance for equity funds 5,725 2,219 $ 12,246 $ 15,053

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2021 Cost Accumulated amortization Net book value Power sales contracts $ 58,112 $ 43,118 $ 14,994 Customer relationships 78,140 12,337 65,803 Interconnection agreements 15,072 1,721 13,351 Other (a) 10,968 — 10,968 $ 162,292 $ 57,176 $ 105,116 2020 Cost Accumulated amortization Net book value Power sales contracts $ 57,943 $ 41,184 $ 16,759 Customer relationships 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 Estimated amortization expense for intangible assets for each of the next five years is $3,125. All goodwill pertains to the Regulated Services Group. 2021 2020 Opening balance $ 1,208,390 $ 1,031,696 Business acquisitions (note 3) 5,535 167,209 Foreign exchange (12,681) 9,485 Closing balance $ 1,201,244 $ 1,208,390

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Regulatory matters	Regulatory matters The operating companies within the Regulated Services Group are subject to regulation by the respective Regulators of the jurisdictions in which they operate. The respective Regulators 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, Province or Country Regulatory Proceeding Type Details BELCO Bermuda General rate review On May 7, 2021, the Regulator issued a final decision, approving a weighted average cost of capital (“WACC”) of 7.5% and authorizing $211,432 in revenue with $13,426 in deferred revenue to be collected over 5 years at a minimum WACC of 7.5%. The new rates were effective June 1, 2021. EnergyNorth Gas System New Hampshire General rate review The New Hampshire Public Utilities Commission (“NHPUC”) issued an order approving a permanent increase of $6,300 in annual distribution revenues for EnergyNorth effective August 1, 2021. The NHPUC approved the Company’s right to request two step increases for 2020 and 2021 projects, capped at $4,000 and $3,200, respectively, which will be addressed in separate proceedings. The Company’s request for the $4,000 step increase for 2020 projects is pending. The Company expects to make a filing for approval of the second step increase in the second quarter of 2022. The NHPUC also approved a property tax reconciliation mechanism. Recovery of Granite Bridge feasibility costs, which were included in a supplemental filing in November 2020, were separately litigated in hearings in June 2021. An order denying recovery of litigated Granite Bridge costs was received in October 2021. In that order, the New Hampshire Public Utilities Commission denied recovery of the costs related to the Granite Bridge Project based on a legal interpretation of a New Hampshire statute that prohibits recovery of construction work in progress. The Company's request for rehearing was denied on February 17, 2022. The Company intends to appeal the decision to the New Hampshire Supreme Court. Various Various General rate review Approval of approximately $800 in rate increases for natural gas and wastewater utilities. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2021 December 31, 2020 Regulatory assets Fuel and commodity cost adjustments (a) $ 339,900 $ 18,094 Retired generating plant (b) 185,073 194,192 Pension and post-employment benefits (c) 134,141 178,403 Rate adjustment mechanism (d) 117,309 99,853 Environmental remediation (e) 81,802 87,308 Income taxes (f) 79,472 77,730 Deferred capitalized costs (g) 62,599 34,398 Wildfire mitigation and vegetation management (h) 35,789 22,736 Debt premium (i) 34,204 35,688 Asset retirement obligation (j) 26,810 26,546 Clean energy and other customer programs (k) 26,015 26,400 Rate review costs (l) 9,167 8,054 Long-term maintenance contract (m) 9,134 14,405 Other 26,210 22,712 Total regulatory assets $ 1,167,625 $ 846,519 Less: current regulatory assets (158,212) (64,090) Non-current regulatory assets $ 1,009,413 $ 782,429 Regulatory liabilities Income taxes (f) $ 295,720 $ 322,317 Cost of removal (n) 191,981 200,739 Pension and post-employment benefits (c) 34,468 26,311 Fuel and commodity cost adjustments (a) 18,229 20,136 Clean energy and other customer programs (k) 14,829 10,440 Rate adjustment mechanism (d) 3,316 5,214 Other 17,646 16,361 Total regulatory liabilities $ 576,189 $ 601,518 Less: current regulatory liabilities (65,809) (38,483) Non-current regulatory liabilities $ 510,380 $ 563,035 (a) 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. 7. Regulatory matters (continued) (a) Fuel and commodity cost adjustments (continued) In February 2021, the Company's operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (“Midwest Extreme Weather Event”). As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses. The Company has made a filing with the Missouri regulator requesting approval to treat the incremental fuel costs incurred in the same manner as normal pass-through fuel costs and proposing to extend the recovery period to mitigate the impact on customer bills. In July 2021, Missouri House Bill 734 was signed into law, creating an option for utilities to finance the recovery of extraordinary weather event costs. In January 2022, the Company removed all costs related to the Midwest Extreme Winter Weather Event from its rate request and filed a Petition for Financing Order authorization of the issuance of securitized utility tariff bonds regarding 100% of the extraordinary costs incurred during the Midwest Extreme Winter Weather Event. A decision by the Regulator regarding the securitization request is required by August 22, 2022. (b) 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 operating and capital expenses in Missouri for consideration in the next rate case. The accrual for this estimated amount includes revenues collected related to Asbury that will be subject to review and possible refund to customers. In July 2021, Missouri House Bill 734 created an option for utilities to finance the recovery of costs related to the retirement of obsolescent generation infrastructure, including recovery of undepreciated ratebase balances and financing costs, through securitized utility tariff bonds. In January 2022, the Company removed all balances associated with Asbury from its rate request and expects to file a Petition for Financing Order to securitize these balances in March 2022. (c) 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 applicable 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. 7. Regulatory matters (continued) (d) Rate adjustment mechanism Revenue for CalPeco Electric System, Park Water System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, Granite State Electric System, Peach State 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 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. (e) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap. (f) 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. (g) 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 29 years. In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable 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. (h) Wildfire mitigation and vegetation management The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company's California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. (i) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (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. 7. Regulatory matters (continued) (k) 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. (l) 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. (m) 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. (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. 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, 2021
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: December 31, 2021 December 31, 2020 Long-term investments carried at fair value Atlantica (a) $ 1,750,914 $ 1,706,900 Atlantica share subscription agreement (a) — 20,015 Atlantica Yield Energy Solutions Canada Inc. (b) 95,246 110,514 Other 2,296 1,783 $ 1,848,456 $ 1,839,212 Other long-term investments Equity-method investees (c) $ 433,850 $ 186,452 Development loans receivable from equity-method investees (d) 31,468 22,912 San Antonio Water System and other (e) 30,508 5,219 $ 495,826 $ 214,583 8. Long-term investments (continued) Income (loss) from long-term investments from the years ended December 31 is as follows: Year ended December 31, 2021 2020 Fair value gain (loss) on investments carried at fair value Atlantica $ (107,030) $ 519,297 Atlantica share subscription agreement — 20,015 Atlantica Yield Energy Solutions Canada Inc. (15,915) 20,272 Other 526 117 $ (122,419) $ 559,701 Dividend and interest income from investments carried at fair value Atlantica $ 83,971 $ 74,604 Atlantica Yield Energy Solutions Canada Inc. 17,222 14,731 Other 330 2,113 $ 101,523 $ 91,448 Other long-term investments Equity method income (loss) $ (26,337) $ 209 Interest and other income 20,776 13,380 $ (5,561) $ 13,589 Income (loss) from long-term investments $ (26,457) $ 664,738 (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% (2020 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. On December 9, 2020, the Company entered into a subscription agreement to purchase additional ordinary shares of Atlantica at $33.00 per share. The contract was accounted for as a derivative under ASC 815, Derivatives and Hedging . On January 7, 2021, the subscription closed and the Company paid $132,688 for the additional 4,020,860 shares of Atlantica. The total cost for the Atlantica shares as of December 31, 2021 is $1,167,444. The Company accounts for its investment in Atlantica at fair value, with changes in fair value reflected in the consolidated statements of operations. (b) Investment in AYES Canada AQN and Atlantica own 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”). The investment of $96,752 by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party (notes 17). 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. As at December 31, 2021, the Company's maximum exposure to loss is $95,246 (2020 - $110,514), which represents the fair value of the investment. 8. Long-term investments (continued) (c) Equity-method investees The Company has non-controlling interests in various corporations, partnerships and joint ventures with a total carrying value of $433,850 (2020 - $186,452) including investments in VIEs of $86,202 (2020 - $174,685). i) Operating facilities The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. The Company also owns a 50% economic interest in Val-Éo, a 24 MW wind facility which achieved commercial operation in December 2021. The Company does not control the entities and therefore accounts for its interest using the eq uity method. During the first quarter of 2021, the Company acquired a 51% interest in three wind facilities from a portfolio of four wi nd facilities located in Texas (“Texas Coastal Wind Facilities”) for $234,274. On August 12, 2021, the Company acquired a 51% interest in the fourth Texas Coastal Wind Facility for $110,609. All facilities have achieved commercial operations. The Company does not control the entities and therefore accounts for its 51% interest using the eq uity method. ii) Development and construction projects The Company also has 50% equity interests in several wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining interest in most development projects at a pre-agreed price. During the year, the Company acquired the remaining 50% equity interest of the North Fork Ridge Wind Facility, the Kings Point Wind Facility, the Sugar Creek Wind Facility, the Maverick Creek Wind Facility and the Altavista Solar Facility. As a result, the Company obtained control of the facilities and accounted for these transactions as asset acquisitions (note 3). During the year, the Sandy Ridge II Wind Project, the Shady Oaks II Wind Project and the New Market Solar Project net assets of $220,677 were contributed into joint venture entities in exchange for 50% equity interests in the joint ventures and loans receivable in the net amount of $10,779 (note 8(d)) and a contract asset of $17,018 recognized for the portion of consideration payable upon mechanical completion but in no event later than December 31, 2022. The transfer of the New Market Solar Project resulted in a gain of $26,182. The projects are accounted using the equity method. During the third quarter of 2021, the Company paid $1,500 to Abengoa S.A. (“Abengoa”) to purchase all of Abengoa's interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A. included project development assets for $2,662 and working capital of $1,507. The existing loan between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership. Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors through an investment of $19,688 each in Liberty Development JV Inc., which in turn invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. The investment by Liberty Development JV Inc. is presented as a non-controlling interest held by a related party (note 17). AQN and Ares also formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects. The Shady Oaks II Wind Project and the New Market Solar Project noted above were Liberty Construction JV's first investments. 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's investments in significant partnerships and joint ventures as at December 31 is as follows: 2021 2020 Total assets $ 2,126,934 $ 3,201,967 Total liabilities 945,971 2,913,188 Net assets $ 1,180,963 $ 288,779 AQN's ownership interest in the entities 327,555 141,666 Difference between investment carrying amount and underlying equity in net assets (a) 106,295 44,786 AQN's investment carrying amount for the entities $ 433,850 $ 186,452 (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. Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), all 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, 2021, 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; 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, 2021 amounts to $4,612 (2020 - $12,273). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2021 2020 AQN's maximum exposure in regards to VIEs Carrying amount $ 86,202 $ 174,685 Development loans receivable (d) 31,468 21,804 Performance guarantees and other commitments on behalf of VIEs 409,232 965,291 $ 526,902 $ 1,161,780 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. (d) 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 twelfth anniversary of the development agreement or commercial operation date. (e) San Antonio Water System and other

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2021
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, 2021 December 31, 2020 Senior unsecured revolving credit facilities and delayed draw term facility (a) — 2022-2024 N/A $ 368,806 $ 223,507 Senior unsecured bank credit facilities (b) — 2022-2031 N/A 141,956 152,338 Commercial paper — 2022 N/A 338,700 122,000 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,140,801 — Senior unsecured notes (d) 3.46 % 2022-2047 $ 1,700,000 1,689,792 1,688,390 Senior unsecured utility notes (e) 6.34 % 2023-2035 $ 142,000 155,571 157,212 Senior secured utility bonds (f) 4.71 % 2026-2044 $ 556,219 558,177 561,494 Canadian dollar borrowings Senior unsecured notes (g) 3.81 % 2022-2050 C$ 1,400,669 1,099,403 899,710 Senior secured project notes 10.21 % 2027 C$ 23,256 18,344 20,315 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds (h) 4.18 % 2028-2040 CLF 1,753 77,963 92,183 $ 5,589,513 $ 3,917,149 Subordinated U.S. dollar borrowings Subordinated unsecured notes (i) 6.50 % 2078-2079 $ 637,500 621,862 621,321 $ 6,211,375 $ 4,538,470 Less: current portion (356,397) (139,874) $ 5,854,978 $ 4,398,596 Short-term obligations of $478,248 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. 9. Long-term debt (continued) Recent financing activities: (a) Senior unsecured revolving credit facilities As at December 31, 2021, the Company had a $500,000 senior unsecured syndicated revolving credit facility maturing on July 12, 2024. As at December 31, 2021, the Regulated Services Group had a $500,000 senior unsecured syndicated revolving credit facility maturing on February 23, 2023. As at December 31, 2021, the Renewable Energy Group's bank lines consisted of a $500,000 senior unsecured syndicated revolving credit facility maturing on October 6, 2023 and a $350,000 letter of credit facility that was amended to extend the maturity to June 30, 2023. On November 8, 2020, in connection with the acquisition of Ascendant, the Company assumed $62,654 of debt outstanding under its revolving credit facility. The facility was amended to extend the maturity to June 30, 2022. In the second quarter of 2020, the Company obtained three senior unsecured delayed draw non-revolving credit facilities for a total of $1,600,000. On October 5, 2020, these facilities were replaced with two syndicated revolving credit facilities for a total of $1,600,000 that matured on December 31, 2021. (b) Senior unsecured bank credit facilities On December 20, 2021, the Regulated Services Group entered into a $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”) which matures on December 19, 2022. As at December 31, 2021, the Regulated Services Delayed Draw Term Facility had no amounts drawn. Subsequent to year-end on January 3, 2022, the purchase price, plus certain adjustments and acquisition costs, for the acquisition of Liberty NY Water (note 3(a)) of approximately $610,400 was funded through a draw on the Regulated Services Delayed Draw Term Facility. In conjunction with the Kentucky Power Transaction (note 3(b)), the Company obtained a commitment from lenders to provide syndicated unsecured credit facilities in an aggregate amount of up to $2,725,000. This acquisition financing commitment is subject to customary terms and conditions, including certain commitment reductions upon closing of permanent financing. As at March 3, 2022, $1,086,000 remained available under the acquisition financing commitment. On November 8, 2020, in connection with the acquisition of Ascendant, the Company assumed $97,029 of debt outstanding under two term loan facilities that mature on June 29, 2023 and December 26, 2031. On October 13, 2020, in connection with the acquisition of ESSAL, 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. During 2020, the Regulated Services Group fully repaid its C$135,000 term loan upon maturity. (c) U.S dollar senior unsecured notes (Green Equity Units) In June 2021, the Company sold 23,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1,150,000. Each Green Equity Unit was issued in a stated amount of $50, at issuance, consisted of a contract to purchase AQN common shares (the “share purchase contract”) and a 5% undivided beneficial ownership interest in a remarketable senior note of AQN due June 15, 2026, issued in the principal amount of $1,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The interest rate on the notes will be reset following a successful marketing, which would occur in 2024. The present value of the contract adjustment payments was estimated at $222,378 and is recorded against additional paid-in capital (“APIC”) to the extent of the APIC balance and against retained earnings (deficit) for the remainder. The corresponding amount of $222,378 was recorded in other liabilities and is accreted over the three-year period (note 12(a)). 9. Long-term debt (continued) Recent financing activities (continued): (c) U.S dollar senior unsecured notes (Green Equity Units) (continued) Each share purchase contract requires the holder to purchase by no later than June 15, 2024 for a price of $50 in cash, a number of AQN common shares (“common shares”) based on the applicable market value to be determined using the volume-weighted average price of the common shares over a 20-day trading period ending June 14, 2024. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18 per common share. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by $15 per common share. The common share purchase obligation of holders of Green Equity Units will be satisfied by the proceeds raised from a successful remarketing of the notes, unless a holder has elected to settle with separate cash. Holders’ beneficial ownership interest in each note has been pledged to AQN to secure the holders' obligation to purchase common shares under the related share purchase contract. Prior to the issuance of common shares, the share purchase contracts, if dilutive, will be reflected in the Company's diluted earnings per share calculations using the treasury stock method. (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 amounts of $45,000 and $30,000. (f) Senior secured utility bonds On February 15, 2020 and June 1, 2020, the Company repaid, upon their maturities, a $6,500 and a $100,000 secured utility bond, respectively. (g) Canadian dollar senior unsecured notes Subsequent to year-end on February 15, 2022, the Company repaid a C$200,000 senior unsecured note on its maturity. On February 15, 2021, the Renewable Energy Group repaid a C$150,000 unsecured note upon its maturity. Concurrent with the repayments, the Renewable Energy Group unwound and settled the related cross-currency fixed-for-fixed interest rate swap (note 24(b)(iii)). On April 9, 2021, the Renewable Energy Group issued C$400,000 senior unsecured debentures bearing interest at 2.85% with a maturity date of July 15, 2031. The notes were sold at a price of C$999.92 per C$1,000.00 principal amount. Concurrent with the offering, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap to convert the Canadian-dollar-denominated coupon and principal payments from the offering into U.S. dollars (note 24(b)(iii)). 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. (h) Chilean Unidad de Fomento senior unsecured bonds On October 13, 2020, in connection with the acquisition of ESSAL, 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 2021, the Company repaid CL F 116 (2020 - CLF 58) of obligations under the series B bonds. 9. Long-term debt (continued) Recent financing activities (continued): (i) Subordinated unsecured notes Subsequent to year-end on January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Offering”) of $750,000 aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Offering” and, together with the U.S. Offering, the “Offerings”) of C$400,000 (approximately $320,000) aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). Concurrent with the pricing of the Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Offering into U.S. dollars, and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten-year period of the Notes. As of December 31, 2021, the Company had accrued $49,806 in interest expense (2020 - $50,486). Interest expense on the long-term debt, net of capitalized interest, in 2021 was $159,545 (2020 - $175,358). Principal payments due in the next five years and thereafter are as follows: 2022 2023 2024 2025 2026 Thereafter Total $ 834,645 $ 125,520 $ 374,550 $ 44,951 $ 1,172,284 $ 3,671,384 $ 6,223,334

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2021
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 2021 were $10,836 (2020 - $9,672). The Company provides a defined benefit cash balance pension plan under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. In conjunction with the utility acquisitions, the Company also 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 permanently freezes the accrual of benefits for participants in legacy plans. Thereafter, employees accrue benefits under the Company’s cash balance plan. 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 2021 2020 2021 2020 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 834,913 $ 564,970 $ 306,524 $ 219,217 Projected benefit obligation assumed from business combination — 195,231 — 44,950 Plan Settlements (1,294) — — — Service cost 14,673 15,450 7,307 6,175 Interest cost 20,676 19,281 8,048 7,695 Actuarial loss (gain) (36,597) 76,618 (18,977) 34,507 Contributions from retirees — 171 2,040 2,037 Plan amendments 237 (191) 310 — Medicare Part D — — 373 377 Benefits paid (66,800) (37,020) (12,979) (8,434) Foreign exchange (190) 403 — — Projected benefit obligation, end of year $ 765,618 $ 834,913 $ 292,646 $ 306,524 Change in plan assets Fair value of plan assets, beginning of year 629,157 407,074 176,616 158,873 Plan assets acquired in business combination — 179,600 — — Actual return on plan assets 58,721 52,876 15,200 21,219 Employer contributions 29,058 26,099 11,178 2,583 Plan Settlements (1,294) — — — Contributions from retirees — 171 1,988 1,998 Medicare Part D subsidy receipts — — 372 377 Benefits paid (66,800) (37,020) (12,979) (8,434) Foreign exchange 22 357 — — Fair value of plan assets, end of year $ 648,864 $ 629,157 $ 192,375 $ 176,616 Unfunded status $ (116,754) $ (205,756) $ (100,271) $ (129,908) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 84 488 11,879 10,174 Current liabilities (1,902) (1,989) (699) (2,835) Non-current liabilities (114,936) (204,255) (111,451) (137,247) Net amount recognized $ (116,754) $ (205,756) $ (100,271) $ (129,908) The accumulated benefit obligation for the pension plans was $1,008,754 and $1,080,685 as of December 31, 2021 and 2020, 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 2021 2020 2021 2020 Accumulated benefit obligation $ 489,043 $ 727,981 $ 274,649 $ 288,594 Fair value of plan assets $ 396,679 $ 578,143 $ 162,592 $ 148,496 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2021 2020 2021 2020 Projected benefit obligation $ 580,841 $ 833,846 $ 274,649 $ 288,594 Fair value of plan assets $ 452,333 $ 627,601 $ 162,592 $ 148,496 (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, 2020 $ 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) $ — Additions to AOCI (59,754) 237 (24,126) 24 Amortization in current period (13,130) 1,626 (2,021) 310 Amortization pursuant to plan settlements (210) — — — Reclassification to regulatory accounts 31,670 (752) 14,816 — Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 334 The movements in AOCI for Empire Electric and Gas Systems' and St. Lawrence Gas System's 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(c)). 10. Pension and other post-employment benefits (continued) (c) Assumptions Weighted average assumptions used to determine net benefit obligation for 2021 and 2020 were as follows: Pension benefits OPEB 2021 2020 2021 2020 Discount rate 2.94 % 2.49 % 2.92 % 2.58 % Interest crediting rate (for cash balance plans) 4.00 % 4.15 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 5.875 % 6.00 % Age 65 and after 5.875 % 6.00 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031 The mortality assumption for December 31, 2021 uses the Pri-2012 mortality table and the projected generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31, 2021 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 2021 and 2020 were as follows: Pension benefits OPEB 2021 2020 2021 2020 Discount rate 2.49 % 3.19 % 2.58 % 3.29 % Expected return on assets 6.20 % 6.85 % 4.79 % 5.57 % Rate of compensation increase 3.99 % 3.96 % n/a n/a Health care cost trend rate Before Age 65 5.122 % 6.125 % Age 65 and after 5.122 % 6.125 % Assumed ultimate medical inflation rate 4.05 % 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 2021 2020 2021 2020 Service cost $ 14,673 $ 15,450 $ 7,307 $ 6,175 Non-service costs Interest cost 20,676 19,281 8,048 7,695 Expected return on plan assets (35,972) (26,285) (10,052) (8,748) Amortization of net actuarial loss 13,126 5,430 2,021 509 Amortization of prior service credits (1,626) (1,609) 11 — Settlement Loss Recognized 198 — — — Amortization of regulatory accounts 19,665 16,272 218 1,527 $ 16,067 $ 13,089 $ 246 $ 983 Net benefit cost $ 30,740 $ 28,539 $ 7,553 $ 7,158 (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 48 % 30% -100% Debt securities 43 % 20% - 60% Other 9 % 0% - 20% 100 % The fair values of investments as of December 31, 2021, by asset category, are as follows: Asset class 2021 Percentage Equity securities $ 429,147 51 % Debt securities 350,834 42 % Other 61,259 7 % $ 841,240 100 % As of December 31, 2021, the plan assets do not include any material investments in AQN. 10. Pension and other post-employment benefits (continued) (e) Plan assets (continued) All investments as of December 31, 2021 were valued using level 1 inputs except for 17,314 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, 2021 $ 7,745 Contributions into funds 6,233 Unrealized gains 4,257 Distributions (921) Balance, December 31, 2021 $ 17,314 (f) Cash flows The Company expects to contribute $21,305 to its pension plans and $12,208 to its post-employment benefit plans in 2021. The expected benefit payments over the next ten years are as follows: 2022 2023 2024 2025 2026 2027-2031 Pension plan $ 47,802 $ 43,760 $ 44,478 $ 46,318 $ 47,554 $ 238,011 OPEB 10,465 11,064 11,646 12,060 12,543 68,454

Other assets

Other assets	12 Months Ended
	Dec. 31, 2021
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2021 2020 Restricted cash $ 36,232 $ 28,404 OPEB plan assets (note 10(a)) 11,963 10,662 Long-term deposits 10,735 13,459 Income taxes recoverable 7,649 4,717 Deferred financing costs (a) 30,544 6,774 Other 14,891 9,953 $ 112,014 $ 73,969 Less: current portion (16,153) (7,266) $ 95,861 $ 66,703 (a) Deferred financing costs

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2021
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2021 2020 Contract adjustment payments (a) $ 187,580 $ — Asset retirement obligations (b) 142,147 79,968 Advances in aid of construction (c) 82,580 79,864 Environmental remediation obligation (d) 55,224 69,383 Customer deposits (e) 32,633 31,939 Unamortized investment tax credits (f) 17,439 17,893 Deferred credits and contingent consideration (g) 35,982 21,399 Preferred shares, Series C (h) 13,348 13,698 Hook up fees (i) 21,904 17,704 Lease liabilities (note 1(q)) 22,512 14,288 Contingent development support obligations (j) 4,612 12,273 Note payable to related party (k) 25,808 30,493 Other 42,050 23,027 $ 683,819 $ 411,929 Less: current portion (167,908) (72,748) $ 515,911 $ 339,181 (a) Contract adjustment payment In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000 (note 9(c)). Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period. (b) 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: 2021 2020 Opening balance $ 79,968 $ 53,879 Obligation assumed 57,067 20,420 Retirement activities (4,133) (1,724) Accretion 4,381 2,674 Change in cash flow estimates 4,864 4,719 Closing balance $ 142,147 $ 79,968 12. Other long-term liabilities (continued) (b) Asset retirement obligations (continued) As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)). (c) 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 2021, $6,376 (2020 - $1,994) was transferred from advances in aid of construction to contributions in aid of construction. (d) 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(f)), 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 $57,167 (2020 - $64,766), which at discount rates ranging from 1.0% to 3.4% represents the recorded accrual of $55,224 as of December 31, 2021 (2020 - $69,383). Approximately $36,627 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 30 years. Changes in the environmental remediation obligation are as follows: 2021 2020 Opening balance $ 69,383 $ 58,061 Remediation activities (9,865) (5,130) Accretion 1,025 436 Changes in cash flow estimates 2,265 3,828 Revision in assumptions (7,584) 3,402 Obligation assumed from business acquisition — 8,786 Closing balance $ 55,224 $ 69,383 The Regulators 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, 2021, the Company has reflected a regulatory asset of $81,802 (2020 - $87,308) for the MGP and related sites (note 7(e)). (e) Customer deposits Customer deposits result from the Company’s obligation by 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. 12. Other long-term liabilities (continued) (f) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. 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. (g) Deferred credits and contingent consideration In 2021, the Company settled a $5,000 contingent consideration related to the Company's investment in SAWS (note 8(e)) and recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(e)). (h) Preferred shares, Series C AQN has 100 redeemable preferred shares, Series C 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 preferred shares, Series C 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 preferred shares, Series C 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 preferred shares, Series C carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2022 $ 1,102 2023 1,330 2024 1,542 2025 1,559 2026 1,406 Thereafter to 2031 6,320 Redemption amount 4,212 $ 17,471 Less: amounts representing interest (4,123) $ 13,348 Less current portion (1,102) $ 12,246 (i) 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. (j) 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(c)). 12. Other long-term liabilities (continued) (k) 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(c)). Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable of $30,493 to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually. The note was repaid in full during the second quarter of 2021. In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project (note 8(c)). Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

Shareholders' capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2021 2020 Common shares, beginning of year 597,142,219 524,223,323 Public offering 67,611,465 66,130,063 Dividend reinvestment plan 6,184,686 5,217,071 Exercise of share-based awards (c) 1,020,020 1,565,537 Conversion of convertible debentures 1,886 6,225 Common shares, end of year 671,960,276 597,142,219 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 of AQN (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 November 8, 2021, AQN issued 44,080,000 common shares at $14.63 (C$18.15) per share for gross proceeds of $642,664 (C$800,052) before issuance costs of $26,173 (C$32,583) anticipated to be used to fund a portion of the purchase price of the Kentucky Power Transaction (note 3(b)). For ward contracts were used to manage the Canadian dollar risk (note 24(b)(iv)). 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)). 13. Shareholders’ capital (continued) (ii) At-the-market equity program On May 15, 2020, AQN re-established an at-the-market equity program (“ATM program”) that allowed 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, 2021, the Company issued 23,531,465 common shares under the ATM program at an average price of $15.70 per common share for gross proceeds of $369,495 ($364,876 net of commissions). Other related costs were $872. The Company has issued since the inception of the ATM program in 2019 a cumulative total of 33,952,827 common shares at an average price of $15.08 per share for gross proceeds of $512,163 ($505,761 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4,285. (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by AQN from Treasury. Effective March 3, 2022, common shares purchased under the plan will be issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Subsequent to year-end, AQN issued an addition al 1,625,414 co mmon shares under the dividend reinvestment plan. (b) Preferred shares AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2021 and 2020: Preferred shares Number of shares Price per share Carrying amount C$ 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 preferred shares, Series A 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 preferred shares, Series A 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 preferred shares, Series A have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2023, and every fifth year thereafter. The holders of preferred shares, Series D are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.2728 per share for each year up to, but excluding, March 31, 2024. 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 preferred shares, Series D 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 preferred shares, Series D have the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024, and every fifth year thereafter. The Company has 100 redeemable preferred shares, Series C issued and outstanding. The mandatorily redeemable preferred shares, Series C are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(h)). 13. Shareholders’ capital (continued) (c) Share-based compensation For the year ended December 31, 2021, AQN recorded $8,395 (2020 - $24,637) in total share-based compensation expense as follows: 2021 2020 Share options $ 939 $ 1,743 Director deferred share units 821 870 Employee share purchase 592 511 Performance and restricted share units 6,043 21,513 Total share-based compensation $ 8,395 $ 24,637 The compensation expense is recorded with payroll expenses in the consolidated statements of operations, except for $12,639 recorded in 2020 related to management succession and executive retirement expenses, which was recorded in other net losses (note 19(b)). The portion of share-based compensation costs capitalized as cost of construction is insignificant. As of December 31, 2021, total unrecognized compensation costs related to non-vested share-based awards was $17,137 and is expected to be recognized over a period of 1.67 years. (i) 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 common 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. 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 common shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN common shares. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (ii) Share option plan (continued) The following assumptions were used in determining the fair value of share options granted: 2021 2020 Risk-free interest rate 1.1 % 1.2 % Expected volatility 23 % 24 % Expected dividend yield 4.1 % 4.1 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.46 C$ 2.72 Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2020 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 Granted 437,006 19.64 7.22 — Exercised (506,926) 13.92 5.95 1,453 Forfeited — — — — Balance, December 31, 2021 2,040,528 C$ 15.45 6.11 C$ 3,145 Exercisable, December 31, 2021 1,398,668 C$ 16.09 5.83 C$ 3,247 (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, 2021, a total of $355,096 common shares (2020 - $302,727) were issued to employees under the ESPP. (iv) Director's deferred share units Under the Company’s DSU 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 common 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. For the year ended December 31, 2021, a total of 73,467 DSUs (2020 - 84,074) were issued and 87,582 DSUs (2020 - nil) were settled in exchange for 40,786 common shares issued from treasury, and 46,796 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2021, 530,378 (2020 - 544,493) 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 are 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 the 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 common 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, 2020 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$ 54,560 Granted, including dividends 805,433 19.94 2.77 12,881 Exercised (865,067) 13.79 — 17,005 Forfeited (217,901) 18.64 — 3,981 Balance, December 31, 2021 2,443,672 C$ 18.07 1.72 C$ 44,646 Exercisable, December 31, 2021 775,674 C$ 16.12 C$ 14,172 (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, 2021, 56,686 bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 152,564 bonus deferral RSUs in exchange for 70,571 common shares issued from treasury, and 81,993 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, 2021
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, 2020 $ (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) Other comprehensive income (loss) (25,982) (97,103) 32,247 (90,838) Amounts reclassified from AOCI to the consolidated statement of operations (4,288) 42,772 9,804 48,288 Net current period OCI $ (30,270) $ (54,331) $ 42,051 $ (42,550) OCI attributable to the non-controlling interests (249) — — (249) Net current period OCI attributable to shareholders of AQN $ (30,519) $ (54,331) $ 42,051 $ (42,799) Amount reclassified from AOCI to non-controlling interest (note 3(g)) (6,371) — — (6,371) Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677) 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, 2021
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: 2021 2020 Dividend Dividend per share Dividend Dividend per share Common shares $ 423,023 $ 0.6669 $ 344,382 $ 0.6063 Preferred shares, Series A C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Preferred shares, Series D C$ 5,091 C$ 1.2728 C$ 5,091 C$ 1.2728

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2021
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 2021, the Company charged its equity-method investees $25,778 (2020 - $25,693). 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 $2,036 (2020 - $25,985). Investment and acquisition transactions with equity-method investments are described in note 8(c). In 2020, the Company issued a promissory note of $30,493 payable to Altavista Solar Subco, LLC, an equity investee of the Company at the time. The note was repaid in full during the second quarter of 2021. During the fourth quarter of 2021, the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC, an equity investee of the Company (note 12(k)). (b) Redeemable non-controlling interest held by related party Liberty Global Energy Solutions (note 8(c)), an equity investee of the Company, has a secured credit facility in the amount of $306,500 maturing on January 26, 2024. It is collateralized through a pledge of Atlantica shares. 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 shares to eliminate the collateral shortfall. The Liberty Global Energy Solutions secured credit facility is repayable on demand if Atlantica ceases to be a public company. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects as redeemable non-controlling interest held by related party. Redemption is not considered probable as at December 31, 2021. During the year ended December 31, 2021, the Company incurred non-controlling interest attributable to Liberty Global Energy Solutions of $10,435 (2020 - $12,651) and recorded distributions of $10,214 (2020 - $12,198) (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(b)) and an interest in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company, acquired by Liberty Development JV in November 2021 for $39,376 (note 8(c)). During the year ended December 31, 2021, the Company recorded distributions of $17,793 (2020 - $16,064). (d) Transactions with Atlantica During the year ended December 31, 2021, the Company sold Colombian solar assets to Atlantica for consideration of $23,863 , an d contingent consideration of $2,600, if certain milestones are met. As at December 31, 2021 a gain on the sale of $878 has been recognized. 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, 2021
Noncontrolling Interest [Abstract]
Non-controlling interests and redeemable non-controlling interests	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: 2021 2020 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 88,417 $ 62,682 Non-controlling interests - redeemable tax equity partnership units 6,902 6,955 Other net earnings attributable to: Non-controlling interests (5,682) (2,351) $ 89,637 $ 67,286 Redeemable non-controlling interest, held by related party (10,435) (12,651) Net effect of non-controlling interests $ 79,202 $ 54,635 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 The Company obtained control of the three Mid-West Wind Facilities, and the Sugar Creek Wind Facility and Maverick Creek Wind Facility in 2021 (notes 3(c) and 3(e)). During 2021, third-party tax equity investors funded $530,880, $380,829 and $147,914 to the Mid-West Wind Facilities, the Sugar Creek Wind Facility and the Maverick Creek Wind Facility, respectively, in exchange for Class A partnership units in the entities. As of December 31, 2021, non-controlling interests of $1,441,924 (2020 - $399,487) include partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $1,377,117 (2020 - $388,253) and other non-controlling interests of $64,807 (2020 - $11,234). Non-controlling interest held by related party Non-controlling interest was issued to AYES Canada in May 2019 for $96,752 (note 8(b)). The 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, 2021, the Company incurred non-controlling interest of $nil (2020 - $nil) and recorded distributions of $17,793 (2020 - $16,064) during the year. The balance of the non-controlling interest as of December 31, 2021 was $41,782 (2020 - $59,125). Non-controlling interest was issued to Liberty Development JV Inc, in November 2021 for $39,376 (note 8(c)). There was no change to the balance in 2021. 17. Non-controlling interests and redeemable non-controlling interests (continued) 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, 2021. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2021 2020 2021 2020 Opening balance $ 306,316 $ 305,863 $ 20,859 $ 25,913 Net effect from operations 10,435 12,651 (6,902) (6,955) Contributions, net of costs — — — 3,717 Dividends and distributions declared (10,214) (12,198) (968) (951) Repurchase of non-controlling interest — — — (865) Closing balance $ 306,537 $ 306,316 $ 12,989 $ 20,859

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2021
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% (2020 - 26.5%). The differences are as follows: 2021 2020 Expected income tax expense at Canadian statutory rate $ 37,691 $ 209,989 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (47,600) (27,082) Adjustments from investments carried at fair value 2,709 (87,058) Non-controlling interests share of income 25,135 18,243 Non-deductible acquisition costs 3,733 3,223 Tax credits (49,415) (40,185) Adjustment relating to prior periods 1,333 (4,228) Deferred income taxes on regulated income recorded as regulatory assets (3,807) (2,811) Amortization and settlement of excess deferred income tax (16,778) (12,392) Other 3,574 6,884 Income tax expense (recovery) $ (43,425) $ 64,583 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 recorded a one-time income tax expense of $9,300 to reverse the benefit of the deductions taken in a prior year. 18. Income taxes (continued) For the years ended December 31, 2021 and 2020, earnings before income taxes consist of the following: 2021 2020 Canada (1) $ (60,848) $ 622,776 U.S. 153,719 165,431 Other regions 49,361 4,204 $ 142,232 $ 792,411 (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, 2021 Canada $ 4,560 $ (33,993) $ (29,433) United States 1,024 (19,772) (18,748) Other regions $ 1,653 $ 3,103 4,756 $ 7,237 $ (50,662) $ (43,425) Year ended December 31, 2020 Canada $ 4,319 $ 62,061 $ 66,380 United States (1,448) (1,745) (3,193) Other regions $ 2,017 $ (621) 1,396 $ 4,888 $ 59,695 $ 64,583 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, 2021 and 2020 are presented below: 2021 2020 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 761,666 $ 531,353 Pension and OPEB 46,580 66,826 Environmental obligation 15,271 16,145 Regulatory liabilities 166,939 168,054 Other 64,460 65,787 Total deferred income tax assets $ 1,054,916 $ 848,165 Less: valuation allowance (27,471) (29,824) Total deferred tax assets $ 1,027,445 $ 818,341 Deferred tax liabilities: Property, plant and equipment $ 782,829 $ 733,211 Outside basis differentials 412,665 406,429 Regulatory accounts 300,072 212,937 Other 30,471 12,528 Total deferred tax liabilities $ 1,526,037 $ 1,365,105 Net deferred tax liabilities $ (498,592) $ (546,764) Consolidated balance sheets classification: Deferred tax assets $ 31,595 $ 21,880 Deferred tax liabilities (530,187) (568,644) Net deferred tax liabilities $ (498,592) $ (546,764) The valuation allowance for deferred tax assets as at December 31, 2021 was $27,471 (2020 - $29,824). 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, 2021, 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 2022—2026 2027+ Total Canada $ — $ 678,881 $ 678,881 US 11,283 1,334,299 1,345,582 Total non-capital loss carryforward $ 11,283 $ 2,013,180 $ 2,024,463 Tax credits $ 4,476 $ 132,509 $ 136,985 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 $694,947 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, 2021
Other Income and Expenses [Abstract]
Other net losses	Other net losses Other net losses consist of the following: 2021 2020 Acquisition and transition-related costs $ 14,507 $ 14,104 U.S. Tax reform (a) — 11,728 Management succession and executive retirement (b) — 12,639 Other (c) 8,442 22,840 $ 22,949 $ 61,311 (a) U.S. 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 the Empire Electric System 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 In 2020, 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 of expenses, for the year ended December 31, 2020, in relation to these executives’ share-based compensation agreements. (c) Other

Basic and diluted net earnings

Basic and diluted net earnings per share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share, Basic and Diluted [Abstract]
Basic and diluted net earnings per share	Basic and diluted net earnings per share Basic 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, 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 related to the convertible debentures or resulting from the application of the treasury stock method to outstanding share options and Green Equity Units (note 9(c)). 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: 2021 2020 Net earnings attributable to shareholders of AQN $ 264,859 $ 782,463 Preferred shares, Series A dividend 4,942 4,611 Preferred shares, Series D dividend 4,061 3,790 Net earnings attributable to common shareholders of AQN – basic and diluted $ 255,856 $ 774,062 Weighted average number of shares Basic 622,347,677 559,633,275 Effect of dilutive securities 6,600,185 4,740,561 Diluted 628,947,862 564,373,836

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2021
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, Bermuda and Chile; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates, or has investments in, 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 SAWS 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. Beginning in 2021, the Company reported income and losses associated with development activities under corporate, as these are no longer considered in management’s evaluation of the Renewable Energy Group where it was reported previously. Comparative figures have been reclassified to conform to presentation adopted in the current period. Year ended December 31, 2021 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,944,171 $ 267,970 $ — $ 2,212,141 Other revenue 53,441 18,339 1,558 73,338 Fuel, power and water purchased 682,602 36,498 — 719,100 Net revenue 1,315,010 249,811 1,558 1,566,379 Operating expenses 597,850 104,262 16 702,128 Administrative expenses 37,179 28,298 1,249 66,726 Depreciation and amortization 280,452 121,414 1,097 402,963 Loss on foreign exchange — — 4,371 4,371 Gain on sale of renewable assets — (29,063) — (29,063) Operating income 399,529 24,900 (5,175) 419,254 Interest expense (93,411) (71,598) (44,545) (209,554) Income (loss) from long-term investments 18,306 84,046 (128,809) (26,457) Other (24,177) (9,108) (7,726) (41,011) Earnings (loss) before income taxes $ 300,247 $ 28,240 $ (186,255) $ 142,232 Property, plant and equipment $ 7,394,151 $ 3,615,915 $ 32,380 $ 11,042,446 Investments carried at fair value 2,296 1,846,160 — 1,848,456 Equity-method investees 37,492 375,460 20,898 433,850 Total assets 10,512,799 6,123,888 149,149 16,785,836 Capital expenditures $ 998,855 $ 338,637 $ 7,553 $ 1,345,045 (1) Renewable Energy Group revenue includes $57,018 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $19,043 related to alternative revenue programs for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2020 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,386,048 $ 255,954 $ — $ 1,642,002 Other revenue 19,088 14,444 1,457 34,989 Fuel and power purchased 384,363 16,645 — 401,008 Net revenue 1,020,773 253,753 1,457 1,275,983 Operating expenses 442,851 73,957 12 516,820 Administrative expenses 36,749 25,743 630 63,122 Depreciation and amortization 219,089 92,890 2,144 314,123 Gain on foreign exchange — — (2,108) (2,108) Operating income 322,084 61,163 779 384,026 Interest expense (99,161) (52,656) (30,117) (181,934) Income from long-term investments 7,753 93,998 562,987 664,738 Other (40,128) (6,537) (27,754) (74,419) Earnings before income taxes $ 190,548 $ 95,968 $ 505,895 $ 792,411 Property, plant and equipment $ 5,757,532 $ 2,451,706 $ 32,600 $ 8,241,838 Investments carried at fair value — 1,839,212 — 1,839,212 Equity-method investees 74,673 110,414 1,365 186,452 Total assets 8,528,415 4,586,878 108,856 13,224,149 Capital expenditures $ 690,792 $ 80,746 $ 14,492 $ 786,030 (1) Renewable Energy Group revenue includes $28,586 related to net hedging gain from energy derivative contracts 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. 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: 2021 2020 Revenue United States $ 1,801,876 $ 1,475,087 Canada 157,854 153,502 Other regions 325,749 48,402 $ 2,285,479 $ 1,676,991 Property, plant and equipment United States $ 9,464,716 $ 6,666,015 Canada 882,454 884,195 Other regions 695,276 691,628 $ 11,042,446 $ 8,241,838 Intangible assets United States $ 23,575 $ 24,825 Canada 21,780 23,123 Other regions 59,761 66,965 $ 105,116 $ 114,913 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, 2021
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, claiming damages and punitive damages. The action arose 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 agreed to arbitrate the dispute, and concluded hearings on March 17, 2021. The arbitrator released his decision on August 6, 2021, dismissing Gaia's damages claims for oppression and conspiracy, and also dismissing Gaia's punitive damages claim. The arbitrator confirmed that development fees and royalties, calculated as a sliding percentage of the facility's EBITDA (as argued for by the Company), are payable to Gaia in connection with the Company's 74 MW Amherst Island Wind Facility in Ontario. The arbitrator also found that development fees and royalties, calculated on substantially the same basis as the royalties for Amherst Island, are payable to Gaia in connection with the Company's 175 MW Blue Hill Wind Project in Saskatchewan. Condemnation expropriation proceedings On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley”). On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley Water System by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. The Town filed its objections to the Tentative Decision on June 1, 2021. On October 14, 2021, the Court denied the Town’s objections and issued the Final Statement of Decision. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. 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 (“Liberty CalPeco”). The cause of the fire is undetermined at this time, and CAL FIRE has not yet issued a report. There are currently eight active lawsuits that name the Company and/or certain of its subsidiaries as defendants in connection with the Mountain View fire. Four of these lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007. In the fifth active lawsuit brought by County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony alleges similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In three other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits cannot be reasonably predicted. Liberty CalPeco intends to vigorously defend them. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits. (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, 2021. 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) $ 62,759 $ 33,521 $ 33,585 $ 33,821 $ 12,274 $ 155,106 $ 331,066 Gas supply and service agreements (ii) 101,406 75,482 49,328 44,286 26,887 176,535 473,924 Service agreements 65,230 59,641 58,356 54,953 50,181 347,546 635,907 Capital projects 85,130 — — — — — 85,130 Land easements 12,913 13,048 13,212 13,398 13,561 471,755 537,887 Total $ 327,438 $ 181,692 $ 154,481 $ 146,458 $ 102,903 $ 1,150,942 $ 2,063,914 (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, 2021. 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, 2021
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: 2021 2020 Accounts receivable $ (56,751) $ (52,778) Fuel and natural gas in storage (43,642) 237 Supplies and consumables inventory 445 1,058 Income taxes recoverable (3,025) (3,440) Prepaid expenses (1,189) (15,411) Accounts payable (33,399) 40,885 Accrued liabilities 31,845 (29,150) Current income tax liability 4,363 3,818 Asset retirements and environmental obligations (1,185) 3,562 Net regulatory assets and liabilities (419,484) (26,260) $ (522,022) $ (77,479)

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments December 31, 2021 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,848,456 $ 1,848,456 $ 1,753,210 $ — $ 95,246 Development loans and other receivables 32,261 33,286 — 33,286 — Derivative instruments: Energy contracts designated as a cash flow hedge 15,362 15,362 — — 15,362 Interest rate swap designated as a hedge 1,581 1,581 — 1,581 — Commodity contracts for regulated operations 1,721 1,721 — 1,721 — Cross currency swap designated as a net investment hedge 1,958 1,958 — 1,958 — Total derivative instruments 20,622 20,622 — 5,260 15,362 Total financial assets $ 1,901,339 $ 1,902,364 $ 1,753,210 $ 38,546 $ 110,608 Long-term debt $ 6,211,375 $ 6,543,933 $ 2,418,580 $ 4,125,352 $ — Notes payable to related party 25,808 25,808 — 25,808 — Convertible debentures 277 519 519 — — Preferred shares, Series C 13,348 14,580 — 14,580 — Derivative instruments: Energy contracts designated as a cash flow hedge 60,462 60,462 — — 60,462 Energy contracts not designated as a cash flow hedge 1,169 1,169 — — 1,169 Cross-currency swap designated as a net investment hedge 50,258 50,258 — 50,258 — Interest rate swaps designated as a hedge 7,008 7,008 — 7,008 — Commodity contracts for regulated operations 1,348 1,348 — 1,348 — Total derivative instruments 120,245 120,245 — 58,614 61,631 Total financial liabilities $ 6,371,053 $ 6,705,085 $ 2,419,099 $ 4,224,354 $ 61,631 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2020 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,839,212 $ 1,839,212 $ 1,708,683 $ 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 a cash flow hedge 388 388 — — 388 Commodity contracts for regulatory operations 194 194 — 194 — Total derivative instruments 52,107 52,107 — 194 51,913 Total financial assets $ 1,915,123 $ 1,922,407 $ 1,708,683 $ 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 84,218 84,218 — 84,218 — Forward Interest rate swaps designated as a hedge 19,649 19,649 — 19,649 — 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 The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2021 and 2020 du e to the short-term maturity of these instruments. 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange. 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 Company’s level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates and preferred shares, Series C 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 $19.76 to $130.85 with a weighted average of $32.51 as of December 31, 2021. 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 fair value of the investment in AYES Canada is determined using a discounted cash flow approach combined with a binomial tree approach. 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 7.75% to 8.25% with a weighted average of 8.14%, and the expected volatility of Atlantica's share price ranging from 25.49% to 37.16% as of December 31, 2021. 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. (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: 2021 Financial contracts: Swaps 3,239,873 Options 165,671 3,405,544 24. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) 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 adjustme nts (note 7(a)). 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. (ii) Cash flow hedges The Company reduces the price risk on the expected future sale of power generation at the Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. Notional quantity Expiry Receive average Pay floating price 4,585,008 September 2030 $24.54 Illinois Hub 527,931 December 2028 $32.11 PJM Western HUB 2,465,763 December 2027 $23.67 NI HUB 1,998,095 December 2027 $36.46 ERCORT North HUB Upon the acquisition of the Sugar Creek Wind Facility (note 3(e)), the Company redesignated a long-term energy derivative contract to mitigate the price risk on the expected future sale of power generation. The fair value of the derivative on the redesignation date will be amortized into earnings over the remaining life of the contract. 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 11,328 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)). 24. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) In November 2020, upon the acquisition of Ascendant, (note 3(f)), 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. The Company is party to 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 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. The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2021 2020 Effective portion of cash flow hedge $ (97,103) $ (13,418) Amortization of cash flow hedge (2,132) (1,248) Amounts reclassified from AOCI 44,904 (9,616) OCI attributable to shareholders of AQN $ (54,331) $ (24,282) The Company expects unrealized loss of $1,843 and unrealized gains of $1,555 and $1,206 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. 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 $168 for the year ended December 31, 2021 (2020 - loss of $656) was recorded in OCI. On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes issued on such date, 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 $4,232 for the year ended December 31, 2021 (2020 - loss of $13,256) 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 gain of $1,595 for the year ended December 31, 2021 (2020 - loss of $3,581) was recorded in OCI. The Company is party to C$500,000 (December 31, 2020 - C$650,000) cross currency swaps to effectively convert Canadian dollar debentures 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 $7,824 for the year ended December 31, 2021 (2020 - gain of $18,875) was recorded in OCI. On February 15, 2021, the Renewable Energy Group settled the related cross-currency swap related to its C$150,000 debenture that was repaid. On April 9, 2021, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap, coterminous with the senior unsecured debentures issued on such date (note 9(g)), to effectively convert the C$400,000 Canadian-dollar-denominated offering into U.S. dollars. The Renewable Energy Group designated the entire notional amount of the fixed-for-fixed cross-currency interest rate swap as a hedge fair value changes of the swap are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $1,925 for the year ended December 31, 2021 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. The Company executed on currency forward contracts to manage the currency exposure to the Canadian dollar shares issuance (note 13(a)). A foreign currency gain of $2,329 (2020 - $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: 2021 2020 Change in unrealized loss on derivative financial instruments: Energy derivative contracts $ (5,353) $ (901) Total change in unrealized loss on derivative financial instruments $ (5,353) $ (901) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ (108) $ (1,145) Currency forward contract 2,329 2,363 Total realized loss on derivative financial instruments $ 2,221 $ 1,218 Loss on derivative financial instruments not accounted for as hedges (3,132) 317 Amortization of AOCI gains frozen as a result of hedge dedesignation 3,712 3,009 $ 580 $ 3,326 Amounts recognized in the consolidated statements of operations consist of: Gain (loss) on derivative financial instruments $ (1,749) $ 964 Gain on foreign exchange 2,329 2,362 $ 580 $ 3,326 (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 to 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 the majority 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, Bermuda and Chile. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $293,895 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, 2021, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2021 Cash and cash equivalents and restricted cash $ 161,389 Accounts receivable 422,752 Allowance for doubtful accounts (19,327) Notes receivable 31,468 $ 596,282 In addition, the Company 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 take steps to ensure, to the extent possible, that it will have sufficient liquidity to meet liabilities when due. As of December 31, 2021, in addition to cash on hand of $125,157, the Company had $1,826,256 available to be drawn on its revolving and term credit facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn. 24. Financial instruments (continued) (c) Risk management (continued) Liquidity risk (continued) The Company’s liabilities mature as follows: Due less Due 2 to 3 Due 4 to 5 Due after Total Long-term debt obligations $ 834,645 $ 500,070 $ 1,217,235 $ 3,671,384 $ 6,223,334 Interest on long-term debt 196,824 348,479 297,461 1,004,448 1,847,212 Purchase obligations 614,024 — — — 614,024 Environmental obligation 12,751 23,876 1,066 19,474 57,167 Advances in aid of construction 1,706 — — 80,874 82,580 Derivative financial instruments: Cross-currency swap 27,936 23,115 2,604 1,888 55,543 Interest rate swaps 2,145 2,141 1,335 1,394 7,015 Energy derivative and commodity contracts 8,489 20,148 16,517 17,826 62,980 Contract adjustment payments on Green Equity Units 75,555 112,025 — — 187,580 Other obligations 66,916 4,473 4,427 260,111 335,927 Total obligations $ 1,840,991 $ 1,034,327 $ 1,540,645 $ 5,057,399 $ 9,473,362

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2021
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.

Significant accounting polici_2

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2021
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 applicable Regulator(s) 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.
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(a)). 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(c)) 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 2021 2020 2021 2020 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 40 Equipment 5-50 5-50 11 11 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. 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. 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.
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, 2021 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; and a restricted share unit (“RSU”) and 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 revenue derives primarily from 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 derives primarily from 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. Revenue related to the sale of capacity is 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 applies the invoicing expedient to the electricity and capacity in the Renewable Energy Group contracts. As such, 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” and in Chilean Unidad de Fomento with “CLF” 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 preferred shares, Series C 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.
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 (“IRS”) 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. In 2021, IRS further extended the deadline (six years for renewable energy facilities that began construction in 2016 through 2019, five years for renewable energy facilities that began construction in 2020) to address continuing delays caused by the COVID-19 pandemic. 1. Significant accounting policies (continued) (aa) COVID-19 pandemic (continued)
Recently adopted and issued accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The Financial Accounting Standards Board (“FASB”) issued ASU 2020-01, Investments — Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to address the diversity in practice associated with accounting for certain equity securities upon the application or discontinuation of the equity method of accounting and certain scope considerations for forward contracts and purchased options. The adoption of this update did not have an impact on the consolidated financial statements. The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes to reduce complexity in the accounting standards generally. The update removed certain exceptions to the general principles of Topic 740, Income Taxes and made certain amendments to improve consistent application of other areas of Topic 740. The adoption of this update did not have an impact on the consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. 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 2020-06, 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 at 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, 2021
Accounting Policies [Abstract]
Schedule of 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 2021 2020 2021 2020 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 40 Equipment 5-50 5-50 11 11

Business acquisitions and dev_2

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2021
Mid-West Wind Facilities
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the aggregate assets acquired and liabilities assumed at the acquisition dates. Mid-West Wind Working capital $ (28,630) Property, plant and equipment 1,141,884 Long-term debt (789,804) Asset retirement obligation (27,053) Deferred tax liability (4,566) Other liabilities (104,129) Non-controlling interest (tax equity investors) (29,141) Total net assets acquired 158,561 Cash and cash equivalents 15,860 Net assets acquired, net of cash and cash equivalents $ 142,701
Altavista Solar Facility
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date of the solar facility. Altavista Solar Working capital $ 870 Property, plant and equipment 138,343 Long-term debt (122,024) Deferred tax liability (421) Asset retirement obligation (3,332) Total net assets acquired 13,436 Cash and cash equivalents 33 Net assets acquired, net of cash and cash equivalents $ 13,403
Maverick Creek and Sugar Creek Wind Facilities
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date of the two wind facilities. The existing loans between the Company and the partnerships of $87,035 were treated as additional consideration incurred to acquire the partnerships. Maverick Creek and Sugar Creek Working capital $ (15,557) Property, plant and equipment 1,062,613 Long-term debt (855,409) Asset retirement obligation (23,402) Deferred tax liability (337) Derivative instruments 7,575 Total net assets acquired 175,483 Cash and cash equivalents 4,241 Net assets acquired, net of cash and cash equivalents $ 171,242
Acquisition of Ascendant Group Limited
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the final 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
Acquisition of ESSAL
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the final allocation of the acquisition price of $87,975 to the assets acquired and liabilities assumed when control was obtained. Working capital $ 10,575 Property, plant and equipment 238,504 Intangible assets 37,095 Goodwill 75,917 Other assets 1,394 Long-term debt (144,335) Other post-employment benefits (2,292) Deferred tax liabilities, net (29,477) 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, 2021
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment consist of the following: 2021 Cost Accumulated depreciation Net book value Generation $ 4,187,197 $ 751,219 $ 3,435,978 Distribution and transmission 7,468,236 780,537 6,687,699 Land 114,821 — 114,821 Equipment 101,971 56,464 45,507 Construction in progress Generation 148,302 — 148,302 Distribution and transmission 610,139 — 610,139 $ 12,630,666 $ 1,588,220 $ 11,042,446 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
Schedule of Capitalization of Interest	Interest and AFUDC capitalized to the cost of the assets in 2021 and 2020 are as follows: 2021 2020 Interest capitalized on non-regulated property $ 3,313 $ 9,359 AFUDC capitalized on regulated property: Allowance for borrowed funds 3,208 3,475 Allowance for equity funds 5,725 2,219 $ 12,246 $ 15,053

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	Intangible assets consist of the following: 2021 Cost Accumulated amortization Net book value Power sales contracts $ 58,112 $ 43,118 $ 14,994 Customer relationships 78,140 12,337 65,803 Interconnection agreements 15,072 1,721 13,351 Other (a) 10,968 — 10,968 $ 162,292 $ 57,176 $ 105,116 2020 Cost Accumulated amortization Net book value Power sales contracts $ 57,943 $ 41,184 $ 16,759 Customer relationships 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
Schedule of Goodwill	All goodwill pertains to the Regulated Services Group. 2021 2020 Opening balance $ 1,208,390 $ 1,031,696 Business acquisitions (note 3) 5,535 167,209 Foreign exchange (12,681) 9,485 Closing balance $ 1,201,244 $ 1,208,390

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	The following regulatory proceedings were recently completed: Utility State, Province or Country Regulatory Proceeding Type Details BELCO Bermuda General rate review On May 7, 2021, the Regulator issued a final decision, approving a weighted average cost of capital (“WACC”) of 7.5% and authorizing $211,432 in revenue with $13,426 in deferred revenue to be collected over 5 years at a minimum WACC of 7.5%. The new rates were effective June 1, 2021. EnergyNorth Gas System New Hampshire General rate review The New Hampshire Public Utilities Commission (“NHPUC”) issued an order approving a permanent increase of $6,300 in annual distribution revenues for EnergyNorth effective August 1, 2021. The NHPUC approved the Company’s right to request two step increases for 2020 and 2021 projects, capped at $4,000 and $3,200, respectively, which will be addressed in separate proceedings. The Company’s request for the $4,000 step increase for 2020 projects is pending. The Company expects to make a filing for approval of the second step increase in the second quarter of 2022. The NHPUC also approved a property tax reconciliation mechanism. Recovery of Granite Bridge feasibility costs, which were included in a supplemental filing in November 2020, were separately litigated in hearings in June 2021. An order denying recovery of litigated Granite Bridge costs was received in October 2021. In that order, the New Hampshire Public Utilities Commission denied recovery of the costs related to the Granite Bridge Project based on a legal interpretation of a New Hampshire statute that prohibits recovery of construction work in progress. The Company's request for rehearing was denied on February 17, 2022. The Company intends to appeal the decision to the New Hampshire Supreme Court. Various Various General rate review Approval of approximately $800 in rate increases for natural gas and wastewater utilities. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2021 December 31, 2020 Regulatory assets Fuel and commodity cost adjustments (a) $ 339,900 $ 18,094 Retired generating plant (b) 185,073 194,192 Pension and post-employment benefits (c) 134,141 178,403 Rate adjustment mechanism (d) 117,309 99,853 Environmental remediation (e) 81,802 87,308 Income taxes (f) 79,472 77,730 Deferred capitalized costs (g) 62,599 34,398 Wildfire mitigation and vegetation management (h) 35,789 22,736 Debt premium (i) 34,204 35,688 Asset retirement obligation (j) 26,810 26,546 Clean energy and other customer programs (k) 26,015 26,400 Rate review costs (l) 9,167 8,054 Long-term maintenance contract (m) 9,134 14,405 Other 26,210 22,712 Total regulatory assets $ 1,167,625 $ 846,519 Less: current regulatory assets (158,212) (64,090) Non-current regulatory assets $ 1,009,413 $ 782,429 Regulatory liabilities Income taxes (f) $ 295,720 $ 322,317 Cost of removal (n) 191,981 200,739 Pension and post-employment benefits (c) 34,468 26,311 Fuel and commodity cost adjustments (a) 18,229 20,136 Clean energy and other customer programs (k) 14,829 10,440 Rate adjustment mechanism (d) 3,316 5,214 Other 17,646 16,361 Total regulatory liabilities $ 576,189 $ 601,518 Less: current regulatory liabilities (65,809) (38,483) Non-current regulatory liabilities $ 510,380 $ 563,035 (a) 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. 7. Regulatory matters (continued) (a) Fuel and commodity cost adjustments (continued) In February 2021, the Company's operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (“Midwest Extreme Weather Event”). As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses. The Company has made a filing with the Missouri regulator requesting approval to treat the incremental fuel costs incurred in the same manner as normal pass-through fuel costs and proposing to extend the recovery period to mitigate the impact on customer bills. In July 2021, Missouri House Bill 734 was signed into law, creating an option for utilities to finance the recovery of extraordinary weather event costs. In January 2022, the Company removed all costs related to the Midwest Extreme Winter Weather Event from its rate request and filed a Petition for Financing Order authorization of the issuance of securitized utility tariff bonds regarding 100% of the extraordinary costs incurred during the Midwest Extreme Winter Weather Event. A decision by the Regulator regarding the securitization request is required by August 22, 2022. (b) 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 operating and capital expenses in Missouri for consideration in the next rate case. The accrual for this estimated amount includes revenues collected related to Asbury that will be subject to review and possible refund to customers. In July 2021, Missouri House Bill 734 created an option for utilities to finance the recovery of costs related to the retirement of obsolescent generation infrastructure, including recovery of undepreciated ratebase balances and financing costs, through securitized utility tariff bonds. In January 2022, the Company removed all balances associated with Asbury from its rate request and expects to file a Petition for Financing Order to securitize these balances in March 2022. (c) 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 applicable 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. 7. Regulatory matters (continued) (d) Rate adjustment mechanism Revenue for CalPeco Electric System, Park Water System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, Granite State Electric System, Peach State 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 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. (e) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap. (f) 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. (g) 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 29 years. In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable 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. (h) Wildfire mitigation and vegetation management The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company's California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. (i) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (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. 7. Regulatory matters (continued) (k) 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. (l) 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. (m) 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. (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.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure Long Term Investments And Notes Receivable [Abstract]
Schedule of Long-term Investments	Long-term investments consist of the following: December 31, 2021 December 31, 2020 Long-term investments carried at fair value Atlantica (a) $ 1,750,914 $ 1,706,900 Atlantica share subscription agreement (a) — 20,015 Atlantica Yield Energy Solutions Canada Inc. (b) 95,246 110,514 Other 2,296 1,783 $ 1,848,456 $ 1,839,212 Other long-term investments Equity-method investees (c) $ 433,850 $ 186,452 Development loans receivable from equity-method investees (d) 31,468 22,912 San Antonio Water System and other (e) 30,508 5,219 $ 495,826 $ 214,583 8. Long-term investments (continued)
Schedule of Income from Long-term Investments	Income (loss) from long-term investments from the years ended December 31 is as follows: Year ended December 31, 2021 2020 Fair value gain (loss) on investments carried at fair value Atlantica $ (107,030) $ 519,297 Atlantica share subscription agreement — 20,015 Atlantica Yield Energy Solutions Canada Inc. (15,915) 20,272 Other 526 117 $ (122,419) $ 559,701 Dividend and interest income from investments carried at fair value Atlantica $ 83,971 $ 74,604 Atlantica Yield Energy Solutions Canada Inc. 17,222 14,731 Other 330 2,113 $ 101,523 $ 91,448 Other long-term investments Equity method income (loss) $ (26,337) $ 209 Interest and other income 20,776 13,380 $ (5,561) $ 13,589 Income (loss) from long-term investments $ (26,457) $ 664,738 (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% (2020 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. On December 9, 2020, the Company entered into a subscription agreement to purchase additional ordinary shares of Atlantica at $33.00 per share. The contract was accounted for as a derivative under ASC 815, Derivatives and Hedging . On January 7, 2021, the subscription closed and the Company paid $132,688 for the additional 4,020,860 shares of Atlantica. The total cost for the Atlantica shares as of December 31, 2021 is $1,167,444. The Company accounts for its investment in Atlantica at fair value, with changes in fair value reflected in the consolidated statements of operations. (b) Investment in AYES Canada AQN and Atlantica own 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”). The investment of $96,752 by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party (notes 17). 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. As at December 31, 2021, the Company's maximum exposure to loss is $95,246 (2020 - $110,514), which represents the fair value of the investment. 8. Long-term investments (continued) (c) Equity-method investees The Company has non-controlling interests in various corporations, partnerships and joint ventures with a total carrying value of $433,850 (2020 - $186,452) including investments in VIEs of $86,202 (2020 - $174,685). i) Operating facilities The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. The Company also owns a 50% economic interest in Val-Éo, a 24 MW wind facility which achieved commercial operation in December 2021. The Company does not control the entities and therefore accounts for its interest using the eq uity method. During the first quarter of 2021, the Company acquired a 51% interest in three wind facilities from a portfolio of four wi nd facilities located in Texas (“Texas Coastal Wind Facilities”) for $234,274. On August 12, 2021, the Company acquired a 51% interest in the fourth Texas Coastal Wind Facility for $110,609. All facilities have achieved commercial operations. The Company does not control the entities and therefore accounts for its 51% interest using the eq uity method. ii) Development and construction projects The Company also has 50% equity interests in several wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining interest in most development projects at a pre-agreed price. During the year, the Company acquired the remaining 50% equity interest of the North Fork Ridge Wind Facility, the Kings Point Wind Facility, the Sugar Creek Wind Facility, the Maverick Creek Wind Facility and the Altavista Solar Facility. As a result, the Company obtained control of the facilities and accounted for these transactions as asset acquisitions (note 3). During the year, the Sandy Ridge II Wind Project, the Shady Oaks II Wind Project and the New Market Solar Project net assets of $220,677 were contributed into joint venture entities in exchange for 50% equity interests in the joint ventures and loans receivable in the net amount of $10,779 (note 8(d)) and a contract asset of $17,018 recognized for the portion of consideration payable upon mechanical completion but in no event later than December 31, 2022. The transfer of the New Market Solar Project resulted in a gain of $26,182. The projects are accounted using the equity method. During the third quarter of 2021, the Company paid $1,500 to Abengoa S.A. (“Abengoa”) to purchase all of Abengoa's interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A. included project development assets for $2,662 and working capital of $1,507. The existing loan between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership. Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors through an investment of $19,688 each in Liberty Development JV Inc., which in turn invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. The investment by Liberty Development JV Inc. is presented as a non-controlling interest held by a related party (note 17). AQN and Ares also formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects. The Shady Oaks II Wind Project and the New Market Solar Project noted above were Liberty Construction JV's first investments. 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's investments in significant partnerships and joint ventures as at December 31 is as follows: 2021 2020 Total assets $ 2,126,934 $ 3,201,967 Total liabilities 945,971 2,913,188 Net assets $ 1,180,963 $ 288,779 AQN's ownership interest in the entities 327,555 141,666 Difference between investment carrying amount and underlying equity in net assets (a) 106,295 44,786 AQN's investment carrying amount for the entities $ 433,850 $ 186,452 (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. Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), all 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, 2021, 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; 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, 2021 amounts to $4,612 (2020 - $12,273). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2021 2020 AQN's maximum exposure in regards to VIEs Carrying amount $ 86,202 $ 174,685 Development loans receivable (d) 31,468 21,804 Performance guarantees and other commitments on behalf of VIEs 409,232 965,291 $ 526,902 $ 1,161,780 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. (d) 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 twelfth anniversary of the development agreement or commercial operation date. (e) San Antonio Water System and other
Schedule of 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: 2021 2020 Total assets $ 2,126,934 $ 3,201,967 Total liabilities 945,971 2,913,188 Net assets $ 1,180,963 $ 288,779 AQN's ownership interest in the entities 327,555 141,666 Difference between investment carrying amount and underlying equity in net assets (a) 106,295 44,786 AQN's investment carrying amount for the entities $ 433,850 $ 186,452 (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.
Schedule of Variable Interest Entities	Summarized combined information for AQN's VIEs as at December 31 is as follows: 2021 2020 AQN's maximum exposure in regards to VIEs Carrying amount $ 86,202 $ 174,685 Development loans receivable (d) 31,468 21,804 Performance guarantees and other commitments on behalf of VIEs 409,232 965,291 $ 526,902 $ 1,161,780

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Long Term Debt	Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value December 31, 2021 December 31, 2020 Senior unsecured revolving credit facilities and delayed draw term facility (a) — 2022-2024 N/A $ 368,806 $ 223,507 Senior unsecured bank credit facilities (b) — 2022-2031 N/A 141,956 152,338 Commercial paper — 2022 N/A 338,700 122,000 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,140,801 — Senior unsecured notes (d) 3.46 % 2022-2047 $ 1,700,000 1,689,792 1,688,390 Senior unsecured utility notes (e) 6.34 % 2023-2035 $ 142,000 155,571 157,212 Senior secured utility bonds (f) 4.71 % 2026-2044 $ 556,219 558,177 561,494 Canadian dollar borrowings Senior unsecured notes (g) 3.81 % 2022-2050 C$ 1,400,669 1,099,403 899,710 Senior secured project notes 10.21 % 2027 C$ 23,256 18,344 20,315 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds (h) 4.18 % 2028-2040 CLF 1,753 77,963 92,183 $ 5,589,513 $ 3,917,149 Subordinated U.S. dollar borrowings Subordinated unsecured notes (i) 6.50 % 2078-2079 $ 637,500 621,862 621,321 $ 6,211,375 $ 4,538,470 Less: current portion (356,397) (139,874) $ 5,854,978 $ 4,398,596 Short-term obligations of $478,248 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. 9. Long-term debt (continued) Recent financing activities: (a) Senior unsecured revolving credit facilities As at December 31, 2021, the Company had a $500,000 senior unsecured syndicated revolving credit facility maturing on July 12, 2024. As at December 31, 2021, the Regulated Services Group had a $500,000 senior unsecured syndicated revolving credit facility maturing on February 23, 2023. As at December 31, 2021, the Renewable Energy Group's bank lines consisted of a $500,000 senior unsecured syndicated revolving credit facility maturing on October 6, 2023 and a $350,000 letter of credit facility that was amended to extend the maturity to June 30, 2023. On November 8, 2020, in connection with the acquisition of Ascendant, the Company assumed $62,654 of debt outstanding under its revolving credit facility. The facility was amended to extend the maturity to June 30, 2022. In the second quarter of 2020, the Company obtained three senior unsecured delayed draw non-revolving credit facilities for a total of $1,600,000. On October 5, 2020, these facilities were replaced with two syndicated revolving credit facilities for a total of $1,600,000 that matured on December 31, 2021. (b) Senior unsecured bank credit facilities On December 20, 2021, the Regulated Services Group entered into a $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”) which matures on December 19, 2022. As at December 31, 2021, the Regulated Services Delayed Draw Term Facility had no amounts drawn. Subsequent to year-end on January 3, 2022, the purchase price, plus certain adjustments and acquisition costs, for the acquisition of Liberty NY Water (note 3(a)) of approximately $610,400 was funded through a draw on the Regulated Services Delayed Draw Term Facility. In conjunction with the Kentucky Power Transaction (note 3(b)), the Company obtained a commitment from lenders to provide syndicated unsecured credit facilities in an aggregate amount of up to $2,725,000. This acquisition financing commitment is subject to customary terms and conditions, including certain commitment reductions upon closing of permanent financing. As at March 3, 2022, $1,086,000 remained available under the acquisition financing commitment. On November 8, 2020, in connection with the acquisition of Ascendant, the Company assumed $97,029 of debt outstanding under two term loan facilities that mature on June 29, 2023 and December 26, 2031. On October 13, 2020, in connection with the acquisition of ESSAL, 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. During 2020, the Regulated Services Group fully repaid its C$135,000 term loan upon maturity. (c) U.S dollar senior unsecured notes (Green Equity Units) In June 2021, the Company sold 23,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1,150,000. Each Green Equity Unit was issued in a stated amount of $50, at issuance, consisted of a contract to purchase AQN common shares (the “share purchase contract”) and a 5% undivided beneficial ownership interest in a remarketable senior note of AQN due June 15, 2026, issued in the principal amount of $1,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The interest rate on the notes will be reset following a successful marketing, which would occur in 2024. The present value of the contract adjustment payments was estimated at $222,378 and is recorded against additional paid-in capital (“APIC”) to the extent of the APIC balance and against retained earnings (deficit) for the remainder. The corresponding amount of $222,378 was recorded in other liabilities and is accreted over the three-year period (note 12(a)). 9. Long-term debt (continued) Recent financing activities (continued): (c) U.S dollar senior unsecured notes (Green Equity Units) (continued) Each share purchase contract requires the holder to purchase by no later than June 15, 2024 for a price of $50 in cash, a number of AQN common shares (“common shares”) based on the applicable market value to be determined using the volume-weighted average price of the common shares over a 20-day trading period ending June 14, 2024. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18 per common share. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by $15 per common share. The common share purchase obligation of holders of Green Equity Units will be satisfied by the proceeds raised from a successful remarketing of the notes, unless a holder has elected to settle with separate cash. Holders’ beneficial ownership interest in each note has been pledged to AQN to secure the holders' obligation to purchase common shares under the related share purchase contract. Prior to the issuance of common shares, the share purchase contracts, if dilutive, will be reflected in the Company's diluted earnings per share calculations using the treasury stock method. (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 amounts of $45,000 and $30,000. (f) Senior secured utility bonds On February 15, 2020 and June 1, 2020, the Company repaid, upon their maturities, a $6,500 and a $100,000 secured utility bond, respectively. (g) Canadian dollar senior unsecured notes Subsequent to year-end on February 15, 2022, the Company repaid a C$200,000 senior unsecured note on its maturity. On February 15, 2021, the Renewable Energy Group repaid a C$150,000 unsecured note upon its maturity. Concurrent with the repayments, the Renewable Energy Group unwound and settled the related cross-currency fixed-for-fixed interest rate swap (note 24(b)(iii)). On April 9, 2021, the Renewable Energy Group issued C$400,000 senior unsecured debentures bearing interest at 2.85% with a maturity date of July 15, 2031. The notes were sold at a price of C$999.92 per C$1,000.00 principal amount. Concurrent with the offering, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap to convert the Canadian-dollar-denominated coupon and principal payments from the offering into U.S. dollars (note 24(b)(iii)). 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. (h) Chilean Unidad de Fomento senior unsecured bonds On October 13, 2020, in connection with the acquisition of ESSAL, 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 2021, the Company repaid CL F 116 (2020 - CLF 58) of obligations under the series B bonds. 9. Long-term debt (continued) Recent financing activities (continued): (i) Subordinated unsecured notes Subsequent to year-end on January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Offering”) of $750,000 aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Offering” and, together with the U.S. Offering, the “Offerings”) of C$400,000 (approximately $320,000) aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). Concurrent with the pricing of the Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Offering into U.S. dollars, and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten-year period of the Notes. As of December 31, 2021, the Company had accrued $49,806 in interest expense (2020 - $50,486). Interest expense on the long-term debt, net of capitalized interest, in 2021 was $159,545 (2020 - $175,358). Principal payments due in the next five years and thereafter are as follows: 2022 2023 2024 2025 2026 Thereafter Total $ 834,645 $ 125,520 $ 374,550 $ 44,951 $ 1,172,284 $ 3,671,384 $ 6,223,334
Schedule of Maturities of Long-term Debt	Principal payments due in the next five years and thereafter are as follows: 2022 2023 2024 2025 2026 Thereafter Total $ 834,645 $ 125,520 $ 374,550 $ 44,951 $ 1,172,284 $ 3,671,384 $ 6,223,334

Pension and other post-retire_2

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
Schedule of 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 2021 2020 2021 2020 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 834,913 $ 564,970 $ 306,524 $ 219,217 Projected benefit obligation assumed from business combination — 195,231 — 44,950 Plan Settlements (1,294) — — — Service cost 14,673 15,450 7,307 6,175 Interest cost 20,676 19,281 8,048 7,695 Actuarial loss (gain) (36,597) 76,618 (18,977) 34,507 Contributions from retirees — 171 2,040 2,037 Plan amendments 237 (191) 310 — Medicare Part D — — 373 377 Benefits paid (66,800) (37,020) (12,979) (8,434) Foreign exchange (190) 403 — — Projected benefit obligation, end of year $ 765,618 $ 834,913 $ 292,646 $ 306,524 Change in plan assets Fair value of plan assets, beginning of year 629,157 407,074 176,616 158,873 Plan assets acquired in business combination — 179,600 — — Actual return on plan assets 58,721 52,876 15,200 21,219 Employer contributions 29,058 26,099 11,178 2,583 Plan Settlements (1,294) — — — Contributions from retirees — 171 1,988 1,998 Medicare Part D subsidy receipts — — 372 377 Benefits paid (66,800) (37,020) (12,979) (8,434) Foreign exchange 22 357 — — Fair value of plan assets, end of year $ 648,864 $ 629,157 $ 192,375 $ 176,616 Unfunded status $ (116,754) $ (205,756) $ (100,271) $ (129,908) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 84 488 11,879 10,174 Current liabilities (1,902) (1,989) (699) (2,835) Non-current liabilities (114,936) (204,255) (111,451) (137,247) Net amount recognized $ (116,754) $ (205,756) $ (100,271) $ (129,908) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2021 2020 2021 2020 Accumulated benefit obligation $ 489,043 $ 727,981 $ 274,649 $ 288,594 Fair value of plan assets $ 396,679 $ 578,143 $ 162,592 $ 148,496 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2021 2020 2021 2020 Projected benefit obligation $ 580,841 $ 833,846 $ 274,649 $ 288,594 Fair value of plan assets $ 452,333 $ 627,601 $ 162,592 $ 148,496
Schedule of 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, 2020 $ 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) $ — Additions to AOCI (59,754) 237 (24,126) 24 Amortization in current period (13,130) 1,626 (2,021) 310 Amortization pursuant to plan settlements (210) — — — Reclassification to regulatory accounts 31,670 (752) 14,816 — Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 334
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2021 and 2020 were as follows: Pension benefits OPEB 2021 2020 2021 2020 Discount rate 2.94 % 2.49 % 2.92 % 2.58 % Interest crediting rate (for cash balance plans) 4.00 % 4.15 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 5.875 % 6.00 % Age 65 and after 5.875 % 6.00 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Cost	Weighted average assumptions used to determine net benefit cost for 2021 and 2020 were as follows: Pension benefits OPEB 2021 2020 2021 2020 Discount rate 2.49 % 3.19 % 2.58 % 3.29 % Expected return on assets 6.20 % 6.85 % 4.79 % 5.57 % Rate of compensation increase 3.99 % 3.96 % n/a n/a Health care cost trend rate Before Age 65 5.122 % 6.125 % Age 65 and after 5.122 % 6.125 % Assumed ultimate medical inflation rate 4.05 % 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 2021 2020 2021 2020 Service cost $ 14,673 $ 15,450 $ 7,307 $ 6,175 Non-service costs Interest cost 20,676 19,281 8,048 7,695 Expected return on plan assets (35,972) (26,285) (10,052) (8,748) Amortization of net actuarial loss 13,126 5,430 2,021 509 Amortization of prior service credits (1,626) (1,609) 11 — Settlement Loss Recognized 198 — — — Amortization of regulatory accounts 19,665 16,272 218 1,527 $ 16,067 $ 13,089 $ 246 $ 983 Net benefit cost $ 30,740 $ 28,539 $ 7,553 $ 7,158
Schedule of Target Asset Allocation	The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 48 % 30% -100% Debt securities 43 % 20% - 60% Other 9 % 0% - 20% 100 % The fair values of investments as of December 31, 2021, by asset category, are as follows: Asset class 2021 Percentage Equity securities $ 429,147 51 % Debt securities 350,834 42 % Other 61,259 7 % $ 841,240 100 %
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, 2021 $ 7,745 Contributions into funds 6,233 Unrealized gains 4,257 Distributions (921) Balance, December 31, 2021 $ 17,314
Schedule of Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2022 2023 2024 2025 2026 2027-2031 Pension plan $ 47,802 $ 43,760 $ 44,478 $ 46,318 $ 47,554 $ 238,011 OPEB 10,465 11,064 11,646 12,060 12,543 68,454

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2021
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of Other Assets	Other assets consist of the following: 2021 2020 Restricted cash $ 36,232 $ 28,404 OPEB plan assets (note 10(a)) 11,963 10,662 Long-term deposits 10,735 13,459 Income taxes recoverable 7,649 4,717 Deferred financing costs (a) 30,544 6,774 Other 14,891 9,953 $ 112,014 $ 73,969 Less: current portion (16,153) (7,266) $ 95,861 $ 66,703 (a) Deferred financing costs

Other long-term liabilities (Ta

Other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Other Liabilities Disclosure [Abstract]
Schedule Of Other Long Term Liabilities	Other long-term liabilities consist of the following: 2021 2020 Contract adjustment payments (a) $ 187,580 $ — Asset retirement obligations (b) 142,147 79,968 Advances in aid of construction (c) 82,580 79,864 Environmental remediation obligation (d) 55,224 69,383 Customer deposits (e) 32,633 31,939 Unamortized investment tax credits (f) 17,439 17,893 Deferred credits and contingent consideration (g) 35,982 21,399 Preferred shares, Series C (h) 13,348 13,698 Hook up fees (i) 21,904 17,704 Lease liabilities (note 1(q)) 22,512 14,288 Contingent development support obligations (j) 4,612 12,273 Note payable to related party (k) 25,808 30,493 Other 42,050 23,027 $ 683,819 $ 411,929 Less: current portion (167,908) (72,748) $ 515,911 $ 339,181 (a) Contract adjustment payment In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000 (note 9(c)). Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period. (b) 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: 2021 2020 Opening balance $ 79,968 $ 53,879 Obligation assumed 57,067 20,420 Retirement activities (4,133) (1,724) Accretion 4,381 2,674 Change in cash flow estimates 4,864 4,719 Closing balance $ 142,147 $ 79,968 12. Other long-term liabilities (continued) (b) Asset retirement obligations (continued) As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)). (c) 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 2021, $6,376 (2020 - $1,994) was transferred from advances in aid of construction to contributions in aid of construction. (d) 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(f)), 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 $57,167 (2020 - $64,766), which at discount rates ranging from 1.0% to 3.4% represents the recorded accrual of $55,224 as of December 31, 2021 (2020 - $69,383). Approximately $36,627 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 30 years. Changes in the environmental remediation obligation are as follows: 2021 2020 Opening balance $ 69,383 $ 58,061 Remediation activities (9,865) (5,130) Accretion 1,025 436 Changes in cash flow estimates 2,265 3,828 Revision in assumptions (7,584) 3,402 Obligation assumed from business acquisition — 8,786 Closing balance $ 55,224 $ 69,383 The Regulators 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, 2021, the Company has reflected a regulatory asset of $81,802 (2020 - $87,308) for the MGP and related sites (note 7(e)). (e) Customer deposits Customer deposits result from the Company’s obligation by 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. 12. Other long-term liabilities (continued) (f) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. 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. (g) Deferred credits and contingent consideration In 2021, the Company settled a $5,000 contingent consideration related to the Company's investment in SAWS (note 8(e)) and recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(e)). (h) Preferred shares, Series C AQN has 100 redeemable preferred shares, Series C 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 preferred shares, Series C 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 preferred shares, Series C 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 preferred shares, Series C carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2022 $ 1,102 2023 1,330 2024 1,542 2025 1,559 2026 1,406 Thereafter to 2031 6,320 Redemption amount 4,212 $ 17,471 Less: amounts representing interest (4,123) $ 13,348 Less current portion (1,102) $ 12,246 (i) 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. (j) 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(c)). 12. Other long-term liabilities (continued) (k) 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(c)). Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable of $30,493 to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually. The note was repaid in full during the second quarter of 2021. In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project (note 8(c)). Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

Shareholders' capital (Tables)

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Schedule of Number of Common Shares	Number of common shares 2021 2020 Common shares, beginning of year 597,142,219 524,223,323 Public offering 67,611,465 66,130,063 Dividend reinvestment plan 6,184,686 5,217,071 Exercise of share-based awards (c) 1,020,020 1,565,537 Conversion of convertible debentures 1,886 6,225 Common shares, end of year 671,960,276 597,142,219
Schedule of Shares Issued and Outstanding	The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2021 and 2020: 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
Schedule of Share-based Compensation Expense	For the year ended December 31, 2021, AQN recorded $8,395 (2020 - $24,637) in total share-based compensation expense as follows: 2021 2020 Share options $ 939 $ 1,743 Director deferred share units 821 870 Employee share purchase 592 511 Performance and restricted share units 6,043 21,513 Total share-based compensation $ 8,395 $ 24,637
Schedule of Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2021 2020 Risk-free interest rate 1.1 % 1.2 % Expected volatility 23 % 24 % Expected dividend yield 4.1 % 4.1 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.46 C$ 2.72
Schedule of Stock Option Activity	Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2020 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 Granted 437,006 19.64 7.22 — Exercised (506,926) 13.92 5.95 1,453 Forfeited — — — — Balance, December 31, 2021 2,040,528 C$ 15.45 6.11 C$ 3,145 Exercisable, December 31, 2021 1,398,668 C$ 16.09 5.83 C$ 3,247
Schedule of Performance Stock Units	A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2020 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$ 54,560 Granted, including dividends 805,433 19.94 2.77 12,881 Exercised (865,067) 13.79 — 17,005 Forfeited (217,901) 18.64 — 3,981 Balance, December 31, 2021 2,443,672 C$ 18.07 1.72 C$ 44,646 Exercisable, December 31, 2021 775,674 C$ 16.12 C$ 14,172

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of 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, 2020 $ (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) Other comprehensive income (loss) (25,982) (97,103) 32,247 (90,838) Amounts reclassified from AOCI to the consolidated statement of operations (4,288) 42,772 9,804 48,288 Net current period OCI $ (30,270) $ (54,331) $ 42,051 $ (42,550) OCI attributable to the non-controlling interests (249) — — (249) Net current period OCI attributable to shareholders of AQN $ (30,519) $ (54,331) $ 42,051 $ (42,799) Amount reclassified from AOCI to non-controlling interest (note 3(g)) (6,371) — — (6,371) Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677)

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure Cash Dividends [Abstract]
Schedule of Dividends	Dividends declared were as follows: 2021 2020 Dividend Dividend per share Dividend Dividend per share Common shares $ 423,023 $ 0.6669 $ 344,382 $ 0.6063 Preferred shares, Series A C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Preferred shares, Series D C$ 5,091 C$ 1.2728 C$ 5,091 C$ 1.2728

Non-controlling interests and_2

Non-controlling interests and redeemable non-controlling interests (Tables)	12 Months Ended
	Dec. 31, 2021
Noncontrolling Interest [Abstract]
Schedule of Net Loss Attributable to Non-controlling Interests	Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2021 2020 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 88,417 $ 62,682 Non-controlling interests - redeemable tax equity partnership units 6,902 6,955 Other net earnings attributable to: Non-controlling interests (5,682) (2,351) $ 89,637 $ 67,286 Redeemable non-controlling interest, held by related party (10,435) (12,651) Net effect of non-controlling interests $ 79,202 $ 54,635 Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2021 2020 2021 2020 Opening balance $ 306,316 $ 305,863 $ 20,859 $ 25,913 Net effect from operations 10,435 12,651 (6,902) (6,955) Contributions, net of costs — — — 3,717 Dividends and distributions declared (10,214) (12,198) (968) (951) Repurchase of non-controlling interest — — — (865) Closing balance $ 306,537 $ 306,316 $ 12,989 $ 20,859

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The differences are as follows: 2021 2020 Expected income tax expense at Canadian statutory rate $ 37,691 $ 209,989 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (47,600) (27,082) Adjustments from investments carried at fair value 2,709 (87,058) Non-controlling interests share of income 25,135 18,243 Non-deductible acquisition costs 3,733 3,223 Tax credits (49,415) (40,185) Adjustment relating to prior periods 1,333 (4,228) Deferred income taxes on regulated income recorded as regulatory assets (3,807) (2,811) Amortization and settlement of excess deferred income tax (16,778) (12,392) Other 3,574 6,884 Income tax expense (recovery) $ (43,425) $ 64,583
Schedule of Income (Loss) Before Taxes	For the years ended December 31, 2021 and 2020, earnings before income taxes consist of the following: 2021 2020 Canada (1) $ (60,848) $ 622,776 U.S. 153,719 165,431 Other regions 49,361 4,204 $ 142,232 $ 792,411 (1) Inclusive of fair value gain (loss) on investments carried at fair value (note 8)
Schedule of 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, 2021 Canada $ 4,560 $ (33,993) $ (29,433) United States 1,024 (19,772) (18,748) Other regions $ 1,653 $ 3,103 4,756 $ 7,237 $ (50,662) $ (43,425) Year ended December 31, 2020 Canada $ 4,319 $ 62,061 $ 66,380 United States (1,448) (1,745) (3,193) Other regions $ 2,017 $ (621) 1,396 $ 4,888 $ 59,695 $ 64,583
Schedule of 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, 2021 and 2020 are presented below: 2021 2020 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 761,666 $ 531,353 Pension and OPEB 46,580 66,826 Environmental obligation 15,271 16,145 Regulatory liabilities 166,939 168,054 Other 64,460 65,787 Total deferred income tax assets $ 1,054,916 $ 848,165 Less: valuation allowance (27,471) (29,824) Total deferred tax assets $ 1,027,445 $ 818,341 Deferred tax liabilities: Property, plant and equipment $ 782,829 $ 733,211 Outside basis differentials 412,665 406,429 Regulatory accounts 300,072 212,937 Other 30,471 12,528 Total deferred tax liabilities $ 1,526,037 $ 1,365,105 Net deferred tax liabilities $ (498,592) $ (546,764) Consolidated balance sheets classification: Deferred tax assets $ 31,595 $ 21,880 Deferred tax liabilities (530,187) (568,644) Net deferred tax liabilities $ (498,592) $ (546,764)
Schedule of Non Capital Losses Carry Forwards	As of December 31, 2021, 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 2022—2026 2027+ Total Canada $ — $ 678,881 $ 678,881 US 11,283 1,334,299 1,345,582 Total non-capital loss carryforward $ 11,283 $ 2,013,180 $ 2,024,463 Tax credits $ 4,476 $ 132,509 $ 136,985

Other net losses (Tables)

Other net losses (Tables)	12 Months Ended
	Dec. 31, 2021
Other Income and Expenses [Abstract]
Schedule of Other Net Losses	Other net losses consist of the following: 2021 2020 Acquisition and transition-related costs $ 14,507 $ 14,104 U.S. Tax reform (a) — 11,728 Management succession and executive retirement (b) — 12,639 Other (c) 8,442 22,840 $ 22,949 $ 61,311 (a) U.S. 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 the Empire Electric System 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 In 2020, 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 of expenses, for the year ended December 31, 2020, in relation to these executives’ share-based compensation agreements. (c) Other

Basic and diluted net earning_2

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share, Basic and Diluted [Abstract]
Schedule of 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: 2021 2020 Net earnings attributable to shareholders of AQN $ 264,859 $ 782,463 Preferred shares, Series A dividend 4,942 4,611 Preferred shares, Series D dividend 4,061 3,790 Net earnings attributable to common shareholders of AQN – basic and diluted $ 255,856 $ 774,062 Weighted average number of shares Basic 622,347,677 559,633,275 Effect of dilutive securities 6,600,185 4,740,561 Diluted 628,947,862 564,373,836

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Schedule of Results of Operations and Assets for Segments	Year ended December 31, 2021 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,944,171 $ 267,970 $ — $ 2,212,141 Other revenue 53,441 18,339 1,558 73,338 Fuel, power and water purchased 682,602 36,498 — 719,100 Net revenue 1,315,010 249,811 1,558 1,566,379 Operating expenses 597,850 104,262 16 702,128 Administrative expenses 37,179 28,298 1,249 66,726 Depreciation and amortization 280,452 121,414 1,097 402,963 Loss on foreign exchange — — 4,371 4,371 Gain on sale of renewable assets — (29,063) — (29,063) Operating income 399,529 24,900 (5,175) 419,254 Interest expense (93,411) (71,598) (44,545) (209,554) Income (loss) from long-term investments 18,306 84,046 (128,809) (26,457) Other (24,177) (9,108) (7,726) (41,011) Earnings (loss) before income taxes $ 300,247 $ 28,240 $ (186,255) $ 142,232 Property, plant and equipment $ 7,394,151 $ 3,615,915 $ 32,380 $ 11,042,446 Investments carried at fair value 2,296 1,846,160 — 1,848,456 Equity-method investees 37,492 375,460 20,898 433,850 Total assets 10,512,799 6,123,888 149,149 16,785,836 Capital expenditures $ 998,855 $ 338,637 $ 7,553 $ 1,345,045 (1) Renewable Energy Group revenue includes $57,018 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $19,043 related to alternative revenue programs for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2020 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,386,048 $ 255,954 $ — $ 1,642,002 Other revenue 19,088 14,444 1,457 34,989 Fuel and power purchased 384,363 16,645 — 401,008 Net revenue 1,020,773 253,753 1,457 1,275,983 Operating expenses 442,851 73,957 12 516,820 Administrative expenses 36,749 25,743 630 63,122 Depreciation and amortization 219,089 92,890 2,144 314,123 Gain on foreign exchange — — (2,108) (2,108) Operating income 322,084 61,163 779 384,026 Interest expense (99,161) (52,656) (30,117) (181,934) Income from long-term investments 7,753 93,998 562,987 664,738 Other (40,128) (6,537) (27,754) (74,419) Earnings before income taxes $ 190,548 $ 95,968 $ 505,895 $ 792,411 Property, plant and equipment $ 5,757,532 $ 2,451,706 $ 32,600 $ 8,241,838 Investments carried at fair value — 1,839,212 — 1,839,212 Equity-method investees 74,673 110,414 1,365 186,452 Total assets 8,528,415 4,586,878 108,856 13,224,149 Capital expenditures $ 690,792 $ 80,746 $ 14,492 $ 786,030 (1) Renewable Energy Group revenue includes $28,586 related to net hedging gain from energy derivative contracts 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.
Schedule of Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2021 2020 Revenue United States $ 1,801,876 $ 1,475,087 Canada 157,854 153,502 Other regions 325,749 48,402 $ 2,285,479 $ 1,676,991 Property, plant and equipment United States $ 9,464,716 $ 6,666,015 Canada 882,454 884,195 Other regions 695,276 691,628 $ 11,042,446 $ 8,241,838 Intangible assets United States $ 23,575 $ 24,825 Canada 21,780 23,123 Other regions 59,761 66,965 $ 105,116 $ 114,913

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of 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) $ 62,759 $ 33,521 $ 33,585 $ 33,821 $ 12,274 $ 155,106 $ 331,066 Gas supply and service agreements (ii) 101,406 75,482 49,328 44,286 26,887 176,535 473,924 Service agreements 65,230 59,641 58,356 54,953 50,181 347,546 635,907 Capital projects 85,130 — — — — — 85,130 Land easements 12,913 13,048 13,212 13,398 13,561 471,755 537,887 Total $ 327,438 $ 181,692 $ 154,481 $ 146,458 $ 102,903 $ 1,150,942 $ 2,063,914 (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, 2021. 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, 2021
Disclosure Changes In Non Cash Operating Items [Abstract]
Schedule of Changes in Non-Cash Operating Items	The changes in non-cash operating items consist of the following: 2021 2020 Accounts receivable $ (56,751) $ (52,778) Fuel and natural gas in storage (43,642) 237 Supplies and consumables inventory 445 1,058 Income taxes recoverable (3,025) (3,440) Prepaid expenses (1,189) (15,411) Accounts payable (33,399) 40,885 Accrued liabilities 31,845 (29,150) Current income tax liability 4,363 3,818 Asset retirements and environmental obligations (1,185) 3,562 Net regulatory assets and liabilities (419,484) (26,260) $ (522,022) $ (77,479)

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Financial Instruments	Fair value of financial instruments December 31, 2021 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,848,456 $ 1,848,456 $ 1,753,210 $ — $ 95,246 Development loans and other receivables 32,261 33,286 — 33,286 — Derivative instruments: Energy contracts designated as a cash flow hedge 15,362 15,362 — — 15,362 Interest rate swap designated as a hedge 1,581 1,581 — 1,581 — Commodity contracts for regulated operations 1,721 1,721 — 1,721 — Cross currency swap designated as a net investment hedge 1,958 1,958 — 1,958 — Total derivative instruments 20,622 20,622 — 5,260 15,362 Total financial assets $ 1,901,339 $ 1,902,364 $ 1,753,210 $ 38,546 $ 110,608 Long-term debt $ 6,211,375 $ 6,543,933 $ 2,418,580 $ 4,125,352 $ — Notes payable to related party 25,808 25,808 — 25,808 — Convertible debentures 277 519 519 — — Preferred shares, Series C 13,348 14,580 — 14,580 — Derivative instruments: Energy contracts designated as a cash flow hedge 60,462 60,462 — — 60,462 Energy contracts not designated as a cash flow hedge 1,169 1,169 — — 1,169 Cross-currency swap designated as a net investment hedge 50,258 50,258 — 50,258 — Interest rate swaps designated as a hedge 7,008 7,008 — 7,008 — Commodity contracts for regulated operations 1,348 1,348 — 1,348 — Total derivative instruments 120,245 120,245 — 58,614 61,631 Total financial liabilities $ 6,371,053 $ 6,705,085 $ 2,419,099 $ 4,224,354 $ 61,631 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2020 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,839,212 $ 1,839,212 $ 1,708,683 $ 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 a cash flow hedge 388 388 — — 388 Commodity contracts for regulatory operations 194 194 — 194 — Total derivative instruments 52,107 52,107 — 194 51,913 Total financial assets $ 1,915,123 $ 1,922,407 $ 1,708,683 $ 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 84,218 84,218 — 84,218 — Forward Interest rate swaps designated as a hedge 19,649 19,649 — 19,649 — 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
Summary of Commodity Volumes Associated with Derivative Contracts	The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts: 2021 Financial contracts: Swaps 3,239,873 Options 165,671 3,405,544
Schedule of Long-Term Energy Derivative Contracts	The Company reduces the price risk on the expected future sale of power generation at the Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. Notional quantity Expiry Receive average Pay floating price 4,585,008 September 2030 $24.54 Illinois Hub 527,931 December 2028 $32.11 PJM Western HUB 2,465,763 December 2027 $23.67 NI HUB 1,998,095 December 2027 $36.46 ERCORT North HUB
Schedule of 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: 2021 2020 Effective portion of cash flow hedge $ (97,103) $ (13,418) Amortization of cash flow hedge (2,132) (1,248) Amounts reclassified from AOCI 44,904 (9,616) OCI attributable to shareholders of AQN $ (54,331) $ (24,282)
Schedule of 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: 2021 2020 Change in unrealized loss on derivative financial instruments: Energy derivative contracts $ (5,353) $ (901) Total change in unrealized loss on derivative financial instruments $ (5,353) $ (901) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ (108) $ (1,145) Currency forward contract 2,329 2,363 Total realized loss on derivative financial instruments $ 2,221 $ 1,218 Loss on derivative financial instruments not accounted for as hedges (3,132) 317 Amortization of AOCI gains frozen as a result of hedge dedesignation 3,712 3,009 $ 580 $ 3,326 Amounts recognized in the consolidated statements of operations consist of: Gain (loss) on derivative financial instruments $ (1,749) $ 964 Gain on foreign exchange 2,329 2,362 $ 580 $ 3,326
Schedule of Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2021, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2021 Cash and cash equivalents and restricted cash $ 161,389 Accounts receivable 422,752 Allowance for doubtful accounts (19,327) Notes receivable 31,468 $ 596,282
Schedule of 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 $ 834,645 $ 500,070 $ 1,217,235 $ 3,671,384 $ 6,223,334 Interest on long-term debt 196,824 348,479 297,461 1,004,448 1,847,212 Purchase obligations 614,024 — — — 614,024 Environmental obligation 12,751 23,876 1,066 19,474 57,167 Advances in aid of construction 1,706 — — 80,874 82,580 Derivative financial instruments: Cross-currency swap 27,936 23,115 2,604 1,888 55,543 Interest rate swaps 2,145 2,141 1,335 1,394 7,015 Energy derivative and commodity contracts 8,489 20,148 16,517 17,826 62,980 Contract adjustment payments on Green Equity Units 75,555 112,025 — — 187,580 Other obligations 66,916 4,473 4,427 260,111 335,927 Total obligations $ 1,840,991 $ 1,034,327 $ 1,540,645 $ 5,057,399 $ 9,473,362

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements - Narrative (Details)	12 Months Ended
	Dec. 31, 2021businessUnit
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, 2021USD ($)facility	Dec. 31, 2020USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities | facility	3
Number of power generating facilities | facility	2
Generating assets of Long Sault	$ 16,785,836	$ 13,224,149
Long-term debt of Long Sault	9,084,231	7,234,784
Non-regulated energy sales	2,285,479	1,676,991
Interest expense on long-term debt and others	209,554	181,934
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	59,877	59,521
Long-term debt of Long Sault	18,344	20,328
Operating expenses and amortization	5,410	5,400
Interest expense on long-term debt and others	$ 2,055	2,119
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	$ 267,970	255,955
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	$ 16,772	$ 17,116

Significant accounting polici_5

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Generation
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	33 years	33 years
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
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	40 years	40 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	1 year	1 year
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	40 years
Equipment
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	11 years	11 years
Equipment | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Equipment | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years	50 years
Equipment | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	11 years	11 years

Business acquisitions and dev_3

Business acquisitions and development projects (Details) $ in Thousands	Jan. 01, 2022USD ($)	Oct. 26, 2021USD ($)MWac	Nov. 09, 2020USD ($)	Oct. 17, 2020USD ($)	Oct. 13, 2020USD ($)	Apr. 30, 2021USD ($)MWac	Jan. 31, 2021USD ($)	Jan. 31, 2021USD ($)	Jan. 31, 2021USD ($)MWac	Jan. 31, 2021USD ($)windProject	Jan. 31, 2021USD ($)businessUnit	Dec. 31, 2021USD ($)	Dec. 31, 2019USD ($)MWacwindProject	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Net assets acquired, net of cash and cash equivalents
Goodwill (note 6)												$ 1,201,244	$ 1,031,696		$ 1,208,390
Number of wind projects | windProject													3
Business combination, consideration transferred, liabilities incurred							$ 87,035
New York Water Company, Inc | Subsequent Event
Business Acquisition [Line Items]
Total purchase price	$ 608,000
Kentucky Power Company
Net assets acquired, net of cash and cash equivalents
Equity interest (percent)		50.00%
Wind power capacity (megawatt AC) | MWac		780
Business combination, termination fee		$ 65,000
Kentucky Power Transaction
Business Acquisition [Line Items]
Total purchase price		2,846,000
AEP Kentucky Transmission Company, Inc
Business Acquisition [Line Items]
Total purchase price		$ 1,221,000
Mid-West Wind Facilities
Net assets acquired, net of cash and cash equivalents
Working capital												(28,630)
Property, plant and equipment												1,141,884
Long-term debt												(789,804)
Asset retirement obligation												(27,053)
Deferred tax liability												(4,566)
Other liabilities												(104,129)
Non-controlling interest (tax equity investors)												(29,141)
Total net assets acquired												158,561
Cash and cash equivalents												15,860
Net assets acquired, net of cash and cash equivalents												142,701
Wind power capacity (megawatt AC) | MWac													600
Mid-West Wind Facilities | Empire Electric System
Business Acquisition [Line Items]
Total purchase price												97,760
Net assets acquired, net of cash and cash equivalents
Tax equity funding												530,880
Debt repaid upon maturity												$ 789,923
Mid-West Wind Facilities | North Fork Ridge Wind Project
Net assets acquired, net of cash and cash equivalents
Tax equity funding															$ 29,446
Altavista Solar Facility
Business Acquisition [Line Items]
Total purchase price						$ 6,735
Net assets acquired, net of cash and cash equivalents
Working capital						870
Property, plant and equipment						138,343
Long-term debt						(122,024)
Asset retirement obligation						(3,332)
Deferred tax liability						(421)
Total net assets acquired						13,436
Cash and cash equivalents						33
Net assets acquired, net of cash and cash equivalents						$ 13,403
Equity interest (percent)						50.00%
Solar power capacity (megawatt ac) | MWac						80
Ownership interest acquired (percent)						50.00%
Maverick Creek and Sugar Creek Wind Facilities
Business Acquisition [Line Items]
Total purchase price							18,641
Net assets acquired, net of cash and cash equivalents
Working capital							(15,557)	$ (15,557)	$ (15,557)	$ (15,557)	$ (15,557)
Property, plant and equipment							1,062,613	1,062,613	1,062,613	1,062,613	1,062,613
Long-term debt							(855,409)	(855,409)	(855,409)	(855,409)	(855,409)
Asset retirement obligation							(23,402)	(23,402)	(23,402)	(23,402)	(23,402)
Deferred tax liability							(337)	(337)	(337)	(337)	(337)
Derivative instruments							7,575	7,575	7,575	7,575	7,575
Total net assets acquired							175,483	175,483	175,483	175,483	175,483
Cash and cash equivalents							4,241	4,241	4,241	4,241	4,241
Net assets acquired, net of cash and cash equivalents							$ 171,242	$ 171,242	$ 171,242	$ 171,242	$ 171,242
Equity interest (percent)							50.00%	50.00%	50.00%	50.00%	50.00%
Number of wind projects										2	2
Ownership interest acquired (percent)							50.00%	50.00%	50.00%	50.00%	50.00%
Investments in joint venture														$ 43,797
Maverick Creek Wind Facility
Net assets acquired, net of cash and cash equivalents
Wind power capacity (megawatt AC) | MWac									492
Tax equity funding							$ 380,829	$ 380,829	$ 380,829	$ 380,829	$ 380,829
Debt repaid upon maturity							570,579
Sugar Creek Wind Facility
Net assets acquired, net of cash and cash equivalents
Wind power capacity (megawatt AC) | MWac									202
Tax equity funding							147,914	$ 147,914	$ 147,914	$ 147,914	$ 147,914
Debt repaid upon maturity							$ 284,829
Ascendant
Business Acquisition [Line Items]
Total purchase price			$ 364,468
Net assets acquired, net of cash and cash equivalents
Working capital			71,948
Property, plant and equipment			417,947
Intangible assets			27,315
Goodwill (note 6)			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			42,920
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
Net assets acquired, net of cash and cash equivalents
Working capital				10,575
Property, plant and equipment				238,504
Intangible assets				37,095
Goodwill (note 6)				75,917
Other assets				1,394
Long-term debt				(144,335)
Deferred tax liability				(29,477)
Pension and other post-employment benefits				(2,292)
Other liabilities				(14,881)
Non-controlling interest (tax equity investors)				(84,525)
Total net assets acquired				87,975
Cash and cash equivalents				6,983
Net assets acquired, net of cash and cash equivalents				$ 80,992
Ownership interest acquired (percent)				43.00%	51.00%
Weighted average useful life of assets				40 years
Increase in goodwill				$ 5,535
Cumulative ownership interest acquired (percent)				94.00%
ESSAL | Third Party
Net assets acquired, net of cash and cash equivalents
Non-controlling interest (percent)							0.30%	0.30%	0.30%	0.30%	0.30%
Ownership interest sold (percent)								0.32%
Ownership interest sold							$ 51,750
Ownership interest after transaction (percent)							0.64%	0.64%	0.64%	0.64%	0.64%

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 19,327	$ 19,628
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 102,693	$ 91,538

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Cost	$ 12,630,666	$ 9,588,813
Accumulated depreciation	1,588,220	1,346,975
Net book value	11,042,446	8,241,838
Land
Property, Plant and Equipment [Line Items]
Cost	114,821	114,847
Accumulated depreciation	0	0
Net book value	114,821	114,847
Equipment
Property, Plant and Equipment [Line Items]
Cost	101,971	99,722
Accumulated depreciation	56,464	51,979
Net book value	45,507	47,743
Generation
Property, Plant and Equipment [Line Items]
Cost	4,187,197	2,918,692
Accumulated depreciation	751,219	633,210
Net book value	3,435,978	2,285,482
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	148,302	136,424
Accumulated depreciation	0	0
Net book value	148,302	136,424
Distribution and transmission
Property, Plant and Equipment [Line Items]
Cost	7,468,236	5,766,885
Accumulated depreciation	780,537	661,786
Net book value	6,687,699	5,105,099
Distribution and transmission | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	610,139	552,243
Accumulated depreciation	0	0
Net book value	$ 610,139	$ 552,243

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 557,954	$ 531,191
Accumulated depreciation related to commonly owned facilities	59,857	50,919
Expenditures	143,255	61,827
Contribution received	6,376	4,214
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	114,868	111,806
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	46,649	43,444
Depreciation expense	1,716	1,708
Distribution and transmission
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	2,018,039	885,087
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	72,484	28,779
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	$ 1,665	$ 1,321

Property, plant and equipment_3

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Schedule of Capitalization [Line Items]
Total	$ 12,246	$ 15,053
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	3,313	9,359
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	3,208	3,475
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	$ 5,725	$ 2,219

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Cost	$ 162,292	$ 168,522
Accumulated amortization	57,176	53,609
Net book value	105,116	114,913
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	58,112	57,943
Accumulated amortization	43,118	41,184
Net book value	14,994	16,759
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	78,140	83,342
Accumulated amortization	12,337	10,967
Net book value	65,803	72,375
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	15,072	15,028
Accumulated amortization	1,721	1,458
Net book value	13,351	13,570
Other
Finite-Lived Intangible Assets [Line Items]
Cost	10,968	12,209
Accumulated amortization	0	0
Net book value	$ 10,968	$ 12,209

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Details) $ in Thousands	Dec. 31, 2021USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 2	$ 3,125

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 1,208,390	$ 1,031,696
Business acquisitions (note 3)	5,535	167,209
Foreign exchange	(12,681)	9,485
Goodwill end of the period	$ 1,201,244	$ 1,208,390

Regulatory Matters - Regulatory

Regulatory Matters - Regulatory Proceedings (Details) - USD ($) $ in Thousands	Aug. 01, 2021	Jun. 01, 2021	Dec. 31, 2021
BELCO
Regulatory Liabilities [Line Items]
Weighted average cost of capital (percent)		7.50%
Annual revenue increase		$ 211,432
Deferred revenue		$ 13,426
Deferred revenue, period of collection		5 years
EnergyNorth Gas System
Regulatory Liabilities [Line Items]
Annual revenue increase	$ 6,300
Requested increase, 2020	4,000
Requested increase, 2021	$ 3,200
Various
Regulatory Liabilities [Line Items]
Annual revenue increase			$ 800

Regulatory matters - Regulato_2

Regulatory matters - Regulatory Assets and Liabilities (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Mar. 01, 2020MWac
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 1,167,625	$ 846,519
Less: current regulatory assets	(158,212)	(64,090)
Non-current regulatory assets	1,009,413	782,429
Total regulatory liabilities	576,189	601,518
Less: current regulatory liabilities	(65,809)	(38,483)
Non-current regulatory liabilities	$ 510,380	563,035
Capital expenditure shortfall refundable to customers (percent)	80.00%
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 295,720	322,317
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	191,981	200,739
Pension and Postremployment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	34,468	26,311
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18,229	20,136
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14,829	10,440
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3,316	5,214
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17,646	16,361
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory assets	339,900	18,094
Retired generating plant
Regulatory Liabilities [Line Items]
Total regulatory assets	185,073	194,192
Coal generation capacity (MW) | MWac			200
Pension and Postremployment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 134,141	178,403
Future service years of employees	10 years
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 117,309	99,853
Retroactive rate adjustment collection period	24 months
Regulatory asset, amortization period	26 years
Environmental remediation
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 81,802	87,308
Environmental remediation, rate recovery period	7 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 79,472	77,730
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 62,599	34,398
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
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 35,789	22,736
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets	34,204	35,688
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets	26,810	26,546
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets	26,015	26,400
Rate review costs
Regulatory Liabilities [Line Items]
Total regulatory assets	9,167	8,054
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets	9,134	14,405
Other
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 26,210	$ 22,712

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,848,456	$ 1,839,212
Equity-method investees	433,850	186,452
San Antonio Water System and other	30,508	5,219
Long-term investments	495,826	214,583
Notes Receivable | Development loans
Schedule of Equity Method Investments [Line Items]
Development loans receivable from equity-method investees	31,468	22,912
Atlantica
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	1,750,914	1,706,900
Atlantica share subscription agreement
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	0
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	95,246	110,514
Other
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 2,296	$ 1,783

Long-term investments - Income

Long-term investments - Income from Long-term Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	$ (122,419)	$ 559,701
Dividend and interest income from investments carried at fair value	101,523	91,448
Equity method income (loss)	(26,337)	209
Interest and other income	20,776	13,380
Income (loss) from other long-term investments	(5,561)	13,589
Income from long-term investments	(26,457)	664,738
Atlantica
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	(107,030)	519,297
Dividend and interest income from investments carried at fair value	83,971	74,604
Atlantica share subscription agreement
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	0	20,015
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	15,915	(20,272)
Dividend and interest income from investments carried at fair value	17,222	14,731
Other
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	526	117
Dividend and interest income from investments carried at fair value	$ 330	$ 2,113

Long-term investments - Additio

Long-term investments - Additional Information (Detail) $ in Thousands, $ in Thousands	Aug. 12, 2021USD ($)	Dec. 09, 2020$ / instrument	May 31, 2020shares	Sep. 30, 2021USD ($)	Mar. 31, 2021USD ($)windProject	Dec. 31, 2021USD ($)$ / MWh	Dec. 31, 2020USD ($)	Nov. 30, 2021USD ($)	Jan. 07, 2021USD ($)shares	May 31, 2019USD ($)	May 31, 2019CAD ($)	May 24, 2019USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments						$ 433,850	$ 186,452
Non-controlling interests						1,523,082	458,612
Fair value loss						(122,419)	559,701
Investments carried at fair value						1,848,456	1,839,212
Noncontrolling interest in partnerships and joint ventures						433,850	186,452
Fair value of support provided						4,612	12,273
Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Net assets						86,202	174,685
Development loans receivable from equity-method investees						$ 31,468	$ 21,804
Abengoa
Schedule of Equity Method Investments [Line Items]
Option to purchase interest in joint venture				$ 1,500
Atlantica
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						44.00%	44.00%
Equity method investments						$ 1,167,444			$ 132,688
Equity method investment, shares acquired (shares) | shares									4,020,860
Fair value loss						(107,030)	$ 519,297
Investments carried at fair value						$ 1,750,914	1,706,900
Atlantica | Subscription Share Purchase Agreement
Schedule of Equity Method Investments [Line Items]
Subscription purchase agreement, share price (in USD) | $ / instrument		33
Atlantica | Maximum
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						48.50%
Atlantica Yield Energy Solutions Canada Inc. (b)
Schedule of Equity Method Investments [Line Items]
Non-controlling interests						$ 41,782	59,125			$ 96,752
Option to exchange shares | shares			3,500,000
Fair value loss						15,915	(20,272)
Investments carried at fair value						$ 95,246	$ 110,514
Atlantica Yield Energy Solutions Canada Inc. (b) | AIP
Schedule of Equity Method Investments [Line Items]
Non-controlling interests										$ 96,752	$ 130,103	$ 96,752
Red Lily I
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						75.00%
Wind facility capacity (megawatt AC) | $ / MWh						26.4
Val Eo
Schedule of Equity Method Investments [Line Items]
Equity economic interest						50.00%
Wind facility capacity (megawatt AC) | $ / MWh						24
Wind And Solar Power Electric Development
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						50.00%
North Fork Ridge Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)						50.00%
New Market Solar
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						50.00%
Net assets contributed into joint venture entities						$ 220,677
Contract asset						17,018
Equity method investment, gain on transfer						26,182
Loans related to parties						$ 10,779
Texas Wind Farms
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)					51.00%
Equity method investments	$ 110,609				$ 234,274
Equity method investment acquired (percent)	51.00%				51.00%
Number of wind development projects acquired | windProject					3
Number of wind development projects | windProject					4
San Antonio Water System, Joint Venture
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)						20.00%
Liberty Development JV Inc
Schedule of Equity Method Investments [Line Items]
Equity method investments								$ 19,688
Non-controlling interests								39,376
AAGES Spain
Schedule of Equity Method Investments [Line Items]
Acquired assets				2,662
Working capital				1,507
AAGES Spain | Abengoa
Schedule of Equity Method Investments [Line Items]
Loans related to parties				$ 3,089
AY Holdco
Schedule of Equity Method Investments [Line Items]
Equity method investments								$ 39,376

Long-term investments - Investm

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Total assets	$ 16,785,836	$ 13,224,149
Total liabilities	9,084,231	7,234,784
AQN's investment carrying amount for the entities	433,850	186,452
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Total assets	2,126,934	3,201,967
Total liabilities	945,971	2,913,188
Net assets	1,180,963	288,779
Investments in Significant Partnerships and Joint Ventures | APUC
Schedule of Equity Method Investments [Line Items]
AQN's ownership interest in the entities	327,555	141,666
Difference between investment carrying amount and underlying equity in net assets	106,295	44,786
AQN's investment carrying amount for the entities	$ 433,850	$ 186,452

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, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Net assets	$ 86,202	$ 174,685
Development loans receivable	31,468	21,804
Performance guarantees and other commitments on behalf of VIEs	409,232	965,291
APUC's maximum exposure in regard to VIE's	$ 526,902	$ 1,161,780

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail)	Dec. 31, 2021USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021CLP ($)	Jun. 30, 2021	Apr. 09, 2021CAD ($)	Feb. 15, 2021CAD ($)	Dec. 31, 2020USD ($)	Sep. 23, 2020USD ($)	May 23, 2019USD ($)
Debt Instrument [Line Items]
Long-term debt	$ 6,211,375,000						$ 4,538,470,000
Less: current portion	(356,397,000)						(139,874,000)
Long-term debt, excluding current portion	$ 5,854,978,000						4,398,596,000
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	$ 1,689,792,000						1,688,390,000
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	$ 155,571,000						157,212,000
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	$ 556,219,000
Long-term debt	$ 558,177,000						561,494,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Notes (Green Equity Units)
Debt Instrument [Line Items]
Weighted average coupon	1.18%	1.18%	1.18%	1.18%
Par value	$ 1,150,000,000
Long-term debt	$ 1,140,801,000						0
Senior Unsecured Notes | Canadian dollar Senior unsecured notes
Debt Instrument [Line Items]
Weighted average coupon	3.81%	3.81%	3.81%
Par value		$ 1,400,669,000			$ 400,000,000	$ 150,000,000
Long-term debt	$ 1,099,403,000						899,710,000
Senior Unsecured Notes | Canadian dollar Senior secured project notes
Debt Instrument [Line Items]
Weighted average coupon	10.21%	10.21%	10.21%
Par value		$ 23,256,000
Long-term debt	$ 18,344,000						20,315,000
Senior Unsecured Notes | Chilean Unidad de Fomento borrowings Senior unsecured utility bonds
Debt Instrument [Line Items]
Weighted average coupon	4.18%	4.18%	4.18%
Par value			$ 1,753,000
Long-term debt	$ 77,963,000						92,183,000
Senior Unsecured Notes | Senior Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 5,589,513,000						3,917,149,000
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
Long-term debt	621,862,000						621,321,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured revolving credit facilities and delayed draw term facility
Debt Instrument [Line Items]
Long-term debt	368,806,000						223,507,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured bank credit facilities
Debt Instrument [Line Items]
Long-term debt	141,956,000						152,338,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial paper
Debt Instrument [Line Items]
Long-term debt	$ 338,700,000						$ 122,000,000

Long-term debt - Narrative (Det

Long-term debt - Narrative (Detail)

Jan. 18, 2022USD ($)

Oct. 13, 2020USD ($)unsecuredBondcreditFacility

Jul. 31, 2020USD ($)

Jun. 01, 2020USD ($)

Apr. 30, 2020USD ($)

Feb. 15, 2020USD ($)

Dec. 31, 2021CLP ($)

Jun. 30, 2021USD ($)tradingDay$ / sharesshares

Dec. 31, 2020CLP ($)

Dec. 31, 2021USD ($)$ / shares

Dec. 31, 2020USD ($)utilityNote

Dec. 31, 2020CAD ($)utilityNote

Feb. 15, 2022CAD ($)

Dec. 31, 2021CAD ($)

Dec. 31, 2021CLP ($)

Dec. 20, 2021USD ($)

Oct. 26, 2021USD ($)

Apr. 09, 2021CAD ($)

Apr. 09, 2021$ / shares

Feb. 15, 2021CAD ($)

Nov. 08, 2020USD ($)termLoanFacility

Oct. 13, 2020CLP ($)creditFacility

Oct. 05, 2020creditFacility

Sep. 23, 2020USD ($)

Jun. 30, 2020USD ($)creditFacility

Feb. 24, 2020USD ($)

Feb. 14, 2020CAD ($)

May 23, 2019USD ($)

Debt Instrument [Line Items]

Short-term debt

$ 478,248,000

Line of credit facility, remaining borrowing capacity

$ 1,086,000

Green Equity Units issued (in shares) | shares

23,000,000

Green Equity Units, stated value (in USD per share) | $ / shares

$ 50

Green Equity Units, beneficial ownership interest in remarketable senior note (percent)

5.00%

5.00%

5.00%

Green Equity Units, annual distributions (percent)

7.75%

Green Equity Units, share purchase contract, interest rate (percent)

6.57%

Contract Adjustment Payments, Excluding Interest

$ 222,378,000

$ 222,378,000

Contract adjustment payments, accretion period

3 years

Number of trading days included in average price of common shares | tradingDay

20

Debt instrument, convertible debt, conversion ration to common shares

2.7778

Green Equity Unit, threshold appreciation price per share (in USD per share) | $ / shares

$ 18

Green Equity Units, maximum settlement rate under the purchase contracts

3.3333

Green Equity Units, price per share included in maximum settlement rate calculation (in USD per share) | $ / shares

$ 15

Share price (in dollars per share) | $ / shares

$ 999.92

Interest on long-term debt

49,806,000

$ 50,486,000

Interest expense during the year on long-term liabilities

159,545,000

$ 175,358,000

Subsequent Event

Debt Instrument [Line Items]

Par value

$ 320,000

Debt instrument, effective interest rate

4.95%

Debt instrument, term

10 years

New York Water Company, Inc

Debt Instrument [Line Items]

Business acquisitions, purchase price allocation, subsequent years, remaining adjustments

$ 610,400,000

Kentucky Power Company

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 2,725,000,000

Senior unsecured bank credit facilities | Line of Credit

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 135,000,000

Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 1,000

Junior Subordinated Notes Series 2022-B Due January 18, 2082 | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 750,000

Interest rate (percent)

4.75%

Junior Subordinated Notes Series 2022-A Due January 18, 2082 | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 400,000

Interest rate (percent)

5.25%

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 | Canadian dollar Senior unsecured notes

Debt Instrument [Line Items]

Par value

$ 1,400,669,000

400,000,000

$ 150,000,000

Weighted average coupon

3.81%

3.81%

3.81%

Senior Unsecured Debt | Canadian dollar Senior unsecured notes | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 200,000

Senior Unsecured Debt | Senior Unsecured Syndicated Revolving Credit Facility Maturing On July 12, 2024 | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

Senior Unsecured Debt | Senior Unsecured Syndicated Revolving Credit Facility Maturing On February 23, 2023 | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

500,000,000

Senior Unsecured Debt | Senior Unsecured Syndicated Revolving Credit Facility Maturing On October 6, 2023 | 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

Debt Instrument [Line Items]

Par value

$ 1,100,000,000

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 | Ascendant | Revolving Credit Facility

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 62,654,000

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 bank credit facilities | Ascendant | Revolving Credit Facility

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 97,029,000

Number of new credit facilities | termLoanFacility

2

Senior Unsecured Debt | Senior unsecured bank credit facilities | ESSAL | Revolving Credit Facility

Debt Instrument [Line Items]

Debt assumed in acquisition

$ 55,786,000

$ 44,408,558,000

Number of new credit facilities | creditFacility

7

7

Senior Unsecured Debt | U.S. dollar Senior unsecured notes

Debt Instrument [Line Items]

Par value

$ 1,700,000,000

$ 600,000,000

Weighted average coupon

3.46%

3.46%

3.46%

Interest rate (percent)

2.05%

Senior Unsecured Debt | Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 400,000,000

$ 200,000,000

Interest rate (percent)

2.85%

3.315%

Senior Unsecured Debt | Chilean Senior Unsecured Utility Notes

Debt Instrument [Line Items]

Par value

$ 1,753,000

Weighted average coupon

4.18%

4.18%

4.18%

Number of debt instruments repaid | unsecuredBond

2

Senior Unsecured Debt | Chilean Senior Unsecured Utility Notes | 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

$ 116,000

$ 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

$ 350,000,000

Weighted average coupon

6.50%

6.50%

6.50%

Senior Unsecured Debt | U.S. Dollar Senior Unsecured Notes (Green Equity Units)

Debt Instrument [Line Items]

Par value

$ 1,150,000,000

Proceeds from Green Equity Units

$ 1,150,000,000

Weighted average coupon

1.18%

1.18%

1.18%

1.18%

Senior Secured Utility Bonds

Debt Instrument [Line Items]

Number of debt instruments repaid | utilityNote

2

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, 2021USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2022	$ 834,645
2023	125,520
2024	374,550
2025	44,951
2026	1,172,284
Thereafter	3,671,384
Total	$ 6,223,334

Pension and other post-retire_3

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	$ 10,836	$ 9,672
Accumulated benefit obligation for pension plan	1,008,754	1,080,685
Pension benefits
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	648,864	629,157	$ 407,074
Expected employer contributions for next year	21,305
OPEB
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	192,375	$ 176,616	$ 158,873
Expected employer contributions for next year	$ 12,208

Pension and other post-retire_4

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, 2021	Dec. 31, 2020
Change in plan assets
Non-current assets (note 11)	$ 11,963	$ 10,662
Pension benefits
Change in projected benefit obligation
Projected benefit obligation, beginning of year	834,913	564,970
Projected benefit obligation assumed from business combination	0	195,231
Plan Settlements	(1,294)	0
Service cost	14,673	15,450
Interest cost	20,676	19,281
Actuarial loss (gain)	(36,597)	76,618
Contributions from retirees	0	171
Plan amendments	237	(191)
Medicare Part D	0	0
Benefits paid	(66,800)	(37,020)
Foreign exchange	(190)	403
Projected benefit obligation, end of year	765,618	834,913
Change in plan assets
Fair value of plan assets, beginning of year	629,157	407,074
Plan assets acquired in business combination	0	179,600
Actual return on plan assets	58,721	52,876
Employer contributions	29,058	26,099
Plan Settlements	(1,294)	0
Contributions from retirees	0	171
Medicare Part D subsidy receipts	0	0
Benefits paid	(66,800)	(37,020)
Foreign exchange	22	357
Fair value of plan assets, end of year	648,864	629,157
Unfunded status	(116,754)	(205,756)
Non-current assets (note 11)	84	488
Current liabilities	(1,902)	(1,989)
Non-current liabilities	(114,936)	(204,255)
Net amount recognized	(116,754)	(205,756)
OPEB
Change in projected benefit obligation
Projected benefit obligation, beginning of year	306,524	219,217
Projected benefit obligation assumed from business combination	0	44,950
Plan Settlements	0	0
Service cost	7,307	6,175
Interest cost	8,048	7,695
Actuarial loss (gain)	(18,977)	34,507
Contributions from retirees	2,040	2,037
Plan amendments	310	0
Medicare Part D	373	377
Benefits paid	(12,979)	(8,434)
Foreign exchange	0	0
Projected benefit obligation, end of year	292,646	306,524
Change in plan assets
Fair value of plan assets, beginning of year	176,616	158,873
Plan assets acquired in business combination	0	0
Actual return on plan assets	15,200	21,219
Employer contributions	11,178	2,583
Plan Settlements	0	0
Contributions from retirees	1,988	1,998
Medicare Part D subsidy receipts	372	377
Benefits paid	(12,979)	(8,434)
Foreign exchange	0	0
Fair value of plan assets, end of year	192,375	176,616
Unfunded status	(100,271)	(129,908)
Non-current assets (note 11)	11,879	10,174
Current liabilities	(699)	(2,835)
Non-current liabilities	(111,451)	(137,247)
Net amount recognized	$ (100,271)	$ (129,908)

Pension and other post-retire_5

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 489,043	$ 727,981
Fair value of plan assets	396,679	578,143
Projected benefit obligation	580,841	833,846
Fair value of plan assets	452,333	627,601
OPEB
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	274,649	288,594
Fair value of plan assets	162,592	148,496
Projected benefit obligation	274,649	288,594
Fair value of plan assets	$ 162,592	$ 148,496

Pension and other post-retire_6

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension benefits
Actuarial losses (gains)
Balance, January 1	$ 57,231	$ 38,510
Additions to AOCI	(59,754)	50,026
Amortization in current period	(13,130)	(5,430)
Amortization pursuant to plan settlements	(210)
Reclassification to regulatory accounts	31,670	(25,875)
Ending balance, December 31	15,807	57,231
Past service gains
Beginning balance, January 1	(5,306)	(6,180)
Additions to AOCI	237	(191)
Amortization in current period	1,626	1,609
Amortization pursuant to plan settlements	0
Reclassification to regulatory accounts	(752)	(544)
Ending balance, December 31	(4,195)	(5,306)
OPEB
Actuarial losses (gains)
Balance, January 1	(4,299)	(9,146)
Additions to AOCI	(24,126)	22,036
Amortization in current period	(2,021)	(509)
Amortization pursuant to plan settlements	0
Reclassification to regulatory accounts	14,816	(16,680)
Ending balance, December 31	(15,630)	(4,299)
Past service gains
Beginning balance, January 1	0	0
Additions to AOCI	24	0
Amortization in current period	310	0
Amortization pursuant to plan settlements	0
Reclassification to regulatory accounts	0	0
Ending balance, December 31	$ 334	$ 0

Pension and other post-retire_7

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.94%	2.49%
Interest crediting rate (for cash balance plans)	4.00%	4.15%
Rate of compensation increase	4.00%	4.00%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.92%	2.58%
Health care cost trend rate
Before age 65	5.875%	6.00%
Age 65 and after	5.875%	6.00%
Assumed ultimate medical inflation rate	4.75%	4.75%
Year in which ultimate rate is reached	2031	2031

Pension and other post-retire_8

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.49%	3.19%
Expected return on assets	6.20%	6.85%
Rate of compensation increase	3.99%	3.96%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.58%	3.29%
Expected return on assets	4.79%	5.57%
Health care cost trend rate
Before Age 65	5.122%	6.125%
Age 65 and after	5.122%	6.125%
Assumed ultimate medical inflation rate	4.05%	4.75%
Year in which ultimate rate is reached	2031	2031

Pension and other post-retire_9

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, 2021	Dec. 31, 2020
Non-service costs
Non-service Costs	$ 16,313	$ 14,072
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	14,673	15,450
Non-service costs
Interest cost	20,676	19,281
Expected return on plan assets	(35,972)	(26,285)
Amortization of net actuarial loss	13,126	5,430
Amortization of prior service credits	(1,626)	(1,609)
Settlement Loss Recognized	198	0
Impact of regulatory accounts	19,665	16,272
Non-service Costs	16,067	13,089
Net benefit cost	30,740	28,539
OPEB
Defined Benefit Plan Disclosure [Line Items]
Service cost	7,307	6,175
Non-service costs
Interest cost	8,048	7,695
Expected return on plan assets	(10,052)	(8,748)
Amortization of net actuarial loss	2,021	509
Amortization of prior service credits	11	0
Settlement Loss Recognized	0	0
Impact of regulatory accounts	218	1,527
Non-service Costs	246	983
Net benefit cost	$ 7,553	$ 7,158

Pension and other post-retir_10

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	48.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	43.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	9.00%
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, 2021USD ($)
Defined Benefit Plan Disclosure [Line Items]
2021	$ 841,240
Percentage	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
2021	$ 429,147
Percentage	51.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
2021	$ 350,834
Percentage	42.00%
Other
Defined Benefit Plan Disclosure [Line Items]
2021	$ 61,259
Percentage	7.00%

Pension and other post-retir_12

Pension and other post-retirement benefits- Change in Plan Assets (Details) - Level 3 - Private Equity Funds $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets, beginning of year	$ 7,745
Contributions into funds	6,233
Unrealized gains	4,257
Distributions	(921)
Fair value of plan assets, end of year	$ 17,314

Pension and other post-retir_13

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2021USD ($)
Pension plan
Defined Benefit Plan Disclosure [Line Items]
2022	$ 47,802
2023	43,760
2024	44,478
2025	46,318
2026	47,554
2027-2031	238,011
OPEB
Defined Benefit Plan Disclosure [Line Items]
2022	10,465
2023	11,064
2024	11,646
2025	12,060
2026	12,543
2027-2031	$ 68,454

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	$ 36,232	$ 28,404
OPEB plan assets (note 10(a))	11,963	10,662
Long-term deposits	10,735	13,459
Income taxes recoverable	7,649	4,717
Deferred financing costs (a)	30,544	6,774
Other	14,891	9,953
Total other assets	112,014	73,969
Less: current portion	(16,153)	(7,266)
Other assets (note 11)	$ 95,861	$ 66,703

Other long-term liabilities - S

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2021USD ($)shares	Dec. 31, 2021USD ($)shares	Dec. 31, 2020USD ($)	Dec. 31, 2021$ / shares	Dec. 31, 2019USD ($)
Other Long-term Liabilities
Contract adjustment payments on Green Equity Units		$ 187,580	$ 0
Asset retirement obligations		142,147	79,968		$ 53,879
Advances in aid of construction		82,580	79,864
Environmental remediation obligation		55,224	69,383		$ 58,061
Customer deposits		32,633	31,939
Unamortized investment tax credits		17,439	17,893
Deferred credits and contingent consideration		35,982	21,399
Preferred shares, Series C		13,348	13,698
Hook-up fees		21,904	17,704
Lease liabilities (note 1(q))		22,512	14,288
Contingent development support obligations		4,612	12,273
Notes payable to related party		25,808	30,493
Other		42,050	23,027
Other long-term liabilities		683,819	411,929
Less: current portion		(167,908)	(72,748)
Other long-term liabilities, excluding current		515,911	339,181
Green Equity Units issued (in shares) | shares	23,000,000
Green Equity Units, annual distributions (percent)	7.75%
Green Equity Units, share purchase contract, interest rate (percent)	6.57%
Contract adjustment payments, accretion period	3 years
Transfers from advances in aid of construction to contributions in aid of construction		6,376	1,994
Undiscounted, unescalated cost of environmental cleanup activities		57,167	64,766
Accrual for environmental loss contingencies to be incurred over next four years		36,627
Regulatory assets		$ 1,167,625	846,519
U.S. Dollar Senior Unsecured Notes (Green Equity Units) | Senior Unsecured Notes
Other Long-term Liabilities
Proceeds from Green Equity Units	$ 1,150,000
Weighted average coupon	1.18%	1.18%
Equity Method Investee
Other Long-term Liabilities
Notes payable to related party		$ 25,808	$ 30,493
Series C Preferred Stock
Other Long-term Liabilities
Redeemable preferred stock issued (in shares) | shares		100
Preferred stock redemption price per share (in CAD per share) | $ / shares				$ 53,400,000
Note payable to related party
Other Long-term Liabilities
Interest rate (percent)		4.00%	0.675%
Other
Other Long-term Liabilities
Contingent consideration related to prior acquisition		$ 5,000
Environmental costs
Other Long-term Liabilities
Environmental remediation, rate recovery period		7 years
Regulatory assets		$ 81,802	$ 87,308
Minimum
Other Long-term Liabilities
Other liability repayment period		5 years
Accrual for environmental cleanup, discount rate (percent)		1.00%
Maximum
Other Long-term Liabilities
Other liability repayment period		40 years
Accrual for environmental cleanup, discount rate (percent)		3.40%

Other long-term liabilities - A

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 79,968	$ 53,879
Obligation assumed	57,067	20,420
Retirement activities	(4,133)	(1,724)
Accretion	4,381	2,674
Change in cash flow estimates	4,864	4,719
Closing balance	$ 142,147	$ 79,968

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 69,383	$ 58,061
Remediation activities	(9,865)	(5,130)
Accretion	1,025	436
Changes in cash flow estimates	2,265	3,828
Revision in assumptions	(7,584)	3,402
Obligation assumed from business acquisition	0	8,786
Closing balance	$ 55,224	$ 69,383

Other long-term liabilities - P

Other long-term liabilities - Preferred Shares, Series C (Details) $ in Thousands	Dec. 31, 2021USD ($)shares	Dec. 31, 2021$ / shares	Dec. 31, 2020USD ($)
Class of Stock [Line Items]
Total Preferred shares series C	$ 13,348		$ 13,698
Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued (in shares) | shares	100
Preferred stock redemption price per share (in CAD per share) | $ / shares		$ 53,400,000
Series C Preferred Stock | Dividends Payable
Class of Stock [Line Items]
2022	$ 1,102
2023	1,330
2024	1,542
2025	1,559
2026	1,406
Thereafter to 2031	6,320
Redemption amount	4,212
Estimated dividend and redemption payments	17,471
Less: amounts representing interest	(4,123)
Total Preferred shares series C	13,348
Less current portion	(1,102)
Preferred shares series C, noncurrent	$ 12,246

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Common Shares Rollforward
Beginning balance (in shares)	597,142,219	524,223,323
Public offering (in shares)	67,611,465	66,130,063
Dividend reinvestment plan (in shares)	6,184,686	5,217,071
Exercise of share-based awards (in shares)	1,020,020	1,565,537
Conversion of convertible debentures (in shares)	1,886	6,225
Ending balance (in shares)	671,960,276	597,142,219

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands	Mar. 03, 2022	Nov. 08, 2021USD ($)shares	Nov. 08, 2021CAD ($)$ / sharesshares	Oct. 31, 2019USD ($)shares	Oct. 31, 2019CAD ($)$ / sharesshares	Mar. 03, 2022shares	Dec. 31, 2021USD ($)shares	Dec. 31, 2021USD ($)voterightshares	Dec. 31, 2021USD ($)$ / sharesshares	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2021USD ($)$ / sharesshares	Dec. 31, 2021CAD ($)$ / sharesshares	Nov. 08, 2021$ / shares	Jul. 17, 2020$ / shares	May 15, 2020USD ($)	Oct. 31, 2019$ / 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%
Preferred shares | $							$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000
Total share-based compensation | $								8,395,000		$ 24,637,000
Unrecognized compensation costs, non-vested awards | $							$ 17,137,000	$ 17,137,000	$ 17,137,000		$ 17,137,000
Unrecognized compensation costs, non-vested options, period of recognition								1 year 8 months 1 day
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%
Other Net Losses
Stockholders Equity Note [Line Items]
Total share-based compensation | $								$ 12,639,000
Preferred shares, Series A
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
Preferred shares							$ 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 variable rate								2.94%
Preferred shares, Series D
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
Preferred shares							$ 83,836,000	$ 83,836,000	$ 83,836,000		$ 83,836,000	$ 97,259
Dividend declared per preferred share (CAD per share) | (per share)									$ 1.2728	$ 1.2728
Preferred dividend rate reset period								5 years
Basis spread on variable rate								3.28%
Series C Preferred Stock
Stockholders Equity Note [Line Items]
Redeemable preferred stock issued (in shares)							100	100	100		100	100
Retirement Restricted Share Units
Stockholders Equity Note [Line Items]
Awards vested (percent)								100.00%
Share options
Stockholders Equity Note [Line Items]
Total share-based compensation | $								$ 939,000		$ 1,743,000
Percentage of shares reserved under the plan (must not exceed)								8.00%
Bonus Deferral Restricted Stock Units
Stockholders Equity Note [Line Items]
Shares issued during period (in shares)								56,686
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)								355,096		302,727
Deferred Share Units
Stockholders Equity Note [Line Items]
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
Exercise of share-based awards (in shares)								73,467		84,074
Exercise of share-based awards settled (in shares)								87,582		0
Common shares issued from treasury (in shares)										40,786
DSUs settled for cash value as payment for tax withholding (in shares)										46,796
Shares issued during period (in shares)								530,378		544,493
Common stock, shares issued (in shares)							152,564	152,564	152,564		152,564	152,564
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
ATM Equity Program
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)								23,531,465			33,952,827
Cash proceeds from issuance of shares | $								$ 369,495,000			$ 512,163,000
Treasury atock, amount reserved for issuance under the plan | $															$ 500,000
Sale of stock, average price per share (in USD) | (per share)								15.70			$ 15.08
Gross proceeds from sale of stock, net of commissions | $								364,876,000			$ 505,761,000
Sale of stock, other related costs | $								$ 872,000			$ 4,285,000
Treasury Stock, Common
Stockholders Equity Note [Line Items]
Shares issued from treasury to settles RSUs and PSUs (in shares)								70,571
Common shares
Stockholders Equity Note [Line Items]
Discount rate on share purchases under dividend reinvestment plan (percent)								5.00%
Equity other than options settled at cash value for payment of the exercise price and for tax withholdings (in shares)							81,993
Common shares | Subsequent Event
Stockholders Equity Note [Line Items]
Discount rate on share purchases under dividend reinvestment plan (percent)	3.00%
Dividend reinvestment plan shares issued (in shares)						1,625,414
Common shares | Public Stock Offering
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)		44,080,000	44,080,000	57,465,500	57,465,500
Shares issued, price per share (USD and CAD per share) | (per share)			$ 800,052		$ 17.10								$ 18.15	$ 14.63		$ 12.60
Cash proceeds from issuance of shares		$ 642,664,000	$ 32,583	$ 723,926,000	$ 982,660
Issuance costs		$ 26,173,000		$ 25,268,000	$ 34,299
Minimum
Stockholders Equity Note [Line Items]
Percentage of outstanding stock to be purchased to acquire discount (or more)								20.00%
Minimum | Performance Share Units
Stockholders Equity Note [Line Items]
Percentage of shares issued on number of PSU grants (percent)								2.50%
Maximum | Performance Share Units
Stockholders Equity Note [Line Items]
Percentage of shares issued on number of PSU grants (percent)								237.00%

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 8,395	$ 24,637
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	939	1,743
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	821	870
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	592	511
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 6,043	$ 21,513

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Equity [Abstract]
Risk-free interest rate	1.10%	1.20%
Expected volatility	23.00%	24.00%
Expected dividend yield	4.10%	4.10%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (in USD per share)	$ 2.46	$ 2.72

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of awards
Beginning balance (in shares)	2,110,448	3,523,912
Granted (in shares)	437,006	999,962
Exercised (in shares)	(506,926)	(2,386,275)
Forfeited (in shares)	0	(27,151)
Ending balance (in shares)	2,040,528	2,110,448	3,523,912
Exercisable (in shares)	1,398,668
Weighted average exercise price
Beginning balance (in USD per share)	$ 15.45	$ 13.09
Granted (in USD per share)	19.64	16.78
Exercised (in USD per share)	13.92	12.52
Forfeited (in USD per share)	0	14.96
Ending balance (in USD per share)	15.45	$ 15.45	$ 13.09
Exercisable (in USD per share)	$ 16.09
Additional Disclosures
Outstanding shares, weighted average remaining contractual term	6 years 1 month 9 days	6 years 6 months 18 days	5 years 10 months 13 days
Granted, weighted average remaining contractual term	7 years 2 months 19 days	7 years 3 months 7 days
Exercised shares, weighted average remaining contractual term	5 years 11 months 12 days	5 years 1 month 28 days
Exercisable , weighted average remaining contractual term	5 years 9 months 29 days
Beginning balance, aggregate intrinsic value	$ 11,604	$ 18,609
Exercised, aggregate intrinsic value	1,453	18,465
Ending balance, aggregate intrinsic value	3,145	$ 11,604	$ 18,609
Exercisable, aggregate intrinsic value	$ 3,247

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Additional Disclosures
Weighted average remaining contractual term, Exercisable	5 years 9 months 29 days
Performance and restricted share units
Number of awards
Beginning balance (in shares)	2,721,207	2,412,043
Granted, including dividends (in shares)	805,433	1,313,171
Exercised (in shares)	(865,067)	(968,470)
Forfeited (in shares)	(217,901)	(35,537)
Ending balance (in shares)	2,443,672	2,721,207	2,412,043
Exercisable (in shares)	775,674
Weighted average grant-date fair value
Beginning balance (in USD per share)	$ 16.58	$ 14
Granted, including dividends (in USD per share)	19.94	19.31
Exercised (in USD per share)	13.79	14.45
Forfeited (in USD per share)	18.64	15.62
Ending balance (in USD per share)	18.07	$ 16.58	$ 14
Exercisable (in USD per share)	$ 16.12
Additional Disclosures
Outstanding, Weighted average remaining contractual term	1 year 8 months 19 days	11 months 4 days	1 year 10 months 9 days
Granted, including dividends, Weighted average remaining contractual term	2 years 9 months 7 days	2 years
Weighted average remaining contractual term, Exercisable
Outstanding, aggregate intrinsic value	$ 44,646	$ 54,560	$ 44,309
Granted, including dividends, aggregate intrinsic value	12,881	24,966
Exercised, aggregate intrinsic value	17,005	20,105
Forfeited, aggregate intrinsic value	3,981	$ 745
Exercisable, aggregate intrinsic value	$ 14,172

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, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 5,662,190	$ 4,406,595
OCI	(90,838)	(8,739)
Amounts reclassified from AOCI to the consolidated statement of operations	48,288	(4,698)
OCI, net of tax	(42,550)	(13,437)
OCI attributable to the non-controlling interests	(249)	691
Net current period OCI attributable to shareholders of AQN	(42,799)	(12,746)
Amount reclassified from AOCI to non-controlling interest (note 3(g))	(6,371)
Ending Balance	7,382,079	5,662,190
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(39,725)	(68,822)
OCI	(25,982)	25,643
Amounts reclassified from AOCI to the consolidated statement of operations	(4,288)	2,763
OCI, net of tax	(30,270)	28,406
OCI attributable to the non-controlling interests	(249)	691
Net current period OCI attributable to shareholders of AQN	(30,519)	29,097
Amount reclassified from AOCI to non-controlling interest (note 3(g))	(6,371)
Ending Balance	(76,615)	(39,725)
Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	50,817	75,099
OCI	(97,103)	(13,418)
Amounts reclassified from AOCI to the consolidated statement of operations	42,772	(10,864)
OCI, net of tax	(54,331)	(24,282)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	(54,331)	(24,282)
Amount reclassified from AOCI to non-controlling interest (note 3(g))	0
Ending Balance	(3,514)	50,817
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(33,599)	(16,038)
OCI	32,247	(20,964)
Amounts reclassified from AOCI to the consolidated statement of operations	9,804	3,403
OCI, net of tax	42,051	(17,561)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	42,051	(17,561)
Amount reclassified from AOCI to non-controlling interest (note 3(g))	0
Ending Balance	8,452	(33,599)
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(22,507)	(9,761)
Ending Balance	$ (71,677)	$ (22,507)

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021$ / shares	Dec. 31, 2021USD ($)$ / shares	Dec. 31, 2020USD ($)$ / shares
Dividends [Line Items]
Dividend declared for common share holders		$ 423,023	$ 344,382
Cash dividend declared per common share (USD per share) | $ / shares		$ 0.6669	$ 0.6063
Preferred shares, Series A
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
Preferred shares, Series D
Dividends [Line Items]
Dividends declared for preferred share holders		$ 5,091	$ 5,091
Dividend declared per preferred share (CAD per share) | (per share)	$ 1.2728		$ 1.2728

Related party transactions (Det

Related party transactions (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Nov. 30, 2021USD ($)	May 31, 2019USD ($)	May 31, 2019CAD ($)	May 24, 2019USD ($)
Transactions with Third Party [Line Items]
Notes payable to related party	$ 25,808,000	$ 30,493,000
Non-controlling interest incurred	(6,902,000)	(6,955,000)
Distribution to redeemable non-controlling interest	968,000	951,000
Non-controlling interests	1,523,082,000	458,612,000
Equity-method investees	433,850,000	186,452,000
AYES Canada
Transactions with Third Party [Line Items]
Non-controlling interests	41,782,000	59,125,000			$ 96,752,000
AY Holdco
Transactions with Third Party [Line Items]
Equity-method investees				$ 39,376,000
Redeemable Non-Controlling Interest
Transactions with Third Party [Line Items]
Non-controlling interest incurred	10,435,000	12,651,000
Distribution to redeemable non-controlling interest	10,214,000	12,198,000
Redeemable Non-Controlling Interest | Senior Secured Credit Facility
Transactions with Third Party [Line Items]
Line of credit facility, maximum borrowing capacity	306,500,000
Related Party
Transactions with Third Party [Line Items]
Distribution from interest in noncontrolling interest	17,793,000	16,064,000
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses	25,778,000	25,693,000
Development fees	2,036,000		$ 25,985,000
Notes payable to related party	25,808,000	30,493,000
Related Party | AYES Canada
Transactions with Third Party [Line Items]
Non-controlling interests					$ 96,752,000	$ 130,103	$ 96,752,000
Distribution from interest in noncontrolling interest	17,793,000	$ 16,064,000
Atlantica | Related Party
Transactions with Third Party [Line Items]
Purchases from relatedparty	23,863,000
Contingent consideration	2,600,000
Gain on sale with related party	$ 878,000

Non-controlling interests and_3

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)facility	Dec. 31, 2020USD ($)	Dec. 31, 2019windProject	May 31, 2019USD ($)	May 31, 2019CAD ($)	May 24, 2019USD ($)
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests	$ 89,637,000	$ 67,286,000
Non-controlling interests - redeemable tax equity partnership units	6,902,000	6,955,000
Redeemable non-controlling interest, held by related party	(10,435,000)	(12,651,000)
Net effect of non-controlling interests	79,202,000	54,635,000
Number of wind projects | windProject			3
Non-controlling interests	1,441,924,000	399,487,000
Non-controlling interests	1,523,082,000	458,612,000
Contributions from redeemable non-controlling interests	$ 0	3,717,000
North Fork Ridge Wind Project
Noncontrolling Interest [Line Items]
Number of wind projects | facility	3
Atlantica Yield Energy Solutions Canada Inc. (b)
Noncontrolling Interest [Line Items]
Non-controlling interests	$ 41,782,000	59,125,000		$ 96,752,000
Atlantica Yield Energy Solutions Canada Inc. (b) | AIP
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests	0	0
Non-controlling interests				$ 96,752,000	$ 130,103	$ 96,752,000
Mid-West Wind Facilities
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests	530,880,000
Sugar Creek Wind Facility
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests	380,829,000
Maverick Creek Wind Facility
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests	147,914,000
Non-controlling interests
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests	(5,682,000)	(2,351,000)
Non-controlling interests	64,807,000	11,234,000
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests	88,417,000	62,682,000
Non-controlling interests - redeemable tax equity partnership units	6,902,000	6,955,000
Non-controlling interests	$ 1,377,117,000	$ 388,253,000

Non-controlling interests and_4

Non-controlling interests and redeemable non-controlling interests - Change in Redeemable non-controlling Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 20,859	$ 25,913
Net effect from operations	(6,902)	(6,955)
Contributions, net of costs	0	3,717
Dividends and distributions declared	(968)	(951)
Repurchase of non-controlling interest	0	(865)
Closing balance	12,989	20,859
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	306,316	305,863
Net effect from operations	10,435	12,651
Contributions, net of costs	0	0
Dividends and distributions declared	(10,214)	(12,198)
Repurchase of non-controlling interest	0	0
Closing balance	$ 306,537	$ 306,316

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	Apr. 08, 2020	Dec. 31, 2021	Dec. 31, 2020
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		$ 27,471	$ 29,824
Undistributed earnings of foreign subsidiaries		$ 694,947

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Expected income tax expense at Canadian statutory rate	$ 37,691	$ 209,989
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(47,600)	(27,082)
Adjustments from investments carried at fair value	2,709	(87,058)
Non-controlling interests share of income	25,135	18,243
Non-deductible acquisition costs	3,733	3,223
Tax credits	(49,415)	(40,185)
Adjustment relating to prior periods	1,333	(4,228)
Deferred income taxes on regulated income recorded as regulatory assets	(3,807)	(2,811)
Amortization and settlement of excess deferred income tax	(16,778)	(12,392)
Other	3,574	6,884
Income tax expense (recovery)	$ (43,425)	$ 64,583

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 142,232	$ 792,411
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	(60,848)	622,776
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	153,719	165,431
Other regions
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 49,361	$ 4,204

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Tax Expenses [Line Items]
Current	$ 7,237	$ 4,888
Deferred	(50,662)	59,695
Total	(43,425)	64,583
Canada
Income Tax Expenses [Line Items]
Current	4,560	4,319
Deferred	(33,993)	62,061
Total	(29,433)	66,380
United States
Income Tax Expenses [Line Items]
Current	1,024	(1,448)
Deferred	(19,772)	(1,745)
Total	(18,748)	(3,193)
Other regions
Income Tax Expenses [Line Items]
Current	1,653	2,017
Deferred	3,103	(621)
Total	$ 4,756	$ 1,396

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, 2021	Dec. 31, 2020
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 761,666	$ 531,353
Pension and OPEB	46,580	66,826
Environmental obligation	15,271	16,145
Regulatory liabilities	166,939	168,054
Other	64,460	65,787
Total deferred income tax assets	1,054,916	848,165
Less: valuation allowance	(27,471)	(29,824)
Total deferred tax assets	1,027,445	818,341
Deferred tax liabilities:
Property, plant and equipment	782,829	733,211
Outside basis differentials	412,665	406,429
Regulatory accounts	300,072	212,937
Other	30,471	12,528
Total deferred tax liabilities	1,526,037	1,365,105
Net deferred tax liabilities	(498,592)	(546,764)
Deferred tax assets	31,595	21,880
Deferred tax liabilities	$ (530,187)	$ (568,644)

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2021USD ($)
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 2,024,463
Tax credits	136,985
Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	678,881
U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	1,345,582
2022—2026
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	11,283
Tax credits	4,476
2022—2026 | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	0
2022—2026 | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	11,283
2027+
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	2,013,180
Tax credits	132,509
2027+ | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	678,881
2027+ | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 1,334,299

Other net losses Other Losses (

Other net losses Other Losses (Details) - USD ($) $ in Thousands	Jul. 01, 2020	Dec. 31, 2021	Dec. 31, 2020
Other Income and Expenses [Abstract]
Acquisition and transition-related costs		$ 14,507	$ 14,104
U.S. Tax reform		0	11,728
Management succession and executive retirement		0	12,639
Other		8,442	22,840
Other losses		22,949	61,311
Accumulated Other Comprehensive Income (Loss) [Line Items]
Period for refund of taxes collected at the higher rate	5 years
U.S. Tax reform		0	11,728
Management succession and executive retirement		$ 0	$ 12,639

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, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Net earnings attributable to shareholders of AQN	$ 264,859	$ 782,463
Series A and D Preferred shares dividend	9,003	8,401
Net earnings attributable to common shareholders of AQN – basic and diluted	$ 255,856	$ 774,062
Weighted average number of shares
Basic (in shares)	622,347,677	559,633,275
Effect of dilutive securities (in shares)	6,600,185	4,740,561
Diluted (in shares)	628,947,862	564,373,836
Preferred shares, Series A
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,942	$ 4,611
Preferred shares, Series D
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,061	$ 3,790

Basic and diluted net earning_4

Basic and diluted net earnings per share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures (in shares)	437,006	479,836

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021businessUnitsegment
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, 2021	Dec. 31, 2020
Revenue
Revenue	$ 2,212,141	$ 1,642,002
Other revenue	2,285,479	1,676,991
Fuel, power and water purchased	719,100	401,008
Net revenue	1,566,379	1,275,983
Operating expenses	702,128	516,820
Administrative expenses	66,726	63,122
Depreciation and amortization	402,963	314,123
Loss (gain) on foreign exchange	4,371	(2,108)
Gain on sale of renewable assets	(29,063)	0
Operating income	419,254	384,026
Interest expense	(209,554)	(181,934)
Income (loss) from long-term investments	(26,457)	664,738
Other	(41,011)	(74,419)
Earnings before income taxes	142,232	792,411
Property, plant and equipment	11,042,446	8,241,838
Investments carried at fair value	1,848,456	1,839,212
Equity-method investees	433,850	186,452
Total assets	16,785,836	13,224,149
Capital expenditures	1,345,045	786,030
Revenue related to net hedging loss, not recognized as revenue from contract with customers	57,018	28,586
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	19,043	24,928
Other revenue
Revenue
Other revenue	73,338	34,989
Regulated Services Group
Revenue
Revenue	1,944,171	1,386,048
Fuel, power and water purchased	682,602	384,363
Net revenue	1,315,010	1,020,773
Operating expenses	597,850	442,851
Administrative expenses	37,179	36,749
Depreciation and amortization	280,452	219,089
Loss (gain) on foreign exchange	0	0
Gain on sale of renewable assets	0
Operating income	399,529	322,084
Interest expense	(93,411)	(99,161)
Income (loss) from long-term investments	18,306	7,753
Other	(24,177)	(40,128)
Earnings before income taxes	300,247	190,548
Property, plant and equipment	7,394,151	5,757,532
Investments carried at fair value	2,296	0
Equity-method investees	37,492	74,673
Total assets	10,512,799	8,528,415
Capital expenditures	998,855	690,792
Regulated Services Group | Other revenue
Revenue
Other revenue	53,441	19,088
Renewable Energy Group
Revenue
Revenue	267,970	255,954
Fuel, power and water purchased	36,498	16,645
Net revenue	249,811	253,753
Operating expenses	104,262	73,957
Administrative expenses	28,298	25,743
Depreciation and amortization	121,414	92,890
Loss (gain) on foreign exchange	0	0
Gain on sale of renewable assets	(29,063)
Operating income	24,900	61,163
Interest expense	(71,598)	(52,656)
Income (loss) from long-term investments	84,046	93,998
Other	(9,108)	(6,537)
Earnings before income taxes	28,240	95,968
Property, plant and equipment	3,615,915	2,451,706
Investments carried at fair value	1,846,160	1,839,212
Equity-method investees	375,460	110,414
Total assets	6,123,888	4,586,878
Capital expenditures	338,637	80,746
Renewable Energy Group | Other revenue
Revenue
Other revenue	18,339	14,444
Corporate
Revenue
Revenue	0	0
Fuel, power and water purchased	0	0
Net revenue	1,558	1,457
Operating expenses	16	12
Administrative expenses	1,249	630
Depreciation and amortization	1,097	2,144
Loss (gain) on foreign exchange	4,371	(2,108)
Gain on sale of renewable assets	0
Operating income	(5,175)	779
Interest expense	(44,545)	(30,117)
Income (loss) from long-term investments	(128,809)	562,987
Other	(7,726)	(27,754)
Earnings before income taxes	(186,255)	505,895
Property, plant and equipment	32,380	32,600
Investments carried at fair value	0	0
Equity-method investees	20,898	1,365
Total assets	149,149	108,856
Capital expenditures	7,553	14,492
Corporate | Other revenue
Revenue
Other revenue	$ 1,558	$ 1,457

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenue	$ 2,285,479	$ 1,676,991
Property, plant and equipment	11,042,446	8,241,838
Intangible assets	105,116	114,913
United States
Segment Reporting Information [Line Items]
Revenue	1,801,876	1,475,087
Property, plant and equipment	9,464,716	6,666,015
Intangible assets	23,575	24,825
Canada
Segment Reporting Information [Line Items]
Revenue	157,854	153,502
Property, plant and equipment	882,454	884,195
Intangible assets	21,780	23,123
Other regions
Segment Reporting Information [Line Items]
Revenue	325,749	48,402
Property, plant and equipment	695,276	691,628
Intangible assets	$ 59,761	$ 66,965

Commitments and contingencies -

Commitments and contingencies - Estimates of Future Commitments (Detail) $ in Thousands	Aug. 06, 2021MWac	Mar. 03, 2022lawsuit	Dec. 31, 2021USD ($)
Commitments Disclosure [Line Items]
Year 1			$ 327,438
Year 2			181,692
Year 3			154,481
Year 4			146,458
Year 5			102,903
Thereafter			1,150,942
Total			2,063,914
Power purchase
Commitments Disclosure [Line Items]
Year 1			62,759
Year 2			33,521
Year 3			33,585
Year 4			33,821
Year 5			12,274
Thereafter			155,106
Total			331,066
Gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1			101,406
Year 2			75,482
Year 3			49,328
Year 4			44,286
Year 5			26,887
Thereafter			176,535
Total			473,924
Service agreements
Commitments Disclosure [Line Items]
Year 1			65,230
Year 2			59,641
Year 3			58,356
Year 4			54,953
Year 5			50,181
Thereafter			347,546
Total			635,907
Capital projects
Commitments Disclosure [Line Items]
Year 1			85,130
Year 2			0
Year 3			0
Year 4			0
Year 5			0
Thereafter			0
Total			85,130
Land easements
Commitments Disclosure [Line Items]
Year 1			12,913
Year 2			13,048
Year 3			13,212
Year 4			13,398
Year 5			13,561
Thereafter			471,755
Total			$ 537,887
Gaia Power Inc. vs APUC | Amherst Island Wind Facility
Commitments Disclosure [Line Items]
Wind power capacity (megawatt AC) | MWac	74
Gaia Power Inc. vs APUC | Blue Hill Wind Project
Commitments Disclosure [Line Items]
Wind power capacity (megawatt AC) | MWac	175
Mountain View Fire | Subsequent Event
Commitments Disclosure [Line Items]
Number of active lawsuits | lawsuit		8
Number of lawsuits filed by groups of individual plaintiffs | lawsuit		4
Number of lawsuits filed by insurance companies | lawsuit		3

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ (56,751)	$ (52,778)
Fuel and natural gas in storage	(43,642)	237
Supplies and consumables inventory	445	1,058
Income taxes recoverable	(3,025)	(3,440)
Prepaid expenses	(1,189)	(15,411)
Accounts payable	(33,399)	40,885
Accrued liabilities	31,845	(29,150)
Current income tax liability	4,363	3,818
Asset retirements and environmental obligations	(1,185)	3,562
Net regulatory assets and liabilities	(419,484)	(26,260)
Changes in non-cash operating items	$ (522,022)	$ (77,479)

Financial instruments - Fair Va

Financial instruments - Fair Value of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Fair Value of Financial Instruments [Line Items]
Notes payable to related party	$ 25,808	$ 30,493
Interest rate swaps designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	7,015
Cross-currency swap designated as a net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	55,543
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,753,210	1,708,683
Total financial assets	1,753,210	1,708,683
Long-term debt	2,418,580	2,316,586
Convertible debentures	519	623
Total financial liabilities	2,419,099	2,317,209
Level 2
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value		20,015
Development loans and other receivables	33,286	31,088
Total derivative instruments	5,260	194
Total financial assets	38,546	51,297
Long-term debt	4,125,352	2,823,473
Notes payable to related party	25,808	30,493
Convertible debentures	0
Total derivative instruments	58,614	104,481
Total financial liabilities	4,224,354	2,974,012
Level 2 | Interest rate swaps designated as a hedge | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,581
Total derivative instruments	7,008	19,649
Level 2 | Commodity contracts for regulated operations
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,721	194
Total derivative instruments	1,348	614
Level 2 | Cross-currency swap designated as a net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,958
Level 2 | Cross-currency swap designated as a net investment hedge | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	50,258	84,218
Level 2 | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	14,580	15,565
Level 3
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	95,246	110,514
Development loans and other receivables		0
Total derivative instruments	15,362	51,913
Total financial assets	110,608	162,427
Total derivative instruments	61,631	5,929
Total financial liabilities	61,631	5,929
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,362	51,525
Total derivative instruments	60,462	5,597
Level 3 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,169
Level 3 | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		388
Total derivative instruments		332
Carrying amount
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,848,456	1,839,212
Development loans and other receivables	32,261	23,804
Total derivative instruments	20,622	52,107
Total financial assets	1,901,339	1,915,123
Long-term debt	6,211,375	4,538,470
Notes payable to related party		30,493
Convertible debentures	277	295
Total derivative instruments	120,245	110,410
Total financial liabilities	6,371,053	4,693,366
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,362	51,525
Total derivative instruments	60,462	5,597
Carrying amount | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,169
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		388
Total derivative instruments		332
Carrying amount | Interest rate swaps designated as a hedge | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,581
Total derivative instruments	7,008	19,649
Carrying amount | Commodity contracts for regulated operations
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,721	194
Total derivative instruments	1,348	614
Carrying amount | Cross-currency swap designated as a net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,958
Carrying amount | Cross-currency swap designated as a net investment hedge | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	50,258	84,218
Carrying amount | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	13,348	13,698
Fair value
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,848,456	1,839,212
Development loans and other receivables	33,286	31,088
Total derivative instruments	20,622	52,107
Total financial assets	1,902,364	1,922,407
Long-term debt	6,543,933	5,140,059
Notes payable to related party	25,808	30,493
Convertible debentures	519	623
Total derivative instruments	120,245	110,410
Total financial liabilities	6,705,085	5,297,150
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,362	51,525
Total derivative instruments	60,462	5,597
Fair value | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,169
Fair value | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		388
Total derivative instruments		332
Fair value | Interest rate swaps designated as a hedge | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,581
Total derivative instruments	7,008	19,649
Fair value | Commodity contracts for regulated operations
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,721	194
Total derivative instruments	1,348	614
Fair value | Cross-currency swap designated as a net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,958
Fair value | Cross-currency swap designated as a net investment hedge | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	50,258	84,218
Fair value | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	$ 14,580	$ 15,565

Financial instruments - Additio

Financial instruments - Additional Information (Detail)	1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 30, 2020USD ($)termLoanFacilityderivativeContract	Dec. 31, 2021USD ($)$ / MWh	Dec. 31, 2021USD ($)$ / MWh	Dec. 31, 2020USD ($)	Dec. 31, 2021CAD ($)$ / MWh	Apr. 09, 2021CAD ($)	Feb. 15, 2021CAD ($)	Dec. 31, 2020CAD ($)	Sep. 30, 2019USD ($)	May 23, 2019USD ($)
Derivative [Line Items]
Number of term loan facilities | termLoanFacility	2
Foreign currency gain (loss)			$ (30,270,000)	$ 28,406,000
Revenue collection period			45 days
Accounts receivable		$ 422,752,000	$ 422,752,000
Cash on hand		125,157,000	125,157,000
Available to be drawn on senior debt facilities		1,826,256,000	1,826,256,000
Liberty Power Group
Derivative [Line Items]
Foreign currency gain (loss)			7,824,000	18,875,000
Non-regulated Energy Sales
Derivative [Line Items]
Unrealized gains (loss) in AOCI to be reclassified			(1,843,000)
Interest expense
Derivative [Line Items]
Unrealized gains (loss) in AOCI to be reclassified			(1,555,000)
Derivative gains
Derivative [Line Items]
Unrealized gains (loss) in AOCI to be reclassified			1,206,000
Senior Unsecured Notes | U.S. dollar Subordinated unsecured notes
Derivative [Line Items]
Par value		637,500,000	637,500,000							$ 350,000,000
Senior Unsecured Notes | Canadian dollar Senior unsecured notes
Derivative [Line Items]
Par value					$ 1,400,669,000	$ 400,000,000	$ 150,000,000
Interest rate swaps designated as a hedge | U.S. dollar Subordinated unsecured notes
Derivative [Line Items]
Derivative notional amount									$ 350,000,000
Currency Swap
Derivative [Line Items]
Derivative notional amount					$ 500,000,000			$ 650,000
Foreign currency gain (loss)			4,232,000	13,256,000
Currency Swap | Senior Unsecured Notes | Canadian dollar Senior unsecured notes
Derivative [Line Items]
Foreign currency gain (loss)		$ 1,925,000
Foreign exchange contract
Derivative [Line Items]
Foreign currency gain (loss)			(1,595,000)	3,581,000
Currency forward contract
Derivative [Line Items]
Foreign currency gain on settlement of derivative			2,329,000	2,363,000
Ascendant
Derivative [Line Items]
Number of interest rate swaps redesignated as cash flow hedges | derivativeContract	2
Ascendant | Interest Rate Swap One
Derivative [Line Items]
Derivative notional amount	$ 87,627,000
Derivative, fixed interest rate (percent)	3.28%
Ascendant | Interest Rate Swap Two
Derivative [Line Items]
Derivative notional amount	$ 8,875,000
Derivative, fixed interest rate (percent)	3.02%
Canadian Investments and Subsidiaries
Derivative [Line Items]
Foreign currency gain (loss)			$ 168,000	$ 656,000
Minimum
Derivative [Line Items]
Forward price | $ / MWh		19.76	19.76		19.76
Minimum | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0775	0.0775		0.0775
Minimum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.2549	0.2549		0.2549
Maximum
Derivative [Line Items]
Forward price | $ / MWh		130.85	130.85		130.85
Maximum | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0825	0.0825		0.0825
Maximum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.3716	0.3716		0.3716
Weighted Average
Derivative [Line Items]
Forward price | $ / MWh		32.51	32.51		32.51
Weighted Average | AYES Canada | Measurement Input, Discount Rate
Derivative [Line Items]
Alternative investment, measurement input (percent)		0.0814	0.0814		0.0814

Financial instruments - Summary

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2021MMBTU
Derivative [Line Items]
Commodity volumes, Gas	3,405,544
Financial contracts: Swaps
Derivative [Line Items]
Commodity volumes, Gas	3,239,873
Options
Derivative [Line Items]
Commodity volumes, Gas	165,671

Financial instruments - Long-te

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2021MWh$ / MWh$ / MWh
Illinois Hub, Expiry September 2030
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	4,585,008
Receive average prices (per MW-hr) | $ / MWh	24.54
PJM Western HUB, Expiry December 2028
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	527,931
Receive average prices (per MW-hr) | $ / MWh	32.11
NI HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,465,763
Receive average prices (per MW-hr) | $ / MWh	23.67
ERCOT North HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	1,998,095
Receive average prices (per MW-hr) | $ / MWh	36.46
Salisbury, Expiry February 2022
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	11,328
Receive average prices (per MW-hr) | $ / MWh	38.95

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, 2021	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge	$ (97,103)	$ (13,418)
Amortization of cash flow hedge	(2,132)	(1,248)
Amounts reclassified from AOCI	44,904	(9,616)
OCI attributable to shareholders of AQN	$ (54,331)	$ (24,282)

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, 2021	Dec. 31, 2020
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss on derivative financial instruments	$ 5,609	$ 2,124
Total realized loss on derivative financial instruments	2,329	2,362
Gain (loss) on derivative instruments	580	3,326
Gain (loss) on derivative financial instruments	(1,749)	964
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss on derivative financial instruments	(5,353)	(901)
Total realized loss on derivative financial instruments	2,221	1,218
Loss on derivative financial instruments not accounted for as hedges	(3,132)	317
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss on derivative financial instruments	(5,353)	(901)
Total realized loss on derivative financial instruments	(108)	(1,145)
Not Designated as Hedging Instrument | Currency forward contract
Fair Value of Financial Instruments [Line Items]
Total realized loss on derivative financial instruments	2,329	2,363
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Amortization of AOCI gains frozen as a result of hedge dedesignation	$ 3,712	$ 3,009

Financial instruments - Maximum

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) $ in Thousands	Dec. 31, 2021USD ($)
Segment Reporting Information [Line Items]
Cash and cash equivalents and restricted cash	$ 161,389
Accounts receivable	422,752
Allowance for doubtful accounts	(19,327)
Notes receivable	31,468
Maximum exposure to credit risk for financial instruments	596,282
Regulated Services Group
Segment Reporting Information [Line Items]
Accounts receivable	$ 293,895

Financial instruments - Liabili

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Long-term debt obligations	$ 6,223,334
Interest on long-term debt	1,847,212
Purchase obligations	614,024
Environmental obligation	57,167
Advances in aid of construction	82,580	$ 79,864
Contract adjustment payments on Green Equity Units	187,580	$ 0
Other obligations	335,927
Total obligations	9,473,362
Cross-currency swap
Derivative [Line Items]
Total derivative instruments	55,543
Interest rate swaps
Derivative [Line Items]
Total derivative instruments	7,015
Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	62,980
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	834,645
Interest on long-term debt	196,824
Purchase obligations	614,024
Environmental obligation	12,751
Advances in aid of construction	1,706
Contract adjustment payments on Green Equity Units	75,555
Other obligations	66,916
Total obligations	1,840,991
Due less than 1 year | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	27,936
Due less than 1 year | Interest rate swaps
Derivative [Line Items]
Total derivative instruments	2,145
Due less than 1 year | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	8,489
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	500,070
Interest on long-term debt	348,479
Purchase obligations	0
Environmental obligation	23,876
Advances in aid of construction	0
Contract adjustment payments on Green Equity Units	112,025
Other obligations	4,473
Total obligations	1,034,327
Due 2 to 3 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	23,115
Due 2 to 3 years | Interest rate swaps
Derivative [Line Items]
Total derivative instruments	2,141
Due 2 to 3 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	20,148
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	1,217,235
Interest on long-term debt	297,461
Purchase obligations	0
Environmental obligation	1,066
Advances in aid of construction	0
Contract adjustment payments on Green Equity Units	0
Other obligations	4,427
Total obligations	1,540,645
Due 4 to 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	2,604
Due 4 to 5 years | Interest rate swaps
Derivative [Line Items]
Total derivative instruments	1,335
Due 4 to 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	16,517
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	3,671,384
Interest on long-term debt	1,004,448
Purchase obligations	0
Environmental obligation	19,474
Advances in aid of construction	80,874
Contract adjustment payments on Green Equity Units	0
Other obligations	260,111
Total obligations	5,057,399
Due after 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	1,888
Due after 5 years | Interest rate swaps
Derivative [Line Items]
Total derivative instruments	1,394
Due after 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	$ 17,826