Algonquin Power & Utilities (AQN) 40-F 17 Mar 23 2022 FY Annual report (Canada) Financial data

Cover Page

Cover Page - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Entity File Number	001-37946
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	354 Davis Road
Entity Address, City or Town	Oakville
Entity Address, State or Province	ON
Entity Address, Postal Zip Code	L6J 2X1
Entity Address, Country	CA
City Area Code	905
Local Phone Number	465-4500
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	683,614,803	671,960,276	597,142,219
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Central Index Key	0001174169
Amendment Flag	false
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078
Entity Information [Line Items]
Title of 12(b) Security	6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078
Trading Symbol	AQNA
Security Exchange Name	NYSE
6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079
Entity Information [Line Items]
Title of 12(b) Security	6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079
Trading Symbol	AQNB
Security Exchange Name	NYSE
Common shares
Entity Information [Line Items]
Title of 12(b) Security	Common shares, no par value
Trading Symbol	AQN
Security Exchange Name	NYSE
Corporate Units
Entity Information [Line Items]
Title of 12(b) Security	Corporate Units
Trading Symbol	AQNU
Security Exchange Name	NYSE
Rights to Purchase One Common Share of the Company
Entity Information [Line Items]
Title of 12(b) Security	Rights to Purchase One Common Share of the Company
Trading Symbol	N/A
Security Exchange Name	NYSE
Business Contact
Entity Information [Line Items]
Entity Address, Address Line One	111 Eighth Avenue
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10011
City Area Code	212
Local Phone Number	894-8940
Contact Personnel Name	CT Corporation System

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
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, 2022	Dec. 31, 2021
Revenue
Other revenue	$ 2,765,155	$ 2,274,142
Expenses
Administrative expenses	80,232	66,726
Depreciation and amortization	455,520	402,963
Asset impairment charge (note 5)	159,568	0
Loss on foreign exchange	13,833	4,371
Costs and expenses, total	2,427,138	1,890,103
Gain on sale of renewable assets (notes 3(a) and 16(c))	64,028	29,063
Operating income (loss)	402,045	413,102
Interest expense	(278,574)	(209,554)
Fair value change, income (loss) and impairment charge on long-term investments (note 8)	(465,206)	(26,457)
Other net losses (note 19)	(21,391)	(22,949)
Pension and other post-employment non-service costs (note 10)	(10,950)	(16,313)
Gain on derivative financial instruments (note 24(b)(iv))	4,408	4,403
Nonoperating income (expense)	(771,713)	(270,870)
Income (loss) before income taxes	(369,668)	142,232
Income tax recovery (expense) (note 18)
Current	(7,843)	(7,237)
Deferred	69,356	50,662
Income tax expense	61,513	43,425
Net earnings (loss)	(308,155)	185,657
Non-controlling interests	111,323	89,637
Non-controlling interests held by related party	(15,157)	(10,435)
Net effect of non-controlling interests	96,166	79,202
Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	(211,989)	264,859
Preferred shares, Series A and preferred shares, Series D dividend (note 15)	8,720	9,003
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp.	$ (220,709)	$ 255,856
Basic net earnings (loss) per share (USD per share)	$ (0.33)	$ 0.41
Diluted net earnings (loss) per share (USD per share)	$ (0.33)	$ 0.41
Regulated electricity distribution
Revenue
Other revenue	$ 1,277,409	$ 1,183,399
Expenses
Expenses	465,570	475,764
Regulated natural gas distribution
Revenue
Other revenue	686,744	525,897
Expenses
Expenses	340,792	194,174
Regulated water reclamation and distribution
Revenue
Other revenue	364,383	234,875
Expenses
Expenses	18,308	12,664
Non-regulated energy sales
Revenue
Other revenue	350,939	256,633
Expenses
Expenses	41,826	31,313
Other revenue
Revenue
Other revenue	85,680	73,338
Operating expenses
Expenses
Expenses	$ 851,489	$ 702,128

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net earnings (loss)	$ (308,155)	$ 185,657
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax expense of $2,423 and recovery of $3,219, respectively (notes 24(b)(iii) and 24(b)(iv))	(23,502)	(30,270)
Change in fair value of cash flow hedges, net of tax expense of $20,644 and recovery of $22,077, respectively (note 24(b)(ii))	(94,295)	(54,331)
Change in pension and other post-employment benefits, net of tax expense of $8,330 and $9,176, respectively (note 10)	27,761	42,051
OCI, net of tax	(90,036)	(42,550)
Comprehensive income (loss)	(398,191)	143,107
Comprehensive loss attributable to the non-controlling interests	(97,816)	(78,953)
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$ (300,375)	$ 222,060

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, net of tax (recovery) and expense	$ 2,423	$ (3,219)
Change in fair value of cash flow hedges, net of tax (recovery) and expense	20,644	(22,077)
Change in unrealized pension and other post-employment expense, net of tax expense and (recovery)	$ (8,330)	$ 9,176

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 57,623	$ 125,157
Trade and other receivables, net (note 4)	528,057	403,426
Fuel and natural gas in storage	95,350	74,209
Supplies and consumables inventory	129,571	103,552
Regulatory assets (note 7)	190,393	158,212
Prepaid expenses	58,653	54,548
Derivative instruments (note 24)	12,270	3,486
Other assets (note 11)	22,564	16,153
Assets, current, total	1,094,481	938,743
Property, plant and equipment, net (note 5)	11,944,885	11,042,446
Intangible assets, net (note 6)	96,683	105,116
Goodwill (note 6)	1,320,579	1,201,244
Regulatory assets (note 7)	1,081,108	1,009,413
Long-term investments (note 8)
Investments carried at fair value	1,344,207	1,848,456
Other long-term investments	462,325	495,826
Derivative instruments (note 24)	71,630	17,136
Deferred income taxes (note 18)	84,416	31,595
Other assets (note 11)	127,299	107,528
Assets	17,627,613	16,797,503
Current liabilities:
Accounts payable	186,080	185,291
Accrued liabilities	555,792	428,733
Dividends payable (note 15)	125,655	114,544
Regulatory liabilities (note 7)	69,865	65,809
Long-term debt (note 9)	423,274	356,397
Other long-term liabilities (note 12)	134,212	167,908
Derivative instruments (note 24)	32,491	38,569
Other liabilities	7,091	7,461
Liabilities, current, total	1,534,460	1,364,712
Long-term debt (note 9)	7,088,743	5,854,978
Regulatory liabilities (note 7)	558,317	510,380
Deferred income taxes (note 18)	565,639	530,187
Derivative instruments (note 24)	137,830	81,676
Pension and other post-employment benefits obligation (note 10)	125,579	238,054
Other long-term liabilities (note 12)	461,230	515,911
Liabilities, noncurrent, total	8,937,338	7,731,186
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party	307,856	306,537
Redeemable non-controlling interests	11,520	12,989
Redeemable non-controlling interests, total	319,376	319,526
Equity:
Preferred shares	184,299	184,299
Common shares (note 13(a))	6,183,943	6,032,792
Additional paid-in capital	9,413	2,007
Deficit	(997,945)	(288,424)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(160,063)	(71,677)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,219,647	5,858,997
Non-controlling interests (note 17)
Non-controlling interests - tax equity partnership units	1,225,608	1,377,117
Other non-controlling interests	333,362	64,807
Non-controlling interest, held by related party	57,822	81,158
Non-controlling interests, total	1,616,792	1,523,082
Total equity	6,836,439	7,382,079
Commitments and contingencies (note 22)
Liabilities and equity, total	$ 17,627,613	$ 16,797,503

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, 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 (loss)	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, net of cost	1,150,305			6,919		(6,371)	1,149,757
Common shares issued upon conversion of convertible debentures	16	16
Common shares issued upon public offering, net of tax effected cost	988,886	988,886
Common shares issued under employee share purchase plan	5,108	5,108
Share-based compensation	10,036			10,036
Common shares issued pursuant to share-based awards	(9,326)	10,983		(13,437)	(6,872)
Contract adjustment payments (note 7(a))	(222,378)			(62,240)	(160,138)
Non-controlling interest assumed on asset acquisition (note 3(d))	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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	(308,155)				(211,989)
Net income, non-controlling interests	96,166						(96,166)
Effect of redeemable non-controlling interests not included in equity (note 17)	(8,859)						(8,859)
OCI	(90,036)					(88,386)	(1,650)
Dividends declared and distributions to non-controlling interests	(458,028)				(396,965)		(61,063)
Dividends and issuance of shares under dividend reinvestment plan	0	97,801			(97,801)
Contributions received from non-controlling interests, net of cost	273,697						273,697
Common shares issued upon conversion of convertible debentures	6	6
Common shares issued upon public offering, net of tax effected cost	38,227	38,227
Common shares issued under employee share purchase plan	5,319	5,319
Share-based compensation	14,849			14,849
Common shares issued pursuant to share-based awards	(7,711)	9,798		(14,743)	(2,766)
Repurchase of non-controlling interest (note 17)	(4,949)			7,300			(12,249)
Ending Balance at Dec. 31, 2022	$ 6,836,439	$ 6,183,943	$ 184,299	$ 9,413	$ (997,945)	$ (160,063)	$ 1,616,792

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net earnings (loss)	$ (308,155)	$ 185,657
Adjustments and items not affecting cash:
Depreciation and amortization	455,520	402,963
Deferred taxes	(69,356)	(50,662)
Initial value and unrealized loss (gain) on derivative financial instruments	2,462	(5,609)
Share-based compensation	10,920	8,395
Cost of equity funds used for construction purposes	(1,896)	(637)
Change in value of investments carried at fair value	499,125	122,419
Pension and post-employment expense lower than contributions	(15,329)	(14,146)
Distributions received from equity investments, net of income	23,829	29,818
Impairment of assets	235,478	0
Other	8,116	1,290
Net change in non-cash operating items (note 23)	(221,618)	(522,022)
Net cash provided by (used in) operating activities, total	619,096	157,466
Financing activities
Increase in long-term debt	16,825,796	12,834,047
Repayments of long-term debt	(15,461,078)	(12,895,091)
Issuance of common shares, net of costs	43,546	985,619
Cash dividends on common shares	(378,597)	(307,115)
Dividends on preferred shares	(8,720)	(9,003)
Contributions from non-controlling interests and redeemable non-controlling interests	272,515	1,125,548
Production-based cash contributions from non-controlling interest	6,182	4,832
Distributions to non-controlling interests, related party (note 17)	(34,816)	(28,007)
Distributions to non-controlling interests	(43,919)	(12,830)
Payments upon settlement of derivatives	(28,913)	(33,782)
Shares surrendered to fund withholding taxes on exercised share options	(4,667)	(3,372)
Acquisition of non-controlling interest	(1,580)	0
Increase in other long-term liabilities	19,324	62,000
Decrease in other long-term liabilities	(94,837)	(49,130)
Net cash provided by (used in) financing activities, total	1,110,236	1,673,716
Investing activities
Additions to property, plant and equipment and intangible assets	(1,089,024)	(1,345,045)
Increase in long-term investments	(221,281)	(622,320)
Acquisitions of operating entities (note 3(c))	(632,797)	0
Increase in other assets	(26,527)	(43,306)
Receipt of principal on development loans receivable	178,300	206,319
Decrease in long-term investments	2,920	220
Other proceeds	0	6,023
Net cash provided by (used in) investing activities, total	(1,788,409)	(1,798,109)
Effect of exchange rate differences on cash and restricted cash	(1,127)	(1,702)
Increase (decrease) in cash, cash equivalents and restricted cash	(60,204)	31,371
Cash, cash equivalents and restricted cash, beginning of year	161,389	130,018
Cash, cash equivalents and restricted cash, end of year	101,185	161,389
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	272,734	219,025
Cash paid during the year for income taxes	10,962	5,019
Cash received during the year for distributions from equity investments	112,951	112,309
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	120,819	103,427
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	112,918	108,586
Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	$ 90,700	$ 90,821

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2022
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, 2022
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 regulatory assets or property, plant and equipment 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)) once 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 2022 2021 2022 2021 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 39 40 Equipment 5-54 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. Commonly owned facilities represent cost of $559,630 (2021 - $557,954) and accumulated depreciation of $75,820 (2021 - $59,857). The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. Total expenditures incurred on these facilities for the year ended December 31, 2022 were $110,268 (2021 - $143,255). (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. During the fourth quarter of 2022, the Company recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374 (note 5). 1. Significant accounting policies (continued) (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). 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 $57,241 (2021 - $59,877) and $15,024 (2021 - 18,344), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $19,752 (2021 - 16,772), operating expenses and amortization of $5,834 (2021 - $5,410) and interest expense of $1,723 (2021 - $2,055). (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. During the fourth quarter of 2022, the Renewable Energy Group recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities (as defined herein) from $282,726 to 206,816 (note 8(c)). 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, 2022 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, water and natural gas. 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 natural 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 re

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2022
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently adopted accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The Financial Accounting Standards Board (“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 adoption of this update did not have an impact on the consolidated financial statements. 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 adoption of this update did not have an impact on the consolidated financial statements. 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 FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. 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 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

Business acquisitions and dispo

Business acquisitions and disposition transactions	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Business acquisitions, development projects and disposition transactions	Business acquisitions, development projects and disposition transactions (a) Partial disposition of renewable assets On December 29, 2022, the Company closed the sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada. The transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. The Company retains control over the U.S. facilities. The Company will continue to oversee day-to-day operations and provide management services to each of the facilities. The cash proceeds of $277,500 for the U.S. facilities, which continue to be consolidated, were recorded as non-controlling interest (subject to certain potential future post-closing adjustments). The investment in the Blue Hill Wind Facility continues to be recorded as an equity-method investee. Cash proceeds of C$108,610 were received for the Blue Hill Wind Facility (subject to certain potential future post-closing adjustments). A gain on disposition of $62,828 was recognized and included in gain on sale of renewable assets on the consolidated statements of operations. (b) Pending acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc . On October 26, 2021, Liberty Utilities Co., an indirect subsidiary of AQN, entered into an agreement (the “Kentucky Acquisition Agreement”) with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company (“Kentucky Power”) and AE P 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”). On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduces the purchase price by $200,000. Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility in 20 eastern Kentucky counties and operating 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 Interconnection, L.L.C. Kentucky Power and Kentucky TransCo are both regulated by FERC. Closing of the Kentucky Power Transaction remains subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed). On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the proposed transaction. On February 14, 2023, a new application was filed with FERC for approval of the Kentucky Power Transaction. If the Kentucky Power Transaction has not closed by April 26, 2023, either party may, if certain requirements are met, terminate the Kentucky Acquisition Agreement in accordance with its terms . (c) Acquisition of New York American Water Company, Inc. 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”)). Liberty NY Water is a regulated water and wastewater utility, serving customers in eight counties in southeastern New York. 3. Business acquisitions, development projects and disposition transactions (continued) (c) Acquisition of New York American Water Company, Inc. (continued) A purchase price of $609,000 was paid for this acquisition. The acquisition related costs were expensed through the consolidated statement of operations (note 19). The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained. Working capital $ 4,820 Property, plant and equipment (i) 499,252 Goodwill (ii) 116,254 Regulatory assets (iii) 65,621 Other assets 4,507 Pension and other post-employment benefits (13,402) Regulatory liabilities (iii) (59,727) Other liabilities (8,028) Total net assets acquired $ 609,297 Cash and cash equivalents acquired 49 Total net assets acquired, net of cash and cash equivalents $ 609,248 The determination of the fair value of assets acquired and liabilities assumed is based upon management’s estimates and certain assumptions. i. Property, plant and equipment, consist of regulated water distribution infrastructure and wastewater collection and treatment facilities. They 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 Liberty NY Water’s assets is 64.74 years. ii. 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 of savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group. iii. The Company is subject to regulation by the New York State Public Service Commission (“NYPSC”), which has jurisdiction with respect to rates, service, accounting procedures, acquisitions, and other matters. 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 (note 7). As part of the approval of the acquisition of Liberty NY Water, a settlement agreement was approved which requires a full year of ownership prior to the filing of a new rate case. As a result, new rates would not come into effect until 2024. Liberty NY Water was consolidated upon acquisition. In 2022, Liberty NY Water generated approximately $125,370 in revenue and $21,776 operating income. (d) Acquisition of Mid-West Wind Facilities In 2021, the Empire District Electric Company (“Empire Electric System”), a wholly owned subsidiary of the Company, acquired 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”). Up to that point, the Company had held an interest in the construction projects for the North Fork Ridge Wind Facility and the Kings Point Wind Facility. The Empire Electric System paid consideration to third-party developers of $97,760 and obtained control of the facilities. In 2021, subsequent to acquisition, the tax equity investors provided additional funding of 3. Business acquisitions, development projects and disposition transactions (continued) (d) Acquisition of Mid-West Wind Facilities (continued) The following table summarizes the allocation of the aggregate purchase price to the 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 (e) 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 purchase price to 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 (f) 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. 3. Business acquisitions, development projects and disposition transactions (continued) (f) Maverick Creek Wind Facility and Sugar Creek Wind Facility (continued) The following table summarizes the allocation of the purchase price to 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 $570,578, respectively, were repaid subsequent to the acquisition of the remaining 50% interests in the facilities in 2021. A partial interest in the Sugar Creek Wind Facility was subsequently sold in December 2022 (note 3(a)).

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivableAccounts receivable as of December 31, 2022 include unbilled revenue of $149,015 (December 31, 2021 - $102,693) from the Company’s regulated utilities. Accounts receivable as of December 31, 2022 are presented net of allowance for doubtful accounts of $24,857 (December 31, 2021 - $19,327).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2022 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,119,514 $ 1,016,784 $ 3,102,730 Utility plant 8,640,224 990,975 7,649,249 Land 113,153 — 113,153 Equipment 111,707 50,904 60,803 Construction in progress Generation 196,287 — 196,287 Distribution and transmission 822,663 — 822,663 $ 14,003,548 $ 2,058,663 $ 11,944,885 5. Property, plant and equipment (continued) 2021 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,187,197 $ 751,219 $ 3,435,978 Utility plant 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 During the fourth quarter of 2022, the Company concluded that some assets in the Renewable Energy Group may not be recoverable due to declining forecasted energy prices in the Electric Reliability Council of Texas (“ERCOT”) market, mainly affecting the results of the Senate Wind Facility (which began commercial operations in 2012). Accordingly, the Company performed fair value analysis based on the income approach and recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value. Renewable generation facilities include cost of $111,192 (2021 - $114,868) and accumulated depreciation of $46,666 (2021 - $46,649) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,489 (2021 - $1,716). Utility plant includes cost of $3,076 (2021 - $3,076) and accumulated depreciation of $2,041 (2021 - $1,665) related to assets under finance lease. Utility plant includes cost of $2,033,391 (2021 - $2,018,039) and accumulated depreciation of $133,644 (2021 - $72,484) related to regulated generation assets. For the year ended December 31, 2022, contributions received in aid of construction of $1,299 (2021 - $6,376) have been credited to the cost of the assets. Interest and AFUDC capitalized to the cost of the assets in 2022 and 2021 are as follows: 2022 2021 Interest capitalized on non-regulated property $ 4,762 $ 3,313 AFUDC capitalized on regulated property: Allowance for borrowed funds 6,040 3,208 Allowance for equity funds 1,901 829 $ 12,703 $ 7,350

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2022 Cost Accumulated amortization Net book value Power sales contracts $ 56,926 $ 42,818 $ 14,108 Customer relationships 77,850 13,709 64,141 Interconnection agreements 10,098 1,851 8,247 Other (a) 10,338 151 10,187 $ 155,212 $ 58,529 $ 96,683 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 (a) Other includes brand names, water rights and miscellaneous intangibles Estimated amortization expense for intangible assets for each of the next year is $2,580 and $2,572 for years two to five. All goodwill pertains to the Regulated Services Group. 2022 2021 Opening balance $ 1,201,244 $ 1,208,390 Business acquisitions (note 3) 123,751 5,535 Foreign exchange (4,416) (12,681) Closing balance $ 1,320,579 $ 1,201,244

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2022
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. 7. Regulatory matters (continued) 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 March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22,800, for a revenue allowance of $224,056 and $226,160 in revenue for 2022 and 2023, respectively. The RA authorized a rate of return of 7.16%, comprised of a 62% equity and an 8.92% return on equity. The new rates are effective from April 1, 2022. In April, 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review. Empire Electric Missouri General Rate Case (GRC) and Securitization On April 6, 2022, the Missouri Public Service Commission (the "MPSC") approved an annual base rate increase of $35,516, as well as another $4,000 in revenues associated with the Empire Wind Facilities. The new rates became effective in June 2022. On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022 (note 7(a) and (b)). Briefing of the case is expected to be completed in April 2023. 7. Regulatory matters (continued) Utility State, Province or Country Regulatory Proceeding Type Details Empire Electric Kansas GRC On May 27, 2021, Empire Electric submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments resulting in a base rate decrease of $636, and granted Empire Electric's motion to withdraw its request to recover cost associated with the Empire Wind Facilities. New rates became effective in July 2022. Empire District Gas Company Missouri GRC In June 2022, the Commission approved an annual increase of $1,000 in base rate revenues. New rates became effective in August 2022. Empire Electric Oklahoma GRC On December 29, 2022 the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5,100. New Brunswick Gas Canada GRC On November 22, 2021, New Brunswick Gas filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Natural Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1,041 to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Board issued a Final Order and approved an annual revenue increase of $1,265 based on an ROE of 9.8%. New rates became effective January 1, 2023. Apple Valley Ranchos Water System California GRC Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,412. New rates are retroactive to July 1, 2022. Park Water System California GRC Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,105. New rates are retroactive to July 1, 2022. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2022 December 31, 2021 Regulatory assets Fuel and commodity cost adjustments (a) $ 388,294 $ 339,900 Retired generating plant (b) 174,609 185,073 Rate adjustment mechanism (c) 136,198 117,309 Income taxes (d) 97,414 79,472 Deferred capitalized costs (e) 90,121 62,599 Pension and post-employment benefits (f) 80,736 134,287 Environmental remediation (g) 70,529 81,802 Wildfire mitigation and vegetation management (h) 66,156 35,726 Clean energy and other customer programs (i) 28,145 25,857 Asset retirement obligation (j) 27,172 26,810 Debt premium (k) 24,888 34,204 Cost of removal (l) 11,084 — Rate review costs (m) 9,481 9,167 Long-term maintenance contract (n) 6,504 9,134 Other (o) 60,170 26,285 Total regulatory assets $ 1,271,501 $ 1,167,625 Less: current regulatory assets (190,393) (158,212) Non-current regulatory assets $ 1,081,108 $ 1,009,413 Regulatory liabilities Income taxes (d) $ 312,671 $ 295,720 Cost of removal (l) 191,173 191,981 Pension and post-employment benefits (f) 68,085 34,468 Fuel and commodity cost adjustments (a) 24,991 18,175 Clean energy and other customer programs (i) 11,572 14,829 Rate adjustment mechanism (c) 343 3,316 Other 19,347 17,700 Total regulatory liabilities $ 628,182 $ 576,189 Less: current regulatory liabilities (69,865) (65,809) Non-current regulatory liabilities $ 558,317 $ 510,380 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 does not earn a return on the regulatory balances except for carrying charges on fuel and commodity cost adjustments (a), rate adjustment mechanism (c), clean energy and other customer programs (i), and rate review costs of some jurisdictions (m). Carrying charges on regulatory balances are recognized on the consolidated statement of operations under Interest and other income (note 8) and are computed using only the debt component of the allowed returned. 7. Regulatory matters (continued) (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 fuel purchased differ from power or fuel 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 fuel in future periods ranging mostly from 6 to 24 months, 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. 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. In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, these two cases regarding the quantum financeable through securitization, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals - Western District on November 10, 2022. Briefing of the case is expected to be completed in April 2023. (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 net book value that may be retained as an asset on the balance sheet for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the 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 Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. AQN believes it is probable that the Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, has netted its regulatory liability against its retired generation facilities regulatory asset. As noted above under (a) Fuel and commodity cost adjustments , in March 2022, Empire Electric filed petitions for securitization of the impact of the Midwest Extreme Weather Event and the retirement of Asbury. 7. Regulatory matters (continued) (c) Rate adjustment mechanism Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth 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 over periods ranging from one (d) 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 over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. (e) 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. 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. (f) Pension and post-employment benefits To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of 3 to 8 years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980, Regulated Operations . The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement 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 had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (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. 7. Regulatory matters (continued) (g) Environmental remediation Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap. (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. The assets are recovered over two years. (i) 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. The assets are generally included in rate base and recovered over periods of six (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 once expenditures are made. (k) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (l) 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 (or asset) tracks the amounts that have been collected from customers net of costs incurred to date. (m) Rate review costs The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one (n) 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 generally included in rate base and recovered over five years. (o) Other The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs, and equipment costs, which are probable of recovery under existing mechanisms.

Long-term investments

Long-term investments	12 Months Ended
	Dec. 31, 2022
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: December 31, 2022 December 31, 2021 Long-term investments carried at fair value Atlantica (a) $ 1,268,140 $ 1,750,914 Atlantica Yield Energy Solutions Canada Inc. (b) 74,083 95,246 Other 1,984 2,296 $ 1,344,207 $ 1,848,456 Other long-term investments Equity-method investees (c) $ 381,802 $ 433,850 Development loans receivable from equity-method investees (d) 52,923 31,468 San Antonio Water System and other (e) 27,600 30,508 $ 462,325 $ 495,826 Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows: Year ended December 31, 2022 2021 Fair value gain (loss) on investments carried at fair value Atlantica $ (482,774) $ (107,030) Atlantica Yield Energy Solutions Canada Inc. (16,018) (15,915) Other (333) 526 $ (499,125) $ (122,419) Dividend and interest income from investments carried at fair value Atlantica $ 86,664 $ 83,971 Atlantica Yield Energy Solutions Canada Inc. 20,443 17,222 Other 36 330 $ 107,143 $ 101,523 Other long-term investments Equity method loss (c) $ (21,416) $ (26,337) Impairment of equity-method investee (c) (75,910) — Interest and other income 24,102 20,776 $ (73,224) $ (5,561) Fair value change, income (loss) and impairment expense related to long-term investments $ (465,206) $ (26,457) (a) Investment in Atlantica Liberty (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 42% (2021 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2022 is $1,167,444 (2021 - $1,167,444). T he Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations. 8. Long-term investments (continued) (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. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment 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, AQN has the option to exchange approxima tely 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, 2022, the Company's maximum exposure to loss is $74,083 (2021 - $95,246 ), which represents the fair value of the investment. (c) Equity-method investees The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value o f $310,103 (2021 - $375,460). The Regulated Services Group has non-controlling interest of $56,199 (2021 - 37,492) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $15,500 and (2021 - $20,898) is reported under Corporate. Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. Economic interest Capacity Texas Coastal Wind Facilities 51 % 861 MW Blue Hill Wind Facility 20 % 175 MW Red Lily Wind Facility 75 % 26.4 MW Val-Eo Wind Facility 50 % 24 MW During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. As at December 31, 2022, the Company had issued $113,630 (2021 - $119,750) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to 206,816 . Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value. Development: 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 as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. 8. Long-term investments (continued) (c) Equity-method investees (continued) Construction: The Renewable Energy Group has 50% equi ty interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The transfers resulted i n a gain of $nil (2021 - $26,182) . The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. Changes in the carrying value of equity method investees were as follows: 2022 2021 Carrying value, January 1 $ 433,850 $ 186,452 Additional Investments 110,441 418,434 Net loss attributable to AQN (21,416) (26,337) Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733 Operating projects bought back by AQN — (129,075) Dividend received (1,183) (2,981) Impairment (75,910) — Reclassification during the period (note 8(e)) — (25,634) Other 3,130 5,258 Carrying value, December 31 $ 381,802 $ 433,850 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge, Summarized combined information for AQN's equity method investees as at December 31 is as follows: 2022 2021 Total assets $ 2,740,132 $ 2,126,934 Total liabilities 1,507,079 945,971 Net assets 1,233,053 1,180,963 AQN's ownership interest in the entities 332,663 327,555 Difference between investment carrying amount and underlying equity in net assets (a) 49,139 106,295 Total carrying value $ 381,802 $ 433,850 (a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs. 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows: 2022 2021 Revenue $ 65,025 $ 20,262 Net loss $ (31,070) $ (46,293) Other comprehensive income (loss) (a) $ (130,729) $ 15,177 Net loss attributable to AQN $ (21,416) $ (26,337) Other comprehensive loss attributable to AQN (a) $ (67,110) $ 7,733 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge, Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction 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, 2022, 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, 2022 am ounts to $8,824 (2021 - $4,612). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2022 2021 AQN's maximum exposure in regards to VIEs Carrying amount $ 122,752 $ 86,202 Development loans receivable (d) 52,923 31,468 Performance guarantees and other commitments on behalf of VIEs 658,224 409,232 $ 833,899 $ 526,902 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 Renewable Energy Group 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 on the twelfth anniversary of the development agreement or commercial operation date. (e) San Antonio Water System and other The Company no longer has significant influe nce over its 20% interest in the San Antonio Water System (“SAWS”), and therefore has discontinued the equity method of accountin

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Senior unsecured revolving credit facilities (a) — 2024-2027 N/A $ 351,786 $ 368,806 Senior unsecured bank credit facilities and delayed draw term facility (b) — 2023-2031 N/A 773,643 141,956 Commercial paper — 2023 N/A 407,000 338,700 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,142,814 1,140,801 Senior unsecured notes (d) 3.39 % 2023-2047 $ 1,505,000 1,496,101 1,689,792 Senior unsecured utility notes 6.34 % 2023-2035 $ 142,000 154,271 155,571 Senior secured utility bonds 4.71 % 2026-2044 $ 556,209 554,822 558,177 Canadian dollar borrowings Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 882,899 1,099,403 Senior secured project notes 10.21 % 2027 C$ 20,349 15,024 18,344 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds 4.05 % 2028-2040 CLF 1,637 77,206 77,963 $ 5,855,566 $ 5,589,513 Subordinated U.S. dollar borrowings Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 291,238 — Subordinated unsecured notes (f) 5.56 % 2078-2082 $ 1,387,500 1,365,213 621,862 $ 7,512,017 $ 6,211,375 Less: current portion (423,274) (356,397) $ 7,088,743 $ 5,854,978 Short-term obligations of $705,386 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) The following table sets out the bank credit facilities available to AQN and its operating groups as at December 31, 2022: December 31, 2022 December 31, 2021 Revolving and term credit facilities $ 4,513,300 $ 3,217,000 Funds drawn on facilities/ commercial paper issued (1,532,500) (849,600) Letters of credit issued (465,200) (317,200) Liquidity available under the facilities 2,515,600 2,050,200 Undrawn portion of uncommitted letter of credit facilities (226,900) (224,000) Cash on hand 57,623 125,157 Total liquidity and capital reserves $ 2,346,323 $ 1,951,357 Recent financing activities: (a) Senior unsecured revolving credit facilities Regulated Services Group On April 29, 2022, the Regulated Services Group entered into two new senior unsecured revolving credit facilities: a $1,000,000 senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the “Long-Term Regulated Services Credit Facility”) and a $500,000 short-term senior unsecured revolving credit facility maturing originally on March 31, 2023 and extended to February 28, 2024, subsequent to year-end. Subject to the terms and conditions therein, the Long-Term Regulated Services Credit Facility may be extended for two additional one-year periods. In conjunction with the new facilities, the Regulated Services Group’s $500,000 senior unsecured syndicated revolving credit facility was cancelled. On December 23, 2022, the Regulated Services Group amended and restated its $75,000 senior unsecured revolving credit facility in Bermuda with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25,000 senior unsecured bilateral revolving credit facility in Bermuda that matures on June 24, 2024. Renewable Energy Group On July 22, 2022, the Renewable Energy Group amended and restated its $500,000 senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods. On July 22, 2022, the Renewable Energy Group entered into a new $250,000 uncommitted bilateral letter of credit facility. On November 8, 2022, the Renewable Energy Group's $350,000 uncommitted letter of credit facility was amended and restated with a new maturity date of June 30, 2024. (b) Senior unsecured bank credit facilities On November 30, 2022, the Regulated Services Group amended and restated its $1,100,000 senior unsecured delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023. (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. 9. Long-term debt (continued) Recent financing activities (continued): (c) U.S dollar senior unsecured notes (Green Equity Units) (continued) 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)). 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 wil l 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) U.S. dollar senior unsecured notes On April 30, 2022, the Company repaid a $80,000 senior unsecured note on its maturity. On August 1, 2022, the Company repaid a $115,000 senior unsecured note on its maturity. Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity. (e) Canadian dollar senior unsecured notes 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)). 9. Long-term debt (continued) Recent financing activities (continued): (f) Subordinated unsecured notes 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, 2022, the Company had accrued $70,274 in interest expense (2021 - $49,806). Interest expense for the years ended December 31 consists of the following : 2022 2021 Long-term debt $ 261,535 $ 217,123 Commercial paper, credit facility draws and related fees 43,015 17,065 Accretion of fair value adjustments (16,547) (18,174) Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521) Other 1,373 61 $ 278,574 $ 209,554 Principal payments due in the next five years and thereafter are as follows: 2023 2024 2025 2026 2027 Thereafter Total $ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2022
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 2022 were $12,126 (2021 - $10,836). 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 2022 2021 2022 2021 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 765,618 $ 834,913 $ 292,646 $ 306,524 Projected benefit obligation assumed from business combination 87,933 — 5,195 — Plan Settlements (112) (1,294) — — Service cost 16,309 14,673 6,277 7,307 Interest cost 24,787 20,676 9,146 8,048 Actuarial gain (198,074) (36,597) (82,991) (18,977) Contributions from retirees — — 2,220 2,040 Plan amendments — 237 (2,452) 310 Medicare Part D — — 367 373 Benefits paid (68,197) (66,800) (13,078) (12,979) Foreign exchange (129) (190) — — Projected benefit obligation, end of year $ 628,135 $ 765,618 $ 217,330 $ 292,646 Change in plan assets Fair value of plan assets, beginning of year 648,864 629,157 192,375 176,616 Plan assets acquired in business combination 74,532 — 8,577 — Actual return on plan assets (109,118) 58,721 (30,105) 15,200 Employer contributions 23,296 29,058 11,811 11,178 Plan Settlements (112) (1,294) — — Contributions from retirees — — 2,220 1,988 Medicare Part D subsidy receipts — — 367 372 Benefits paid (68,197) (66,800) (13,078) (12,979) Foreign exchange (10) 22 — — Fair value of plan assets, end of year $ 569,255 $ 648,864 $ 172,167 $ 192,375 Unfunded status $ (58,880) $ (116,754) $ (45,163) $ (100,271) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 12,264 11,751 14,218 11,879 Current liabilities (1,907) (1,902) (3,039) (699) Non-current liabilities (69,237) (126,603) (56,342) (111,451) Net amount recognized $ (58,880) $ (116,754) $ (45,163) $ (100,271) The accumulated benefit obligation for the pension and OPEB plans was $815,589 and $1,080,685 as of December 31, 2022 and 2021, 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 2022 2021 2022 2021 Accumulated benefit obligation $ 413,041 $ 489,043 $ 198,463 $ 274,649 Fair value of plan assets $ 364,229 $ 396,679 $ 139,368 $ 162,592 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2022 2021 2022 2021 Projected benefit obligation $ 489,140 $ 580,841 $ 198,463 $ 274,649 Fair value of plan assets $ 417,994 $ 452,333 $ 139,368 $ 162,592 (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 losses (gains) Balance, January 1, 2021 $ 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) 334 Amortization due to plan settlements (210) — — — Reclassification to regulatory accounts 31,670 (752) 14,816 — Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 310 Additions to AOCI (47,473) — (41,527) (24) Amortization in current period (3,429) 1,584 56 (2,476) Amortization due to plan settlements 15 — — — Reclassification to regulatory accounts 34,409 (752) 23,551 — Balance, December 31, 2022 $ (671) $ (3,363) $ (33,550) $ (2,190) The movements related to pension and OPEB in AOCI for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(f)). 10. Pension and other post-employment benefits (continued) (c) Assumptions Weighted average assumptions used to determine net benefit obligation for 2022 and 2021 were as follows: Pension benefits OPEB 2022 2021 2022 2021 Discount rate 5.48 % 2.94 % 5.49 % 3.00 % Interest crediting rate (for cash balance plans) 4.50 % 4.00 % N/A N/A Rate of compensation increase 3.70 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.00 % 5.88 % Age 65 and after 6.00 % 5.88 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2033 2031 The mortality assumption for December 31, 2022 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, 2022 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B. In selecting an assumed discount rate, the Company uses a modelling 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 modelling 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 2022 and 2021 were as follows: Pension benefits OPEB 2022 2021 2022 2021 Discount rate 2.94 % 2.49 % 3.00 % 2.58 % Expected return on assets 6.19 % 6.20 % 6.48 % 4.79 % Rate of compensation increase 3.91 % 3.99 % n/a n/a Health care cost trend rate Before Age 65 5.88 % 5.12 % Age 65 and after 5.88 % 5.12 % Assumed ultimate medical inflation rate 4.75 % 4.05 % 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 2022 2021 2022 2021 Service cost $ 16,309 $ 14,673 $ 6,277 $ 7,307 Non-service costs Interest cost 24,787 20,676 9,146 8,048 Expected return on plan assets (41,226) (35,972) (11,359) (10,052) Amortization of net actuarial loss 3,452 13,126 (56) 2,021 Amortization of prior service credits (1,584) (1,626) 24 11 Amortization due to plan settlements (15) 198 — — Amortization of regulatory accounts 22,951 19,665 4,829 218 $ 8,365 $ 16,067 $ 2,584 $ 246 Net benefit cost $ 24,674 $ 30,740 $ 8,861 $ 7,553 (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 41 % 30% -100% Debt securities 49 % 20% - 60% Other 10 % 0% - 20% 100 % The fair values of investments as of December 31, 2022, by asset category, are as follows: Asset class 2022 Percentage Equity securities $ 317,088 43 % Debt securities 356,654 48 % Other 67,680 9 % $ 741,422 100 % As of December 31, 2022, 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, 2022 were valued using level 1 inputs except for 21,904 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, 2022 $ 17,314 Contributions into funds 4,781 Return on assets 2,094 Distributions (2,285) Balance, December 31, 2022 $ 21,904 (f) Cash flows The Company expects to contribute $22,386 to its pension plans and $9,819 to its post-employment benefit plans in 2023. The expected benefit payments over the next ten years are as follows: 2023 2024 2025 2026 2027 2028-2032 Pension plan $ 48,174 $ 47,428 $ 49,794 $ 50,585 $ 50,433 $ 259,082 OPEB $ 11,483 $ 12,025 $ 12,548 $ 12,925 $ 13,479 $ 72,684

Other assets

Other assets	12 Months Ended
	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2022 2021 Restricted cash $ 43,562 $ 36,232 Pension and OPEB plan assets (note 10(a)) 26,482 23,630 Long-term deposits and cash collateral 22,537 14,713 Income taxes recoverable 7,100 7,649 Deferred financing costs (a) 28,586 30,544 Other (b) 21,596 10,913 $ 149,863 $ 123,681 Less: current portion (22,564) (16,153) $ 127,299 $ 107,528 (a) Deferred financing costs Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units (note 9(c)) that will be recorded against the common shares when issued. (b) Other

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2022 2021 Contract adjustment payments (a) $ 113,876 $ 187,580 Asset retirement obligations (b) 116,584 142,147 Advances in aid of construction (c) 88,546 82,584 Environmental remediation obligation (d) 42,457 55,224 Customer deposits (e) 34,675 32,629 Unamortized investment tax credits (f) 17,649 17,439 Deferred credits and contingent consideration (g) 39,498 43,495 Preferred shares, Series C (h) 12,072 13,348 Hook up fees (i) 32,463 21,904 Lease liabilities (note 1(q)) 21,834 22,512 Contingent development support obligations (j) 8,824 4,615 Note payable to related party (k) 25,808 25,808 Other 41,156 34,534 $ 595,442 $ 683,819 Less: current portion (134,212) (167,908) $ 461,230 $ 515,911 (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 natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural 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: 2022 2021 Opening balance $ 142,147 $ 79,968 Obligation assumed 793 57,067 Retirement activities (27,980) (4,133) Accretion 4,589 4,381 Change in cash flow estimates (2,965) 4,864 Closing balance $ 116,584 $ 142,147 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 fro m 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 2022, $1,299 (2021 - $6,376) 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 natural 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. The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities wil l be $48,346 (2021 - $57,167), which at discount rates ranging from 3.4% to 4.2% represents the recorded accrual of $42,457 as of December 31, 2022 (2021 - $55,224 ). Approximately $27,410 is expected to be incurred over the next three years, with the balance of cash flows to b e incurred over the follow ing 30 y ears. Changes in the environmental remediation obligation are as follows: 2022 2021 Opening balance $ 55,224 $ 69,383 Remediation activities (5,243) (9,865) Accretion 2,167 1,025 Changes in cash flow estimates 1,344 2,265 Revision in assumptions (11,035) (7,584) Closing balance $ 42,457 $ 55,224 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 perio d of 7 years and, accordingly, as of December 31, 2022, the Company has reflected a regulatory asset o f $70,529 (2021 - $81,802) for the MGP and re lated sites (note 7(g)) . (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 Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid. In 2021, the Company recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(f)). (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: 2023 $ 1,245 2024 1,443 2025 1,459 2026 1,316 2027 1,262 Thereafter to 2031 4,654 Redemption amount 3,943 $ 15,322 Less: amounts representing interest (3,250) $ 12,072 Less current portion (1,245) $ 10,827 (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. 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, 2022
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2022 2021 Common shares, beginning of year 671,960,276 597,142,219 Public offering 2,861,709 67,611,465 Dividend reinvestment plan 7,676,666 6,184,686 Exercise of share-based awards (c) 1,115,398 1,020,020 Conversion of convertible debentures 754 1,886 Common shares, end of year 683,614,803 671,960,276 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 2025. 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 a price of $14.63 (C$18.15)per share for total gross proceeds of $642,664 (C$800,052) before issuance costs of $26,173 (C$32,583), which AQN intends to use to partially finance the Kentucky Power Transaction; provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Company has used the net proceeds to repay certain indebtedness of AQN and its subsidiaries (note 3(b)). Forward contracts were used to manage the Canadian dollar risk (note 24(b)(iv)). 13. Shareholders’ capital (continued) (a) Common shares (continued) (ii) At-the-market equity program On August 15, 2022, AQN re-established its at-the-market equity program (“ATM program”) which allows the Company to issue up to $500,000 (or the equivalent in Canadian dollars) 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 Toronto Stock Exchange (“TSX”), the New York Stock Exchange (“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, 2022, the Company issued 2,861,709 common shares under the ATM program at an average price of $13.94 per common share for gross proceeds of $38,923 ($38,534 net of commissions). Other related costs were $558. The Company has issued since the inception of the ATM program in 2019 a cumulative total of 36,814,536 common shares at an average price of $15.00 per share for gross proceeds of $551,086 ($544,295 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4,843. (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Subsequent to year-end, AQN issued an addition al 4,370,289 co mmon shares under the dividend reinvestment plan. Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Dividends will only be paid in cash while the reinvestment plan is suspended. (b) Preferred shares AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2022 and 2021: Preferred shares Number of shares Price per share Carrying amount C$ 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. 13. Shareholders’ capital (continued) (b) Preferred shares (continued) 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)). (c) Share-based compensation For the year ended December 31, 2022, AQN recorded $10,920 (2021 - $8,395) in total share-based compensation expense as follows: 2022 2021 Share options $ 980 $ 939 Director deferred share units 960 821 Employee share purchase 562 592 Performance and restricted share units 8,418 6,043 Total share-based compensation $ 10,920 $ 8,395 The compensation expense is recorded with operating expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant. As of December 31, 2022, total unrecognized compensation costs related to non-vested share-based awards was $10,732 and is expected to be recognized over a period of 1.8 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: 2022 2021 Risk-free interest rate 1.9 % 1.1 % Expected volatility 23 % 23 % Expected dividend yield 4.3 % 4.1 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.44 C$ 2.46 Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2021 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 Granted 646,090 19.11 7.22 — Exercised (40,074) 13.92 5.95 103 Forfeited (19,764) 19.11 — — Balance, December 31, 2022 2,626,780 C$ 16.02 5.63 C$ — Exercisable, December 31, 2022 2,052,946 C$ 17.35 5.63 C$ — (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, 2022, a total of 414,338 common shares (2021 - 355,096 ) 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, 2022, a total of 120,513 DSUs (2021 - 73,467) were issued and 5,176 DSUs (2021 - 87,582 ) were settled in exchange for 2,403 common shares issued from treasury, and 2,773 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2022, 645,714 (2021 - 530,378) 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, 2021 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 Granted, including dividends 1,090,457 17.99 2.00 17,524 Exercised (1,221,620) 12.62 — 23,636 Forfeited (202,799) 18.94 — 418 Balance, December 31, 2022 2,109,710 C$ 18.38 1.76 C$ 18,608 Exercisable, December 31, 2022 769,458 C$ 18.70 0.10 C$ 6,787 (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, 2022, 55,445 (2021 - 56,686) bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 178,368 (2021 - 152,564) bonus deferral RSUs in exchange for 82,886 (2021 - 70,571) common shares issued from treasury, and 95,482 (2021- 81,993) RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2022, 158,486 (2021 - 281,411) bonus deferral RSUs were outstanding.

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2022
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, 2021 $ (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 (6,371) — — (6,371) Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677) Other comprehensive income (loss) (18,013) (128,838) 23,722 (123,129) Amounts reclassified from AOCI to the consolidated statement of operations (5,489) 34,543 4,039 33,093 Net current period OCI $ (23,502) (94,295) 27,761 $ (90,036) OCI attributable to the non-controlling interests 1,650 — — 1,650 Net current period OCI attributable to shareholders of AQN $ (21,852) (94,295) 27,761 $ (88,386) Balance, December 31, 2022 $ (98,467) $ (97,809) $ 36,213 $ (160,063) 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.

Dividends

Dividends	12 Months Ended
	Dec. 31, 2022
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: 2022 2021 Dividend Dividend per share Dividend Dividend per share Common shares $ 486,043 $ 0.7130 $ 423,023 $ 0.6669 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, 2022
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 2022, the Company charged its equity-method investees $63,861 (2021 - $25,778). Additionally, Liberty Development JV Inc., an equity-method investee (note 8(c)) 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 $12,628 (2021 - $2,036). Investment and acquisition transactions with equity-method investments are described in note 8(c). In addition, during 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 f or $2,662 and working capital of $1,507. The loan at that date between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership. 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) Non-controlling interest and redeemable non-controlling interest held by related party Non-controlling interest and redeemable non-controlling interest held by related party are described in note 17. (c) Transactions with Atlantica During 2021, the Company sold Colombian solar assets to Atlantica for consideration of $23,863, with a gain on sale of $878, and contingent consideration of $2,600. The contingency was resolved in 2022 and, as a result, an additional gain of $1,200 was 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, 2022
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: 2022 2021 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 108,695 $ 88,417 Non-controlling interests - redeemable tax equity partnership units 6,298 6,902 Other net earnings attributable to: Non-controlling interests (3,670) (5,682) $ 111,323 $ 89,637 Redeemable non-controlling interest, held by related party (15,157) (10,435) Net effect of non-controlling interests $ 96,166 $ 79,202 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). 17. Non-controlling interests and redeemable non-controlling interests (continued) Non-controlling interests Non-controlling interests - tax equity partnership units (a) Other non-controlling interests (b) Non-controlling interests held by related parties (c) 2022 2021 2022 2021 2022 2021 Opening balance $ 1,377,117 $ 388,253 $ 64,807 $ 11,234 $ 81,158 $ 59,125 Net earnings attributable to NCI (105,371) (87,422) 345 3,354 — — Contributions received, net 6,182 1,058,929 267,515 51,451 — 39,376 Dividends and distributions declared (40,086) (11,795) — (1,021) (20,978) (17,793) Repurchase of non-controlling interest (12,249) — — — — — Non-controlling interest assumed on asset acquisition — 29,141 — — — — OCI 15 11 695 (211) (2,358) 450 Closing balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158 (a) Non-controlling interests - tax equity partnership units The Company obtained control of t he three Mid-West Wind Facilities, Sugar Creek Wind Facility and Maverick Creek Wind Facility in 202 1 (notes 3(d) and 3(f)), assuming non-controlling interest of $29,141. Post acquisition in 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. (b) Other non-controlling interests On December 29, 2022, the Company sold a 49% non-controlling interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois. The consideration of $277,500 was recorded as an increase to non-controlling interest, except for a portion of $5,000, which is subject to refund if some conditions are met and as such was recorded as redeemable non-controlling interest. 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 indirectly owns approximately 64% of the outstanding shares of ESSAL and continues to consolidate ESSAL's operations. (c) Non-controlling interest held by related parties In November 2021, Liberty Development JV Inc. invest ed $39,376 i n Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. In May 2019, AYES Canada acquired an interest in a consolidated subsidiary of the Company for $96,752 (C$130,103) (note 8(b)). The investment by AYES Canada and Liberty Development JV Inc. are presented as a non-controlling interest held by related parties. 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, 2022. 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 ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit 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 or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects as redeemable non-controlling interest held by related party. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2022 2021 2022 2021 Opening balance $ 306,537 $ 306,316 $ 12,989 $ 20,859 Net earnings attributable to NCI 15,157 10,435 (6,298) (6,902) Contributions, net of costs — — 5,000 — Dividends and distributions declared (13,838) (10,214) (171) (968) Closing balance $ 307,856 $ 306,537 $ 11,520 $ 12,989

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2022
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 of 26.5% (2021 - 26.5%). The differences are as follows: 2022 2021 Expected income tax expense at Canadian statutory rate $ (97,962) $ 37,691 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (55,315) (47,600) Adjustments from investments carried at fair value 51,314 2,709 Non-controlling interests share of income 30,025 25,135 Change in valuation allowance 41,702 (118) Non-deductible acquisition costs 1,341 3,733 Acquisition related state deferred tax adjustments 5,998 — Capital gain rate differential on disposal of renewable assets (7,340) — Tax credits (18,440) (49,415) Adjustment relating to prior periods (1,390) 1,333 Deferred income taxes on regulated income recorded as regulatory assets (2,155) (3,807) Amortization and settlement of excess deferred income tax (14,855) (16,778) Other 5,564 3,692 Income tax recovery $ (61,513) $ (43,425) 18. Income taxes (continued) For the years ended December 31, 2022 and 2021, earnings (loss) before income taxes consist of the following: 2022 2021 Canada (1) $ (363,050) $ (60,848) U.S. (37,322) 153,719 Other regions 30,704 49,361 $ (369,668) $ 142,232 (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, 2022 Canada $ 4,184 $ (74,595) $ (70,411) United States 1,579 6,183 7,762 Other regions 2,080 (944) 1,136 $ 7,843 $ (69,356) $ (61,513) 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) 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, 2022 and 2021 are presented below: 2022 2021 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 878,000 $ 761,666 Pension and OPEB 16,845 46,580 Environmental obligation 12,118 15,271 Regulatory liabilities 156,285 166,939 Other 61,917 64,460 Total deferred income tax assets $ 1,125,165 $ 1,054,916 Less: valuation allowance (107,583) (27,471) Total deferred tax assets $ 1,017,582 $ 1,027,445 Deferred tax liabilities: Property, plant and equipment $ 846,331 $ 782,829 Outside basis differentials 315,581 412,665 Regulatory accounts 303,059 300,072 Other 33,834 30,471 Total deferred tax liabilities $ 1,498,805 $ 1,526,037 Net deferred tax liabilities $ (481,223) $ (498,592) Consolidated balance sheets classification: Deferred tax assets $ 84,416 $ 31,595 Deferred tax liabilities (565,639) (530,187) Net deferred tax liabilities $ (481,223) $ (498,592) The valuation allowance for deferred tax assets as of December 31, 2022 was $107,583 (2021 - $27,471). 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. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as Management projections for growth. Primarily as a result of the impairment charges discussed in notes 5 and 8(c), the U.S. entities in the Renewable Energy Group, which have historically been in an overall deferred tax liability position, are in an overall deferred tax asset position as at December 31, 2022. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded that, during the fourth quarter of 2022, it was no longer probable that the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group. AQN’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group, including material impairment charges recorded on certain assets, insufficient taxable temporary differences to allow the full utilization of the deferred tax asset, insufficient forecasted taxable income and a historical 3 year cumulative loss position. 18. Income taxes (continued) The following table illustrates the annual movement in the deferred tax valuation allowance: 2022 2021 Beginning balance $ 27,471 $ 29,824 Charged to income tax expense (recovery) 41,702 (118) Charged (reduction) to OCI 40,613 (1,707) Reductions to other accounts (2,203) (528) Ending balance $ 107,583 $ 27,471 As of December 31, 2022, 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 2023—2027 2028+ Total Canada $ 3,261 $ 728,529 $ 731,790 US 9,962 1,707,139 1,717,101 Total non-capital loss carryforward $ 13,223 $ 2,435,668 $ 2,448,891 Tax credits $ 4,428 $ 151,676 $ 156,104 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 l y $824,052 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, 2022
Other Income and Expenses [Abstract]
Other net losses	Other net losses Other net losses consist of the following: 2022 2021 Acquisition and transition-related costs $ 17,442 $ 14,507 Other (a) 3,949 8,442 $ 21,391 $ 22,949 (a) Other Other losses primarily consist of costs pertaining to a condemnation proceeding, and miscellaneous asset write-downs, net of miscellaneous gains. Other losses in 2021 also included an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts.

Basic and diluted net earnings

Basic and diluted net earnings (loss) per share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share, Basic and Diluted EPS [Abstract]
Basic and diluted net earnings (loss) per share	Basic and diluted net earnings (loss) 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: 2022 2021 Net earnings (loss) attributable to shareholders of AQN $ (211,989) $ 264,859 Preferred shares, Series A dividend 4,786 4,942 Preferred shares, Series D dividend 3,934 4,061 Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ (220,709) $ 255,856 Weighted average number of shares Basic 677,862,207 622,347,677 Effect of dilutive securities — 6,600,185 Diluted 677,862,207 628,947,862

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2022
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, water distribution and wastewater collection, and natural gas 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 energy generation assets. 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. Year ended December 31, 2022 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,328,536 $ 350,939 $ — $ 2,679,475 Other revenue 55,732 28,447 1,501 85,680 Fuel, power and water purchased 824,670 41,826 — 866,496 Net revenue 1,559,598 337,560 1,501 1,898,659 Operating expenses 736,515 114,463 511 851,489 Administrative expenses 46,484 26,424 7,324 80,232 Depreciation and amortization 317,300 137,203 1,017 455,520 Asset impairment expense — 159,568 — 159,568 Loss on foreign exchange — — 13,833 13,833 459,299 (100,098) (21,184) 338,017 Gain on sale of renewable assets — 64,028 — 64,028 Operating income (loss) 459,299 (36,070) (21,184) 402,045 Interest expense (113,482) (64,285) (100,807) (278,574) Income (loss) from long-term investments 21,884 15,254 (502,344) (465,206) Other (14,765) (570) (12,598) (27,933) Earnings (loss) before income taxes $ 352,936 $ (85,671) $ (636,933) $ (369,668) Property, plant and equipment $ 8,554,938 $ 3,360,687 $ 29,260 $ 11,944,885 Investments carried at fair value 1,984 1,342,223 — 1,344,207 Equity-method investees 56,199 310,103 15,500 381,802 Total assets 12,109,575 5,251,933 266,105 17,627,613 Capital expenditures $ 908,676 $ 180,348 $ — $ 1,089,024 (1) Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2021 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,944,171 $ 256,633 $ — $ 2,200,804 Other revenue 53,441 18,339 1,558 73,338 Fuel and power purchased 682,602 31,313 — 713,915 Net revenue 1,315,010 243,659 1,558 1,560,227 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 4,371 399,529 (10,315) (5,175) 384,039 Gain on sale of renewable assets — 29,063 — 29,063 Operating income (loss) 399,529 18,748 (5,175) 413,102 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) (2,956) (7,726) (34,859) 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 10,524,466 6,123,888 149,149 16,797,503 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 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. 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: 2022 2021 Revenue United States $ 2,232,959 $ 1,790,539 Canada 175,005 157,854 Other regions 357,191 325,749 $ 2,765,155 $ 2,274,142 Property, plant and equipment United States $ 10,351,736 $ 9,464,716 Canada 848,560 882,454 Other regions 744,589 695,276 $ 11,944,885 $ 11,042,446 Intangible assets United States $ 18,818 $ 23,575 Canada 19,038 21,780 Other regions 58,827 59,761 $ 96,683 $ 105,116 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, 2022
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. 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. On October 14, 2021, the Court issued the Final Statement of Decision. The Court signed and entered an Order of Dismissal and Judgment on November 12, 2021. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. On August 2, 2022, the Court issued a ruling awarding Liberty Apple Valley approximately $13,222 in attorney’s fees and litigation costs. The Town filed a notice of appeal of the fee award on August 22, 2022. The Town’s appeal of the condemnation judgment and fee award have been consolidated into one appellate docket. The Company has not recorded the possible recovery of these attorney’s fees and litigation costs. 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 remains under investigation, and CAL FIRE has not yet released its final report. There are currently 17 active lawsuits that name certain subsidiaries of the Company as defendants in connection with the Mountain View Fire, as well as one non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs. Twelve 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 (one of these twelve lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). In another lawsuit, County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In four 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(b) and 8, the following significant commitments exist as of December 31, 2022. AQN has outstanding purchase commitments for power purchases, natural 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) $ 89,846 $ 32,490 $ 32,726 $ 12,274 $ 12,520 $ 142,586 $ 322,442 Natural gas supply and service agreements (ii) 113,775 81,719 57,014 40,372 31,457 188,138 512,475 Service agreements 67,477 57,886 55,835 49,596 46,511 298,516 575,821 Capital projects 7,163 — — — — — 7,163 Land easements 13,295 13,316 13,503 13,667 13,837 463,785 531,403 Total $ 291,556 $ 185,411 $ 159,078 $ 115,909 $ 104,325 $ 1,093,025 $ 1,949,304 (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, 2022. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Natural gas supply and service agreements: AQN’s natural 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, 2022
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: 2022 2021 Accounts receivable $ (124,631) $ (56,751) Fuel and natural gas in storage (21,140) (43,642) Supplies and consumables inventory (24,088) 445 Income taxes recoverable 549 (3,025) Prepaid expenses (4,269) (1,189) Accounts payable 24,395 (33,399) Accrued liabilities 127,076 31,845 Current income tax liability (2,741) 4,363 Asset retirements and environmental obligations (22,342) (1,185) Net regulatory assets and liabilities (174,427) (419,484) $ (221,618) $ (522,022)

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments December 31, 2022 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,344,207 $ 1,344,207 $ 1,270,138 $ — $ 74,083 Development loans and other receivables 53,680 50,300 — 50,300 — Derivative instruments: Energy contracts not designated as cash flow hedge 393 393 — — 393 Interest rate swap designated as a hedge 69,188 69,188 — 69,188 — Interest rate cap not designated as a hedge 2,659 2,659 — 2,659 — Congestion revenue rights not designated as a cash flow hedge 10,110 10,110 — — 10,110 Cross currency swap designated as a net investment hedge 1,267 1,267 — 1,267 — Commodity contracts for regulated operations 283 283 — 283 — Total derivative instruments 83,900 83,900 — 73,397 10,503 Total financial assets $ 1,481,787 $ 1,478,407 $ 1,270,138 $ 123,697 $ 84,586 Long-term debt $ 7,512,017 $ 6,699,031 $ 2,623,628 $ 4,075,403 $ — Notes payable to related party 25,808 15,180 — 15,180 — Convertible debentures 245 276 276 — — Preferred shares, Series C 12,072 11,675 — 11,675 — Derivative instruments: Energy contracts designated as a cash flow hedge 120,284 120,284 — — 120,284 Energy contracts not designated as a cash flow hedge 8,617 8,617 — — 8,617 Cross-currency swap designated as a net investment hedge 24,371 24,371 — 24,371 — Cross currency swap designated as a cash flow hedge 15,435 15,435 — 15,435 — Commodity contracts for regulated operations 1,614 1,614 — 1,614 — Total derivative instruments 170,321 170,321 — 41,420 128,901 Total financial liabilities $ 7,720,463 $ 6,896,483 $ 2,623,904 $ 4,143,678 $ 128,901 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2021 Carrying Fair Level 1 Level 2 Level 3 Long-term investment 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 — Cross-currency swap designated as a net investment hedge 1,958 1,958 — 1,958 — Commodity contracts for regulated operations 1,721 1,721 — 1,721 — 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 The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2022 and 2021 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, notes payable to related party 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, caps, 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, congestion revenue rights ("CRRs") and the fair value of th e 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 $23.32 to $109.91 with a weighted average of $44.76 as of December 31, 2022. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of CRRs are recent CRR auction prices ranging from $nil to $23.20 with a weighted average of $7.83 as at December 31, 2022. 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 8.00% to 8.50% with a weighted average of 8.34%, and the expected volatility of Atlantica's share price ranging from 26.99% to 34.89% as of December 31, 2022. 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 natural gas and electric service territories. The Company’s strategy is to minimize fluctuations in natural gas sale prices to regulated customers. The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts: 2022 Financial contracts: Swaps 1,687,217 Options 35,824 1,723,041 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 by entering into the following long-term energy derivative contracts. Upon the acquisition of the Sugar Creek Wind Facility in 2021 (note 3(f)), 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. Notional quantity Expiry Receive average Pay floating price 4,059,905 September 2030 $24.54 Illinois Hub 413,620 December 2028 $29.15 PJM Western HUB 1,977,766 December 2027 $22.05 NI HUB 1,665,318 December 2027 $36.46 ERCORT North HUB The Company is party to two interest rate swap contracts as cash flow hedges to mitigate the risk that interest rates will increase over the life of certain term loan facilities. Under the terms of the interest rate swap contracts, the Company has fixed its interest rate expense on such term loan facilities. The fair value of the derivative on the designation date is amortized into earnings over the remaining life of the contract. 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. In January 2022, the Company entered into a cross-currency interest rate swap, coterminous with the Canadian Notes, to effectively convert the C$400,000 Canadian Offering into U.S. dollars. The change in the carrying amount of the Canadian 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 Canadian Notes. An offsetting portion of the AOCI balance related to changes in fair value of the cross-currency fixed-for-fixed interest rate swap attributable to changes in the spot exchange rates is also immediately reclassified into the consolidated statements of operations as an offsetting (gain) loss on foreign exchange. 24. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2022 2021 Effective portion of cash flow hedge $ (128,838) $ (97,103) Amortization of cash flow hedge (12,180) (2,132) Amounts reclassified from AOCI 46,723 44,904 OCI attributable to shareholders of AQN $ (94,295) $ (54,331) The Company expects $32,467 of unrealized losses currently in AOCI to be reclassified, net of taxes into non-regulated energy sales, investment loss, 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 gain of $2,262 for the year ended December 31, 2022 (2021 - loss of $168) 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 gain of $22,091 for the year ended December 31, 2022 (2021 - loss of $4,232 was recorded in OCI). Canadian operations The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases. The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of $18,561 for the year ended December 31, 2022 (2021 - gain o f $1,595) 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 (continued) The Company is party to C$300,000 (December 31, 2021 - $500,000) fixed-for-fixed cross-currency cross currency swaps to effectively convert Canadian dollar debentures into U.S. dollars. In February 2022, the Company settled the cross-currency swap related to its C$200,000 (2021 - C$150,000) debenture that was repaid. 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 loss of $11,082 for the year ended December 31, 2022 (2021 - gain of $7,824) was recorded in OCI. On April 9, 2021, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap, coterm inous 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 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 loss of $13,374 for the year ended December 31, 2022 (2021 - loss of $1,925) 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 and 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. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings. The Company mitigates the volatility of energy congestion charges at the ERCOT transmission grid by entering into CRRs, which as of December 31, 2022 had notional quantity of 1,328,510 MW-hours at prices ranging from $1.58 per MW-hr to $19.06 per MW-hr with a weighted average of $7.80 per MW-hr for January 2023 to April 2025. These CRRs are not designated as an accounting hedge. On December 17, 2022, the Company entered into an interest rate cap agreement in the amount of $390,000 for the period between January 15, 2023 and January 15, 2024. The Company was party to an interest rate swap to mitigate the interest rate risk related to debt at its Blue Hill Wind Facility. The contract was novated upon the sale of the Blue Hill Wind Facility. The loss recognized on the derivative was recorded as a reduction of the gain on sale of renewable assets on the consolidated statements of operations (note 3(a)). 24. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives and risk management (continued) The Company mitigates the price risk on the expected future sale of power generation of one of its solar facilities through a long-term energy derivative contract with a notional quantity of 516,202 MW-hours, a price of $25.15 per MW-hr and expiring in August 2030 as an economic hedge to the price of energy sales. The derivative contract is not designated as an accounting hedge. During 2021, 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 was recorded in 2021 as a result of the settlement. The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2022 2021 Unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (945) $ (5,353) Commodity contracts 185 — Total unrealized loss on derivative financial instruments $ (760) $ (5,353) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ 6,939 $ (108) Currency forward contract — 2,329 Interest rate swaps (7,185) — Total realized gain (loss) on derivative financial instruments $ (246) $ 2,221 Loss on derivative financial instruments not accounted for as hedges (1,006) (3,132) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,465 3,712 $ 2,459 $ 580 Consolidated statements of operations classification: Gain on derivative financial instruments $ 4,408 $ 4,403 Gain on foreign exchange — 2,329 Renewable energy sales 5,236 (6,152) Reduction to gain on sale of renewable assets (7,185) — $ 2,459 $ 580 24. Financial instruments (continued) (c) Risk management (continued) In addition to the risk management strategies described above, the Company manages exposure to risks arising from financial instruments, including credit risk and liquidity risk. 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. The remaining revenue is primarily earned by the Regulated Services Group, which consists of electric, water distribution and wastewater, and natural 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 $404,258 is spread over hundreds of 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, 2022, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2022 Cash and cash equivalents and restricted cash $ 101,185 Accounts receivable 552,914 Allowance for doubtful accounts (24,857) Notes receivable 53,680 $ 682,922 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, 2022, in addition to cash on hand of $57,623 , the Company had $2,288,765 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 $ 1,128,660 $ 404,633 $ 1,984,855 $ 4,019,166 $ 7,537,314 Interest on long-term debt 310,863 447,227 386,560 3,936,205 5,080,855 Purchase obligations 741,888 — — — 741,888 Environmental obligation 9,326 18,084 1,915 19,021 48,346 Advances in aid of construction 1,554 — — 86,992 88,546 Derivative financial instruments: Cross-currency swap 3,205 5,541 6,279 24,781 39,806 Energy derivative and commodity contracts 29,286 49,865 29,896 21,468 130,515 Contract adjustment payments on Green Equity Units 76,208 37,668 — — 113,876 Other obligations 37,209 6,392 5,080 271,962 320,643 Total obligations $ 2,338,199 $ 969,410 $ 2,414,585 $ 8,379,595 $ 14,101,789

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Comparative figures	Comparative figuresCertain of the comparative figures have been reclassified to conform to the consolidated financial statement presentation adopted in the current year.

Significant accounting polici_2

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2022
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 regulatory assets or property, plant and equipment 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)) once 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 2022 2021 2022 2021 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 39 40 Equipment 5-54 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. Commonly owned facilities represent cost of $559,630 (2021 - $557,954) and accumulated depreciation of $75,820 (2021 - $59,857). The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. Total expenditures incurred on these facilities for the year ended December 31, 2022 were $110,268 (2021 - $143,255).
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. During the fourth quarter of 2022, the Company recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374 (note 5).
Variable interest entities	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). 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. During the fourth quarter of 2022, the Renewable Energy Group recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities (as defined herein) from $282,726 to 206,816 (note 8(c)).
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, 2022 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, water and natural gas. 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 natural 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 (note 24).
Income taxes	Income taxes Income 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. 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 natural 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.
Recently adopted accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The Financial Accounting Standards Board (“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 adoption of this update did not have an impact on the consolidated financial statements. 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 adoption of this update did not have an impact on the consolidated financial statements. 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 FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. 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 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

Significant accounting polici_3

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2022 2021 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 39 40 Equipment 5-54 5-50 11 11

Business acquisitions, developm

Business acquisitions, development projects and disposition transactions (Tables)	12 Months Ended
	Dec. 31, 2022
New York Water Company, Inc
Business Acquisition [Line Items]
Schedule of Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained. Working capital $ 4,820 Property, plant and equipment (i) 499,252 Goodwill (ii) 116,254 Regulatory assets (iii) 65,621 Other assets 4,507 Pension and other post-employment benefits (13,402) Regulatory liabilities (iii) (59,727) Other liabilities (8,028) Total net assets acquired $ 609,297 Cash and cash equivalents acquired 49 Total net assets acquired, net of cash and cash equivalents $ 609,248
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 purchase price to the 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 purchase price to 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 purchase price to 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

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment consist of the following: 2022 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,119,514 $ 1,016,784 $ 3,102,730 Utility plant 8,640,224 990,975 7,649,249 Land 113,153 — 113,153 Equipment 111,707 50,904 60,803 Construction in progress Generation 196,287 — 196,287 Distribution and transmission 822,663 — 822,663 $ 14,003,548 $ 2,058,663 $ 11,944,885 5. Property, plant and equipment (continued) 2021 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,187,197 $ 751,219 $ 3,435,978 Utility plant 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
Schedule of Capitalization of Interest	Interest and AFUDC capitalized to the cost of the assets in 2022 and 2021 are as follows: 2022 2021 Interest capitalized on non-regulated property $ 4,762 $ 3,313 AFUDC capitalized on regulated property: Allowance for borrowed funds 6,040 3,208 Allowance for equity funds 1,901 829 $ 12,703 $ 7,350

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	Intangible assets consist of the following: 2022 Cost Accumulated amortization Net book value Power sales contracts $ 56,926 $ 42,818 $ 14,108 Customer relationships 77,850 13,709 64,141 Interconnection agreements 10,098 1,851 8,247 Other (a) 10,338 151 10,187 $ 155,212 $ 58,529 $ 96,683 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 (a) Other includes brand names, water rights and miscellaneous intangibles
Schedule of Goodwill	All goodwill pertains to the Regulated Services Group. 2022 2021 Opening balance $ 1,201,244 $ 1,208,390 Business acquisitions (note 3) 123,751 5,535 Foreign exchange (4,416) (12,681) Closing balance $ 1,320,579 $ 1,201,244

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2022
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 March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22,800, for a revenue allowance of $224,056 and $226,160 in revenue for 2022 and 2023, respectively. The RA authorized a rate of return of 7.16%, comprised of a 62% equity and an 8.92% return on equity. The new rates are effective from April 1, 2022. In April, 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review. Empire Electric Missouri General Rate Case (GRC) and Securitization On April 6, 2022, the Missouri Public Service Commission (the "MPSC") approved an annual base rate increase of $35,516, as well as another $4,000 in revenues associated with the Empire Wind Facilities. The new rates became effective in June 2022. On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022 (note 7(a) and (b)). Briefing of the case is expected to be completed in April 2023. 7. Regulatory matters (continued) Utility State, Province or Country Regulatory Proceeding Type Details Empire Electric Kansas GRC On May 27, 2021, Empire Electric submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments resulting in a base rate decrease of $636, and granted Empire Electric's motion to withdraw its request to recover cost associated with the Empire Wind Facilities. New rates became effective in July 2022. Empire District Gas Company Missouri GRC In June 2022, the Commission approved an annual increase of $1,000 in base rate revenues. New rates became effective in August 2022. Empire Electric Oklahoma GRC On December 29, 2022 the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5,100. New Brunswick Gas Canada GRC On November 22, 2021, New Brunswick Gas filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Natural Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1,041 to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Board issued a Final Order and approved an annual revenue increase of $1,265 based on an ROE of 9.8%. New rates became effective January 1, 2023. Apple Valley Ranchos Water System California GRC Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,412. New rates are retroactive to July 1, 2022. Park Water System California GRC Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,105. New rates are retroactive to July 1, 2022. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2022 December 31, 2021 Regulatory assets Fuel and commodity cost adjustments (a) $ 388,294 $ 339,900 Retired generating plant (b) 174,609 185,073 Rate adjustment mechanism (c) 136,198 117,309 Income taxes (d) 97,414 79,472 Deferred capitalized costs (e) 90,121 62,599 Pension and post-employment benefits (f) 80,736 134,287 Environmental remediation (g) 70,529 81,802 Wildfire mitigation and vegetation management (h) 66,156 35,726 Clean energy and other customer programs (i) 28,145 25,857 Asset retirement obligation (j) 27,172 26,810 Debt premium (k) 24,888 34,204 Cost of removal (l) 11,084 — Rate review costs (m) 9,481 9,167 Long-term maintenance contract (n) 6,504 9,134 Other (o) 60,170 26,285 Total regulatory assets $ 1,271,501 $ 1,167,625 Less: current regulatory assets (190,393) (158,212) Non-current regulatory assets $ 1,081,108 $ 1,009,413 Regulatory liabilities Income taxes (d) $ 312,671 $ 295,720 Cost of removal (l) 191,173 191,981 Pension and post-employment benefits (f) 68,085 34,468 Fuel and commodity cost adjustments (a) 24,991 18,175 Clean energy and other customer programs (i) 11,572 14,829 Rate adjustment mechanism (c) 343 3,316 Other 19,347 17,700 Total regulatory liabilities $ 628,182 $ 576,189 Less: current regulatory liabilities (69,865) (65,809) Non-current regulatory liabilities $ 558,317 $ 510,380 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 fuel purchased differ from power or fuel 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 fuel in future periods ranging mostly from 6 to 24 months, 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. 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. In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, these two cases regarding the quantum financeable through securitization, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals - Western District on November 10, 2022. Briefing of the case is expected to be completed in April 2023. (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 net book value that may be retained as an asset on the balance sheet for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the 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 Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. AQN believes it is probable that the Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, has netted its regulatory liability against its retired generation facilities regulatory asset. As noted above under (a) Fuel and commodity cost adjustments , in March 2022, Empire Electric filed petitions for securitization of the impact of the Midwest Extreme Weather Event and the retirement of Asbury. 7. Regulatory matters (continued) (c) Rate adjustment mechanism Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth 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 over periods ranging from one (d) 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 over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. (e) 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. 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. (f) Pension and post-employment benefits To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of 3 to 8 years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980, Regulated Operations . The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement 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 had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (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. 7. Regulatory matters (continued) (g) Environmental remediation Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap. (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. The assets are recovered over two years. (i) 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. The assets are generally included in rate base and recovered over periods of six (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 once expenditures are made. (k) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (l) 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 (or asset) tracks the amounts that have been collected from customers net of costs incurred to date. (m) Rate review costs The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one (n) 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 generally included in rate base and recovered over five years. (o) Other The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs, and equipment costs, which are probable of recovery under existing mechanisms.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure Long Term Investments And Notes Receivable [Abstract]
Schedule of Long-term Investments	Long-term investments consist of the following: December 31, 2022 December 31, 2021 Long-term investments carried at fair value Atlantica (a) $ 1,268,140 $ 1,750,914 Atlantica Yield Energy Solutions Canada Inc. (b) 74,083 95,246 Other 1,984 2,296 $ 1,344,207 $ 1,848,456 Other long-term investments Equity-method investees (c) $ 381,802 $ 433,850 Development loans receivable from equity-method investees (d) 52,923 31,468 San Antonio Water System and other (e) 27,600 30,508 $ 462,325 $ 495,826
Schedule of Income from Long-term Investments	Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows: Year ended December 31, 2022 2021 Fair value gain (loss) on investments carried at fair value Atlantica $ (482,774) $ (107,030) Atlantica Yield Energy Solutions Canada Inc. (16,018) (15,915) Other (333) 526 $ (499,125) $ (122,419) Dividend and interest income from investments carried at fair value Atlantica $ 86,664 $ 83,971 Atlantica Yield Energy Solutions Canada Inc. 20,443 17,222 Other 36 330 $ 107,143 $ 101,523 Other long-term investments Equity method loss (c) $ (21,416) $ (26,337) Impairment of equity-method investee (c) (75,910) — Interest and other income 24,102 20,776 $ (73,224) $ (5,561) Fair value change, income (loss) and impairment expense related to long-term investments $ (465,206) $ (26,457) (a) Investment in Atlantica Liberty (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 42% (2021 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2022 is $1,167,444 (2021 - $1,167,444). T he Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations. 8. Long-term investments (continued) (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. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment 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, AQN has the option to exchange approxima tely 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, 2022, the Company's maximum exposure to loss is $74,083 (2021 - $95,246 ), which represents the fair value of the investment. (c) Equity-method investees The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value o f $310,103 (2021 - $375,460). The Regulated Services Group has non-controlling interest of $56,199 (2021 - 37,492) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $15,500 and (2021 - $20,898) is reported under Corporate. Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. Economic interest Capacity Texas Coastal Wind Facilities 51 % 861 MW Blue Hill Wind Facility 20 % 175 MW Red Lily Wind Facility 75 % 26.4 MW Val-Eo Wind Facility 50 % 24 MW During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. As at December 31, 2022, the Company had issued $113,630 (2021 - $119,750) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to 206,816 . Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value. Development: 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 as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. 8. Long-term investments (continued) (c) Equity-method investees (continued) Construction: The Renewable Energy Group has 50% equi ty interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The transfers resulted i n a gain of $nil (2021 - $26,182) . The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the eq uity method. Changes in the carrying value of equity method investees were as follows: 2022 2021 Carrying value, January 1 $ 433,850 $ 186,452 Additional Investments 110,441 418,434 Net loss attributable to AQN (21,416) (26,337) Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733 Operating projects bought back by AQN — (129,075) Dividend received (1,183) (2,981) Impairment (75,910) — Reclassification during the period (note 8(e)) — (25,634) Other 3,130 5,258 Carrying value, December 31 $ 381,802 $ 433,850 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge, Summarized combined information for AQN's equity method investees as at December 31 is as follows: 2022 2021 Total assets $ 2,740,132 $ 2,126,934 Total liabilities 1,507,079 945,971 Net assets 1,233,053 1,180,963 AQN's ownership interest in the entities 332,663 327,555 Difference between investment carrying amount and underlying equity in net assets (a) 49,139 106,295 Total carrying value $ 381,802 $ 433,850 (a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs. 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows: 2022 2021 Revenue $ 65,025 $ 20,262 Net loss $ (31,070) $ (46,293) Other comprehensive income (loss) (a) $ (130,729) $ 15,177 Net loss attributable to AQN $ (21,416) $ (26,337) Other comprehensive loss attributable to AQN (a) $ (67,110) $ 7,733 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge, Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction 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, 2022, 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, 2022 am ounts to $8,824 (2021 - $4,612). Summarized combined information for AQN's VIEs as at December 31 is as follows: 2022 2021 AQN's maximum exposure in regards to VIEs Carrying amount $ 122,752 $ 86,202 Development loans receivable (d) 52,923 31,468 Performance guarantees and other commitments on behalf of VIEs 658,224 409,232 $ 833,899 $ 526,902 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 Renewable Energy Group 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 on the twelfth anniversary of the development agreement or commercial operation date. (e) San Antonio Water System and other The Company no longer has significant influe nce over its 20% interest in the San Antonio Water System (“SAWS”), and therefore has discontinued the equity method of accountin
Summary of Operating Entities	Company accounts for its interests using the eq uity method. Economic interest Capacity Texas Coastal Wind Facilities 51 % 861 MW Blue Hill Wind Facility 20 % 175 MW Red Lily Wind Facility 75 % 26.4 MW Val-Eo Wind Facility 50 % 24 MW
Equity Method Investments	Changes in the carrying value of equity method investees were as follows: 2022 2021 Carrying value, January 1 $ 433,850 $ 186,452 Additional Investments 110,441 418,434 Net loss attributable to AQN (21,416) (26,337) Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733 Operating projects bought back by AQN — (129,075) Dividend received (1,183) (2,981) Impairment (75,910) — Reclassification during the period (note 8(e)) — (25,634) Other 3,130 5,258 Carrying value, December 31 $ 381,802 $ 433,850 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge, Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows: 2022 2021 Revenue $ 65,025 $ 20,262 Net loss $ (31,070) $ (46,293) Other comprehensive income (loss) (a) $ (130,729) $ 15,177 Net loss attributable to AQN $ (21,416) $ (26,337) Other comprehensive loss attributable to AQN (a) $ (67,110) $ 7,733 (a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,
Schedule of Investments in Partnerships and Joint Ventures	Summarized combined information for AQN's equity method investees as at December 31 is as follows: 2022 2021 Total assets $ 2,740,132 $ 2,126,934 Total liabilities 1,507,079 945,971 Net assets 1,233,053 1,180,963 AQN's ownership interest in the entities 332,663 327,555 Difference between investment carrying amount and underlying equity in net assets (a) 49,139 106,295 Total carrying value $ 381,802 $ 433,850 (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: 2022 2021 AQN's maximum exposure in regards to VIEs Carrying amount $ 122,752 $ 86,202 Development loans receivable (d) 52,923 31,468 Performance guarantees and other commitments on behalf of VIEs 658,224 409,232 $ 833,899 $ 526,902

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Senior unsecured revolving credit facilities (a) — 2024-2027 N/A $ 351,786 $ 368,806 Senior unsecured bank credit facilities and delayed draw term facility (b) — 2023-2031 N/A 773,643 141,956 Commercial paper — 2023 N/A 407,000 338,700 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,142,814 1,140,801 Senior unsecured notes (d) 3.39 % 2023-2047 $ 1,505,000 1,496,101 1,689,792 Senior unsecured utility notes 6.34 % 2023-2035 $ 142,000 154,271 155,571 Senior secured utility bonds 4.71 % 2026-2044 $ 556,209 554,822 558,177 Canadian dollar borrowings Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 882,899 1,099,403 Senior secured project notes 10.21 % 2027 C$ 20,349 15,024 18,344 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds 4.05 % 2028-2040 CLF 1,637 77,206 77,963 $ 5,855,566 $ 5,589,513 Subordinated U.S. dollar borrowings Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 291,238 — Subordinated unsecured notes (f) 5.56 % 2078-2082 $ 1,387,500 1,365,213 621,862 $ 7,512,017 $ 6,211,375 Less: current portion (423,274) (356,397) $ 7,088,743 $ 5,854,978 Short-term obligations of $705,386 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) The following table sets out the bank credit facilities available to AQN and its operating groups as at December 31, 2022: December 31, 2022 December 31, 2021 Revolving and term credit facilities $ 4,513,300 $ 3,217,000 Funds drawn on facilities/ commercial paper issued (1,532,500) (849,600) Letters of credit issued (465,200) (317,200) Liquidity available under the facilities 2,515,600 2,050,200 Undrawn portion of uncommitted letter of credit facilities (226,900) (224,000) Cash on hand 57,623 125,157 Total liquidity and capital reserves $ 2,346,323 $ 1,951,357 Recent financing activities: (a) Senior unsecured revolving credit facilities Regulated Services Group On April 29, 2022, the Regulated Services Group entered into two new senior unsecured revolving credit facilities: a $1,000,000 senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the “Long-Term Regulated Services Credit Facility”) and a $500,000 short-term senior unsecured revolving credit facility maturing originally on March 31, 2023 and extended to February 28, 2024, subsequent to year-end. Subject to the terms and conditions therein, the Long-Term Regulated Services Credit Facility may be extended for two additional one-year periods. In conjunction with the new facilities, the Regulated Services Group’s $500,000 senior unsecured syndicated revolving credit facility was cancelled. On December 23, 2022, the Regulated Services Group amended and restated its $75,000 senior unsecured revolving credit facility in Bermuda with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25,000 senior unsecured bilateral revolving credit facility in Bermuda that matures on June 24, 2024. Renewable Energy Group On July 22, 2022, the Renewable Energy Group amended and restated its $500,000 senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods. On July 22, 2022, the Renewable Energy Group entered into a new $250,000 uncommitted bilateral letter of credit facility. On November 8, 2022, the Renewable Energy Group's $350,000 uncommitted letter of credit facility was amended and restated with a new maturity date of June 30, 2024. (b) Senior unsecured bank credit facilities On November 30, 2022, the Regulated Services Group amended and restated its $1,100,000 senior unsecured delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023. (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. 9. Long-term debt (continued) Recent financing activities (continued): (c) U.S dollar senior unsecured notes (Green Equity Units) (continued) 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)). 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 wil l 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) U.S. dollar senior unsecured notes On April 30, 2022, the Company repaid a $80,000 senior unsecured note on its maturity. On August 1, 2022, the Company repaid a $115,000 senior unsecured note on its maturity. Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity. (e) Canadian dollar senior unsecured notes 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)). 9. Long-term debt (continued) Recent financing activities (continued): (f) Subordinated unsecured notes 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, 2022, the Company had accrued $70,274 in interest expense (2021 - $49,806). Interest expense for the years ended December 31 consists of the following : 2022 2021 Long-term debt $ 261,535 $ 217,123 Commercial paper, credit facility draws and related fees 43,015 17,065 Accretion of fair value adjustments (16,547) (18,174) Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521) Other 1,373 61 $ 278,574 $ 209,554 Principal payments due in the next five years and thereafter are as follows: 2023 2024 2025 2026 2027 Thereafter Total $ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314
Schedule of Maturities of Long-term Debt	Principal payments due in the next five years and thereafter are as follows: 2023 2024 2025 2026 2027 Thereafter Total $ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314
Schedule of Interest Expense	Interest expense for the years ended December 31 consists of the following : 2022 2021 Long-term debt $ 261,535 $ 217,123 Commercial paper, credit facility draws and related fees 43,015 17,065 Accretion of fair value adjustments (16,547) (18,174) Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521) Other 1,373 61 $ 278,574 $ 209,554

Pension and other post-retire_2

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2022 2021 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 765,618 $ 834,913 $ 292,646 $ 306,524 Projected benefit obligation assumed from business combination 87,933 — 5,195 — Plan Settlements (112) (1,294) — — Service cost 16,309 14,673 6,277 7,307 Interest cost 24,787 20,676 9,146 8,048 Actuarial gain (198,074) (36,597) (82,991) (18,977) Contributions from retirees — — 2,220 2,040 Plan amendments — 237 (2,452) 310 Medicare Part D — — 367 373 Benefits paid (68,197) (66,800) (13,078) (12,979) Foreign exchange (129) (190) — — Projected benefit obligation, end of year $ 628,135 $ 765,618 $ 217,330 $ 292,646 Change in plan assets Fair value of plan assets, beginning of year 648,864 629,157 192,375 176,616 Plan assets acquired in business combination 74,532 — 8,577 — Actual return on plan assets (109,118) 58,721 (30,105) 15,200 Employer contributions 23,296 29,058 11,811 11,178 Plan Settlements (112) (1,294) — — Contributions from retirees — — 2,220 1,988 Medicare Part D subsidy receipts — — 367 372 Benefits paid (68,197) (66,800) (13,078) (12,979) Foreign exchange (10) 22 — — Fair value of plan assets, end of year $ 569,255 $ 648,864 $ 172,167 $ 192,375 Unfunded status $ (58,880) $ (116,754) $ (45,163) $ (100,271) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 12,264 11,751 14,218 11,879 Current liabilities (1,907) (1,902) (3,039) (699) Non-current liabilities (69,237) (126,603) (56,342) (111,451) Net amount recognized $ (58,880) $ (116,754) $ (45,163) $ (100,271) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2022 2021 2022 2021 Accumulated benefit obligation $ 413,041 $ 489,043 $ 198,463 $ 274,649 Fair value of plan assets $ 364,229 $ 396,679 $ 139,368 $ 162,592 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2022 2021 2022 2021 Projected benefit obligation $ 489,140 $ 580,841 $ 198,463 $ 274,649 Fair value of plan assets $ 417,994 $ 452,333 $ 139,368 $ 162,592
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 losses (gains) Balance, January 1, 2021 $ 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) 334 Amortization due to plan settlements (210) — — — Reclassification to regulatory accounts 31,670 (752) 14,816 — Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 310 Additions to AOCI (47,473) — (41,527) (24) Amortization in current period (3,429) 1,584 56 (2,476) Amortization due to plan settlements 15 — — — Reclassification to regulatory accounts 34,409 (752) 23,551 — Balance, December 31, 2022 $ (671) $ (3,363) $ (33,550) $ (2,190)
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2022 and 2021 were as follows: Pension benefits OPEB 2022 2021 2022 2021 Discount rate 5.48 % 2.94 % 5.49 % 3.00 % Interest crediting rate (for cash balance plans) 4.50 % 4.00 % N/A N/A Rate of compensation increase 3.70 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.00 % 5.88 % Age 65 and after 6.00 % 5.88 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2033 2031
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Cost	Weighted average assumptions used to determine net benefit cost for 2022 and 2021 were as follows: Pension benefits OPEB 2022 2021 2022 2021 Discount rate 2.94 % 2.49 % 3.00 % 2.58 % Expected return on assets 6.19 % 6.20 % 6.48 % 4.79 % Rate of compensation increase 3.91 % 3.99 % n/a n/a Health care cost trend rate Before Age 65 5.88 % 5.12 % Age 65 and after 5.88 % 5.12 % Assumed ultimate medical inflation rate 4.75 % 4.05 % 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 2022 2021 2022 2021 Service cost $ 16,309 $ 14,673 $ 6,277 $ 7,307 Non-service costs Interest cost 24,787 20,676 9,146 8,048 Expected return on plan assets (41,226) (35,972) (11,359) (10,052) Amortization of net actuarial loss 3,452 13,126 (56) 2,021 Amortization of prior service credits (1,584) (1,626) 24 11 Amortization due to plan settlements (15) 198 — — Amortization of regulatory accounts 22,951 19,665 4,829 218 $ 8,365 $ 16,067 $ 2,584 $ 246 Net benefit cost $ 24,674 $ 30,740 $ 8,861 $ 7,553
Schedule of Target Asset Allocation	The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 41 % 30% -100% Debt securities 49 % 20% - 60% Other 10 % 0% - 20% 100 % The fair values of investments as of December 31, 2022, by asset category, are as follows: Asset class 2022 Percentage Equity securities $ 317,088 43 % Debt securities 356,654 48 % Other 67,680 9 % $ 741,422 100 %
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, 2022 $ 17,314 Contributions into funds 4,781 Return on assets 2,094 Distributions (2,285) Balance, December 31, 2022 $ 21,904
Schedule of Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2023 2024 2025 2026 2027 2028-2032 Pension plan $ 48,174 $ 47,428 $ 49,794 $ 50,585 $ 50,433 $ 259,082 OPEB $ 11,483 $ 12,025 $ 12,548 $ 12,925 $ 13,479 $ 72,684

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of Other Assets	Other assets consist of the following: 2022 2021 Restricted cash $ 43,562 $ 36,232 Pension and OPEB plan assets (note 10(a)) 26,482 23,630 Long-term deposits and cash collateral 22,537 14,713 Income taxes recoverable 7,100 7,649 Deferred financing costs (a) 28,586 30,544 Other (b) 21,596 10,913 $ 149,863 $ 123,681 Less: current portion (22,564) (16,153) $ 127,299 $ 107,528 (a) Deferred financing costs Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units (note 9(c)) that will be recorded against the common shares when issued. (b) Other

Other long-term liabilities (Ta

Other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Schedule Of Other Long Term Liabilities	Other long-term liabilities consist of the following: 2022 2021 Contract adjustment payments (a) $ 113,876 $ 187,580 Asset retirement obligations (b) 116,584 142,147 Advances in aid of construction (c) 88,546 82,584 Environmental remediation obligation (d) 42,457 55,224 Customer deposits (e) 34,675 32,629 Unamortized investment tax credits (f) 17,649 17,439 Deferred credits and contingent consideration (g) 39,498 43,495 Preferred shares, Series C (h) 12,072 13,348 Hook up fees (i) 32,463 21,904 Lease liabilities (note 1(q)) 21,834 22,512 Contingent development support obligations (j) 8,824 4,615 Note payable to related party (k) 25,808 25,808 Other 41,156 34,534 $ 595,442 $ 683,819 Less: current portion (134,212) (167,908) $ 461,230 $ 515,911 (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 natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural 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: 2022 2021 Opening balance $ 142,147 $ 79,968 Obligation assumed 793 57,067 Retirement activities (27,980) (4,133) Accretion 4,589 4,381 Change in cash flow estimates (2,965) 4,864 Closing balance $ 116,584 $ 142,147 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 fro m 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 2022, $1,299 (2021 - $6,376) 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 natural 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. The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities wil l be $48,346 (2021 - $57,167), which at discount rates ranging from 3.4% to 4.2% represents the recorded accrual of $42,457 as of December 31, 2022 (2021 - $55,224 ). Approximately $27,410 is expected to be incurred over the next three years, with the balance of cash flows to b e incurred over the follow ing 30 y ears. Changes in the environmental remediation obligation are as follows: 2022 2021 Opening balance $ 55,224 $ 69,383 Remediation activities (5,243) (9,865) Accretion 2,167 1,025 Changes in cash flow estimates 1,344 2,265 Revision in assumptions (11,035) (7,584) Closing balance $ 42,457 $ 55,224 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 perio d of 7 years and, accordingly, as of December 31, 2022, the Company has reflected a regulatory asset o f $70,529 (2021 - $81,802) for the MGP and re lated sites (note 7(g)) . (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 Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid. In 2021, the Company recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(f)). (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: 2023 $ 1,245 2024 1,443 2025 1,459 2026 1,316 2027 1,262 Thereafter to 2031 4,654 Redemption amount 3,943 $ 15,322 Less: amounts representing interest (3,250) $ 12,072 Less current portion (1,245) $ 10,827 (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. 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, 2022
Equity [Abstract]
Schedule of Number of Common Shares	Number of common shares 2022 2021 Common shares, beginning of year 671,960,276 597,142,219 Public offering 2,861,709 67,611,465 Dividend reinvestment plan 7,676,666 6,184,686 Exercise of share-based awards (c) 1,115,398 1,020,020 Conversion of convertible debentures 754 1,886 Common shares, end of year 683,614,803 671,960,276
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, 2022 and 2021: 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, 2022, AQN recorded $10,920 (2021 - $8,395) in total share-based compensation expense as follows: 2022 2021 Share options $ 980 $ 939 Director deferred share units 960 821 Employee share purchase 562 592 Performance and restricted share units 8,418 6,043 Total share-based compensation $ 10,920 $ 8,395
Schedule of Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2022 2021 Risk-free interest rate 1.9 % 1.1 % Expected volatility 23 % 23 % Expected dividend yield 4.3 % 4.1 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 2.44 C$ 2.46
Schedule of Stock Option Activity	Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2021 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 Granted 646,090 19.11 7.22 — Exercised (40,074) 13.92 5.95 103 Forfeited (19,764) 19.11 — — Balance, December 31, 2022 2,626,780 C$ 16.02 5.63 C$ — Exercisable, December 31, 2022 2,052,946 C$ 17.35 5.63 C$ —
Schedule of Performance Stock Units	A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2021 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 Granted, including dividends 1,090,457 17.99 2.00 17,524 Exercised (1,221,620) 12.62 — 23,636 Forfeited (202,799) 18.94 — 418 Balance, December 31, 2022 2,109,710 C$ 18.38 1.76 C$ 18,608 Exercisable, December 31, 2022 769,458 C$ 18.70 0.10 C$ 6,787

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2021 $ (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 (6,371) — — (6,371) Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677) Other comprehensive income (loss) (18,013) (128,838) 23,722 (123,129) Amounts reclassified from AOCI to the consolidated statement of operations (5,489) 34,543 4,039 33,093 Net current period OCI $ (23,502) (94,295) 27,761 $ (90,036) OCI attributable to the non-controlling interests 1,650 — — 1,650 Net current period OCI attributable to shareholders of AQN $ (21,852) (94,295) 27,761 $ (88,386) Balance, December 31, 2022 $ (98,467) $ (97,809) $ 36,213 $ (160,063)

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure Cash Dividends [Abstract]
Schedule of Dividends	Dividends declared were as follows: 2022 2021 Dividend Dividend per share Dividend Dividend per share Common shares $ 486,043 $ 0.7130 $ 423,023 $ 0.6669 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, 2022
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: 2022 2021 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 108,695 $ 88,417 Non-controlling interests - redeemable tax equity partnership units 6,298 6,902 Other net earnings attributable to: Non-controlling interests (3,670) (5,682) $ 111,323 $ 89,637 Redeemable non-controlling interest, held by related party (15,157) (10,435) Net effect of non-controlling interests $ 96,166 $ 79,202 Non-controlling interests - tax equity partnership units (a) Other non-controlling interests (b) Non-controlling interests held by related parties (c) 2022 2021 2022 2021 2022 2021 Opening balance $ 1,377,117 $ 388,253 $ 64,807 $ 11,234 $ 81,158 $ 59,125 Net earnings attributable to NCI (105,371) (87,422) 345 3,354 — — Contributions received, net 6,182 1,058,929 267,515 51,451 — 39,376 Dividends and distributions declared (40,086) (11,795) — (1,021) (20,978) (17,793) Repurchase of non-controlling interest (12,249) — — — — — Non-controlling interest assumed on asset acquisition — 29,141 — — — — OCI 15 11 695 (211) (2,358) 450 Closing balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158 Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2022 2021 2022 2021 Opening balance $ 306,537 $ 306,316 $ 12,989 $ 20,859 Net earnings attributable to NCI 15,157 10,435 (6,298) (6,902) Contributions, net of costs — — 5,000 — Dividends and distributions declared (13,838) (10,214) (171) (968) Closing balance $ 307,856 $ 306,537 $ 11,520 $ 12,989

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The differences are as follows: 2022 2021 Expected income tax expense at Canadian statutory rate $ (97,962) $ 37,691 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (55,315) (47,600) Adjustments from investments carried at fair value 51,314 2,709 Non-controlling interests share of income 30,025 25,135 Change in valuation allowance 41,702 (118) Non-deductible acquisition costs 1,341 3,733 Acquisition related state deferred tax adjustments 5,998 — Capital gain rate differential on disposal of renewable assets (7,340) — Tax credits (18,440) (49,415) Adjustment relating to prior periods (1,390) 1,333 Deferred income taxes on regulated income recorded as regulatory assets (2,155) (3,807) Amortization and settlement of excess deferred income tax (14,855) (16,778) Other 5,564 3,692 Income tax recovery $ (61,513) $ (43,425)
Schedule of Income (Loss) Before Taxes	For the years ended December 31, 2022 and 2021, earnings (loss) before income taxes consist of the following: 2022 2021 Canada (1) $ (363,050) $ (60,848) U.S. (37,322) 153,719 Other regions 30,704 49,361 $ (369,668) $ 142,232 (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, 2022 Canada $ 4,184 $ (74,595) $ (70,411) United States 1,579 6,183 7,762 Other regions 2,080 (944) 1,136 $ 7,843 $ (69,356) $ (61,513) 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)
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, 2022 and 2021 are presented below: 2022 2021 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 878,000 $ 761,666 Pension and OPEB 16,845 46,580 Environmental obligation 12,118 15,271 Regulatory liabilities 156,285 166,939 Other 61,917 64,460 Total deferred income tax assets $ 1,125,165 $ 1,054,916 Less: valuation allowance (107,583) (27,471) Total deferred tax assets $ 1,017,582 $ 1,027,445 Deferred tax liabilities: Property, plant and equipment $ 846,331 $ 782,829 Outside basis differentials 315,581 412,665 Regulatory accounts 303,059 300,072 Other 33,834 30,471 Total deferred tax liabilities $ 1,498,805 $ 1,526,037 Net deferred tax liabilities $ (481,223) $ (498,592) Consolidated balance sheets classification: Deferred tax assets $ 84,416 $ 31,595 Deferred tax liabilities (565,639) (530,187) Net deferred tax liabilities $ (481,223) $ (498,592)
Summary of Valuation Allowance	The following table illustrates the annual movement in the deferred tax valuation allowance: 2022 2021 Beginning balance $ 27,471 $ 29,824 Charged to income tax expense (recovery) 41,702 (118) Charged (reduction) to OCI 40,613 (1,707) Reductions to other accounts (2,203) (528) Ending balance $ 107,583 $ 27,471
Schedule of Non Capital Losses Carry Forwards	As of December 31, 2022, 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 2023—2027 2028+ Total Canada $ 3,261 $ 728,529 $ 731,790 US 9,962 1,707,139 1,717,101 Total non-capital loss carryforward $ 13,223 $ 2,435,668 $ 2,448,891 Tax credits $ 4,428 $ 151,676 $ 156,104

Other net losses (Tables)

Other net losses (Tables)	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Schedule of Other Net Losses	Other net losses consist of the following: 2022 2021 Acquisition and transition-related costs $ 17,442 $ 14,507 Other (a) 3,949 8,442 $ 21,391 $ 22,949 (a) Other Other losses primarily consist of costs pertaining to a condemnation proceeding, and miscellaneous asset write-downs, net of miscellaneous gains. Other losses in 2021 also included an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts.

Basic and diluted net earning_2

Basic and diluted net earnings (loss) per share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share, Basic and Diluted EPS [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: 2022 2021 Net earnings (loss) attributable to shareholders of AQN $ (211,989) $ 264,859 Preferred shares, Series A dividend 4,786 4,942 Preferred shares, Series D dividend 3,934 4,061 Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ (220,709) $ 255,856 Weighted average number of shares Basic 677,862,207 622,347,677 Effect of dilutive securities — 6,600,185 Diluted 677,862,207 628,947,862

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Schedule of Results of Operations and Assets for Segments	Year ended December 31, 2022 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,328,536 $ 350,939 $ — $ 2,679,475 Other revenue 55,732 28,447 1,501 85,680 Fuel, power and water purchased 824,670 41,826 — 866,496 Net revenue 1,559,598 337,560 1,501 1,898,659 Operating expenses 736,515 114,463 511 851,489 Administrative expenses 46,484 26,424 7,324 80,232 Depreciation and amortization 317,300 137,203 1,017 455,520 Asset impairment expense — 159,568 — 159,568 Loss on foreign exchange — — 13,833 13,833 459,299 (100,098) (21,184) 338,017 Gain on sale of renewable assets — 64,028 — 64,028 Operating income (loss) 459,299 (36,070) (21,184) 402,045 Interest expense (113,482) (64,285) (100,807) (278,574) Income (loss) from long-term investments 21,884 15,254 (502,344) (465,206) Other (14,765) (570) (12,598) (27,933) Earnings (loss) before income taxes $ 352,936 $ (85,671) $ (636,933) $ (369,668) Property, plant and equipment $ 8,554,938 $ 3,360,687 $ 29,260 $ 11,944,885 Investments carried at fair value 1,984 1,342,223 — 1,344,207 Equity-method investees 56,199 310,103 15,500 381,802 Total assets 12,109,575 5,251,933 266,105 17,627,613 Capital expenditures $ 908,676 $ 180,348 $ — $ 1,089,024 (1) Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2021 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,944,171 $ 256,633 $ — $ 2,200,804 Other revenue 53,441 18,339 1,558 73,338 Fuel and power purchased 682,602 31,313 — 713,915 Net revenue 1,315,010 243,659 1,558 1,560,227 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 4,371 399,529 (10,315) (5,175) 384,039 Gain on sale of renewable assets — 29,063 — 29,063 Operating income (loss) 399,529 18,748 (5,175) 413,102 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) (2,956) (7,726) (34,859) 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 10,524,466 6,123,888 149,149 16,797,503 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 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.
Schedule of Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2022 2021 Revenue United States $ 2,232,959 $ 1,790,539 Canada 175,005 157,854 Other regions 357,191 325,749 $ 2,765,155 $ 2,274,142 Property, plant and equipment United States $ 10,351,736 $ 9,464,716 Canada 848,560 882,454 Other regions 744,589 695,276 $ 11,944,885 $ 11,042,446 Intangible assets United States $ 18,818 $ 23,575 Canada 19,038 21,780 Other regions 58,827 59,761 $ 96,683 $ 105,116

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
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) $ 89,846 $ 32,490 $ 32,726 $ 12,274 $ 12,520 $ 142,586 $ 322,442 Natural gas supply and service agreements (ii) 113,775 81,719 57,014 40,372 31,457 188,138 512,475 Service agreements 67,477 57,886 55,835 49,596 46,511 298,516 575,821 Capital projects 7,163 — — — — — 7,163 Land easements 13,295 13,316 13,503 13,667 13,837 463,785 531,403 Total $ 291,556 $ 185,411 $ 159,078 $ 115,909 $ 104,325 $ 1,093,025 $ 1,949,304 (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, 2022. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Natural gas supply and service agreements: AQN’s natural 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, 2022
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: 2022 2021 Accounts receivable $ (124,631) $ (56,751) Fuel and natural gas in storage (21,140) (43,642) Supplies and consumables inventory (24,088) 445 Income taxes recoverable 549 (3,025) Prepaid expenses (4,269) (1,189) Accounts payable 24,395 (33,399) Accrued liabilities 127,076 31,845 Current income tax liability (2,741) 4,363 Asset retirements and environmental obligations (22,342) (1,185) Net regulatory assets and liabilities (174,427) (419,484) $ (221,618) $ (522,022)

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Financial Instruments	Fair value of financial instruments December 31, 2022 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,344,207 $ 1,344,207 $ 1,270,138 $ — $ 74,083 Development loans and other receivables 53,680 50,300 — 50,300 — Derivative instruments: Energy contracts not designated as cash flow hedge 393 393 — — 393 Interest rate swap designated as a hedge 69,188 69,188 — 69,188 — Interest rate cap not designated as a hedge 2,659 2,659 — 2,659 — Congestion revenue rights not designated as a cash flow hedge 10,110 10,110 — — 10,110 Cross currency swap designated as a net investment hedge 1,267 1,267 — 1,267 — Commodity contracts for regulated operations 283 283 — 283 — Total derivative instruments 83,900 83,900 — 73,397 10,503 Total financial assets $ 1,481,787 $ 1,478,407 $ 1,270,138 $ 123,697 $ 84,586 Long-term debt $ 7,512,017 $ 6,699,031 $ 2,623,628 $ 4,075,403 $ — Notes payable to related party 25,808 15,180 — 15,180 — Convertible debentures 245 276 276 — — Preferred shares, Series C 12,072 11,675 — 11,675 — Derivative instruments: Energy contracts designated as a cash flow hedge 120,284 120,284 — — 120,284 Energy contracts not designated as a cash flow hedge 8,617 8,617 — — 8,617 Cross-currency swap designated as a net investment hedge 24,371 24,371 — 24,371 — Cross currency swap designated as a cash flow hedge 15,435 15,435 — 15,435 — Commodity contracts for regulated operations 1,614 1,614 — 1,614 — Total derivative instruments 170,321 170,321 — 41,420 128,901 Total financial liabilities $ 7,720,463 $ 6,896,483 $ 2,623,904 $ 4,143,678 $ 128,901 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2021 Carrying Fair Level 1 Level 2 Level 3 Long-term investment 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 — Cross-currency swap designated as a net investment hedge 1,958 1,958 — 1,958 — Commodity contracts for regulated operations 1,721 1,721 — 1,721 — 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
Summary of Commodity Volumes Associated with Derivative Contracts	The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts: 2022 Financial contracts: Swaps 1,687,217 Options 35,824 1,723,041
Schedule of Long-Term Energy Derivative Contracts	The Company reduces the price risk on the expected future sale of power generation by entering into the following long-term energy derivative contracts. Upon the acquisition of the Sugar Creek Wind Facility in 2021 (note 3(f)), 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. Notional quantity Expiry Receive average Pay floating price 4,059,905 September 2030 $24.54 Illinois Hub 413,620 December 2028 $29.15 PJM Western HUB 1,977,766 December 2027 $22.05 NI HUB 1,665,318 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: 2022 2021 Effective portion of cash flow hedge $ (128,838) $ (97,103) Amortization of cash flow hedge (12,180) (2,132) Amounts reclassified from AOCI 46,723 44,904 OCI attributable to shareholders of AQN $ (94,295) $ (54,331)
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: 2022 2021 Unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (945) $ (5,353) Commodity contracts 185 — Total unrealized loss on derivative financial instruments $ (760) $ (5,353) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ 6,939 $ (108) Currency forward contract — 2,329 Interest rate swaps (7,185) — Total realized gain (loss) on derivative financial instruments $ (246) $ 2,221 Loss on derivative financial instruments not accounted for as hedges (1,006) (3,132) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,465 3,712 $ 2,459 $ 580 Consolidated statements of operations classification: Gain on derivative financial instruments $ 4,408 $ 4,403 Gain on foreign exchange — 2,329 Renewable energy sales 5,236 (6,152) Reduction to gain on sale of renewable assets (7,185) — $ 2,459 $ 580
Schedule of Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2022, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 2022 Cash and cash equivalents and restricted cash $ 101,185 Accounts receivable 552,914 Allowance for doubtful accounts (24,857) Notes receivable 53,680 $ 682,922
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 $ 1,128,660 $ 404,633 $ 1,984,855 $ 4,019,166 $ 7,537,314 Interest on long-term debt 310,863 447,227 386,560 3,936,205 5,080,855 Purchase obligations 741,888 — — — 741,888 Environmental obligation 9,326 18,084 1,915 19,021 48,346 Advances in aid of construction 1,554 — — 86,992 88,546 Derivative financial instruments: Cross-currency swap 3,205 5,541 6,279 24,781 39,806 Energy derivative and commodity contracts 29,286 49,865 29,896 21,468 130,515 Contract adjustment payments on Green Equity Units 76,208 37,668 — — 113,876 Other obligations 37,209 6,392 5,080 271,962 320,643 Total obligations $ 2,338,199 $ 969,410 $ 2,414,585 $ 8,379,595 $ 14,101,789

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 business_unit
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	3 Months Ended	12 Months Ended
	Dec. 31, 2022 USD ($) facility	Dec. 31, 2022 USD ($) facility	Dec. 31, 2021 USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities | facility	3	3
Cost of plant in service	$ 559,630	$ 559,630	$ 557,954
Liquidity available under the facilities	2,515,600	2,515,600	2,050,200
Accumulated depreciation related to commonly owned facilities	75,820	75,820	59,857
Expenditures		110,268	143,255
U.S. Tax reform		$ 159,568
Number of power generating facilities | facility		2
Generating assets of Long Sault	17,627,613	$ 17,627,613	16,797,503
Non-regulated energy sales		2,765,155	2,274,142
Interest expense on long-term debt and others		278,574	209,554
Asset impairment charges		(235,478)	0
Non-Regulated Energy
Significant Accounting Policies [Line Items]
Non-regulated energy sales		350,939	256,633
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	57,241	57,241	59,877
Long-term debt of Long Sault	15,024	15,024	18,344
Operating expenses and amortization		5,834	5,410
Interest expense on long-term debt and others		1,723	2,055
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant | Non-Regulated Energy
Significant Accounting Policies [Line Items]
Non-regulated energy sales		$ 19,752	$ 16,772
Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ (75,910)
Minimum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		7.52%
U.S. Tax reform		$ 100,374
Lease renewal term	1 year	1 year
Minimum | Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ 206,816
Maximum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		60%
U.S. Tax reform		$ 259,942
Lease renewal term	5 years	5 years
Maximum | Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ 282,726
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

Significant accounting polici_5

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Generation | Weighted Average
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
Generation | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		60 years
Distribution | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	39 years	40 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		1 year
Distribution | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		100 years
Equipment | Weighted Average
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	54 years	50 years

Business acquisitions, develo_2

Business acquisitions, development projects and disposition transactions - Additional Information (Details) $ in Thousands, $ in Thousands

1 Months Ended

12 Months Ended

Dec. 29, 2022 CAD ($) business_unit

Sep. 29, 2022 USD ($)

Jan. 01, 2022 USD ($) country

Oct. 26, 2021 USD ($)

Apr. 30, 2021 USD ($) MWac

Jan. 31, 2021 USD ($) MWac wind_project

Dec. 31, 2022 USD ($) county

Dec. 31, 2021 USD ($) wind_project MWac

Dec. 31, 2019 MWac

Dec. 29, 2022 USD ($)

Dec. 29, 2022 CAD ($)

Mar. 31, 2022 USD ($)

Business Acquisition [Line Items]

Gain on sale of renewable assets

$ 64,028

$ 29,063

Number of counties served | county

20

Business combination, consideration transferred, liabilities incurred

$ 87,035

Operating Wind Facilities in the United States

Business Acquisition [Line Items]

Equity interest (percent)

49%

49%

Number of ownership interest | business_unit

3

Wind power capacity (megawatt AC) | MWac

551

Altavista Solar Facility

Business Acquisition [Line Items]

Equity interest (percent)

50%

Blue Hill Wind Facility

Business Acquisition [Line Items]

Equity interest (percent)

80%

80%

Wind power capacity (megawatt AC) | MWac

175

Proceeds from sale of renewable assets

$ 277,500

$ 108,610

Gain on sale of renewable assets

$ 62,828

Kentucky Power Transaction

Business Acquisition [Line Items]

Total purchase price

$ 2,846,000

Reduction to the purchase price

$ 200,000

AEP Kentucky Transmission Company, Inc

Business Acquisition [Line Items]

Debt assumed

$ 1,221,000

New York Water Company, Inc

Business Acquisition [Line Items]

Total purchase price

$ 609,000

Number of countries | country

8

Intangible asset, useful life

64 years 8 months 26 days

Revenue

$ 125,370

Operating income

$ 21,776

Mid-West Wind Facilities

Business Acquisition [Line Items]

Debt assumed

$ 789,804

Mid-West Wind Facilities | Empire Electric System

Business Acquisition [Line Items]

Wind power capacity (megawatt AC) | MWac

600

Total purchase price

$ 97,760

Tax equity funding

530,880

Debt repaid upon maturity

$ 789,923

Number of wind projects | wind_project

3

Maverick Creek and Sugar Creek Wind Facilities

Business Acquisition [Line Items]

Debt assumed

855,409

Total purchase price

$ 18,641

Number of wind projects | wind_project

2

Ownership interest acquired (percent)

50%

Investments in joint venture

$ 43,797

Altavista Solar Facility

Business Acquisition [Line Items]

Debt assumed

$ 122,024

Total purchase price

$ 6,735

Solar power capacity (megawatt ac) | MWac

80

Maverick Creek Wind Facility

Business Acquisition [Line Items]

Wind power capacity (megawatt AC) | MWac

492

Tax equity funding

$ 380,829

Debt repaid upon maturity

$ 570,578

Sugar Creek Wind Facility

Business Acquisition [Line Items]

Wind power capacity (megawatt AC) | MWac

202

Tax equity funding

$ 147,914

Debt repaid upon maturity

$ 284,829

Business acquisitions, develo_3

Business acquisitions, development projects and disposition transactions - Schedule of Preliminary Allocation Of The Acquisition Prices Of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Jan. 01, 2022	Dec. 31, 2021	Apr. 30, 2021	Jan. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Goodwill (note 6)	$ 1,320,579		$ 1,201,244			$ 1,208,390
New York Water Company, Inc
Business Acquisition [Line Items]
Working capital		$ 4,820
Property, plant and equipment		499,252
Goodwill (note 6)		116,254
Regulatory assets		65,621
Other assets		4,507
Pension and other post-employment benefits		(13,402)
Regulatory liabilities		(59,727)
Other liabilities		(8,028)
Total net assets acquired		609,297
Cash and cash equivalents		49
Net assets acquired, net of cash and cash equivalents		$ 609,248
Mid-West Wind Facilities
Business Acquisition [Line Items]
Working capital			(28,630)
Property, plant and equipment			1,141,884
Long-term debt			(789,804)
Deferred tax liability			(4,566)
Asset retirement obligation			(27,053)
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]
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]
Working capital					$ (15,557)
Property, plant and equipment					1,062,613
Long-term debt					(855,409)
Deferred tax liability					(337)
Asset retirement obligation					(23,402)
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

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 24,857	$ 19,327
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 149,015	$ 102,693

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Cost	$ 14,003,548	$ 12,630,666
Accumulated depreciation	2,058,663	1,588,220
Net book value	11,944,885	11,042,446
Land
Property, Plant and Equipment [Line Items]
Cost	113,153	114,821
Accumulated depreciation	0	0
Net book value	113,153	114,821
Equipment
Property, Plant and Equipment [Line Items]
Cost	111,707	101,971
Accumulated depreciation	50,904	56,464
Net book value	60,803	45,507
Generation
Property, Plant and Equipment [Line Items]
Cost	4,119,514	4,187,197
Accumulated depreciation	1,016,784	751,219
Net book value	3,102,730	3,435,978
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	196,287	148,302
Accumulated depreciation	0	0
Net book value	196,287	148,302
Utility plant
Property, Plant and Equipment [Line Items]
Cost	8,640,224	7,468,236
Accumulated depreciation	990,975	780,537
Net book value	7,649,249	6,687,699
Distribution and transmission | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	822,663	610,139
Accumulated depreciation	0	0
Net book value	$ 822,663	$ 610,139

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 559,630	$ 557,954
Accumulated depreciation related to commonly owned facilities	75,820	59,857
Expenditures	110,268	143,255
Contribution received	1,299	6,376
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	111,192	114,868
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	46,666	46,649
Depreciation expense	1,489	1,716
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	2,041	1,665
Utility plant
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	2,033,391	2,018,039
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	$ 133,644	$ 72,484

Property, plant and equipment_3

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Capitalization [Line Items]
Total	$ 12,703	$ 7,350
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	4,762	3,313
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	6,040	3,208
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	$ 1,901	$ 829

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Cost	$ 155,212	$ 162,292
Accumulated amortization	58,529	57,176
Net book value	96,683	105,116
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	56,926	58,112
Accumulated amortization	42,818	43,118
Net book value	14,108	14,994
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	77,850	78,140
Accumulated amortization	13,709	12,337
Net book value	64,141	65,803
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	10,098	15,072
Accumulated amortization	1,851	1,721
Net book value	8,247	13,351
Other
Finite-Lived Intangible Assets [Line Items]
Cost	10,338	10,968
Accumulated amortization	151	0
Net book value	$ 10,187	$ 10,968

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 2,580
Estimated amortization expense for intangibles in year 2	2,572
Estimated amortization expense for intangibles in year 3	2,572
Estimated amortization expense for intangibles in year 4	2,572
Estimated amortization expense for intangibles in year 5	$ 2,572

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 1,201,244	$ 1,208,390
Business acquisitions (note 3)	123,751	5,535
Foreign exchange	(4,416)	(12,681)
Goodwill end of the period	$ 1,320,579	$ 1,201,244

Regulatory Matters - Regulatory

Regulatory Matters - Regulatory Proceedings (Details) - USD ($) $ in Thousands							1 Months Ended
	Feb. 03, 2023	Dec. 29, 2022	Dec. 22, 2022	Mar. 18, 2022	Jan. 19, 2022	Nov. 22, 2021	Jun. 30, 2022	May 31, 2022	Jan. 31, 2022
BELCO
Regulatory Liabilities [Line Items]
Revenue allowance, 2022				$ 224,056
Approved revenue increase (decrease)				22,800
Revenue allowance, 2023				$ 226,160
Weighted average cost of capital (percent)				7.16%
Approved equity capital structure, (percent)				62%
Approved return on equity, (percent)				8.92%
Empire Electric System - Missouri
Regulatory Liabilities [Line Items]
First requested increase					$ 35,516
Second requested increase					4,000
Qualified extraordinary costs					$ 290,383
Empire Electric System - Kansas
Regulatory Liabilities [Line Items]
Requested increase								$ 636
Empire District Gas Company
Regulatory Liabilities [Line Items]
Requested increase							$ 1,000
Empire Electric - Oklahoma
Regulatory Liabilities [Line Items]
Requested increase		$ 5,100
New Brunswick Gas - Canada
Regulatory Liabilities [Line Items]
Approved equity capital structure, (percent)						45%
Approved return on equity, (percent)			9.80%			8.50%
Annual revenue increase (decrease)			$ 1,265						$ 1,041
Apple Valley Ranchos Water System | Subsequent Event
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)	$ (1,412)
Park Water System | Subsequent Event
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)	$ 1,105

Regulatory matters - Regulato_2

Regulatory matters - Regulatory Assets and Liabilities (Detail) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 22, 2022 USD ($)	Dec. 31, 2022 USD ($)	Apr. 27, 2022 regulatory_case	Dec. 31, 2021 USD ($)	Mar. 01, 2020 MWac
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 1,271,501		$ 1,167,625
Less: current regulatory assets		(190,393)		(158,212)
Non-current regulatory assets		1,081,108		1,009,413
Total regulatory liabilities		628,182		576,189
Less: current regulatory liabilities		(69,865)		(65,809)
Non-current regulatory liabilities		$ 558,317		510,380
Capital expenditure shortfall refundable to customers (percent)		80%
Retroactive rate adjustment collection period		24 months
Regulatory asset, amortization period		26 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 312,671		295,720
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities		191,173		191,981
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities		68,085		34,468
Fuel and commodity costs adjustments
Regulatory Liabilities [Line Items]
Total regulatory liabilities		24,991		18,175
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities		11,572		14,829
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 343		3,316
Rate adjustment mechanism | Minimum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		1 year
Rate adjustment mechanism | Maximum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		5 years
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 19,347		17,700
Fuel and commodity costs adjustments
Regulatory Liabilities [Line Items]
Total regulatory assets		388,294		339,900
Asset Retirement Obligation		21,283
Number of regulatory cases | regulatory_case			2
Qualified extraordinary costs	$ 290,383
Recovery denied (percent)	5%
Fuel and commodity costs adjustments | Midwest Extreme Weather Event
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount		221,646
Fuel and commodity costs adjustments | Energy Transistion Costs
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount		140,774
Retired generating plant
Regulatory Liabilities [Line Items]
Total regulatory assets		174,609		185,073
Coal generation capacity (MW) | MWac					200
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 80,736		134,287
Future service years of employees		10 years
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 136,198		117,309
Environmental remediation
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 70,529		81,802
Environmental remediation, rate recovery period		7 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 97,414		79,472
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 90,121		62,599
Regulatory asset, amortization period		20 years
Capitalized operating and maintenance costs, recovery rate, (percent)		2.43%
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 66,156		35,726
Regulatory assets, recovery period		2 years
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 24,888		34,204
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory assets		11,084		0
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets		27,172		26,810
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 28,145		25,857
Clean energy and other customer programs | Minimum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		6 years
Clean energy and other customer programs | Maximum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		10 years
Rate review costs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 9,481		9,167
Rate review costs | Minimum
Regulatory Liabilities [Line Items]
Costs capitalized and amortized period		1 year
Rate review costs | Maximum
Regulatory Liabilities [Line Items]
Costs capitalized and amortized period		5 years
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 6,504		9,134
Regulatory assets, recovery period		5 years
Other
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 60,170		$ 26,285

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,344,207	$ 1,848,456
Equity-method investees	381,802	433,850
Other	27,600	30,508
Long-term investments	462,325	495,826
Notes Receivable | Development loans
Schedule of Equity Method Investments [Line Items]
Development loans receivable from equity-method investees	52,923	31,468
Atlantica
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	1,268,140	1,750,914
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	74,083	95,246
Other
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,984	$ 2,296

Long-term investments - Income

Long-term investments - Income from Long-term Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	$ (499,125)	$ (122,419)
Dividend and interest income from investments carried at fair value	107,143	101,523
Net loss attributable to AQN	(21,416)	(26,337)
Impairment		0
Interest and other income	24,102	20,776
Income (loss) from other long-term investments	(73,224)	(5,561)
Loss from long-term investments	(465,206)	(26,457)
Atlantica
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	(482,774)	(107,030)
Dividend and interest income from investments carried at fair value	86,664	83,971
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	(16,018)	(15,915)
Dividend and interest income from investments carried at fair value	20,443	17,222
Other
Schedule of Equity Method Investments [Line Items]
Fair value gain (loss) on investments carried at fair value	(333)	$ 526
Dividend and interest income from investments carried at fair value	$ 36

Long-term investments - Additio

Long-term investments - Additional Information (Detail) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	May 31, 2020 shares	Mar. 31, 2021 wind_project	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 29, 2022	Nov. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 381,802	$ 433,850
Investments carried at fair value			1,344,207	1,848,456
Noncontrolling interest in partnerships and joint ventures			381,802	433,850
Number of wind development projects | wind_project		4
Guarantor obligations			113,630	119,750
Fair value of support provided			8,824	4,612
Net loss attributable to AQN			(21,416)	(26,337)
Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Net assets			$ 122,752	$ 86,202
Atlantica
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			42%	44%
Equity interest, maximum (percent)			48.50%
AQN's investment carrying amount for the entities			$ 1,167,444	$ 1,167,444
Investments carried at fair value			$ 1,268,140	1,750,914
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Option to exchange shares | shares	3,500,000
Common stock, conversion ratio			1
Investments carried at fair value			$ 74,083	95,246
Texas Coastal Wind Facilities
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities				344,883
Equity method investment acquired (percent)		51%	51%
Texas Coastal Wind Facilities | Maximum
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 282,726
Texas Coastal Wind Facilities | Minimum
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities				206,816
Liberty Development JV Inc
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities						$ 19,688
Equity method investment, gain on transfer			$ 0	26,182
Wind And Solar Power Electric Development
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			50%
San Antonio Water System
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			20%
Blue Hill Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)					80%
Equity method investment acquired (percent)			20%
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 381,802	433,850			$ 186,452
Net loss attributable to AQN			$ (21,416)	$ (26,337)

Long-term investments - Operati

Long-term investments - Operating entities (Detail) - $ / MWh	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2022
Texas Coastal Wind Facilities
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)	51%	51%
Wind facility capacity (megawatt AC)		861,000
Blue Hill Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		20%
Wind facility capacity (megawatt AC)		175,000
Red Lily Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		75%
Wind facility capacity (megawatt AC)		26,400
Val-Eo Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		50%
Wind facility capacity (megawatt AC)		24,000

Long-term investments - Equity

Long-term investments - Equity method investees (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investment [Roll Forward]
Carrying value, January 1	$ 433,850
Net loss attributable to AQN	(21,416)	$ (26,337)
Operating projects bought back by AQN	0	(129,075)
Dividend received	(23,829)	(29,818)
Impairment		0
Reclassification during the period (note 8(e))	0	(25,634)
Carrying value, December 31	381,802	433,850
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment [Roll Forward]
Carrying value, January 1	433,850	186,452
Additional Investments	110,441	418,434
Net loss attributable to AQN	(21,416)	(26,337)
Other comprehensive loss attributable to AQN	(67,110)	7,733
Dividend received	(1,183)	(2,981)
Other	3,130	5,258
Carrying value, December 31	$ 381,802	$ 433,850

Long-term investments - Investm

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Equity Method Investment, Summarized Financial Information [Abstract]
Total assets	$ 17,627,613	$ 16,797,503
AQN's investment carrying amount for the entities	381,802	433,850
Long-term debt	7,512,017	6,211,375
Income Statement [Abstract]
Revenue	2,765,155	2,274,142
Net loss	(308,155)	185,657
Other comprehensive loss	(90,036)	(42,550)
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment, Summarized Financial Information [Abstract]
Total assets	2,740,132	2,126,934
Total liabilities	1,507,079	945,971
Net assets	1,233,053	1,180,963
Income Statement [Abstract]
Revenue	65,025	20,262
Net loss	(31,070)	(46,293)
Other comprehensive loss	(130,729)	15,177
Investments in Significant Partnerships and Joint Ventures | APUC
Income Statement [Abstract]
Net loss	(21,416)	(26,337)
Other comprehensive loss	(67,110)	7,733
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment, Summarized Financial Information [Abstract]
AQN's investment carrying amount for the entities	381,802	433,850	$ 186,452
Investments in Significant Partnerships and Joint Ventures | APUC
Equity Method Investment, Summarized Financial Information [Abstract]
AQN's ownership interest in the entities	332,663	327,555
Difference between investment carrying amount and underlying equity in net assets	49,139	106,295
AQN's investment carrying amount for the entities	$ 381,802	$ 433,850

Long-term investments - Combine

Long-term investments - Combined Information for APUC's interest in VIE's (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Interest income	$ 107,143	$ 101,523
Impairment		0
Other
Variable Interest Entity [Line Items]
Interest income		330
Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Carrying amount	122,752	86,202
Development loans receivable	52,923	31,468
Performance guarantees and other commitments on behalf of VIEs	658,224	409,232
APUC's maximum exposure in regard to VIE's	$ 833,899	$ 526,902

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 CLP ($)	Feb. 15, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Jun. 30, 2021	Feb. 15, 2021 CAD ($)
Debt Instrument [Line Items]
Long-term debt	$ 7,512,017,000				$ 6,211,375,000
Less: current portion	(423,274,000)				(356,397,000)
Long-term debt, excluding current portion	$ 7,088,743,000				5,854,978,000
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	$ 1,142,814,000				1,140,801,000
Senior Unsecured Notes | Senior unsecured notes
Debt Instrument [Line Items]
Weighted average coupon	3.39%	3.39%	3.39%
Par value	$ 1,505,000,000
Long-term debt	$ 1,496,101,000				1,689,792,000
Senior Unsecured Notes | 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	$ 154,271,000				155,571,000
Senior Unsecured Notes | Senior secured utility bonds
Debt Instrument [Line Items]
Weighted average coupon	4.71%	4.71%	4.71%
Par value	$ 556,209,000
Long-term debt	$ 554,822,000				558,177,000
Senior Unsecured Notes | Canadian dollar Senior unsecured notes
Debt Instrument [Line Items]
Weighted average coupon	3.68%	3.68%	3.68%
Par value		$ 1,200,000,000		$ 200,000			$ 150,000
Long-term debt	$ 882,899,000				1,099,403,000
Senior Unsecured Notes | Senior secured project notes
Debt Instrument [Line Items]
Weighted average coupon	10.21%	10.21%	10.21%
Par value		$ 20,349,000
Long-term debt	$ 15,024,000				18,344,000
Senior Unsecured Notes | Senior unsecured utility bonds
Debt Instrument [Line Items]
Weighted average coupon	4.05%	4.05%	4.05%
Par value			$ 1,637,000
Long-term debt	$ 77,206,000				77,963,000
Senior Unsecured Notes | Senior Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 5,855,566,000				5,589,513,000
Senior Unsecured Notes | 5.25%, U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	5.25%	5.25%	5.25%
Par value		$ 400,000,000
Long-term debt	$ 291,238,000				0
Senior Unsecured Notes | 5.56%, U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	5.56%	5.56%	5.56%
Par value	$ 1,387,500,000
Long-term debt	1,365,213,000				621,862,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured revolving credit facilities
Debt Instrument [Line Items]
Long-term debt	351,786,000				368,806,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured bank credit facilities and delayed draw term facility
Debt Instrument [Line Items]
Long-term debt	773,643,000				141,956,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial paper
Debt Instrument [Line Items]
Long-term debt	$ 407,000,000				$ 338,700,000

Long-term debt - Bank Credit Fa

Long-term debt - Bank Credit Facilities Available to AQN and its Operating Groups (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Revolving and term credit facilities	$ 4,513,300	$ 3,217,000
Funds drawn on facilities/ commercial paper issued	(1,532,500)	(849,600)
Letters of credit issued	(465,200)	(317,200)
Liquidity available under the facilities	2,515,600	2,050,200
Undrawn portion of uncommitted letter of credit facilities	(226,900)	(224,000)
Cash and cash equivalents	57,623	125,157
Total liquidity and capital reserves	$ 2,346,323	$ 1,951,357

Long-term debt - Additional Inf

Long-term debt - Additional Information (Detail)

1 Months Ended

3 Months Ended

Nov. 08, 2022 USD ($)

Aug. 01, 2022 USD ($)

Jul. 22, 2022 USD ($)

Apr. 30, 2022 USD ($)

Apr. 29, 2022 USD ($)

Jan. 18, 2022 USD ($)

Jun. 30, 2021 USD ($) business_unit $ / shares shares

Mar. 17, 2023 USD ($)

Dec. 31, 2022 USD ($) $ / shares

Dec. 31, 2022 CAD ($)

Jun. 24, 2022 USD ($)

Apr. 29, 2022 creditFacility

Apr. 29, 2022 extension_period

Feb. 15, 2022 CAD ($)

Jan. 18, 2022 CAD ($)

Dec. 31, 2021 USD ($)

Dec. 20, 2021 USD ($)

Apr. 09, 2021 CAD ($) $ / shares

Feb. 15, 2021 CAD ($)

Debt Instrument [Line Items]

Short-term debt

$ 705,386,000

Liquidity available under the facilities

2,515,600,000

$ 2,050,200,000

Letters of credit issued

$ 465,200,000

317,200,000

Green Equity Units issued (in shares) | shares

23,000,000

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

$ 50

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

5%

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

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

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 USD per share) | $ / shares

$ 999.92

Debt instrument, effective interest rate

4.95%

4.95%

Debt instrument, term

10 years

Interest on long-term debt

$ 70,274,000

$ 49,806,000

Senior unsecured revolving credit facilities | Regulated Services Credit Facility

Debt Instrument [Line Items]

Par value

$ 1,000,000,000

Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 1,000

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

Debt Instrument [Line Items]

Par value

$ 750,000,000

Interest rate (percent)

4.75%

4.75%

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

Debt Instrument [Line Items]

Par value

$ 320,000,000

$ 400,000,000

Interest rate (percent)

5.25%

5.25%

Senior Unsecured Notes

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 115,000

$ 80,000,000

Senior Unsecured Notes | Subsequent Event

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 15,000,000

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

Debt Instrument [Line Items]

Weighted average coupon

1.18%

1.18%

Senior Unsecured Notes | Senior unsecured revolving credit facilities | Regulated Services Credit Facility

Debt Instrument [Line Items]

Par value

$ 500,000,000

$ 25,000,000

Line of Credit Facility, Expiration Period

1 year

Senior Unsecured Notes | Senior unsecured revolving credit facilities | Renewable Energy Group

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ (500,000,000)

Line of Credit Facility, Expiration Period

1 year

Senior Unsecured Notes | Senior unsecured bank credit facilities | Regulated Services Group

Debt Instrument [Line Items]

Par value

$ 1,100,000,000

Senior Unsecured Notes | 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%

Senior Unsecured Notes | Canadian dollar Senior unsecured notes

Debt Instrument [Line Items]

Par value

$ 1,200,000,000

$ 200,000

$ 150,000

Weighted average coupon

3.68%

3.68%

Senior Unsecured Notes | Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 400,000

Interest rate (percent)

2.85%

Senior Unsecured Notes | Short-Term Debt | Senior unsecured revolving credit facilities | Regulated Services Credit Facility

Debt Instrument [Line Items]

Par value

$ 500,000,000

Senior Debt | Canadian dollar Senior unsecured notes

Debt Instrument [Line Items]

Par value

$ 1,000

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

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ (75,000,000)

Letter of Credit | Renewable Energy Group

Debt Instrument [Line Items]

Letters of credit issued

$ 250,000,000

Lines of credit

$ 350,000

Line of Credit | Senior Unsecured Notes | Senior unsecured revolving credit facilities | Regulated Services Credit Facility

Debt Instrument [Line Items]

Number of new credit facilities

2

2

Long-term debt - Principal Paym

Long-term debt - Principal Payments (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2023	$ 1,128,660
2024	359,371
2025	45,262
2026	1,265,711
2027	719,144
Thereafter	4,019,166
Total	$ 7,537,314

Long-term debt - Schedule of In

Long-term debt - Schedule of Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-term debt	$ 261,535	$ 217,123
Commercial paper, credit facility draws and related fees	43,015	17,065
Accretion of fair value adjustments	(16,547)	(18,174)
Capitalized interest and AFUDC capitalized on regulated property	(10,802)	(6,521)
Other	1,373	61
Interest expense	$ 278,574	$ 209,554

Pension and other post-retire_3

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	$ 12,126	$ 10,836
Accumulated benefit obligation for pension plan	815,589	1,080,685
Pension benefits
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	569,255	648,864	$ 629,157
Expected employer contributions for next year	22,386
OPEB
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	172,167	192,375	$ 176,616
Expected employer contributions for next year	9,819
Private Equity Funds | Level 3
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 21,904	$ 17,314

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, 2022	Dec. 31, 2021
Change in plan assets
Non-current assets (note 11)	$ 26,482	$ 23,630
Pension benefits
Change in projected benefit obligation
Projected benefit obligation, beginning of year	765,618	834,913
Projected benefit obligation assumed from business combination	87,933	0
Plan Settlements	(112)	(1,294)
Service cost	16,309	14,673
Interest cost	24,787	20,676
Actuarial gain	(198,074)	(36,597)
Contributions from retirees	0	0
Plan amendments	0	237
Medicare Part D	0	0
Benefits paid	(68,197)	(66,800)
Foreign exchange	(129)	(190)
Projected benefit obligation, end of year	628,135	765,618
Change in plan assets
Fair value of plan assets, beginning of year	648,864	629,157
Plan assets acquired in business combination	74,532	0
Actual return on plan assets	(109,118)	58,721
Employer contributions	23,296	29,058
Plan Settlements	(112)	(1,294)
Contributions from retirees	0	0
Medicare Part D subsidy receipts	0	0
Benefits paid	(68,197)	(66,800)
Foreign exchange	(10)	22
Fair value of plan assets, end of year	569,255	648,864
Unfunded status	(58,880)	(116,754)
Non-current assets (note 11)	12,264	11,751
Current liabilities	(1,907)	(1,902)
Non-current liabilities	(69,237)	(126,603)
Net amount recognized	(58,880)	(116,754)
OPEB
Change in projected benefit obligation
Projected benefit obligation, beginning of year	292,646	306,524
Projected benefit obligation assumed from business combination	5,195	0
Plan Settlements	0	0
Service cost	6,277	7,307
Interest cost	9,146	8,048
Actuarial gain	(82,991)	(18,977)
Contributions from retirees	2,220	2,040
Plan amendments	(2,452)	310
Medicare Part D	367	373
Benefits paid	(13,078)	(12,979)
Foreign exchange	0	0
Projected benefit obligation, end of year	217,330	292,646
Change in plan assets
Fair value of plan assets, beginning of year	192,375	176,616
Plan assets acquired in business combination	8,577	0
Actual return on plan assets	(30,105)	15,200
Employer contributions	11,811	11,178
Plan Settlements	0	0
Contributions from retirees	2,220	1,988
Medicare Part D subsidy receipts	367	372
Benefits paid	(13,078)	(12,979)
Foreign exchange	0	0
Fair value of plan assets, end of year	172,167	192,375
Unfunded status	(45,163)	(100,271)
Non-current assets (note 11)	14,218	11,879
Current liabilities	(3,039)	(699)
Non-current liabilities	(56,342)	(111,451)
Net amount recognized	$ (45,163)	$ (100,271)

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, 2022	Dec. 31, 2021
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 413,041	$ 489,043
Fair value of plan assets	364,229	396,679
Projected benefit obligation	489,140	580,841
Fair value of plan assets	417,994	452,333
OPEB
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	198,463	274,649
Fair value of plan assets	139,368	162,592
Projected benefit obligation	198,463	274,649
Fair value of plan assets	$ 139,368	$ 162,592

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, 2022	Dec. 31, 2021
Pension benefits
Actuarial losses (gains)
Balance, January 1	$ 15,807	$ 57,231
Additions to AOCI	(47,473)	(59,754)
Amortization in current period	(3,429)	(13,130)
Amortization due to plan settlements	15
Amortization due to plan settlements		(210)
Reclassification to regulatory accounts	34,409	31,670
Ending balance, December 31	(671)	15,807
Past service losses (gains)
Beginning balance, January 1	(4,195)	(5,306)
Additions to AOCI	0	237
Amortization in current period	1,584	1,626
Amortization due to plan settlements	0
Amortization due to plan settlements		0
Reclassification to regulatory accounts	(752)	(752)
Ending balance, December 31	(3,363)	(4,195)
OPEB
Actuarial losses (gains)
Balance, January 1	(15,630)	(4,299)
Additions to AOCI	(41,527)	(24,126)
Amortization in current period	56	(2,021)
Amortization due to plan settlements	0
Amortization due to plan settlements		0
Reclassification to regulatory accounts	23,551	14,816
Ending balance, December 31	(33,550)	(15,630)
Past service losses (gains)
Beginning balance, January 1	310	0
Additions to AOCI	(24)	(24)
Amortization in current period	(2,476)	334
Amortization due to plan settlements	0
Amortization due to plan settlements		0
Reclassification to regulatory accounts	0	0
Ending balance, December 31	$ (2,190)	$ 310

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, 2022	Dec. 31, 2021
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.48%	2.94%
Interest crediting rate (for cash balance plans)	4.50%	4%
Rate of compensation increase	3.70%	4%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.49%	3%
Health care cost trend rate
Before age 65	6%	5.88%
Age 65 and after	6%	5.88%
Assumed ultimate medical inflation rate	4.75%	4.75%
Year in which ultimate rate is reached	2033	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, 2022	Dec. 31, 2021
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.94%	2.49%
Expected return on assets	6.19%	6.20%
Rate of compensation increase	3.91%	3.99%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3%	2.58%
Expected return on assets	6.48%	4.79%
Health care cost trend rate
Before Age 65	5.88%	5.12%
Age 65 and after	5.88%	5.12%
Assumed ultimate medical inflation rate	4.75%	4.05%
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, 2022	Dec. 31, 2021
Non-service costs
Non-service costs	$ 10,950	$ 16,313
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	16,309	14,673
Non-service costs
Interest cost	24,787	20,676
Expected return on plan assets	(41,226)	(35,972)
Amortization of net actuarial loss	3,452	13,126
Amortization of prior service credits	(1,584)	(1,626)
Amortization due to plan settlements	(15)	198
Impact of regulatory accounts	22,951	19,665
Non-service costs	8,365	16,067
Net benefit cost	24,674	30,740
OPEB
Defined Benefit Plan Disclosure [Line Items]
Service cost	6,277	7,307
Non-service costs
Interest cost	9,146	8,048
Expected return on plan assets	(11,359)	(10,052)
Amortization of net actuarial loss	(56)	2,021
Amortization of prior service credits	24	11
Amortization due to plan settlements	0	0
Impact of regulatory accounts	4,829	218
Non-service costs	2,584	246
Net benefit cost	$ 8,861	$ 7,553

Pension and other post-retir_10

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	41%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	49%
Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	10%
Minimum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	30%
Minimum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	20%
Minimum | Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	0%
Maximum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100%
Maximum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	60%
Maximum | Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	20%

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, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2022	$ 741,422
Percentage	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
2022	$ 317,088
Percentage	43%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
2022	$ 356,654
Percentage	48%
Other
Defined Benefit Plan Disclosure [Line Items]
2022	$ 67,680
Percentage	9%

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, 2022 USD ($)
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets, beginning of year	$ 17,314
Contributions into funds	4,781
Return on assets	2,094
Distributions	(2,285)
Fair value of plan assets, end of year	$ 21,904

Pension and other post-retir_13

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Pension plan
Defined Benefit Plan Disclosure [Line Items]
2023	$ 48,174
2024	47,428
2025	49,794
2026	50,585
2027	50,433
2028-2032	259,082
OPEB
Defined Benefit Plan Disclosure [Line Items]
2023	11,483
2024	12,025
2025	12,548
2026	12,925
2027	13,479
2028-2032	$ 72,684

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	$ 43,562	$ 36,232
Pension and OPEB plan assets (note 10	26,482	23,630
Long-term deposits and cash collateral	22,537	14,713
Income taxes recoverable	7,100	7,649
Deferred financing costs	28,586	30,544
Other (b)	21,596	10,913
Total other assets	149,863	123,681
Less: current portion	(22,564)	(16,153)
Other assets (note 11)	$ 127,299	$ 107,528

Other long-term liabilities - S

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Contract adjustment payments	$ 113,876	$ 187,580
Asset retirement obligations	116,584	142,147	$ 79,968
Advances in aid of construction	88,546	82,584
Environmental remediation obligation	42,457	55,224	69,383
Customer deposits	34,675	32,629
Unamortized investment tax credits	17,649	17,439
Deferred credits and contingent consideration	39,498	43,495
Preferred shares, Series C	12,072	13,348
Hook-up fees	32,463	21,904
Lease liabilities (note 1)	21,834	22,512
Contingent development support obligations	8,824	4,615
Note payable to related party	25,808	25,808	$ 30,493
Other	41,156	34,534
Other long-term liabilities	595,442	683,819
Less: current portion	(134,212)	(167,908)
Other long-term liabilities, excluding current	$ 461,230	$ 515,911

Other long-term liabilities - A

Other long-term liabilities - Additional Information (Detail) $ in Thousands	1 Months Ended		12 Months Ended
	Jun. 30, 2021 USD ($) shares	Jan. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	Dec. 31, 2022 $ / shares	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
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, excluding interest	$ 222,378		$ 222,378
Contract adjustment payments, accretion period	3 years
Transfers from advances in aid of construction to contributions in aid of construction			1,299	$ 6,376
Undiscounted, unescalated cost of environmental cleanup activities			48,346	57,167
Environmental remediation obligation			42,457	55,224		$ 69,383
Accrual for environmental loss contingencies to be incurred over next four years			27,410
Regulatory assets			1,271,501	1,167,625
Note payable to related party			$ 25,808	25,808		30,493
Maverick Creek and Sugar Creek Wind Facilities
Debt Instrument [Line Items]
Total purchase price		$ 18,641
Equity Method Investee
Debt Instrument [Line Items]
Note payable to related party				$ 25,808		$ 30,493
Note payable to related party
Debt Instrument [Line Items]
Interest rate (percent)				4%		0.675%
Preferred shares, Series C
Debt Instrument [Line Items]
Redeemable preferred stock issued (in shares) | shares			100
Preferred stock redemption price per share (in CAD per share) | $ / shares					$ 53,400
Environmental costs
Debt Instrument [Line Items]
Environmental remediation, rate recovery period			7 years
Regulatory assets			$ 70,529	$ 81,802
Minimum
Debt Instrument [Line Items]
Other liability repayment period			5 years
Accrual for environmental cleanup, discount rate (percent)			3.40%
Maximum
Debt Instrument [Line Items]
Other liability repayment period			40 years
Accrual for environmental cleanup, discount rate (percent)			4.20%
U.S. Dollar Senior Unsecured Notes (Green Equity Units) | Senior Unsecured Notes
Debt Instrument [Line Items]
Proceeds from green equity units	$ 1,150,000
Weighted average coupon	1.18%		1.18%

Other long-term liabilities -_2

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 142,147	$ 79,968
Obligation assumed	793	57,067
Retirement activities	(27,980)	(4,133)
Accretion	4,589	4,381
Change in cash flow estimates	(2,965)	4,864
Closing balance	$ 116,584	$ 142,147

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 55,224	$ 69,383
Remediation activities	(5,243)	(9,865)
Accretion	2,167	1,025
Changes in cash flow estimates	1,344	2,265
Revision in assumptions	(11,035)	(7,584)
Closing balance	$ 42,457	$ 55,224

Other long-term liabilities - P

Other long-term liabilities - Preferred Shares, Series C (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Total Preferred shares series C	$ 12,072	$ 13,348
Preferred shares, Series C | Dividends Payable
Class of Stock [Line Items]
2023	1,245
2024	1,443
2025	1,459
2026	1,316
2027	1,262
Thereafter to 2031	4,654
Redemption amount	3,943
Estimated dividend and redemption payments	15,322
Less: amounts representing interest	(3,250)
Total Preferred shares series C	12,072
Less current portion	(1,245)
Preferred shares series C, noncurrent	$ 10,827

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Common Shares Rollforward
Beginning balance (in shares)	671,960,276	597,142,219
Public offering (in shares)	2,861,709	67,611,465
Dividend reinvestment plan (in shares)	7,676,666	6,184,686
Exercise of share-based awards (in shares)	1,115,398	1,020,020
Conversion of convertible debentures (in shares)	754	1,886
Ending balance (in shares)	683,614,803	671,960,276

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands

2 Months Ended

12 Months Ended

35 Months Ended

Mar. 03, 2022

Nov. 08, 2021 USD ($) $ / shares shares

Nov. 08, 2021 CAD ($) shares

Mar. 03, 2023 shares

Dec. 31, 2022 $ / shares

Dec. 31, 2022 USD ($) right vote $ / shares shares

Dec. 31, 2021 $ / shares

Dec. 31, 2021 USD ($) shares

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

Dec. 31, 2022 USD ($) shares

Aug. 15, 2022 USD ($)

Nov. 08, 2021 $ / 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%

Total share-based compensation | $

$ 10,920,000

$ 8,395,000

Unrecognized compensation costs, non-vested awards | $

$ 10,732,000

Unrecognized compensation costs, non-vested options, period of recognition

1 year 9 months 18 days

Common shares issued from treasury (in shares)

2,403

Share based awards settled for cash value as payment for tax withholding (in shares)

2,773

Share options

Stockholders Equity Note [Line Items]

Total share-based compensation | $

$ 980,000

$ 939,000

Percentage of shares reserved under the plan (must not exceed)

8%

ESPP

Stockholders Equity Note [Line Items]

Number of shares issued pursuant to public offering (in shares)

414,338

355,096

Vesting period of matching contribution shares

1 year

Maximum aggregate number of shares reserved for future issuance (in shares)

4,000,000

Deferred Share Units

Stockholders Equity Note [Line Items]

Maximum aggregate number of shares reserved for future issuance (in shares)

1,000,000

Exercise of share-based awards (in shares)

120,513

73,467

Shares issued during period (in shares)

645,714

530,378

Performance and restricted share units

Stockholders Equity Note [Line Items]

Maximum aggregate number of shares reserved for future issuance (in shares)

7,000,000

Award vesting period

3 years

Company Match, First $5,000 Contributed by Employee

Stockholders Equity Note [Line Items]

Employer matching contribution (percent)

20%

Company Match, Employee Contributions $5,001 to $10,000

Stockholders Equity Note [Line Items]

Employer matching contribution (percent)

10%

Preferred shares, Series A

Stockholders Equity Note [Line Items]

Shares issued, price per share (USD and CAD per share) | $ / shares

$ 25

Dividend declared per preferred share (USD per share) | $ / shares

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

Dividend declared per preferred share (USD per share) | $ / shares

$ 1.2728

$ 1.2728

Preferred dividend rate reset period

5 years

Basis spread on variable rate

3.28%

Preferred shares, Series C

Stockholders Equity Note [Line Items]

Redeemable preferred stock issued (in shares)

100

ATM Equity Program

Stockholders Equity Note [Line Items]

Number of shares issued pursuant to public offering (in shares)

2,861,709

36,814,536

Cash proceeds from issuance of shares | $

$ 38,923,000

$ 551,086,000

Treasury stock, amount reserved for issuance under the plan | $

$ 500,000,000

Sale of stock, average price per share (in USD) | $ / shares

$ 13.94

$ 15

Proceeds from sale of stock, net of commissions | $

$ 38,534,000

$ 544,295,000

Sale of stock, other related costs | $

$ 558,000

$ 4,843,000

Common shares

Stockholders Equity Note [Line Items]

Discount rate on share purchases under dividend reinvestment plan (percent)

3%

5%

Common shares | Subsequent Event

Stockholders Equity Note [Line Items]

Dividend reinvestment plan shares issued (in shares)

4,370,289

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

Shares issued, price per share (USD and CAD per share) | (per share)

$ 14.63

$ 18.15

Cash proceeds from issuance of shares

$ 642,664,000

$ 800,052

Issuance costs | $

$ 32,583

Proceeds from sale of stock, net of commissions | $

$ 26,173,000

Exercise of share-based awards settled (in shares)

5,176

87,582

Minimum

Stockholders Equity Note [Line Items]

Percentage of outstanding stock to be purchased to acquire discount (or more)

20%

Minimum | Performance and restricted share units

Stockholders Equity Note [Line Items]

Percentage of shares issued on number of PSU grants (percent)

2.50%

Maximum | Performance and restricted share units

Stockholders Equity Note [Line Items]

Percentage of shares issued on number of PSU grants (percent)

237%

Shareholders' capital - Preferr

Shareholders' capital - Preferred Shares (Detail) $ / shares in Units, $ in Thousands, $ in Thousands	Dec. 31, 2022 USD ($) shares	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2021 USD ($)
Stockholders Equity Note [Line Items]
Preferred shares | $	$ 184,299		$ 184,299
Series A
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares) | shares	4,800,000	4,800,000
Shares issued, price per share (USD and CAD per share) | $ / shares		$ 25
Preferred shares	$ 100,463	$ 116,546
Series D
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares) | shares	4,000,000	4,000,000
Shares issued, price per share (USD and CAD per share) | $ / shares		$ 25
Preferred shares	$ 83,836	$ 97,259

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 10,920	$ 8,395
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	980	939
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	960	821
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	562	592
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 8,418	$ 6,043

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Risk-free interest rate	1.90%	1.10%
Expected volatility	23%	23%
Expected dividend yield	4.30%	4.10%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (in USD per share)	$ 2.44	$ 2.46

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Number of awards
Beginning balance (in shares)	2,040,528	2,110,448
Granted (in shares)	646,090	437,006
Exercised (in shares)	(40,074)	(506,926)
Forfeited (in shares)	(19,764)	0
Ending balance (in shares)	2,626,780	2,040,528	2,110,448
Exercisable (in shares)	2,052,946
Weighted average exercise price
Beginning balance (in USD per share)	$ 15.45
Granted (in USD per share)	19.11	$ 19.64
Exercised (in USD per share)	13.92	13.92
Forfeited (in USD per share)	19.11	0
Ending balance (in USD per share)	16.02	$ 15.45
Exercisable (in USD per share)	$ 17.35
Weighted average remaining contractual term (years)
Outstanding shares, weighted average remaining contractual term	5 years 7 months 17 days	6 years 1 month 9 days	6 years 6 months 18 days
Granted, weighted average remaining contractual term	7 years 2 months 19 days	7 years 2 months 19 days
Exercised shares, weighted average remaining contractual term	5 years 11 months 12 days	5 years 11 months 12 days
Beginning balance, aggregate intrinsic value	$ 3,145	$ 11,604
Exercised, aggregate intrinsic value	103	1,453
Ending balance, aggregate intrinsic value	$ 0	$ 3,145	$ 11,604
Exercisable , weighted average remaining contractual term	5 years 7 months 17 days

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Weighted average remaining contractual term (years)
Weighted average remaining contractual term, Exercisable	5 years 7 months 17 days
Performance and restricted share units
Number of awards
Beginning balance (in shares)	2,443,672	2,721,207
Granted, including dividends (in shares)	1,090,457	805,433
Exercised (in shares)	(1,221,620)	(865,067)
Forfeited (in shares)	(202,799)	(217,901)
Ending balance (in shares)	2,109,710	2,443,672	2,721,207
Exercisable (in shares)	769,458
Weighted average grant-date fair value
Beginning balance (in USD per share)	$ 18.07	$ 16.58
Granted, including dividends (in USD per share)	17.99	19.94
Exercised (in USD per share)	12.62	13.79
Forfeited (in USD per share)	18.94	18.64
Ending balance (in USD per share)	18.38	$ 18.07	$ 16.58
Exercisable (in USD per share)	$ 18.70
Weighted average remaining contractual term (years)
Outstanding, Weighted average remaining contractual term	1 year 9 months 3 days	1 year 8 months 19 days	11 months 4 days
Granted, including dividends, Weighted average remaining contractual term	2 years	2 years 9 months 7 days
Weighted average remaining contractual term, Exercisable	1 month 6 days
Outstanding, aggregate intrinsic value	$ 18,608	$ 44,646	$ 54,560
Granted, including dividends, aggregate intrinsic value	17,524	12,881
Exercised, aggregate intrinsic value	23,636	17,005
Forfeited, aggregate intrinsic value	418	$ 3,981
Exercisable, aggregate intrinsic value	$ 6,787

Shareholder's capital - Bonus D

Shareholder's capital - Bonus Deferral RSUs (Detail) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Treasury Stock, Common
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued from treasury to settles RSUs and PSUs (in shares)	82,886	70,571
Common shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity other than options settled at cash value for payment of the exercise price and for tax withholdings (in shares)	95,482	81,993
Retirement Restricted Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vested (percent)	100%
Bonus Deferral Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued during period (in shares)	55,445	56,686
Deferred Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued during period (in shares)	645,714	530,378
Common stock, shares issued (in shares)	178,368	152,564
Awards outstanding (in shares)	158,486	281,411

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, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 7,382,079	$ 5,662,190
OCI	(123,129)	(90,838)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	33,093	48,288
OCI, net of tax	(90,036)	(42,550)
OCI attributable to the non-controlling interests	1,650	(249)
Net current period OCI attributable to shareholders of AQN	(88,386)	(42,799)
Amounts reclassified from AOCI to non-controlling interest		(6,371)
Ending Balance	6,836,439	7,382,079
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(71,677)	(22,507)
OCI, net of tax	(88,386)	(42,799)
Ending Balance	(160,063)	(71,677)
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(76,615)	(39,725)
OCI	(18,013)	(25,982)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	(5,489)	(4,288)
OCI, net of tax	(23,502)	(30,270)
OCI attributable to the non-controlling interests	1,650	(249)
Net current period OCI attributable to shareholders of AQN	(21,852)	(30,519)
Amounts reclassified from AOCI to non-controlling interest		(6,371)
Ending Balance	(98,467)	(76,615)
Unrealized gain (loss) on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(3,514)	50,817
OCI	(128,838)	(97,103)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	34,543	42,772
OCI, net of tax	(94,295)	(54,331)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	(94,295)	(54,331)
Amounts reclassified from AOCI to non-controlling interest		0
Ending Balance	(97,809)	(3,514)
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	8,452	(33,599)
OCI	23,722	32,247
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	4,039	9,804
OCI, net of tax	27,761	42,051
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	27,761	42,051
Amounts reclassified from AOCI to non-controlling interest		0
Ending Balance	$ 36,213	$ 8,452

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2022 CAD ($) $ / shares	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2021 CAD ($) $ / shares
Dividends [Line Items]
Dividend declared for common share holders | $	$ 486,043		$ 423,023
Cash dividend declared per common share (USD per share) | $ / shares	$ 0.7130		$ 0.6669
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) | $ / shares		$ 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) | $ / shares		$ 1.2728		$ 1.2728

Related party transactions (Det

Related party transactions (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Transactions with Third Party [Line Items]
Note payable to related party		$ 25,808	$ 25,808	$ 30,493
AAGES Spain
Transactions with Third Party [Line Items]
Acquired assets	$ 2,662
Working capital	1,507
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses		63,861	25,778
Development fees		12,628	2,036
Note payable to related party			25,808	$ 30,493
Abengoa
Transactions with Third Party [Line Items]
Option to purchase interest in joint venture	1,500
Abengoa | AAGES Spain
Transactions with Third Party [Line Items]
Loans related to parties	$ 3,089
Atlantica | Related Party
Transactions with Third Party [Line Items]
Purchases from related party			23,863
Gain on sale with related party		$ 1,200	878
Contingent consideration			$ 2,600

Non-controlling interests and_3

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Noncontrolling Interest [Line Items]
Net earnings attributable to NCI	$ 111,323	$ 89,637
Redeemable non-controlling interest, held by related party	(15,157)	(10,435)
Net effect of non-controlling interests	96,166	79,202
Tax Equity Partnership Units
Noncontrolling Interest [Line Items]
Net earnings attributable to NCI	108,695	88,417
Redeemable Tax Equity Partnership Units
Noncontrolling Interest [Line Items]
Net earnings attributable to NCI	6,298	6,902
Non-controlling interests
Noncontrolling Interest [Line Items]
Net earnings attributable to NCI	$ (3,670)	$ (5,682)

Non-controlling interests and_4

Non-controlling interests and redeemable non-controlling interests - Change in Non-Controlling Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	$ 1,523,082
Net earnings attributable to NCI	111,323	$ 89,637
Contributions received, net	5,000	0
Non-controlling interest assumed on asset acquisition		29,141
OCI	1,650	(249)
Closing balance	1,616,792	1,523,082
Atlantica Yield Energy Solutions Canada Inc. (b)
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	81,158	59,125
Net earnings attributable to NCI	0	0
Contributions received, net	0	39,376
Dividends and distributions declared	(20,978)	(17,793)
Repurchase of non-controlling interest	0	0
Non-controlling interest assumed on asset acquisition	0	0
OCI	(2,358)	450
Closing balance	57,822	81,158
Non-controlling interests
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	64,807	11,234
Net earnings attributable to NCI	345	3,354
Contributions received, net	267,515	51,451
Dividends and distributions declared	0	(1,021)
Repurchase of non-controlling interest	0	0
Non-controlling interest assumed on asset acquisition	0	0
OCI	695	(211)
Closing balance	333,362	64,807
Class A Units | Class A Partnership Units
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	1,377,117	388,253
Net earnings attributable to NCI	(105,371)	(87,422)
Contributions received, net	6,182	1,058,929
Dividends and distributions declared	(40,086)	(11,795)
Repurchase of non-controlling interest	(12,249)	0
Non-controlling interest assumed on asset acquisition	0	29,141
OCI	15	11
Closing balance	$ 1,225,608	$ 1,377,117

Non-controlling interests and_5

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest - Additional Information (Details) $ in Thousands		12 Months Ended
	Jan. 01, 2021 USD ($)	Dec. 31, 2022 USD ($) wind_project	Dec. 31, 2021 USD ($)	Dec. 29, 2022 USD ($)	Nov. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)	May 31, 2019 USD ($)	May 31, 2019 CAD ($)
Noncontrolling Interest [Line Items]
Non-controlling interests		$ 1,616,792,000	$ 1,523,082,000
Contributions received, net		5,000,000	0
Non-controlling interests, tax equity investors		1,225,608,000	1,377,117,000
Non-controlling interest calculated using the HLBV method of accounting		(111,323,000)	(89,637,000)
Redeemable non-controlling interests		11,520,000	12,989,000	$ 5,000,000		$ 20,859,000
AQN's investment carrying amount for the entities		381,802,000	433,850,000
Atlantica Yield Energy Solutions Canada Inc. (b)
Noncontrolling Interest [Line Items]
Non-controlling interests		57,822,000	81,158,000			59,125,000
Contributions received, net		0	39,376,000
Non-controlling interest calculated using the HLBV method of accounting		0	0
Distribution from interest in noncontrolling interest		20,978,000	17,793,000
ESSAL
Noncontrolling Interest [Line Items]
Equity method investment remaining ownership percentage	64%
Noncontrolling interest, ownership percentage by parent	30%
Eco Acquisitionco SpA
Noncontrolling Interest [Line Items]
Contributions received, net	$ 51,750,000
Sale of equity interest percentage	32%
Senior Secured Utility Bonds | Redeemable Non-Controlling Interest
Noncontrolling Interest [Line Items]
Line of credit facility, maximum borrowing capacity		$ 306,500,000
North Fork Ridge Wind Project
Noncontrolling Interest [Line Items]
Number of wind projects | wind_project		3
Non-controlling interests			29,141,000
AIP | Atlantica Yield Energy Solutions Canada Inc. (b)
Noncontrolling Interest [Line Items]
Non-controlling interests							$ 96,752,000	$ 130,103
Non-controlling interests
Noncontrolling Interest [Line Items]
Non-controlling interests		$ 333,362,000	64,807,000			11,234,000
Contributions received, net		267,515,000	51,451,000
Non-controlling interest calculated using the HLBV method of accounting		(345,000)	(3,354,000)
Distribution from interest in noncontrolling interest		0	1,021,000
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Non-controlling interests		1,225,608,000	1,377,117,000			$ 388,253,000
Contributions received, net		6,182,000	1,058,929,000
Non-controlling interest calculated using the HLBV method of accounting		105,371,000	87,422,000
Distribution from interest in noncontrolling interest		$ 40,086,000	11,795,000
Mid-West Wind Facilities
Noncontrolling Interest [Line Items]
Contributions received, net			530,880,000
Sugar Creek Wind Facility
Noncontrolling Interest [Line Items]
Contributions received, net			380,829,000
Maverick Creek Wind Facility
Noncontrolling Interest [Line Items]
Contributions received, net			$ 147,914,000
Liberty Development JV Inc
Noncontrolling Interest [Line Items]
AQN's investment carrying amount for the entities					$ 19,688,000
AY Holdco
Noncontrolling Interest [Line Items]
AQN's investment carrying amount for the entities					$ 39,376,000

Non-controlling interests and_6

Non-controlling interests and redeemable non-controlling interests - Change in Redeemable non-controlling Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 12,989	$ 20,859
Net earnings attributable to NCI	(6,298)	(6,902)
Contributions, net of costs	5,000	0
Dividends and distributions declared	(171)	(968)
Closing balance	11,520	12,989
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	306,537	306,316
Net earnings attributable to NCI	15,157	10,435
Contributions, net of costs	0	0
Dividends and distributions declared	(13,838)	(10,214)
Closing balance	$ 307,856	$ 306,537

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Canadian enacted statutory rate (percent)	26.50%	26.50%
Valuation allowance for deferred tax assets	$ 107,583	$ 27,471	$ 29,824
Undistributed earnings of foreign subsidiaries	$ 824,052

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Expected income tax recovery at Canadian statutory rate	$ (97,962)	$ 37,691
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(55,315)	(47,600)
Adjustments from investments carried at fair value	51,314	2,709
Non-controlling interests share of income	30,025	25,135
Change in valuation allowance	41,702	(118)
Non-deductible acquisition costs	1,341	3,733
Acquisition related state deferred tax adjustments	5,998	0
Capital gain rate differential on disposal of renewable assets	(7,340)	0
Tax credits	(18,440)	(49,415)
Adjustment relating to prior periods	(1,390)	1,333
Deferred income taxes on regulated income recorded as regulatory assets	(2,155)	(3,807)
Amortization and settlement of excess deferred income tax	(14,855)	(16,778)
Other	5,564	3,692
Total	$ (61,513)	$ (43,425)

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ (369,668)	$ 142,232
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	(363,050)	(60,848)
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	(37,322)	153,719
Other regions
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 30,704	$ 49,361

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Expenses [Line Items]
Current	$ 7,843	$ 7,237
Deferred	(69,356)	(50,662)
Total	(61,513)	(43,425)
Canada
Income Tax Expenses [Line Items]
Current	4,184	4,560
Deferred	(74,595)	(33,993)
Total	(70,411)	(29,433)
United States
Income Tax Expenses [Line Items]
Current	1,579	1,024
Deferred	6,183	(19,772)
Total	7,762	(18,748)
Other regions
Income Tax Expenses [Line Items]
Current	2,080	1,653
Deferred	(944)	3,103
Total	$ 1,136	$ 4,756

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 878,000	$ 761,666
Pension and OPEB	16,845	46,580
Environmental obligation	12,118	15,271
Regulatory liabilities	156,285	166,939
Other	61,917	64,460
Total deferred income tax assets	1,125,165	1,054,916
Less: valuation allowance	(107,583)	(27,471)	$ (29,824)
Total deferred tax assets	1,017,582	1,027,445
Deferred tax liabilities:
Property, plant and equipment	846,331	782,829
Outside basis differentials	315,581	412,665
Regulatory accounts	303,059	300,072
Other	33,834	30,471
Total deferred tax liabilities	1,498,805	1,526,037
Net deferred tax liabilities	(481,223)	(498,592)
Deferred tax assets	84,416	31,595
Deferred tax liabilities	$ (565,639)	$ (530,187)

Income taxes - Summary of Valua

Income taxes - Summary of Valuation Allowance for Deferred Tax Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Deferred Tax Assets, Valuation Allowance [Roll Forward]
Beginning balance	$ 27,471	$ 29,824
Charged to income tax expense (recovery)	41,702	(118)
Charged (reduction) to OCI	40,613	(1,707)
Reductions to other accounts	(2,203)	(528)
Ending balance	$ 107,583	$ 27,471

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 2,448,891
Tax credits	156,104
Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	731,790
U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	1,717,101
2023—2027
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	13,223
Tax credits	4,428
2023—2027 | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	3,261
2023—2027 | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	9,962
2028+
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	2,435,668
Tax credits	151,676
2028+ | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	728,529
2028+ | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 1,707,139

Other net losses Other Losses (

Other net losses Other Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Other Income and Expenses [Abstract]
Impairment of assets	$ 235,478	$ 0
Acquisition and transition-related costs	17,442	14,507
Other	3,949	8,442
Other losses	$ 21,391	$ 22,949

Basic and diluted net earning_3

Basic and diluted net earnings (loss) per share - Schedule of Earnings per Share (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Net earnings (loss) attributable to shareholders of AQN	$ (211,989,000)	$ 264,859,000
Series A and D Preferred shares dividend	8,720,000	9,003,000
Net earnings (loss) attributable to common shareholders of AQN – basic (in shares)	(220,709,000)	255,856,000
Net earnings (loss) attributable to common shareholders of AQN – diluted (in shares)	$ (220,709,000)	$ 255,856,000
Weighted average number of shares
Basic (in shares)	677,862,207	622,347,677
Effect of dilutive securities (in shares)	0	6,600,185
Diluted (in shares)	677,862,207	628,947,862
Preferred shares, Series A dividend
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,786,000	$ 4,942,000
Preferred shares, Series D dividend
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 3,934,000	$ 4,061,000

Basic and diluted net earning_4

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

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2022 segment business_unit
Segment Reporting [Abstract]
Number of business units | business_unit	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, 2022	Dec. 31, 2021
Revenue
Revenue	$ 2,679,475	$ 2,200,804
Other revenue	2,765,155	2,274,142
Fuel, power and water purchased	866,496	713,915
Net revenue	1,898,659	1,560,227
Operating expenses	851,489	702,128
Administrative expenses	80,232	66,726
Depreciation and amortization	455,520	402,963
Impairment of assets	159,568	0
Loss on foreign exchange	13,833	4,371
Operating income (loss), before gain on sale of renewable assets	338,017	384,039
Gain on sale of renewable assets	64,028	29,063
Operating income (loss)	402,045	413,102
Interest expense	(278,574)	(209,554)
Income (loss) from long-term investments	(465,206)	(26,457)
Other	(27,933)	(34,859)
Income (loss) before income taxes	(369,668)	142,232
Property, plant and equipment	11,944,885	11,042,446
Investments carried at fair value	1,344,207	1,848,456
Equity-method investees	381,802	433,850
Total assets	17,627,613	16,797,503
Capital expenditures	1,089,024	1,345,045
Revenue related to net hedging loss, not recognized as revenue from contract with customers	63,717	57,018
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	21,640	19,043
Other revenue
Revenue
Other revenue	85,680	73,338
Corporate
Revenue
Revenue	0	0
Fuel, power and water purchased	0	0
Operating expenses	511	16
Administrative expenses	7,324	1,249
Depreciation and amortization	1,017	1,097
Impairment of assets	0
Loss on foreign exchange	13,833	4,371
Gain on sale of renewable assets	0	0
Interest expense	(100,807)	(44,545)
Income (loss) from long-term investments	(502,344)	(128,809)
Other	(12,598)	(7,726)
Property, plant and equipment	29,260	32,380
Investments carried at fair value	0	0
Equity-method investees	15,500	20,898
Total assets	266,105	149,149
Capital expenditures	0	7,553
Corporate | Other revenue
Revenue
Other revenue	1,501	1,558
Regulated Services Group | Operating Segments
Revenue
Revenue	2,328,536	1,944,171
Fuel, power and water purchased	824,670	682,602
Net revenue	1,559,598	1,315,010
Operating expenses	736,515	597,850
Administrative expenses	46,484	37,179
Depreciation and amortization	317,300	280,452
Impairment of assets	0
Loss on foreign exchange	0	0
Operating income (loss), before gain on sale of renewable assets	459,299	399,529
Gain on sale of renewable assets	0
Operating income (loss)	459,299	399,529
Interest expense	(113,482)	(93,411)
Income (loss) from long-term investments	21,884	18,306
Other	(14,765)	(24,177)
Income (loss) before income taxes	352,936	300,247
Property, plant and equipment	8,554,938	7,394,151
Investments carried at fair value	1,984	2,296
Equity-method investees	56,199	37,492
Total assets	12,109,575	10,524,466
Capital expenditures	908,676	998,855
Regulated Services Group | Operating Segments | Other revenue
Revenue
Other revenue	55,732	53,441
Renewable Energy Group
Revenue
Net revenue	337,560
Operating income (loss), before gain on sale of renewable assets	(100,098)	(10,315)
Operating income (loss)	(36,070)
Income (loss) from long-term investments	15,254
Income (loss) before income taxes	(85,671)
Renewable Energy Group | Operating Segments
Revenue
Revenue	350,939	256,633
Fuel, power and water purchased	41,826	31,313
Net revenue		243,659
Operating expenses	114,463	104,262
Administrative expenses	26,424	28,298
Depreciation and amortization	137,203	121,414
Impairment of assets	159,568
Loss on foreign exchange	0	0
Gain on sale of renewable assets	64,028	29,063
Operating income (loss)		18,748
Interest expense	(64,285)	(71,598)
Income (loss) from long-term investments		84,046
Other	(570)	(2,956)
Income (loss) before income taxes		28,240
Property, plant and equipment	3,360,687	3,615,915
Investments carried at fair value	1,342,223	1,846,160
Equity-method investees	310,103	375,460
Total assets	5,251,933	6,123,888
Capital expenditures	180,348	338,637
Renewable Energy Group | Operating Segments | Other revenue
Revenue
Other revenue	28,447	18,339
Corporate
Revenue
Net revenue	1,501	1,558
Operating income (loss), before gain on sale of renewable assets	(21,184)	(5,175)
Operating income (loss)	(21,184)	(5,175)
Income (loss) before income taxes	$ (636,933)	$ (186,255)

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenue	$ 2,765,155	$ 2,274,142
Property, plant and equipment	11,944,885	11,042,446
Intangible assets	96,683	105,116
United States
Segment Reporting Information [Line Items]
Revenue	2,232,959	1,790,539
Property, plant and equipment	10,351,736	9,464,716
Intangible assets	18,818	23,575
Canada
Segment Reporting Information [Line Items]
Revenue	175,005	157,854
Property, plant and equipment	848,560	882,454
Intangible assets	19,038	21,780
Other regions
Segment Reporting Information [Line Items]
Revenue	357,191	325,749
Property, plant and equipment	744,589	695,276
Intangible assets	$ 58,827	$ 59,761

Commitments and contingencies -

Commitments and contingencies - Additional Information (Details) $ in Thousands	Aug. 02, 2022 USD ($)	Dec. 31, 2022 lawsuit
Commitments Disclosure [Line Items]
Attorney’s fees and litigation costs | $	$ 13,222
Mountain View Fire
Commitments Disclosure [Line Items]
Number of active lawsuits		17
Number of lawsuits filed by groups of individual plaintiffs		12
Number of lawsuits filed by insurance companies		4

Commitments and contingencies_2

Commitments and contingencies - Estimates of Future Commitments (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Commitments Disclosure [Line Items]
Year 1	$ 291,556
Year 2	185,411
Year 3	159,078
Year 4	115,909
Year 5	104,325
Thereafter	1,093,025
Total	1,949,304
Power purchase
Commitments Disclosure [Line Items]
Year 1	89,846
Year 2	32,490
Year 3	32,726
Year 4	12,274
Year 5	12,520
Thereafter	142,586
Total	322,442
Gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1	113,775
Year 2	81,719
Year 3	57,014
Year 4	40,372
Year 5	31,457
Thereafter	188,138
Total	512,475
Service agreements
Commitments Disclosure [Line Items]
Year 1	67,477
Year 2	57,886
Year 3	55,835
Year 4	49,596
Year 5	46,511
Thereafter	298,516
Total	575,821
Capital projects
Commitments Disclosure [Line Items]
Year 1	7,163
Year 2	0
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total	7,163
Land easements and others
Commitments Disclosure [Line Items]
Year 1	13,295
Year 2	13,316
Year 3	13,503
Year 4	13,667
Year 5	13,837
Thereafter	463,785
Total	$ 531,403

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ (124,631)	$ (56,751)
Fuel and natural gas in storage	(21,140)	(43,642)
Supplies and consumables inventory	(24,088)	445
Income taxes recoverable	549	(3,025)
Prepaid expenses	(4,269)	(1,189)
Accounts payable	24,395	(33,399)
Accrued liabilities	127,076	31,845
Current income tax liability	(2,741)	4,363
Asset retirements and environmental obligations	(22,342)	(1,185)
Net regulatory assets and liabilities	(174,427)	(419,484)
Changes in non-cash operating items	$ (221,618)	$ (522,022)

Financial instruments - Fair Va

Financial instruments - Fair Value of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value of Financial Instruments [Line Items]
Note payable to related party	$ 25,808	$ 25,808	$ 30,493
Cross currency interest rate contract
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	39,806
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,270,138	1,753,210
Development loans and other receivables	0	0
Total derivative instruments	0	0
Total financial assets	1,270,138	1,753,210
Long-term debt	2,623,628	2,418,580
Note payable to related party	0	0
Convertible debentures	276	519
Total derivative instruments	0	0
Total financial liabilities	2,623,904	2,419,099
Level 1 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Convertible debentures	0
Level 1 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments		0
Level 1 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Total derivative instruments		0
Level 1 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Total derivative instruments		0
Level 1 | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments		0
Level 1 | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Cross currency interest rate contract | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Cross currency interest rate contract | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Cross currency interest rate contract | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments	0	0
Level 1 | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	0	0
Level 1 | Preferred shares, Series C | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	0
Level 2
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	0	0
Development loans and other receivables	50,300	33,286
Total derivative instruments	73,397	5,260
Total financial assets	123,697	38,546
Long-term debt	4,075,403	4,125,352
Note payable to related party	15,180	25,808
Convertible debentures	0	0
Total derivative instruments	41,420	58,614
Total financial liabilities	4,143,678	4,224,354
Level 2 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Convertible debentures	0
Level 2 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments		0
Level 2 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Total derivative instruments		0
Level 2 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	69,188	1,581
Total derivative instruments		7,008
Level 2 | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	2,659
Level 2 | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 2 | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,721
Total derivative instruments		1,348
Level 2 | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	283
Level 2 | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,614
Level 2 | Cross currency interest rate contract | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,267
Level 2 | Cross currency interest rate contract | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,435
Level 2 | Cross currency interest rate contract | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,958
Total derivative instruments	24,371	50,258
Level 2 | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	11,675	14,580
Level 2 | Preferred shares, Series C | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	0
Level 3
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	74,083	95,246
Development loans and other receivables	0	0
Total derivative instruments	10,503	15,362
Total financial assets	84,586	110,608
Long-term debt	0	0
Note payable to related party	0	0
Convertible debentures	0	0
Total derivative instruments	128,901	61,631
Total financial liabilities	128,901	61,631
Level 3 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Convertible debentures	120,284
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		15,362
Total derivative instruments		60,462
Level 3 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	393
Total derivative instruments		1,169
Level 3 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Total derivative instruments		0
Level 3 | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	10,110
Level 3 | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments		0
Level 3 | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 3 | Cross currency interest rate contract | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 3 | Cross currency interest rate contract | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 3 | Cross currency interest rate contract | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Total derivative instruments	0	0
Level 3 | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	0	0
Level 3 | Preferred shares, Series C | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	8,617
Carrying amount
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,344,207	1,848,456
Development loans and other receivables	53,680	32,261
Total derivative instruments	83,900	20,622
Total financial assets	1,481,787	1,901,339
Long-term debt	7,512,017	6,211,375
Note payable to related party	25,808	25,808
Convertible debentures	245	277
Total derivative instruments	170,321	120,245
Total financial liabilities	7,720,463	6,371,053
Carrying amount | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Convertible debentures	120,284
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		15,362
Total derivative instruments		60,462
Carrying amount | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	393
Total derivative instruments		1,169
Carrying amount | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	69,188	1,581
Total derivative instruments		7,008
Carrying amount | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	2,659
Carrying amount | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	10,110
Carrying amount | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,721
Total derivative instruments		1,348
Carrying amount | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	283
Carrying amount | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,614
Carrying amount | Cross currency interest rate contract | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,267
Carrying amount | Cross currency interest rate contract | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,435
Carrying amount | Cross currency interest rate contract | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,958
Total derivative instruments	24,371	50,258
Carrying amount | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	12,072	13,348
Carrying amount | Preferred shares, Series C | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	8,617
Fair value
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,344,207	1,848,456
Development loans and other receivables	50,300	33,286
Total derivative instruments	83,900	20,622
Total financial assets	1,478,407	1,902,364
Long-term debt	6,699,031	6,543,933
Note payable to related party	15,180	25,808
Convertible debentures	276	519
Total derivative instruments	170,321	120,245
Total financial liabilities	6,896,483	6,705,085
Fair value | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Convertible debentures	120,284
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		15,362
Total derivative instruments		60,462
Fair value | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	393
Total derivative instruments		1,169
Fair value | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	69,188	1,581
Total derivative instruments		7,008
Fair value | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	2,659
Fair value | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	10,110
Fair value | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,721
Total derivative instruments		1,348
Fair value | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	283
Fair value | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,614
Fair value | Cross currency interest rate contract | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,267
Fair value | Cross currency interest rate contract | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	15,435
Fair value | Cross currency interest rate contract | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,958
Total derivative instruments	24,371	50,258
Fair value | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	11,675	$ 14,580
Fair value | Preferred shares, Series C | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C	8,617
Fair value | Level 1 | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Fair value | Level 1 | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Fair value | Level 3 | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Fair value | Level 3 | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	$ 0

Financial instruments - Additio

Financial instruments - Additional Information (Detail)

12 Months Ended

Aug. 01, 2022 USD ($)

Apr. 30, 2022 USD ($)

Dec. 31, 2022 USD ($) MWh derivative_contract $ / shares $ / MWh

Dec. 31, 2022 CAD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2021 CAD ($)

Dec. 31, 2022 CAD ($) MWh derivative_contract $ / MWh

Dec. 17, 2022 USD ($) MWh $ / MWh

Feb. 15, 2022 CAD ($)

Jan. 31, 2022 CAD ($)

Apr. 09, 2021 CAD ($)

Feb. 15, 2021 CAD ($)

May 23, 2019 USD ($)

Derivative [Line Items]

Number of interest rate swap contracts | derivative_contract

2

2

Foreign currency gain (loss)

$ (23,502,000)

$ (30,270,000)

Revenue collection period

45 days

45 days

Accounts receivable

$ 552,914,000

Cash on hand

57,623,000

Liquidity available under the facilities

2,515,600,000

2,050,200,000

Regulated Services Group

Derivative [Line Items]

Accounts receivable

404,258,000

Unsecured Debt

Derivative [Line Items]

Debt repaid upon maturity

$ 115,000

$ 80,000,000

Non-regulated Energy Sales

Derivative [Line Items]

Unrealized gains (loss) in AOCI to be reclassified

(32,467,000)

Revolving and Term Credit Facilities

Derivative [Line Items]

Liquidity available under the facilities

2,288,765,000

U.S. dollar Subordinated unsecured notes | Unsecured Debt

Derivative [Line Items]

Par value

500,000,000

$ 300,000,000

$ 350,000,000

Canadian dollar Senior unsecured notes | Unsecured Debt

Derivative [Line Items]

Par value

$ 1,200,000,000

$ 200,000

$ 150,000

Canadian Investments and Subsidiaries

Derivative [Line Items]

Foreign currency gain (loss)

2,262,000

168,000

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]

Cross-currency interest rate swap

$ 400,000,000

Foreign currency gain (loss)

(11,082,000)

7,824,000

Currency Swap | Canadian dollar Senior unsecured notes | Unsecured Debt

Derivative [Line Items]

Foreign currency gain (loss)

(13,374,000)

(1,925,000)

Par value

$ 400,000,000

Foreign exchange contract

Derivative [Line Items]

Foreign currency gain (loss)

$ 22,091,000

4,232,000

Currency forward contract

Derivative [Line Items]

Foreign currency gain on settlement of derivative

$ 2,329,000

Interest Rate Cap

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh

516,202

Receive average prices (per MW-hr) | $ / MWh

25.15

Derivative notional amount

$ 390,000,000

Transmission congestion rights

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh

1,328,510

1,328,510

Cross currency interest rate contract

Derivative [Line Items]

Debt repaid upon maturity

$ 200,000,000

$ 150,000,000

Minimum | Atlantica Yield Energy Solutions Canada Inc. | Measurement Input, Discount Rate

Derivative [Line Items]

Alternative investment, measurement input (percent)

0.0800

0.0800

Minimum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility

Derivative [Line Items]

Alternative investment, measurement input (percent)

0.2699

0.2699

Minimum | Energy contracts

Derivative [Line Items]

Forward price | $ / MWh

23.32

23.32

Minimum | Transmission congestion rights

Derivative [Line Items]

Receive average prices (per MW-hr) | $ / MWh

1.58

1.58

Maximum | Atlantica Yield Energy Solutions Canada Inc. | Measurement Input, Discount Rate

Derivative [Line Items]

Alternative investment, measurement input (percent)

0.0850

0.0850

Maximum | Atlantica Yield Energy Solutions Canada, Inc | Measurement Input, Price Volatility

Derivative [Line Items]

Alternative investment, measurement input (percent)

0.3489

0.3489

Maximum | Energy contracts

Derivative [Line Items]

Forward price | $ / MWh

109.91

109.91

Derivative auction price | $ / shares

$ 23.20

Maximum | Transmission congestion rights

Derivative [Line Items]

Receive average prices (per MW-hr) | $ / MWh

19.06

19.06

Weighted Average | Atlantica Yield Energy Solutions Canada Inc. | Measurement Input, Discount Rate

Derivative [Line Items]

Alternative investment, measurement input (percent)

0.0834

0.0834

Weighted Average | Energy contracts

Derivative [Line Items]

Forward price | $ / MWh

44.76

44.76

Derivative auction price | $ / shares

$ 7.83

Weighted Average | Transmission congestion rights

Derivative [Line Items]

Receive average prices (per MW-hr) | $ / MWh

7.80

7.80

Financial instruments - Summary

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2022 MMBTU
Derivative [Line Items]
Commodity volumes, gas	1,723,041
Financial contracts: Swaps
Derivative [Line Items]
Commodity volumes, gas	1,687,217
Options
Derivative [Line Items]
Commodity volumes, gas	35,824

Financial instruments - Long-te

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2022 MWh $ / MWh
Illinois Hub, Expiry September 2030
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	4,059,905
Receive average prices (per MW-hr) | $ / MWh	24.54
PJM Western HUB, Expiry December 2028
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	413,620
Receive average prices (per MW-hr) | $ / MWh	29.15
NI HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	1,977,766
Receive average prices (per MW-hr) | $ / MWh	22.05
ERCOT North HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	1,665,318
Receive average prices (per MW-hr) | $ / MWh	36.46

Financial instruments - Derivat

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge	$ (128,838)	$ (97,103)
Amortization of cash flow hedge	(12,180)	(2,132)
Amounts reclassified from AOCI	46,723	44,904
OCI attributable to shareholders of AQN	$ (94,295)	$ (54,331)

Financial instruments - Effects

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Fair Value of Financial Instruments [Line Items]
Total unrealized loss on derivative financial instruments	$ (2,462)		$ 5,609
Total realized gain (loss) on derivative financial instruments	0		2,329
Gain (loss) on derivative instruments	2,459		580
Gain on derivative financial instruments	4,408		4,403
Renewable energy sales	5,236		(6,152)
Reduction to gain on sale of renewable assets	(7,185)		0
Canadian dollar Senior unsecured notes | Senior Unsecured Notes
Fair Value of Financial Instruments [Line Items]
Gain on derivative financial instruments		$ 4,408		$ 4,403
Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total unrealized loss on derivative financial instruments	(945)		(5,353)
Currency forward contract
Fair Value of Financial Instruments [Line Items]
Total realized gain (loss) on derivative financial instruments	0		2,329
Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total unrealized loss on derivative financial instruments	185		0
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total unrealized loss on derivative financial instruments	(760)		(5,353)
Total realized gain (loss) on derivative financial instruments	(246)		2,221
Loss on derivative financial instruments not accounted for as hedges	(1,006)		(3,132)
Amortization of AOCI gains frozen as a result of hedge dedesignation	3,465		3,712
Not Designated as Hedging Instrument | Interest rate swaps designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total realized gain (loss) on derivative financial instruments	(7,185)		0
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total realized gain (loss) on derivative financial instruments	6,939		(108)
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Amortization of AOCI gains frozen as a result of hedge dedesignation	$ 18,561		$ 1,595

Financial instruments - Maximum

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Fair Value Disclosures [Abstract]
Cash and cash equivalents and restricted cash	$ 101,185
Accounts receivable	552,914
Allowance for doubtful accounts	(24,857)
Notes receivable	53,680
Maximum exposure to credit risk for financial instruments	$ 682,922

Financial instruments - Liabili

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Long-term debt obligations	$ 7,537,314
Interest on long-term debt	5,080,855
Purchase obligations	741,888
Environmental obligation	48,346
Advances in aid of construction	88,546	$ 82,584
Contract adjustment payments	113,876	$ 187,580
Other obligations	320,643
Total obligations	14,101,789
Cross-currency swap
Derivative [Line Items]
Total derivative instruments	39,806
Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	130,515
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	1,128,660
Interest on long-term debt	310,863
Purchase obligations	741,888
Environmental obligation	9,326
Advances in aid of construction	1,554
Contract adjustment payments	76,208
Other obligations	37,209
Total obligations	2,338,199
Due less than 1 year | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	3,205
Due less than 1 year | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	29,286
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	404,633
Interest on long-term debt	447,227
Purchase obligations	0
Environmental obligation	18,084
Advances in aid of construction	0
Contract adjustment payments	37,668
Other obligations	6,392
Total obligations	969,410
Due 2 to 3 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	5,541
Due 2 to 3 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	49,865
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	1,984,855
Interest on long-term debt	386,560
Purchase obligations	0
Environmental obligation	1,915
Advances in aid of construction	0
Contract adjustment payments	0
Other obligations	5,080
Total obligations	2,414,585
Due 4 to 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	6,279
Due 4 to 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	29,896
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	4,019,166
Interest on long-term debt	3,936,205
Purchase obligations	0
Environmental obligation	19,021
Advances in aid of construction	86,992
Contract adjustment payments	0
Other obligations	271,962
Total obligations	8,379,595
Due after 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	24,781
Due after 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	$ 21,468