Algonquin Power & Utilities (AQN) 40-F 8 Mar 24 2023 FY Annual report (Canada) Financial data

Cover Page

Cover Page - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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	689,271,039	683,614,803	671,960,276
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction Flag	false
Entity Central Index Key	0001174169
Amendment Flag	false
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2023
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
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, 2023
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 ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenue
Other revenue	$ 2,698,015,000	$ 2,765,013,000
Expenses
Administrative expenses	90,359,000	80,232,000
Depreciation and amortization	466,996,000	455,520,000
Asset impairment charge (notes 5, 8 and 16)	23,492,000	159,568,000
Loss on foreign exchange	8,359,000	13,833,000
Costs and expenses, total	2,232,136,000	2,426,996,000
Gain on sale of renewable assets	0	64,028,000
Operating income	465,879,000	402,045,000
Interest expense (note 9)	(353,656,000)	(278,574,000)
Loss from long-term investments (note 8)	(124,974,000)	(483,385,000)
Other income (note 7)	41,410,000	18,179,000
Other net losses (note 19)	(132,889,000)	(21,391,000)
Pension and other post-employment non-service costs (note 10)	(19,939,000)	(10,950,000)
Gain on derivative financial instruments (note 24(b)(iv))	4,564,000	4,408,000
Loss before income taxes	(119,605,000)	(369,668,000)
Income tax recovery (expense) (note 18)
Current	9,740,000	(7,843,000)
Deferred	76,560,000	69,356,000
Income tax expense	86,300,000	61,513,000
Net loss	(33,305,000)	(308,155,000)
Non-controlling interests	87,901,000	111,323,000
Non-controlling interests held by related party	(25,922,000)	(15,157,000)
Net effect of non-controlling interests	61,979,000	96,166,000
Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	28,674,000	(211,989,000)
Series A Shares and Series D Shares dividend (note 15)	8,356,000	8,720,000
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp. - basic (in shares)	20,318,000	(220,709,000)
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp. - diluted (in shares)	$ 20,318,000	$ (220,709,000)
Basic net earnings (loss) per share (USD per share)	$ 0.03	$ (0.33)
Diluted net earnings (loss) per share (USD per share)	$ 0.03	$ (0.33)
Regulated electricity distribution
Revenue
Other revenue	$ 1,295,497,000	$ 1,278,912,000
Expenses
Expenses	429,760,000	465,570,000
Regulated natural gas distribution
Revenue
Other revenue	621,173,000	686,744,000
Expenses
Expenses	267,122,000	340,792,000
Regulated water reclamation and distribution
Revenue
Other revenue	399,052,000	364,383,000
Expenses
Expenses	19,564,000	18,308,000
Non-regulated energy sales
Revenue
Other revenue	296,314,000	350,797,000
Expenses
Expenses	19,499,000	41,684,000
Other revenue
Revenue
Other revenue	85,979,000	84,177,000
Operating expenses
Expenses
Expenses	$ 906,985,000	$ 851,489,000

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net loss	$ (33,305)	$ (308,155)
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax recovery of $6,616 (2022 - tax expense $2,423), (notes 24(b)(iii) and 24(b)(iv))	(5,386)	(23,502)
Change in fair value of cash flow hedges, net of tax recovery of $1,885 (2022 - tax expense of $20,644), (note 24(b)(ii))	59,487	(94,295)
Change in pension and other post-employment benefits, net of tax expense of $1,612 (2022 - tax expense of $8,330), (note 10)	4,693	27,761
OCI, net of tax	58,794	(90,036)
Comprehensive income (loss)	25,489	(398,191)
Comprehensive loss attributable to the non-controlling interests	(60,962)	(97,816)
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$ 86,451	$ (300,375)

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, net of tax (recovery) and expense	$ (6,616)	$ 2,423
Change in fair value of cash flow hedges, net of tax (recovery) and expense	1,885	20,644
Change in pension and other post-employment expense, net of tax (expense) and recovery	$ (1,612)	$ (8,330)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 56,142	$ 57,623
Trade and other receivables, net (note 4)	524,194	528,057
Fuel and natural gas in storage	48,982	95,350
Supplies and consumables inventory	178,150	129,571
Regulatory assets (note 7)	142,970	190,393
Prepaid expenses	81,926	58,653
Derivative instruments (note 24)	10,920	12,270
Other assets (note 11)	23,061	22,564
Assets, current, total	1,066,345	1,094,481
Property, plant and equipment, net (note 5)	12,517,450	11,944,885
Intangible assets, net (note 6)	93,938	96,683
Goodwill (note 6)	1,324,062	1,320,579
Regulatory assets (note 7)	1,184,713	1,081,108
Long-term investments (note 8)
Investments carried at fair value	1,115,729	1,344,207
Other long-term investments	641,920	462,325
Derivative instruments (note 24)	72,328	71,630
Deferred income taxes (note 18)	158,483	84,416
Other assets (note 11)	198,993	127,299
Assets	18,373,961	17,627,613
Current liabilities:
Accounts payable	210,412	186,080
Accrued liabilities	554,875	555,792
Dividends payable (note 15)	74,916	125,655
Regulatory liabilities (note 7)	99,850	69,865
Long-term debt (note 9)	621,856	423,274
Other long-term liabilities (note 12)	80,458	134,212
Derivative instruments (note 24)	34,915	32,491
Other liabilities	7,898	7,091
Liabilities, current, total	1,685,180	1,534,460
Long-term debt (note 9)	7,894,174	7,088,743
Regulatory liabilities (note 7)	634,446	558,317
Deferred income taxes (note 18)	578,902	565,639
Derivative instruments (note 24)	75,961	137,830
Pension and other post-employment benefits obligation (note 10)	96,653	125,579
Other long-term liabilities (note 12)	465,874	461,230
Liabilities, noncurrent, total	9,746,010	8,937,338
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party	308,350	307,856
Redeemable non-controlling interests	10,013	11,520
Redeemable non-controlling interests, total	318,363	319,376
Equity:
Preferred shares	184,299	184,299
Common shares (note 13(a))	6,229,994	6,183,943
Additional paid-in capital	7,254	9,413
Deficit	(1,279,696)	(997,945)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(102,286)	(160,063)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,039,565	5,219,647
Non-controlling interests (note 17)
Non-controlling interests - tax equity partnership units	1,196,720	1,225,608
Other non-controlling interests	347,338	333,362
Non-controlling interest, held by related party	40,785	57,822
Non-controlling interests, total	1,584,843	1,616,792
Total equity	6,624,408	6,836,439
Commitments and contingencies (note 22)
Subsequent events (notes 3(c), 7(a), 8(c), 9(c), 9(d), 16(a), 17(c))
Liabilities and equity, total	$ 18,373,961	$ 17,627,613

Consolidated Statements of Equi

Consolidated Statements 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, 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 earnings (loss)	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)
Non-controlling interest assumed on asset acquisition	(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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	(33,305)				28,674
Net earnings (loss)	61,979						(61,979)
Effect of redeemable non-controlling interests not included in equity (note 17)	(24,598)						(24,598)
OCI	58,794					57,777	1,017
Dividends declared and distributions to non-controlling interests	(333,956)				(279,634)		(54,322)
Dividends and issuance of shares under dividend reinvestment plan	0	30,482			(30,482)
Contributions received from non-controlling interests, net of cost	107,933						107,933
Common shares issued upon conversion of convertible debentures	11	11
Common shares issued under employee share purchase plan	5,229	5,229
Share-based compensation	13,162			13,162
Common shares issued pursuant to share-based awards	(5,301)	10,329		(15,321)	(309)
Ending Balance at Dec. 31, 2023	$ 6,624,408	$ 6,229,994	$ 184,299	$ 7,254	$ (1,279,696)	$ (102,286)	$ 1,584,843

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Operating activities
Net loss	$ (33,305)	$ (308,155)
Adjustments and items not affecting cash:
Depreciation and amortization	466,996	455,520
Deferred taxes	(76,560)	(69,356)
Initial value and changes in derivative financial instruments net of amortization	(15,502)	2,462
Share-based compensation	10,397	10,920
Cost of equity funds used for construction purposes	(3,366)	(1,896)
Change in value of investments carried at fair value	229,988	499,125
Pension and post-employment expense lower than contributions	(7,838)	(15,329)
Distributions received from equity investments, net of income	11,730	23,829
Impairment of assets (notes 5 and 8(c))	23,492	235,478
Other (notes 19(c), 19(e) and 19(f))	108,338	8,116
Net change in non-cash operating items (note 23)	(86,336)	(221,618)
Net cash provided by (used in) operating activities, total	628,034	619,096
Financing activities
Increase in long-term debt	3,033,503	4,622,937
Repayments of long-term debt	(2,297,346)	(3,326,519)
Net change in commercial paper	74,720	68,300
Issuance of common shares, net of costs	5,229	43,546
Cash dividends on common shares	(322,468)	(378,597)
Dividends on preferred shares	(8,356)	(8,720)
Contributions from non-controlling interests and redeemable non-controlling interests (note 3)	98,955	272,515
Production-based cash contributions from non-controlling interest	9,084	6,182
Distributions to non-controlling interests	(51,164)	(43,919)
Payments upon settlement of derivatives	0	(28,913)
Shares surrendered to fund withholding taxes on exercised share options	(2,434)	(4,667)
Redemption of Series C preferred shares (note 12(h))	(14,515)	0
Acquisition of non-controlling interest	0	(1,580)
Increase in other long-term liabilities	22,666	19,324
Decrease in other long-term liabilities	(79,638)	(94,837)
Net cash provided by (used in) financing activities, total	442,808	1,110,236
Investing activities
Additions to property, plant and equipment and intangible assets	(1,026,171)	(1,089,024)
Increase in long-term investments	(243,742)	(221,281)
Acquisitions of operating entities	0	(632,797)
Increase in other assets	(12,220)	(26,527)
Receipt of principal on development loans receivable	174,763	178,300
Decrease in long-term investments	11,749	2,920
Net cash provided by (used in) investing activities, total	(1,095,621)	(1,788,409)
Effect of exchange rate differences on cash and restricted cash	(267)	(1,127)
Decrease in cash, cash equivalents and restricted cash	(25,046)	(60,204)
Cash, cash equivalents and restricted cash, beginning of year	101,185	161,389
Cash, cash equivalents and restricted cash, end of year	76,139	101,185
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	368,511	272,734
Cash paid during the year for income taxes	7,171	10,962
Cash received during the year for distributions from equity investments	112,716	112,951
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	172,165	120,819
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	46,040	112,918
Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	23,938	90,700
Related Party
Financing activities
Distributions to non-controlling interests, related party (note 17)	$ (25,428)	$ (34,816)

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2023
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, 2023
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 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, Suralis (Chile) Water System (“Suralis”) (formerly known as Empresa de Servicios Sanitarios de Los Lagos (ESSAL). 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 Suralis’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 consolidated financial condition and consolidated 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 Gas Distribution Uniform Accounting Regulation - Gas Distribution Act, 1999 (New Brunswick) . (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 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 2023 2022 2023 2022 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 39 Equipment 5-54 5-54 15 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 $552,701 (2022 - $559,630) and accumulated depreciation of $83,283 (2022 - $75,820). The Company’s share of operating costs are recognized in operating expenses. Total expenditures incurred on these facilities for the year ended December 31, 2023 were $72,584 (2022 - $110,268). (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. 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 values of assets and long-term debt of these facilities amount to $57,740 (2022 - $57,241) and $12,738 (2022 - $15,024), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,317 (2022 - $19,752), operating expenses and amortization of $5,986 (2022 - $5,834) and interest expense of $1,384 (2022 - $1,723). (n) Long-term investments and development loans Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee. Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured. If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. 1. Significant accounting policies (continued) (o) Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (loss) (“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 Pension and other post-employment non-service costs 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 of December 31, 2023 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 (loss) and other comprehensive income (loss) (“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 (loss) or comprehensive income (loss) 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 as 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 and generation of electricity, water distribution, wastewater collection and distribution of 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 associate

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently issued accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued Accounting Standards Update (“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. See note 24(c) for details. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2023-02, Accounting for Investments in Tax Credit Structures Using the Proportional Amortization Method — A Consensus of the Emerging Issues Task Force, which permits a reporting entity, if certain conditions are met, to elect to account for its tax equity investments by using the proportional amortization method regardless of the program from which it receives income tax credits. The amendments in this update are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance. The FASB issued ASU 2023-05, Joint Venture Formations: Recognition and Initial Measurement, which requires a joint venture to recognize and initially measure its assets and liabilities at fair value as at the joint venture formation date. The amendments in this update are effective prospectively for all joint venture formations with a formation date on or after January 1, 2025. Additionally, a joint venture formed before January 1, 2025 may elect to apply the amendments retrospectively if it has sufficient information. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance. The FASB issued ASU 2023-07, Segment Reporting: Improvement to Reportable Segments Disclosures, which requires enhanced disclosures about significant segment expenses. The amendments in this update are effective for annual periods beginning on December 15, 2023 and interim periods within annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure. The FASB issued ASU 2023-09, Income Taxes: Improvement to Income Tax Disclosures, which requires a reporting entity to disclose additional income tax information primarily related to the rate reconciliation and income taxes paid information. The amendments in this update are effective prospectively for annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

Business acquisitions, developm

Business acquisitions, development projects and disposition transactions	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Business acquisitions, development projects and disposition transactions	Business acquisitions, development projects and disposition transactions (a) 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 and AEP Kentucky Transmission Company, Inc. (the “Kentucky Power Transaction”). On April 17, 2023, Liberty Utilities Co. mutually agreed with AEP and AEP Transmission Company, LLC to terminate the Kentucky Acquisition Agreement. The Company recognized $46,527 in other net losses for the year ended December 31, 2023 related to a write-off of costs incurred in preparation for the Kentucky Power Transaction and the termination of the Kentucky Acquisition Agreement. See note 19 for details. (b) Acquisition of the Deerfield II Wind Facility On June 15, 2023, the Company, acquired the remaining 50% ownership in the Deerfield II Wind Facility for consideration of $23,142. The transaction has been accounted for as an asset acquisition. Subsequent to acquisition, the tax equity investors provided additional funding of $98,955, and a third-party construction loan of $158,550 was repaid. The following table summarizes the allocation of the aggregate purchase price to the assets acquired and liabilities assumed at the acquisition dates. Deerfield II Working capital $ (10,709) Property, plant and equipment 194,419 Long-term debt (157,935) Asset retirement obligation (1,030) Deferred tax liability (1,603) Total net assets acquired 23,142 Cash and cash equivalents 1,662 Net assets acquired, net of cash and cash equivalents $ 21,480 (c) Acquisition of the Sandy Ridge II Wind Facility Subsequent to year end, on February 15, 2024, the Company acquired the remaining 50% ownership in the Sandy Ridge II Wind Facility for consideration of $8,456. Subsequent to acquisition, the tax equity investors provided additional funding of $60,545, and a third-party construction loan of $162,805 was repaid. Due to the timing of the acquisition, the Company has not completed the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the allocation of the consideration paid to the fair value of the assets acquired and liabilities assumed. (d) 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 I 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 oversees day-to-day operations and provides 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 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 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. 3. Business acquisitions, development projects and disposition transactions (continued) (e) 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. 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.

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivable Accounts receivable as of December 31, 2023 include unbilled revenue of $107,001 (2022 - $149,015) from the Company’s regulated utilities. Accounts receivable as of December 31, 2023 are presented net of allowance for doubtful accounts of $30,244 (2022 - $24,857).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2023 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,200,559 $ 1,139,137 $ 3,061,422 Utility plant 9,332,092 1,191,013 8,141,079 Land 133,483 — 133,483 Equipment 122,929 53,181 69,748 Construction-in-progress Generation 378,043 — 378,043 Distribution and transmission 733,675 — 733,675 $ 14,900,781 $ 2,383,331 $ 12,517,450 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 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. Renewable generation facilities include cost of $117,556 (2022 - $111,192) and accumulated depreciation of $52,506 (2022 - $46,666) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $537 (2022 - $1,489). Utility plant includes cost of $3,270 (2022 - $3,076) and accumulated depreciation of $2,455 (2022 - $2,041) related to assets under finance lease. Utility plant includes cost of $1,922,844 (2022 - $2,033,391) and accumulated depreciation of $141,466 (2022 - $133,644) related to regulated generation assets. For the year ended December 31, 2023, contributions received in aid of construction of $238 (2022 - $1,299) have been credited to the cost of the assets. 5. Property, plant and equipment (continued) Interest and AFUDC capitalized to the cost of the assets in 2023 and 2022 are as follows: 2023 2022 Interest capitalized on non-regulated property $ 6,374 $ 4,762 AFUDC capitalized on regulated property: Allowance for borrowed funds 8,305 6,040 Allowance for equity funds 3,372 1,901 $ 18,051 $ 12,703

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2023 Cost Accumulated amortization Net book value Power sales contracts $ 58,200 $ 43,938 $ 14,262 Customer relationships 77,104 14,625 62,479 Interconnection agreements 10,329 1,977 8,352 Other (a) 10,352 1,507 8,845 $ 155,985 $ 62,047 $ 93,938 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 (a) Other includes brand names, water rights and miscellaneous intangibles Estimated amortization expense for intangible assets for each of the next five years is $2,674. All goodwill pertains to the Regulated Services Group. 2023 2022 Opening balance $ 1,320,579 $ 1,201,244 Business acquisitions 4,195 123,751 Foreign exchange (712) (4,416) Closing balance $ 1,324,062 $ 1,320,579

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2023
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, issuance of securities, acquisitions and other matters. Except for Suralis, 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. 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 Apple Valley Water System California General rate review On February 3, 2023, the California Public Utilities Commission (“CPUC”) issued a final order authorizing an annual revenue increase of $1,494. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023. Park Water System California General rate review On February 3, 2023, the CPUC issued a final order authorizing an annual revenue increase of $1,105. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023. CalPeco Electric System California General rate review On April 27 , 2023, the California Public Utilities Commission (“CPUC”) issued a final order approving a revenue increase of $26,979 . New rates became effective on July 1, 2023 retroactive to January 2022 . The retroactive impact of this final order was recorded in the second quarter of 2023. St. Lawrence Gas New York General rate review On June 22, 2023 , the New York State Department of Public Services issued an Order authorizing a revenue increase of $5,249 to be implemented over the course of 2023-2025. New rates became effective July 1, 2023. Pine Bluff Water Arkansas General rate review On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a unanimous settlement agreement filed by the parties authorizing an annual revenue increase of $3,400. New rates became effective August 15, 2023. Gas New Brunswick New Brunswick General rate review On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a revenue decrease of $700. Empire Electric Arkansas General rate review On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the settlement agreement authorizing a revenue increase of $5,300. New rates became effective January 1, 2024. Empire Electric Missouri Securitization On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the Missouri Public Service Commission’s (“MPSC”) order of $290,383. Subsequent to year-end, on January 30, 2024. t he Company completed the securitization to recover the costs associated with the extreme winter storm conditions experienced in Texas and parts of central U.S in February 2021 (“Midwest Extreme Weather Event”) and the remaining book value of the Asbury generating plant. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus. the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2023 December 31, 2022 Regulatory assets Fuel and commodity cost adjustments (a) $ 326,418 $ 388,294 Retired generating plant (b) 183,732 174,609 Rate adjustment mechanism (c) 192,880 136,198 Income taxes (d) 101,939 97,414 Deferred capitalized costs (e) 124,517 90,121 Pension and post-employment benefits (f) 68,822 80,736 Environmental remediation (g) 66,779 70,529 Wildfire mitigation and vegetation management (h) 64,146 66,156 Clean energy and other customer programs (i) 37,214 28,145 Asset retirement obligation (j) 26,620 27,172 Debt premium (k) 18,995 24,888 Cost of removal (l) 11,084 11,084 Rate review costs (m) 8,815 9,481 Long-term maintenance contract (n) 4,932 6,504 Other regulatory assets (o) 90,790 60,170 Total regulatory assets $ 1,327,683 $ 1,271,501 Less: current regulatory assets (142,970) (190,393) Non-current regulatory assets $ 1,184,713 $ 1,081,108 Regulatory liabilities Income taxes (d) $ 290,121 $ 312,671 Cost of removal (l) 185,786 191,173 Pension and post-employment benefits (f) 104,636 68,085 Fuel and commodity cost adjustments (a) 42,850 24,991 Clean energy and other customer programs (i) 12,730 11,572 Rate adjustment mechanism (c) 2,078 343 Other regulatory liabilities (p) 96,095 19,347 Total regulatory liabilities $ 734,296 $ 628,182 Less: current regulatory liabilities (99,850) (69,865) Non-current regulatory liabilities $ 634,446 $ 558,317 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). During 2023, the Company recognized $41,410 (2022 - $18,179) of carrying charges on regulatory balances on the consolidated statements of operations under other income and was 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 the 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 August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the MPSC’s order of $290,383. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus, the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023. Subsequent to year-end, on January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant. (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 consolidated balance sheets 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 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 1, 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. The Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, the regulatory liability is netted against its retired generation facilities regulatory asset. 7. Regulatory matters (continued) (b) Retired generating plant (continued) On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, the cases regarding the quantum financeable through securitization for Asbury and the Midwest Extreme Weather Event. As noted above under (a) Fuel and commodity cost adjustments , subsequent to year-end, on January 30, 2024, the Company completed the securitization of the costs associated with the retirement of the Asbury plant in accordance with the MPSC’s order. (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 weighted average cost of capital (“WACC”) on certain property, plant and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates. 7. Regulatory matters (continued) (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 three Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. (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 seven 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 regulatory assets 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. 7. Regulatory matters (continued) (p) Other regulatory liabilities During the year, the Company recognized a regulatory liability of $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute.

Long-term investments

Long-term investments	12 Months Ended
	Dec. 31, 2023
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: December 31, 2023 December 31, 2022 Long-term investments carried at fair value Atlantica (a) $ 1,052,703 $ 1,268,140 Atlantica Yield Energy Solutions Canada Inc. (b) 61,064 74,083 Other 1,962 1,984 $ 1,115,729 $ 1,344,207 Other long-term investments Equity-method investees (c) $ 456,393 $ 381,802 Development loans receivable from equity-method investees (d) 158,110 52,923 San Antonio Water System and other (e) 27,417 27,600 $ 641,920 $ 462,325 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, 2023 2022 Fair value loss on investments carried at fair value Atlantica $ (215,437) $ (482,774) Atlantica Yield Energy Solutions Canada Inc. (14,684) (16,018) Other 133 (333) $ (229,988) $ (499,125) Dividend and interest income from investments carried at fair value Atlantica $ 87,154 $ 86,664 Atlantica Yield Energy Solutions Canada Inc. 16,604 20,443 Other 49 36 $ 103,807 $ 107,143 Other long-term investments Equity method loss (c) $ (5,936) $ (21,416) Impairment of equity-method investee (c) — (75,910) Interest and other income 7,143 5,923 $ 1,207 $ (91,403) Fair value change, income (loss) and impairment expense related to long-term investments $ (124,974) $ (483,385) 8. Long-term investments (continued) (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 approxim ately 42% (2022 - 42%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantic a up to 48.5% . The total cost for the Atlantica shares as of December 31, 2023 is $1,167,444 (2022 - $1,167,444). The 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. (b) Investment in Atlantica Yield Energy Solutions Canada Inc. 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 . 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 of December 31, 2023, the Company's maximum exposure to loss is $61,064 (2022 - $74,083 ), 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 of $343,712 (2022 - $310,103). The Regulated Services Group has non-controlling interest of $112,180 (2022 - $56,199) 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 $501 and (2022 - $15,500) 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. 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. 8. Long-term investments (continued) (c) Equity-method investees (continued) As at December 31, 2023, the Company has issued $113,630 (2022 - $113,630) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. 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. On July 5, 2023, the Company provided a $35,000 non-interest-bearing loan to Liberty Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17,500. Further, the Company recognized an impairment loss on its note receivable of $18,911 as it no longer expects to pursue development under this joint venture arrangement and the development fees are no longer expected to be realized. The impairment is recorded within asset impairment charge in the consolidated statements of operations. Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V. 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 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: 2023 2022 Carrying value, January 1 $ 381,802 $ 433,850 Additional investments 91,205 110,441 Net loss attributable to AQN (5,936) (21,416) OCI attributable to AQN (a) 7,693 (67,110) Dividend received (4,600) (1,183) Impairment — (75,910) Other (13,771) 3,130 Carrying value, December 31 $ 456,393 $ 381,802 (a) OCI 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 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's equity method investees as of December 31 is as follows: 2023 2022 Total assets $ 3,235,474 $ 2,740,132 Total liabilities 1,962,115 1,507,079 Net assets 1,273,359 1,233,053 AQN's ownership interest in the entities 388,993 332,663 Difference between investment carrying amount and underlying equity in net assets (a) 67,400 49,139 Total carrying value $ 456,393 $ 381,802 (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. Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows: 2023 2022 Revenue $ 111,446 $ 65,025 Net loss $ (3,633) $ (31,070) OCI (a) $ 12,026 $ (130,729) Net loss attributable to AQN $ (5,936) $ (21,416) OCI attributable to AQN (a) $ 7,693 $ (67,110) (a) OCI 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, 2023, the Company has 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 of December 31, 2023 amounts to $12,666 (2022 - $8,824) . 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's VIEs as of December 31 is as follows: 2023 2022 AQN's maximum exposure in regards to VIEs Carrying amount $ 179,728 $ 122,752 Development loans receivable (d) 158,110 52,923 Indirect guarantees of debt on behalf of VIEs 740,866 436,790 Other indirect guarantees and commitments on behalf of VIEs 303,641 221,433 $ 1,382,345 $ 833,898 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 does not have significant influence over San Antonio Water System investments. It is accounted for using the cost method and as at December 31, 2023, it is recorded at the cost of $25,634 (2022 - $25,634).

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2023
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, 2023 December 31, 2022 Senior unsecured revolving credit facilities (a) — 2024-2028 N/A $ 1,624,186 $ 351,786 Senior unsecured bank credit facilities and delayed draw term facility (b) — 2024-2031 N/A 786,962 773,643 Commercial paper — 2024 N/A 481,720 407,000 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) 1.18 % 2026 $ 1,150,000 1,144,897 1,142,814 Senior unsecured notes (c) 3.36 % 2024-2047 $ 1,415,000 1,406,278 1,496,101 Senior unsecured utility notes 6.30 % 2025-2035 $ 137,000 147,589 154,271 Senior secured utility bonds (d) 4.71 % 2026-2044 $ 556,199 551,166 554,822 Canadian dollar borrowings Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 904,604 882,899 Senior secured project notes 10.21 % 2027 C$ 16,848 12,738 15,024 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds 3.90 % 2028-2040 CLF 1,521 70,967 77,206 $ 7,131,107 $ 5,855,566 Subordinated borrowings Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 298,382 291,238 Subordinated unsecured notes (f) 5.21 % 2079-2082 $ 1,100,000 1,086,541 1,365,213 $ 8,516,030 $ 7,512,017 Less: current portion (621,856) (423,274) $ 7,894,174 $ 7,088,743 Short-term obligations of $766,886 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 of December 31, 2023: December 31, 2023 December 31, 2022 Revolving and term credit facilities $ 4,562,000 $ 4,513,300 Funds drawn on facilities/commercial paper issued (2,892,900) (1,532,500) Letters of credit issued (469,100) (465,200) Liquidity available under the facilities 1,200,000 2,515,600 Undrawn portion of uncommitted letter of credit facilities (254,100) (226,900) Cash on hand 56,142 57,623 Total liquidity and capital reserves $ 1,002,042 $ 2,346,323 Recent financing activities: (a) Senior unsecured revolving credit facilities Corporate On March 31, 2023, the Company's senior unsecured revolving credit facility was amended and restated to increase the borrowing capacity from $500,000 to $1,000,000 with a new maturity date of March 31, 2028. On March 31, 2023, the Company entered into a new $75,000 uncommitted bi-lateral credit facility. On June 1, 2023, the Company terminated its former $50,000 uncommitted bi-lateral credit facility. Regulated Services Group On October 27, 2023, the Company extended the maturity date of the senior unsecured revolving credit facility of $500,000 from February 28, 2024 to October 25, 2024. (b) Senior unsecured bank credit facilities and delayed draw term facilities On April 25, 2023, the Regulated Services Group elected to terminate the undrawn amount of $489,600 of its $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”), which was intended to be used to partially fund the Kentucky Power Transaction. On October 27, 2023, the Company extended the maturity of the Regulated Services Delayed Draw Term Facility of $610,400 from November 29, 2023 to October 25, 2024. (c) Senior unsecured notes On March 13, 2023, the Company repaid a $15,000 senior unsecured note on its maturity. On July 31, 2023, the Company repaid a $75,000 senior unsecured note on its maturity. Subsequent to year-end, on January 12, 2024, Lib erty Utilities Co., completed an offering of $500,000 aggregate principal amount of 5.577% senior notes due January 31, 2029 (the “2029 Notes”); and $350,000 aggregate principal amount of 5.869% senior notes due January 31, 2034 (the “2034 Notes” and together with the 2029 Notes, the “Senior Notes”). The Senior Notes are unsecured and unsubordinated obligations of Lib erty Utilities Co. and rank equally with all of Lib erty Utilities Co.’s existing and future unsecured and unsubordinated indebtedness and senior in right of payment to any existing and future Lib erty Utilities Co.’s subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034 Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities Co. used the net proceeds from the sale of the Senior Notes to repay indebtedness. 9. Long-term debt (continued) (d) Senior unsecured utility bonds Subsequent to the year-end, on January 30, 2024 , Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180,500 of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125,000 aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant described in note 7 . (e) Senior unsecured utility notes On November 1, 2023, the Company repaid a $5,000 senior unsecured utility note on its maturity. (f) Subordinated unsecured notes On November 6, 2023, the Company redeemed all $287,500 of its 6.875% fixed-to-floating subordinated notes - series 2018 - at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. As of December 31, 2023, the Company has accrue d $74,493 in interest expense (2022 - $70,274 ). Interest expense for the year ended December 31 consists of the following : 2023 2022 Long-term debt $ 251,539 $ 258,084 Commercial paper, credit facility draws and related fees 134,678 46,466 Accretion of fair value adjustments (23,834) (16,547) Capitalized interest and AFUDC capitalized on regulated property (14,679) (10,802) Other 5,952 1,373 $ 353,656 $ 278,574 Principal payments due in the next five years and thereafter are as follows: 2024 2025 2026 2027 2028 Thereafter Total $ 621,856 $ 140,241 $ 1,193,531 $ 1,280,846 $ 819,122 $ 4,481,961 $ 8,537,557

Pension and other post-employme

Pension and other post-employment benefits	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Pension and other post-employment 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 2023 were $14,521 (2022 - $12,126). 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 2023 2022 2023 2022 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 628,135 $ 765,618 $ 217,330 $ 292,646 Projected benefit obligation assumed from business combination — 87,933 — 5,195 Plan settlements (3,226) (112) — — Service cost 11,954 16,309 3,253 6,277 Interest cost 33,687 24,787 11,510 9,146 Actuarial loss (gain) 20,172 (198,074) (10,913) (82,991) Contributions from retirees — — 2,189 2,220 Plan amendments — — — (2,452) Medicare Part D — — 355 367 Benefits paid (42,801) (68,197) (14,226) (13,078) Foreign exchange (53) (129) — — Projected benefit obligation, end of year $ 647,868 $ 628,135 $ 209,498 $ 217,330 Change in plan assets Fair value of plan assets, beginning of year 569,255 648,864 172,167 192,375 Plan assets acquired in business combination — 74,532 — 8,577 Actual return on plan assets 65,272 (109,118) 22,620 (30,105) Employer contributions 22,326 23,296 10,677 11,811 Plan settlements (3,226) (112) — — Contributions from retirees — — 2,189 2,220 Medicare Part D subsidy receipts — — 355 367 Benefits paid (42,801) (68,197) (14,226) (13,078) Foreign exchange 2 (10) — — Fair value of plan assets, end of year $ 610,828 $ 569,255 $ 193,782 $ 172,167 Unfunded status $ (37,040) $ (58,880) $ (15,716) $ (45,163) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 12,598 12,264 35,879 14,218 Current liabilities (1,416) (1,907) (3,164) (3,039) Non-current liabilities (48,222) (69,237) (48,431) (56,342) Net amount recognized $ (37,040) $ (58,880) $ (15,716) $ (45,163) The accumulated benefit obligations for the pension and OPEB plans are $827,559 and $815,589 as of December 31, 2023 and 2022, 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 2023 2022 2023 2022 Accumulated benefit obligation $ 425,842 $ 413,041 $ 71,089 $ 198,463 Fair value of plan assets $ 393,857 $ 364,229 $ 18,793 $ 139,368 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2023 2022 2023 2022 Projected benefit obligation $ 507,612 $ 489,140 $ 71,089 $ 198,463 Fair value of plan assets $ 458,497 $ 417,994 $ 18,793 $ 139,368 (b) Pension and post-employment actuarial changes Change in AOCI, before tax Pension OPEB Actuarial losses (gains) Past service losses (gains) Actuarial losses (gains) Past service losses (gains) Balance, January 1, 2022 $ 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) Additions to AOCI (12,600) — (23,797) 853 Amortization in current period 617 1,491 2,554 — Recognition of settlement gain 235 — — — Reclassification to regulatory accounts 5,517 (755) 19,518 — Balance, December 31, 2023 $ (6,902) $ (2,627) $ (35,275) $ (1,337) 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 2023 and 2022 were as follows: Pension benefits OPEB 2023 2022 2023 2022 Discount rate 5.19 % 5.48 % 5.22 % 5.49 % Interest crediting rate (for cash balance plans) 4.48 % 4.50 % N/A N/A Rate of compensation increase 3.60 % 3.70 % N/A N/A Health care cost trend rate Before age 65 7.00 % 6.00 % Age 65 and after 6.00 % 6.00 % Assumed ultimate medical inflation rate 4.50 % 4.75 % Year in which ultimate rate is reached 2034 2033 The mortality assumption for December 31, 2023 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, 2023 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 2023 and 2022 were as follows: Pension benefits OPEB 2023 2022 2023 2022 Discount rate 5.35 % 2.94 % 5.49 % 3.00 % Expected return on assets 6.38 % 6.19 % 6.45 % 6.48 % Rate of compensation increase 3.99 % 3.91 % 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 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 Pension and other post-employment non-service costs 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 2023 2022 2023 2022 Service cost $ 11,954 $ 16,309 $ 3,253 $ 6,277 Non-service costs Interest cost 33,687 24,787 11,510 9,146 Expected return on plan assets (31,990) (41,226) (9,736) (11,359) Amortization of net actuarial loss (852) 3,452 (3,559) (56) Amortization of prior service credits (1,491) (1,584) (853) 24 Amortization due to plan settlements — (15) — — Amortization of regulatory accounts 16,258 22,952 6,965 4,829 $ 15,612 $ 8,366 $ 4,327 $ 2,584 Net benefit cost $ 27,566 $ 24,675 $ 7,580 $ 8,861 (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 41.6 % 30% - 100% Debt securities 48.6 % 20% - 60% Other 9.8 % 0% - 20% 100 % The fair values of investments as of December 31, 2023, by asset category, are as follows: Asset class 2023 Percentage Equity securities $ 376,158 47 % Debt securities 377,272 47 % Other 51,180 6 % $ 804,610 100 % As of December 31, 2023, 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, 2023 are valued using Level 1 inputs except for $26,381 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, 2023 $ 21,904 Contributions into funds 4,603 Return on assets 2,205 Distributions (2,331) Balance, December 31, 2023 $ 26,381 (f) Cash flows The Company expects to contribute $23,248 to its pension plans and $3,583 to its post-employment benefit plans in 2024. The expected benefit payments over the next ten years are as follows: 2024 2025 2026 2027 2028 2029-2033 Pension plan $ 48,271 $ 49,652 $ 49,389 $ 50,443 $ 50,751 $ 255,465 OPEB $ 11,718 $ 12,303 $ 12,623 $ 13,105 $ 13,487 $ 71,230

Other assets

Other assets	12 Months Ended
	Dec. 31, 2023
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2023 2022 Restricted cash $ 19,997 $ 43,562 Pension and OPEB plan assets (note 10(a)) 48,477 26,482 Long-term deposits and cash collateral 19,336 22,537 Income taxes recoverable 9,988 7,100 Deferred financing costs (a) 27,176 28,586 Insurance recoveries (note 22(a)) 66,000 — Other (b) 31,080 21,596 $ 222,054 $ 149,863 Less: current portion (23,061) (22,564) $ 198,993 $ 127,299 (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 that will be recorded against the common shares when issued. 11. Other assets (continued) (b) Other

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2023 2022 Contract adjustment payments (a) $ 39,590 $ 113,876 Asset retirement obligations (b) 115,611 116,584 Advances in aid of construction (c) 88,135 88,546 Environmental remediation obligation (d) 40,772 42,457 Customer deposits (e) 36,294 34,675 Unamortized investment tax credits (f) 17,255 17,649 Deferred credits and contingent consideration (g) 40,945 39,498 Preferred shares, Series C (h) — 12,072 Hook-up fees (i) 7,425 32,463 Lease liabilities 20,493 21,834 Contingent development support obligations (j) 12,666 8,824 Note payable to related party (k) 25,808 25,808 Contingent liability (note 22(a)) 66,000 — Other 35,338 41,156 $ 546,332 $ 595,442 Less: current portion (80,458) (134,212) $ 465,874 $ 461,230 (a) Contract adjustment payment In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The 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. 12. Other long-term liabilities (continued) (b) Asset retirement obligations (continued) Changes in the asset retirement obligations are as follows: 2023 2022 Opening balance $ 116,584 $ 142,147 Obligation assumed 1,077 793 Retirement activities (6,902) (27,980) Accretion 4,440 4,589 Change in cash flow estimates 412 (2,965) Closing balance $ 115,611 $ 116,584 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 2023, $238 (2022 - $1,299) 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 $46,187 (2022 - $48,346), which at discount rates ranging from 3.4% to 4.3% represents the recorded accrual of $40,772 as of December 31, 2023 (2022 - $42,457). Approximately $25,713 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 27 years. Changes in the environmental remediation obligation are as follows: 2023 2022 Opening balance $ 42,457 $ 55,224 Remediation activities (3,687) (5,243) Accretion 1,616 2,167 Changes in cash flow estimates 1,395 1,344 Revision in assumptions (1,009) (11,035) Closing balance $ 40,772 $ 42,457 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 seven years and, accordingly, as of December 31, 2023, the Company has reflected a regulatory asset o f $66,779 (2022 - $70,529) for the MGP and re lated sites (note 7(g)) . 12. Other long-term liabilities (continued) (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. (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. (h) Preferred shares, Series C During the year ended December 31, 2023, 100 Series C preferred shares of AQN that had previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP, were redeemed for $14,515, and a loss on settlement of $2,377 was recorded in other net losses (note 19(f)) in the consolidated statements of operations. As a result of the redemption, no Series C preferred shares of AQN remain outstanding. (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)). (k) Note payable to related party 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. 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, 2023
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2023 2022 Common shares, beginning of year 683,614,803 671,960,276 Public offering — 2,861,709 Dividend reinvestment plan 4,370,289 7,676,666 Exercise of share-based awards (c) 1,284,532 1,115,398 Conversion of convertible debentures 1,415 754 Common shares, end of year 689,271,039 683,614,803 13. Shareholders’ capital (continued) (a) Common shares (continued) 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) At-the-market equity program On August 15, 2022, AQN re-established its at-the-market equity program (“ATM Program”) that allowed 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, 2023, the Company did not issue any common shares under its ATM Program. The ATM Program terminated in accordance with its terms on December 19, 2023. The Company has issued, since the inception of its initial 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 $4,843. (ii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the dividend reinvestment plan began receiving cash dividends. If the Company elects to reinstate the dividend reinvestment plan in the future, shareholders who were enrolled in the dividend reinvestment plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the dividend reinvestment plan. (b) Preferred shares AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. 13. Shareholders’ capital (continued) The Company has the following Cumulative Rate Reset Preferred Shares, Series A (the “Series A Shares”) and Cumulative Rate Reset Preferred Shares, Series D (the “Series D Shares”) issued and outstanding as of December 31, 2023 and 2022: Number of shares Price per share Carrying amount C$ Carrying amount $ Series A Shares 4,800,000 C$25.00 C$ 116,546 $ 100,463 Series D Shares 4,000,000 C$25.00 C$ 97,259 $ 83,836 $ 184,299 The holders of Series A Shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 was an annual amount of C$1.2905 per share. The dividend rate for the five-year period from, and including December 31, 2023 but excluding December 31, 2028 will be an annual amount of C $1.6440 per share. The Series A Shares dividend rate will reset on December 31, 2028 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A Shares were redeemable at C$25 per share at the option of the Company on December 31, 2023 and are redeemable every fifth year thereafter. The holders of Series A Shares have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2028 (or the next business day, if such day is not a business day), and every fifth year thereafter. The holders of Series D Shares 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 Share dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D Shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 (or the next business day, if such day is not a business day) and every fifth year thereafter. Accordingly, the Series D Shares are redeemable by the Company on April 1, 2024, but the Company has elected not to exercise its redemption right. The holders of Series D Shares have the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024 (or the next business day, if such day is not a business day), and every fifth year thereafter. (c) Share-based compensation For the year ended December 31, 2023, AQN recorded $11,293 (2022 - $10,920) in total share-based compensation expense as follows: 2023 2022 Share options $ 1,325 $ 980 Director deferred share units 949 960 Employee share purchase 897 562 Performance and restricted share units 8,122 8,418 Total share-based compensation $ 11,293 $ 10,920 The compensation expense is recorded within 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, 2023, total unrecognized compensation costs related to non-vested share-based awards are $23,883 and are 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. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (i) Share option plan (continued) 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. The following assumptions were used in determining the fair value of share options granted: 2023 2022 Risk-free interest rate 3.4 % 1.9 % Expected volatility 27 % 23 % Expected dividend yield 8.6 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option $ 1.04 $ 2.44 Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2022 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$ — Granted 1,368,744 10.76 7.24 — Exercised — — — — Forfeited (1,327,799) 16.55 — — Balance, December 31, 2023 2,667,725 C$ 14.71 5.18 C$ — Exercisable, December 31, 2023 2,621,420 C$ 17.11 4.50 C$ — 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (ii) 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. 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, 2023, a total of 752,582 common shares (2022 - 414,338) were issued to employees under the ESPP. (iii) 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, 2023, a total of 181,328 DSUs (2022 - 120,513) were issued and 102,460 DSUs (2022 - 5,176) were settled in exchange for 50,677 common shares issued from treasury, and 51,783 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2023, 724,583 (2022 - 645,714) DSUs are 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. (iv) 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 ratably over the performance period. Achievement of the performance criteria is estimated as 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) (iv) Performance and restricted share units (continued) A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2022 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 Granted, including dividends 2,841,967 10.98 2.02 25,329 Exercised (922,883) 18.73 — 10,125 Forfeited (451,047) 15.07 — 3,771 Balance, December 31, 2023 3,577,747 C$ 18.38 1.76 C$ 29,910 Exercisable, December 31, 2023 597,363 C$ 19.98 0.22 C$ 4,994 (v) 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, 2023, 77,981 (2022 - 55,445) bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 69,115 (2022 - 178,368) bonus deferral RSUs in exchange for 31,455 (2022 - 82,886) common shares issued from treasury, and 37,660 (2022- 95,482) RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2023, 167,352 (2022 - 158,486) bonus deferral RSUs are outstanding.

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2023
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, 2022 $ (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) Other comprehensive income (loss) (3,788) 57,351 8,395 61,958 Amounts reclassified from AOCI to the consolidated statement of operations (1,598) 2,136 (3,702) (3,164) Net current period OCI $ (5,386) $ 59,487 $ 4,693 $ 58,794 OCI attributable to the non-controlling interests (1,017) — — (1,017) Net current period OCI attributable to shareholders of AQN $ (6,403) $ 59,487 $ 4,693 $ 57,777 Balance, December 31, 2023 $ (104,870) $ (38,322) $ 40,906 $ (102,286) 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, 2023
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: 2023 2022 Dividend Dividend per share Dividend Dividend per share Common shares $ 301,771 $ 0.4340 $ 486,043 $ 0.7130 Series A Shares C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Series D Shares C$ 5,091 C$ 1.2728 C$ 5,091 C$ 1.2728

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2023
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 2023, the Company charged its equity-method investees $34,733 (2022 - $38,215) for administrative services and $37,802 (2022 - $25,645) for development services. Additionally, Liberty Development JV Inc. (note 8(c)), an equity-method investee of the Company that is the Company’s joint venture with funds managed by the Infrastructure and Power strategy of Ares Management, LLC for its non-regulated development platform, 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 $27,933 (2022 - $12,628). Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V. Investments in and acquisitions of equity-method investments are described in note 8(c). (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). (c) Transactions with Atlantica On December 28, 2023, Liberty Development Spain, S.A., a wholly owned subsidiary of the Company entered into an agreement to sell its 100% equity interests in Liberty Jimena, S.L. and Liberty Caparacena, S.L., and its 80% equity interest in Liberty Infrastructuras, S.L. to Atlantica for a nominal amount. As a result, the Company recorded an impairment loss of $1,481, included in asset impairment charge in the consolidated statements of operations. The transaction closed on January 23, 2024. 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 interests	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 114,141 $ 108,695 Non-controlling interests - redeemable tax equity partnership units 1,324 6,298 Other net earnings attributable to: Non-controlling interests (27,564) (3,670) $ 87,901 $ 111,323 Redeemable non-controlling interest, held by related party (25,922) (15,157) Net effect of non-controlling interests $ 61,979 $ 96,166 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 (loss) 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) 2023 2022 2023 2022 2023 2022 Opening balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158 Net earnings (loss) attributable to NCI (114,141) (108,695) 27,564 3,670 — — Contributions received, net 107,933 6,182 — 267,515 — — Dividends and distributions declared (22,743) (36,736) (14,497) (3,350) (17,082) (20,978) Repurchase of non-controlling interest — (12,249) — — — — OCI 63 (11) 909 720 45 (2,358) Closing balance $ 1,196,720 $ 1,225,608 $ 347,338 $ 333,362 $ 40,785 $ 57,822 (a) Non-controlling interests - tax equity partnership units The Company obtained control of the Deerfield II Wind Facility during the year (note 3). Post-acquisition, third-party tax equity investors funded $98,955 in exchange for Class A partnership units in the entity. In addition, the Company received $9,084 (2022 - $6,182) of production based cash contributions during the year relating to other projects. (b) Other non-controlling interests On December 29, 2022, the Company s old 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. (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, 2023. Liberty Global Energy Solutions (note 8(c)), an equity investee of the Company, has a secured credit facility in the amount of $306,500 with a previous maturity date of January 26, 2024. Subsequent to year-end, on January 8, 2024, the secured credit facility was renewed with a maturity date of September 30, 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. As a result of the subsequent event described in note 8(c), the redeemable non-controlling interest held by related party will be reclassified to long-term debt in 2024. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2023 2022 2023 2022 Opening balance $ 307,856 $ 306,537 $ 11,520 $ 12,989 Net earnings (loss) attributable to NCI 25,922 15,157 (1,324) (6,298) Contributions, net of costs — — — 5,000 Dividends and distributions declared (25,428) (13,838) (183) (171) Closing balance $ 308,350 $ 307,856 $ 10,013 $ 11,520

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2023
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% (2022 - 26.5%). The differences are as follows: 2023 2022 Expected income tax recovery at Canadian statutory rate $ (31,696) $ (97,962) Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (46,628) (55,315) Adjustments from investments carried at fair value 16,128 51,314 Non-controlling interests share of income 24,677 30,025 Change in valuation allowance 10,786 41,702 Acquisition related state deferred tax adjustments — 5,998 Capital gain rate differential on disposal of renewable assets — (7,340) Tax credits (54,788) (18,440) Amortization and settlement of excess deferred income tax (12,785) (14,855) Deferred income taxes on regulated income recorded as regulatory assets (878) (1,986) Other permanent differences 5,341 4,591 Other 3,543 755 Income tax recovery $ (86,300) $ (61,513) 18. Income taxes (continued) On December 27, 2023, the government of Bermuda enacted the Bermuda Corporate Income Tax Act 2023, setting a 15% corporate income tax rate effective for fiscal years commencing January 1, 2025. The Bermuda Corporate Income Tax Act 2023 includes various transition adjustments that may affect the recognition of deferred taxes and as such were considered as part of the initial measurement in the period that includes the December 2023 enactment date. No deferred taxes were required to be recognized as at December 31, 2023. For the years ended December 31, 2023 and 2022, earnings (loss) before income taxes consist of the following: 2023 2022 Canada (1) $ (259,141) $ (363,050) U.S. 102,469 (37,322) Other regions 37,067 30,704 $ (119,605) $ (369,668) (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, 2023 Canada $ 4,352 $ (59,488) $ (55,136) United States (14,820) (23,099) (37,919) Other regions 728 6,027 6,755 $ (9,740) $ (76,560) $ (86,300) 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) 18. Income taxes (continued) The tax effect of temporary differences between the consolidated 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, 2023 and 2022 are presented below: 2023 2022 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 1,030,801 $ 878,000 Pension and OPEB 7,370 16,845 Environmental obligation 11,692 12,118 Regulatory liabilities 180,371 156,285 Other 72,109 61,917 Total deferred income tax assets $ 1,302,343 $ 1,125,165 Less: valuation allowance (97,344) (107,583) Total deferred tax assets $ 1,204,999 $ 1,017,582 Deferred tax liabilities: Property, plant and equipment $ 883,447 $ 846,331 Outside basis differentials 364,511 315,581 Regulatory accounts 317,820 303,059 Other 59,640 33,834 Total deferred tax liabilities $ 1,625,418 $ 1,498,805 Net deferred tax liabilities $ (420,419) $ (481,223) Consolidated balance sheets classification: Deferred tax assets $ 158,483 $ 84,416 Deferred tax liabilities (578,902) (565,639) Net deferred tax liabilities $ (420,419) $ (481,223) The valuation allowance for deferred tax assets as of December 31, 2023 was $97,344 (2022 - $107,583). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized for the Renewable Energy Group. The U.S. entities in the Renewable Energy Group continue to be in an overall deferred tax asset position as at December 31, 2023. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded, similar to 2022, that it was not probable that the U.S. business of the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group (with the exception of certain transferable tax credits). Management’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group . The amount of the deferred tax asset considered realizable 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. The Company’s overall deferred tax asset position related to Canadian attributes increased from $83,434 to $151,759 for the year ended December 31, 2023, primarily due to ongoing interest and financing expenses attributable to the Canadian entities and the decrease in the value of the Company’s investment in Atlantica. As at December 31, 2023, it is considered more likely than not that there will be sufficient taxable income in the future that will allow realization of these deferred tax assets. The Company considered all evidence, both positive and negative, including the announcement of the sale of the renewable energy business, the availability of tax planning strategies, and the carryforward period of its Canadian net operating losses in making this assessment. The Company will continue to monitor this position at each balance sheet date. 18. Income taxes (continued) The following table illustrates the annual movement in the deferred tax valuation allowance: 2023 2022 Beginning balance $ 107,583 $ 27,471 Charged to income tax expense 10,786 41,702 Charged (reduction) to OCI (16,696) 40,613 Reductions to other accounts (4,329) (2,203) Ending balance $ 97,344 $ 107,583 As of December 31, 2023, 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 2024—2028 2029+ Total Canada $ 3,339 $ 913,781 $ 917,120 US 8,441 1,897,609 1,906,050 Total non-capital loss carryforward $ 11,780 $ 2,811,390 $ 2,823,170 Tax credits $ 3,359 $ 200,772 $ 204,131 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 $908,449 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, 2023
Other Income and Expenses [Abstract]
Other net losses	Other net losses Other net losses consist of the following: 2023 2022 Acquisition and transition-related costs $ — $ 6,834 Kentucky termination costs (a) 46,527 10,608 Acquisition-related settlement payment (b) (11,983) — Securitization write-off (c) 63,495 — Renewable energy business sale costs (d) 12,506 — Loss on redemption of long-term note (e) 8,532 — Other (f) 13,812 3,949 $ 132,889 $ 21,391 (a) Kentucky termination costs The loss related to the termination of the Kentucky Power Transaction includes $38,795 for the write-off of capitalized costs, which are primarily related to the implementation of an enterprise software solution. The remaining amount relates to the transaction costs, severance costs and other termination costs. In 2022, the Company incurred $10,608 in anticipation of the Kentucky Power Transaction. (b) Acquisition-related settlement payment During the year, the Company received $12,814 as an acquisition-related settlement payment in connection with the Suralis acquisition. The Company also incurred legal fees of $831 in relation to this settlement. 19. Other net losses (continued) (c) Securitization write-off During the year, the Company has written off $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute (note 7(a)). (d) Renewable energy business sale costs The Company announced that it is pursuing a sale of its renewable energy business. The Company incurred costs of $12,506 related to this process in 2023. (e) Loss on redemption of long-term note During Q4, 2023, the Company redeemed subordinated unsecured long-term note (note 9(f)) and incurred loss on redemption of $8,532. (f) Other Other losses for the year consist primarily of provisions on litigation matters, executive severance costs, the Series C preferred share redemption loss and other miscellaneous write-offs.

Basic and diluted net earnings

Basic and diluted net earnings (loss) per share	12 Months Ended
	Dec. 31, 2023
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 (loss) 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 (loss) and the weighted average shares used in the computation of basic and diluted earnings (loss) per share are as follows: 2023 2022 Net earnings (loss) attributable to shareholders of AQN $ 28,674 $ (211,989) Preferred shares, Series A dividend 4,586 4,786 Preferred shares, Series D dividend 3,770 3,934 Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ 20,318 $ (220,709) Weighted average number of shares Basic 688,738,717 677,862,207 Effect of dilutive securities 2,024,509 — Diluted 690,763,226 677,862,207

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2023
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, 2023 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,315,722 $ 296,314 $ — $ 2,612,036 Other revenue 51,137 33,395 1,447 85,979 Fuel, power and water purchased 716,446 19,499 — 735,945 Net revenue 1,650,413 310,210 1,447 1,962,070 Operating expenses 786,608 119,013 1,364 906,985 Administrative expenses 46,386 36,554 7,419 90,359 Depreciation and amortization 346,188 119,576 1,232 466,996 Asset impairment charge — 23,492 — 23,492 Loss on foreign exchange — — 8,359 8,359 Operating income (loss) 471,231 11,575 (16,927) 465,879 Interest expense (160,998) (61,261) (131,397) (353,656) Income (loss) from long-term investments 44,953 102,188 (230,705) (83,564) Other expenses (121,146) (4,002) (23,116) (148,264) Earnings (loss) before income taxes $ 234,040 $ 48,500 $ (402,145) $ (119,605) Property, plant and equipment $ 8,945,637 $ 3,539,069 $ 32,744 $ 12,517,450 Investments carried at fair value 1,962 1,113,767 — 1,115,729 Equity-method investees 112,180 343,712 501 456,393 Total assets 12,658,955 5,367,011 347,995 18,373,961 Capital expenditures $ 816,788 $ 209,383 $ — $ 1,026,171 (1) Renewable Energy Group revenue includes $5,695 related to net hedging gain from energy derivative contracts and availability credits for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $32,839 related to alternative revenue programs for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2022 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,330,039 $ 350,797 $ — $ 2,680,836 Other revenue 54,229 28,447 1,501 84,177 Fuel and power purchased 824,670 41,684 — 866,354 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 charge — 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 expenses (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 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. 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: 2023 2022 Revenue United States $ 2,169,239 $ 2,232,817 Canada 162,740 175,005 Other regions 366,036 357,191 $ 2,698,015 $ 2,765,013 Property, plant and equipment United States $ 10,826,738 $ 10,351,736 Canada 924,389 848,560 Other regions 766,323 744,589 $ 12,517,450 $ 11,944,885 Intangible assets United States $ 18,666 $ 18,818 Canada 18,111 19,038 Other regions 57,161 58,827 $ 93,938 $ 96,683 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, 2023
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. 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 21 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. Fourteen 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 14 lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). On March 6, 2024, a trial commenced in Los Angeles County Superior Court on four bellwether cases with respect to inverse condemnation liability only. If the Company’s subsidiaries were found liable in those cases, the damages, if any, would not be determined at this trial. In another lawsuit, County of Mono, Antelope Valley Fire Protection District 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 six 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 is uncertain. 22. Commitments and contingencies (continued) (a) Contingencies (continued) In 2023, Liberty CalPeco accrued estimated losses of $66,000 for claims related to the Mountain View Fire, against which Liberty CalPeco has recorded expected recoveries from insurance of $66,000. The resulting net charge to earnings was $nil. The estimate of losses is subject to change as additional information becomes available. The actual amount of losses may be higher or lower than these estimates. While the Company may incur a material loss in excess of the amount accrued, the Company cannot estimate the upper end of the range of reasonably possible losses that may be incurred. 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 development projects disclosed in note 8 , the following significant commitments exist as of December 31, 2023. AQN has outstanding purchase commitments for power purchases, natural gas supply and service agreements, service agreements, capital project commitments, land easements and other 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 (1) $ 55,312 $ 33,869 $ 12,274 $ 12,520 $ 12,768 $ 129,818 $ 256,561 Natural gas supply and service agreements (2) 121,188 71,949 42,643 33,215 30,803 154,757 454,555 Service agreements 73,687 61,889 56,591 53,140 52,898 259,510 557,715 Capital projects 5,598 — — — — — 5,598 Land easements and other 16,437 15,057 15,269 15,425 15,639 536,129 613,956 Total $ 272,222 $ 182,764 $ 126,777 $ 114,300 $ 112,108 $ 1,080,214 $ 1,888,385 (1) 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, 2023. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (2) 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, 2023
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: 2023 2022 Accounts receivable $ 3,863 $ (124,631) Fuel and natural gas in storage 46,368 (21,140) Supplies and consumables inventory (48,539) (24,088) Income taxes recoverable (2,889) 549 Prepaid expenses (13,218) (4,269) Accounts payable 23,847 24,395 Accrued liabilities (488) 127,076 Current income tax liability 1,096 (2,741) Asset retirements and environmental obligations (1,015) (22,342) Net regulatory assets and liabilities (95,361) (174,427) $ (86,336) $ (221,618)

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments December 31, 2023 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,115,729 $ 1,115,729 $ 1,054,665 $ — $ 61,064 Development loans and other receivables 158,110 155,735 — 155,735 — Derivative instruments: Interest rate swap designated as a hedge 72,936 72,936 — 72,936 — Interest rate cap not designated as a hedge 1,854 1,854 — 1,854 — Congestion revenue rights not designated as a cash flow hedge 8,458 8,458 — — 8,458 Total derivative instruments 83,248 83,248 — 74,790 8,458 Total financial assets $ 1,357,087 $ 1,354,712 $ 1,054,665 $ 230,525 $ 69,522 Long-term debt $ 8,516,030 $ 7,423,318 $ 2,532,608 $ 4,890,710 $ — Notes payable to related party 25,808 15,320 — 15,320 — Convertible debentures 230 276 276 — — Derivative instruments: Energy contracts designated as a cash flow hedge 68,070 68,070 — — 68,070 Energy contracts not designated as a cash flow hedge 5,593 5,593 — — 5,593 Cross-currency swap designated as a net investment hedge 10,533 10,533 — 10,533 — Currency forward contract designated as hedge 6,779 6,779 — 6,779 — Interest rate swaps designated as a hedge 11,790 11,790 — 11,790 — Cross currency swap designated as a cash flow hedge 5,547 5,547 — 5,547 — Commodity contracts for regulated operations 2,564 2,564 — 2,564 — Total derivative instruments 110,876 110,876 — 37,213 73,663 Total financial liabilities $ 8,652,944 $ 7,549,790 $ 2,532,884 $ 4,943,243 $ 73,663 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2022 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,344,207 $ 1,344,221 $ 1,270,138 $ — $ 74,083 Development loans and other receivables 53,680 50,300 — 50,300 — Derivative instruments: Energy contracts not designated as a cash flow hedge 393 393 — — 393 Interest rate swap designated as a hedge 69,188 69,188 — 69,188 — Currency forward contract 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 $ 1,478,421 $ 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 The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2023 and 2022 du e to the short-term maturity of these instruments. 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The fair value of the investment in Atlantica (Level 1) is measured at the closing price on the NASDAQ stock exchange. The fair value of development loans and other receivables (Level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. The Company’s Level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s Level 2 fair value of long-term debt at fixed interest rates and notes payable to related party have 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 $26.32 to $144.02 with a weighted average of $38.44 as of December 31, 2023. 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 $$52.02 with a weighted average of $5.69 as of December 31, 2023. 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 fr om 8.00% to 8.50% with a weighted average of 8.27%, and the expected volatility of Atlantica’s share price ranging fro m 27.47% to 33.19% as of December 31, 2023. 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. As at December 31, 2023, the commodity volume, in dekatherms, associated with the above derivative contracts is 2,117,039. 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. Notional quantity Expiry Receive average Pay floating price 353,597 December 2028 $29.19 PJM Western HUB 1,492,926 December 2027 $21.34 NI HUB 1,332,645 December 2027 $36.46 ERCOT North HUB 3,534,802 September 2030 $24.54 Illinois Hub The Company mitigates the risk that interest rates will increase over the life of certain term loan facilities by entering into the following interest rate swap contracts. For an interest rate swap or cross-currency interest rate swap designated as hedging the exposure to variable cash flows of a future transaction, the effective portion of this derivative's gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt. Derivative Notional quantity Expiry Hedged item Forward-starting interest rate swap $ 350,000 July 2029 $350,000 subordinated unsecured notes Cross-currency interest rate swap C$ 400,000 January 2032 C$400,000 subordinated unsecured notes Forward-starting interest rate swap $ 750,000 April 2032 $750,000 subordinated unsecured notes Forward-starting interest rate swap $ 575,000 June 2026 First $575,000 of the expected $1,150,000 senior unsecured notes issuance 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: 2023 2022 Effective portion of cash flow hedge $ 57,351 $ (128,838) Amortization of cash flow hedge (6,173) (12,180) Amounts reclassified from AOCI 8,309 46,723 OCI attributable to shareholders of AQN $ 59,487 $ (94,295) The Company expects $25,895 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 loss of$12,330 for the year ended December 31, 2023 (2022 - gain of $2,262) 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 gain (loss) 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 $6,976 for the year ended December 31, 2023 (2022 - gain of $22,091) 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 gain of $606 for the year ended December 31, 2023 (2022 - loss of $18,561) 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 (2022 - C$300,000) fixed-for-fixed 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 gain of $5,959 for the year ended December 31, 2023 (2022 - loss of $11,082) 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, to effectively convert th e 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 gain of $8,420 for the year ended December 31, 2023 (2022 - loss of $13,374) 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 (loss). The Company was party to an interest rate cap agreement in the amount of $390,000 for the period between January 15, 2023 and January 15, 2024. On September 29, 2023, the Company entered into a new interest rate cap agreement in the amount of $390,000 million for the period between January 15, 2024 and June 17, 2024. The Company was party to interest rate swaps with a notional quantity of C$489,506 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 in 2022. A recognized loss of C$9,732 on the derivative was recorded as a reduction of the gain on sale of renewable assets on the audited consolidated statements of operations. The Company mitigates the volatility of energy congestion charges at the ERCOT transmission grid by entering into CRRs, which as of December 31, 2023 had notional quantity of 5,486,961 MW-hours at prices ranging from $0.55 per MW-hr to $24.88 per MW-hr with a weighted average of $5.16 per MW-hr for January 2024 to June 2026. These CRRs are not designated as an accounting hedge. 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. The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2023 2022 Unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (372) $ (945) Commodity contracts 411 185 Total unrealized gain (loss) on derivative financial instruments $ 39 $ (760) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ (4,896) $ 6,939 Interest rate swaps — (7,185) Total realized loss on derivative financial instruments $ (4,896) $ (246) Loss on derivative financial instruments not accounted for as hedges (4,857) (1,006) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,989 3,465 $ (868) $ 2,459 Consolidated statements of operations classification: Gain on derivative financial instruments $ 4,564 $ 4,408 Renewable energy sales (5,432) 5,236 Reduction to gain on sale of renewable assets — (7,185) $ (868) $ 2,459 (c) Supplier financing programs In the normal course of business, the Company enters into supplier financing programs under which the suppliers can voluntarily elect to sell their receivables. The Company agrees to pay, on the invoice maturity date, the stated amount of the invoices that the Company has confirmed through the execution of bills of exchange. The terms of the trade payable arrangement are consistent with customary industry practice and are not impacted by the supplier’s decision to sell amounts under these arrangements. The roll forwards of the Company's outstanding obligations confirmed as valid under its supplier finance programs for years ended December 31, 2023 and 2022, are as follows: 2023 2022 Confirmed obligations outstanding at the beginning of the year $ 16,785 $ 49,910 Invoices confirmed during the year 90,780 16,785 Confirmed invoices paid during the year (45,392) (49,910) Confirmed obligations outstanding at the end of the year $ 62,173 $ 16,785 24. Financial instruments (continued) (d) Risk management 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 $364,084 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, 2023, the Company’s maximum exposure to credit risk for these financial instruments is as follows: 2023 Cash and cash equivalents and restricted cash $ 76,145 Accounts receivable 554,438 Allowance for doubtful accounts (30,244) Notes receivable 158,836 $ 759,175 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 counties 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, 2023, in addition to cash on hand of $56,147, the Company has $945,853 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) (d) 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 $ 621,856 $ 1,333,772 $ 2,099,968 $ 4,481,961 $ 8,537,557 Interest on long-term debt 391,493 602,761 419,950 3,496,032 4,910,236 Purchase obligations 767,287 — — — 767,287 Environmental obligation 3,136 22,577 1,820 18,654 46,187 Advances in aid of construction 3,640 — — 84,495 88,135 Derivative financial instruments: Cross-currency swap 2,419 4,243 144 9,623 16,429 Interest rate forwards 11,790 — — — 11,790 Energy derivative and commodity contracts 14,276 29,273 20,550 12,127 76,226 Contract adjustment payments on Green Equity Units 39,590 — — — 39,590 Other obligations 27,796 2,901 2,304 247,480 280,481 Total obligations $ 1,883,283 $ 1,995,527 $ 2,544,736 $ 8,350,372 $ 14,773,918

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Comparative figures	Comparative figures Certain 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, 2023
Accounting Policies [Abstract]
Basis of preparation	Basis of preparation
Basis of consolidation	Basis of consolidation The accompanying consolidated financial statements of AQN include the accounts of AQN 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, Suralis (Chile) Water System (“Suralis”) (formerly known as Empresa de Servicios Sanitarios de Los Lagos (ESSAL). 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 Suralis’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 consolidated financial condition and consolidated 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 Gas Distribution Uniform Accounting Regulation - Gas Distribution Act, 1999 (New Brunswick) .
Cash and cash equivalents	Cash and cash equivalents Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
Restricted cash	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.
Accounts receivable	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.
Fuel and natural gas in storage	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.
Supplies and consumables inventory	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.
Property, plant and equipment	Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when 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 2023 2022 2023 2022 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 39 Equipment 5-54 5-54 15 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 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 $552,701 (2022 - $559,630) and accumulated depreciation of $83,283 (2022 - $75,820). The Company’s share of operating costs are recognized in operating expenses. Total expenditures incurred on these facilities for the year ended December 31, 2023 were $72,584 (2022 - $110,268).
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.
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 development loans	Long-term investments and development loans 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.
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 (loss) (“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 Pension and other post-employment non-service costs in the consolidated statements of operations.
Asset retirement obligations	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.
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 of December 31, 2023 and its expected lease payments for the next five years and thereafter are not significant.
Share-based compensation	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.
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 (loss) and other comprehensive income (loss) (“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 (loss) or comprehensive income (loss) 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 as 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 and generation of electricity, water distribution, wastewater collection and distribution of 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.
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 consolidated 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 (redeemed during the year) 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, Green equity units (note 11(a)) 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 (loss) 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 (loss). 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 contingencies Liabilities 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 estimates The 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 as 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 issued accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued Accounting Standards Update (“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. See note 24(c) for details. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2023-02, Accounting for Investments in Tax Credit Structures Using the Proportional Amortization Method — A Consensus of the Emerging Issues Task Force, which permits a reporting entity, if certain conditions are met, to elect to account for its tax equity investments by using the proportional amortization method regardless of the program from which it receives income tax credits. The amendments in this update are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance. The FASB issued ASU 2023-05, Joint Venture Formations: Recognition and Initial Measurement, which requires a joint venture to recognize and initially measure its assets and liabilities at fair value as at the joint venture formation date. The amendments in this update are effective prospectively for all joint venture formations with a formation date on or after January 1, 2025. Additionally, a joint venture formed before January 1, 2025 may elect to apply the amendments retrospectively if it has sufficient information. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance. The FASB issued ASU 2023-07, Segment Reporting: Improvement to Reportable Segments Disclosures, which requires enhanced disclosures about significant segment expenses. The amendments in this update are effective for annual periods beginning on December 15, 2023 and interim periods within annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure. The FASB issued ASU 2023-09, Income Taxes: Improvement to Income Tax Disclosures, which requires a reporting entity to disclose additional income tax information primarily related to the rate reconciliation and income taxes paid information. The amendments in this update are effective prospectively for annual periods beginning on December 15, 2024. 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, 2023
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 2023 2022 2023 2022 Generation 3-60 3-60 33 33 Distribution 1-100 1-100 40 39 Equipment 5-54 5-54 15 11

Business acquisitions, develo_2

Business acquisitions, development projects and disposition transactions (Tables)	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
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. Deerfield II Working capital $ (10,709) Property, plant and equipment 194,419 Long-term debt (157,935) Asset retirement obligation (1,030) Deferred tax liability (1,603) Total net assets acquired 23,142 Cash and cash equivalents 1,662 Net assets acquired, net of cash and cash equivalents $ 21,480 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

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment consist of the following: 2023 Cost Accumulated depreciation Net book value Renewable generation facilities $ 4,200,559 $ 1,139,137 $ 3,061,422 Utility plant 9,332,092 1,191,013 8,141,079 Land 133,483 — 133,483 Equipment 122,929 53,181 69,748 Construction-in-progress Generation 378,043 — 378,043 Distribution and transmission 733,675 — 733,675 $ 14,900,781 $ 2,383,331 $ 12,517,450 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
Schedule of Capitalization of Interest	Interest and AFUDC capitalized to the cost of the assets in 2023 and 2022 are as follows: 2023 2022 Interest capitalized on non-regulated property $ 6,374 $ 4,762 AFUDC capitalized on regulated property: Allowance for borrowed funds 8,305 6,040 Allowance for equity funds 3,372 1,901 $ 18,051 $ 12,703

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	Intangible assets consist of the following: 2023 Cost Accumulated amortization Net book value Power sales contracts $ 58,200 $ 43,938 $ 14,262 Customer relationships 77,104 14,625 62,479 Interconnection agreements 10,329 1,977 8,352 Other (a) 10,352 1,507 8,845 $ 155,985 $ 62,047 $ 93,938 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 (a) Other includes brand names, water rights and miscellaneous intangibles
Schedule of Goodwill	All goodwill pertains to the Regulated Services Group. 2023 2022 Opening balance $ 1,320,579 $ 1,201,244 Business acquisitions 4,195 123,751 Foreign exchange (712) (4,416) Closing balance $ 1,324,062 $ 1,320,579

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2023
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 Apple Valley Water System California General rate review On February 3, 2023, the California Public Utilities Commission (“CPUC”) issued a final order authorizing an annual revenue increase of $1,494. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023. Park Water System California General rate review On February 3, 2023, the CPUC issued a final order authorizing an annual revenue increase of $1,105. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023. CalPeco Electric System California General rate review On April 27 , 2023, the California Public Utilities Commission (“CPUC”) issued a final order approving a revenue increase of $26,979 . New rates became effective on July 1, 2023 retroactive to January 2022 . The retroactive impact of this final order was recorded in the second quarter of 2023. St. Lawrence Gas New York General rate review On June 22, 2023 , the New York State Department of Public Services issued an Order authorizing a revenue increase of $5,249 to be implemented over the course of 2023-2025. New rates became effective July 1, 2023. Pine Bluff Water Arkansas General rate review On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a unanimous settlement agreement filed by the parties authorizing an annual revenue increase of $3,400. New rates became effective August 15, 2023. Gas New Brunswick New Brunswick General rate review On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a revenue decrease of $700. Empire Electric Arkansas General rate review On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the settlement agreement authorizing a revenue increase of $5,300. New rates became effective January 1, 2024. Empire Electric Missouri Securitization On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the Missouri Public Service Commission’s (“MPSC”) order of $290,383. Subsequent to year-end, on January 30, 2024. t he Company completed the securitization to recover the costs associated with the extreme winter storm conditions experienced in Texas and parts of central U.S in February 2021 (“Midwest Extreme Weather Event”) and the remaining book value of the Asbury generating plant. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus. the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: December 31, 2023 December 31, 2022 Regulatory assets Fuel and commodity cost adjustments (a) $ 326,418 $ 388,294 Retired generating plant (b) 183,732 174,609 Rate adjustment mechanism (c) 192,880 136,198 Income taxes (d) 101,939 97,414 Deferred capitalized costs (e) 124,517 90,121 Pension and post-employment benefits (f) 68,822 80,736 Environmental remediation (g) 66,779 70,529 Wildfire mitigation and vegetation management (h) 64,146 66,156 Clean energy and other customer programs (i) 37,214 28,145 Asset retirement obligation (j) 26,620 27,172 Debt premium (k) 18,995 24,888 Cost of removal (l) 11,084 11,084 Rate review costs (m) 8,815 9,481 Long-term maintenance contract (n) 4,932 6,504 Other regulatory assets (o) 90,790 60,170 Total regulatory assets $ 1,327,683 $ 1,271,501 Less: current regulatory assets (142,970) (190,393) Non-current regulatory assets $ 1,184,713 $ 1,081,108 Regulatory liabilities Income taxes (d) $ 290,121 $ 312,671 Cost of removal (l) 185,786 191,173 Pension and post-employment benefits (f) 104,636 68,085 Fuel and commodity cost adjustments (a) 42,850 24,991 Clean energy and other customer programs (i) 12,730 11,572 Rate adjustment mechanism (c) 2,078 343 Other regulatory liabilities (p) 96,095 19,347 Total regulatory liabilities $ 734,296 $ 628,182 Less: current regulatory liabilities (99,850) (69,865) Non-current regulatory liabilities $ 634,446 $ 558,317 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 the 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 August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the MPSC’s order of $290,383. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus, the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023. Subsequent to year-end, on January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant. (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 consolidated balance sheets 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 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 1, 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. The Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, the regulatory liability is netted against its retired generation facilities regulatory asset. 7. Regulatory matters (continued) (b) Retired generating plant (continued) On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, the cases regarding the quantum financeable through securitization for Asbury and the Midwest Extreme Weather Event. As noted above under (a) Fuel and commodity cost adjustments , subsequent to year-end, on January 30, 2024, the Company completed the securitization of the costs associated with the retirement of the Asbury plant in accordance with the MPSC’s order. (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 weighted average cost of capital (“WACC”) on certain property, plant and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates. 7. Regulatory matters (continued) (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 three Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. (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 seven 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 regulatory assets 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. 7. Regulatory matters (continued) (p) Other regulatory liabilities During the year, the Company recognized a regulatory liability of $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2023
Disclosure Long Term Investments And Notes Receivable [Abstract]
Schedule of Long-term Investments	Long-term investments consist of the following: December 31, 2023 December 31, 2022 Long-term investments carried at fair value Atlantica (a) $ 1,052,703 $ 1,268,140 Atlantica Yield Energy Solutions Canada Inc. (b) 61,064 74,083 Other 1,962 1,984 $ 1,115,729 $ 1,344,207 Other long-term investments Equity-method investees (c) $ 456,393 $ 381,802 Development loans receivable from equity-method investees (d) 158,110 52,923 San Antonio Water System and other (e) 27,417 27,600 $ 641,920 $ 462,325
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, 2023 2022 Fair value loss on investments carried at fair value Atlantica $ (215,437) $ (482,774) Atlantica Yield Energy Solutions Canada Inc. (14,684) (16,018) Other 133 (333) $ (229,988) $ (499,125) Dividend and interest income from investments carried at fair value Atlantica $ 87,154 $ 86,664 Atlantica Yield Energy Solutions Canada Inc. 16,604 20,443 Other 49 36 $ 103,807 $ 107,143 Other long-term investments Equity method loss (c) $ (5,936) $ (21,416) Impairment of equity-method investee (c) — (75,910) Interest and other income 7,143 5,923 $ 1,207 $ (91,403) Fair value change, income (loss) and impairment expense related to long-term investments $ (124,974) $ (483,385) 8. Long-term investments (continued) (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 approxim ately 42% (2022 - 42%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantic a up to 48.5% . The total cost for the Atlantica shares as of December 31, 2023 is $1,167,444 (2022 - $1,167,444). The 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. (b) Investment in Atlantica Yield Energy Solutions Canada Inc. 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 . 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 of December 31, 2023, the Company's maximum exposure to loss is $61,064 (2022 - $74,083 ), 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 of $343,712 (2022 - $310,103). The Regulated Services Group has non-controlling interest of $112,180 (2022 - $56,199) 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 $501 and (2022 - $15,500) 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. 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. 8. Long-term investments (continued) (c) Equity-method investees (continued) As at December 31, 2023, the Company has issued $113,630 (2022 - $113,630) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. 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. On July 5, 2023, the Company provided a $35,000 non-interest-bearing loan to Liberty Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17,500. Further, the Company recognized an impairment loss on its note receivable of $18,911 as it no longer expects to pursue development under this joint venture arrangement and the development fees are no longer expected to be realized. The impairment is recorded within asset impairment charge in the consolidated statements of operations. Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V. 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 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: 2023 2022 Carrying value, January 1 $ 381,802 $ 433,850 Additional investments 91,205 110,441 Net loss attributable to AQN (5,936) (21,416) OCI attributable to AQN (a) 7,693 (67,110) Dividend received (4,600) (1,183) Impairment — (75,910) Other (13,771) 3,130 Carrying value, December 31 $ 456,393 $ 381,802 (a) OCI 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 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's equity method investees as of December 31 is as follows: 2023 2022 Total assets $ 3,235,474 $ 2,740,132 Total liabilities 1,962,115 1,507,079 Net assets 1,273,359 1,233,053 AQN's ownership interest in the entities 388,993 332,663 Difference between investment carrying amount and underlying equity in net assets (a) 67,400 49,139 Total carrying value $ 456,393 $ 381,802 (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. Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows: 2023 2022 Revenue $ 111,446 $ 65,025 Net loss $ (3,633) $ (31,070) OCI (a) $ 12,026 $ (130,729) Net loss attributable to AQN $ (5,936) $ (21,416) OCI attributable to AQN (a) $ 7,693 $ (67,110) (a) OCI 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, 2023, the Company has 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 of December 31, 2023 amounts to $12,666 (2022 - $8,824) . 8. Long-term investments (continued) (c) Equity-method investees (continued) Summarized combined information for AQN's VIEs as of December 31 is as follows: 2023 2022 AQN's maximum exposure in regards to VIEs Carrying amount $ 179,728 $ 122,752 Development loans receivable (d) 158,110 52,923 Indirect guarantees of debt on behalf of VIEs 740,866 436,790 Other indirect guarantees and commitments on behalf of VIEs 303,641 221,433 $ 1,382,345 $ 833,898 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 does not have significant influence over San Antonio Water System investments. It is accounted for using the cost method and as at December 31, 2023, it is recorded at the cost of $25,634 (2022 - $25,634).
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: 2023 2022 Carrying value, January 1 $ 381,802 $ 433,850 Additional investments 91,205 110,441 Net loss attributable to AQN (5,936) (21,416) OCI attributable to AQN (a) 7,693 (67,110) Dividend received (4,600) (1,183) Impairment — (75,910) Other (13,771) 3,130 Carrying value, December 31 $ 456,393 $ 381,802 (a) OCI 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: 2023 2022 Revenue $ 111,446 $ 65,025 Net loss $ (3,633) $ (31,070) OCI (a) $ 12,026 $ (130,729) Net loss attributable to AQN $ (5,936) $ (21,416) OCI attributable to AQN (a) $ 7,693 $ (67,110) (a) OCI 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 of December 31 is as follows: 2023 2022 Total assets $ 3,235,474 $ 2,740,132 Total liabilities 1,962,115 1,507,079 Net assets 1,273,359 1,233,053 AQN's ownership interest in the entities 388,993 332,663 Difference between investment carrying amount and underlying equity in net assets (a) 67,400 49,139 Total carrying value $ 456,393 $ 381,802 (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 of December 31 is as follows: 2023 2022 AQN's maximum exposure in regards to VIEs Carrying amount $ 179,728 $ 122,752 Development loans receivable (d) 158,110 52,923 Indirect guarantees of debt on behalf of VIEs 740,866 436,790 Other indirect guarantees and commitments on behalf of VIEs 303,641 221,433 $ 1,382,345 $ 833,898

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 December 31, 2022 Senior unsecured revolving credit facilities (a) — 2024-2028 N/A $ 1,624,186 $ 351,786 Senior unsecured bank credit facilities and delayed draw term facility (b) — 2024-2031 N/A 786,962 773,643 Commercial paper — 2024 N/A 481,720 407,000 U.S. dollar borrowings Senior unsecured notes (Green Equity Units) 1.18 % 2026 $ 1,150,000 1,144,897 1,142,814 Senior unsecured notes (c) 3.36 % 2024-2047 $ 1,415,000 1,406,278 1,496,101 Senior unsecured utility notes 6.30 % 2025-2035 $ 137,000 147,589 154,271 Senior secured utility bonds (d) 4.71 % 2026-2044 $ 556,199 551,166 554,822 Canadian dollar borrowings Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 904,604 882,899 Senior secured project notes 10.21 % 2027 C$ 16,848 12,738 15,024 Chilean Unidad de Fomento borrowings Senior unsecured utility bonds 3.90 % 2028-2040 CLF 1,521 70,967 77,206 $ 7,131,107 $ 5,855,566 Subordinated borrowings Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 298,382 291,238 Subordinated unsecured notes (f) 5.21 % 2079-2082 $ 1,100,000 1,086,541 1,365,213 $ 8,516,030 $ 7,512,017 Less: current portion (621,856) (423,274) $ 7,894,174 $ 7,088,743 Short-term obligations of $766,886 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 of December 31, 2023: December 31, 2023 December 31, 2022 Revolving and term credit facilities $ 4,562,000 $ 4,513,300 Funds drawn on facilities/commercial paper issued (2,892,900) (1,532,500) Letters of credit issued (469,100) (465,200) Liquidity available under the facilities 1,200,000 2,515,600 Undrawn portion of uncommitted letter of credit facilities (254,100) (226,900) Cash on hand 56,142 57,623 Total liquidity and capital reserves $ 1,002,042 $ 2,346,323 Recent financing activities: (a) Senior unsecured revolving credit facilities Corporate On March 31, 2023, the Company's senior unsecured revolving credit facility was amended and restated to increase the borrowing capacity from $500,000 to $1,000,000 with a new maturity date of March 31, 2028. On March 31, 2023, the Company entered into a new $75,000 uncommitted bi-lateral credit facility. On June 1, 2023, the Company terminated its former $50,000 uncommitted bi-lateral credit facility. Regulated Services Group On October 27, 2023, the Company extended the maturity date of the senior unsecured revolving credit facility of $500,000 from February 28, 2024 to October 25, 2024. (b) Senior unsecured bank credit facilities and delayed draw term facilities On April 25, 2023, the Regulated Services Group elected to terminate the undrawn amount of $489,600 of its $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”), which was intended to be used to partially fund the Kentucky Power Transaction. On October 27, 2023, the Company extended the maturity of the Regulated Services Delayed Draw Term Facility of $610,400 from November 29, 2023 to October 25, 2024. (c) Senior unsecured notes On March 13, 2023, the Company repaid a $15,000 senior unsecured note on its maturity. On July 31, 2023, the Company repaid a $75,000 senior unsecured note on its maturity. Subsequent to year-end, on January 12, 2024, Lib erty Utilities Co., completed an offering of $500,000 aggregate principal amount of 5.577% senior notes due January 31, 2029 (the “2029 Notes”); and $350,000 aggregate principal amount of 5.869% senior notes due January 31, 2034 (the “2034 Notes” and together with the 2029 Notes, the “Senior Notes”). The Senior Notes are unsecured and unsubordinated obligations of Lib erty Utilities Co. and rank equally with all of Lib erty Utilities Co.’s existing and future unsecured and unsubordinated indebtedness and senior in right of payment to any existing and future Lib erty Utilities Co.’s subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034 Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities Co. used the net proceeds from the sale of the Senior Notes to repay indebtedness. 9. Long-term debt (continued) (d) Senior unsecured utility bonds Subsequent to the year-end, on January 30, 2024 , Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180,500 of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125,000 aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant described in note 7 . (e) Senior unsecured utility notes On November 1, 2023, the Company repaid a $5,000 senior unsecured utility note on its maturity. (f) Subordinated unsecured notes On November 6, 2023, the Company redeemed all $287,500 of its 6.875% fixed-to-floating subordinated notes - series 2018 - at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. As of December 31, 2023, the Company has accrue d $74,493 in interest expense (2022 - $70,274 ). Interest expense for the year ended December 31 consists of the following : 2023 2022 Long-term debt $ 251,539 $ 258,084 Commercial paper, credit facility draws and related fees 134,678 46,466 Accretion of fair value adjustments (23,834) (16,547) Capitalized interest and AFUDC capitalized on regulated property (14,679) (10,802) Other 5,952 1,373 $ 353,656 $ 278,574 Principal payments due in the next five years and thereafter are as follows: 2024 2025 2026 2027 2028 Thereafter Total $ 621,856 $ 140,241 $ 1,193,531 $ 1,280,846 $ 819,122 $ 4,481,961 $ 8,537,557
Schedule of Interest Expense	Interest expense for the year ended December 31 consists of the following : 2023 2022 Long-term debt $ 251,539 $ 258,084 Commercial paper, credit facility draws and related fees 134,678 46,466 Accretion of fair value adjustments (23,834) (16,547) Capitalized interest and AFUDC capitalized on regulated property (14,679) (10,802) Other 5,952 1,373 $ 353,656 $ 278,574
Schedule of Maturities of Long-term Debt	Principal payments due in the next five years and thereafter are as follows: 2024 2025 2026 2027 2028 Thereafter Total $ 621,856 $ 140,241 $ 1,193,531 $ 1,280,846 $ 819,122 $ 4,481,961 $ 8,537,557

Pension and other post-employ_2

Pension and other post-employment benefits (Tables)	12 Months Ended
	Dec. 31, 2023
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 2023 2022 2023 2022 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 628,135 $ 765,618 $ 217,330 $ 292,646 Projected benefit obligation assumed from business combination — 87,933 — 5,195 Plan settlements (3,226) (112) — — Service cost 11,954 16,309 3,253 6,277 Interest cost 33,687 24,787 11,510 9,146 Actuarial loss (gain) 20,172 (198,074) (10,913) (82,991) Contributions from retirees — — 2,189 2,220 Plan amendments — — — (2,452) Medicare Part D — — 355 367 Benefits paid (42,801) (68,197) (14,226) (13,078) Foreign exchange (53) (129) — — Projected benefit obligation, end of year $ 647,868 $ 628,135 $ 209,498 $ 217,330 Change in plan assets Fair value of plan assets, beginning of year 569,255 648,864 172,167 192,375 Plan assets acquired in business combination — 74,532 — 8,577 Actual return on plan assets 65,272 (109,118) 22,620 (30,105) Employer contributions 22,326 23,296 10,677 11,811 Plan settlements (3,226) (112) — — Contributions from retirees — — 2,189 2,220 Medicare Part D subsidy receipts — — 355 367 Benefits paid (42,801) (68,197) (14,226) (13,078) Foreign exchange 2 (10) — — Fair value of plan assets, end of year $ 610,828 $ 569,255 $ 193,782 $ 172,167 Unfunded status $ (37,040) $ (58,880) $ (15,716) $ (45,163) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) 12,598 12,264 35,879 14,218 Current liabilities (1,416) (1,907) (3,164) (3,039) Non-current liabilities (48,222) (69,237) (48,431) (56,342) Net amount recognized $ (37,040) $ (58,880) $ (15,716) $ (45,163) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2023 2022 2023 2022 Accumulated benefit obligation $ 425,842 $ 413,041 $ 71,089 $ 198,463 Fair value of plan assets $ 393,857 $ 364,229 $ 18,793 $ 139,368 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2023 2022 2023 2022 Projected benefit obligation $ 507,612 $ 489,140 $ 71,089 $ 198,463 Fair value of plan assets $ 458,497 $ 417,994 $ 18,793 $ 139,368
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 losses (gains) Actuarial losses (gains) Past service losses (gains) Balance, January 1, 2022 $ 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) Additions to AOCI (12,600) — (23,797) 853 Amortization in current period 617 1,491 2,554 — Recognition of settlement gain 235 — — — Reclassification to regulatory accounts 5,517 (755) 19,518 — Balance, December 31, 2023 $ (6,902) $ (2,627) $ (35,275) $ (1,337)
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2023 and 2022 were as follows: Pension benefits OPEB 2023 2022 2023 2022 Discount rate 5.19 % 5.48 % 5.22 % 5.49 % Interest crediting rate (for cash balance plans) 4.48 % 4.50 % N/A N/A Rate of compensation increase 3.60 % 3.70 % N/A N/A Health care cost trend rate Before age 65 7.00 % 6.00 % Age 65 and after 6.00 % 6.00 % Assumed ultimate medical inflation rate 4.50 % 4.75 % Year in which ultimate rate is reached 2034 2033
Schedule of Weighted Average Assumptions Used to Determine Net Benefit Cost	Weighted average assumptions used to determine net benefit cost for 2023 and 2022 were as follows: Pension benefits OPEB 2023 2022 2023 2022 Discount rate 5.35 % 2.94 % 5.49 % 3.00 % Expected return on assets 6.38 % 6.19 % 6.45 % 6.48 % Rate of compensation increase 3.99 % 3.91 % 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
Summary of 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 Pension and other post-employment non-service costs 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 2023 2022 2023 2022 Service cost $ 11,954 $ 16,309 $ 3,253 $ 6,277 Non-service costs Interest cost 33,687 24,787 11,510 9,146 Expected return on plan assets (31,990) (41,226) (9,736) (11,359) Amortization of net actuarial loss (852) 3,452 (3,559) (56) Amortization of prior service credits (1,491) (1,584) (853) 24 Amortization due to plan settlements — (15) — — Amortization of regulatory accounts 16,258 22,952 6,965 4,829 $ 15,612 $ 8,366 $ 4,327 $ 2,584 Net benefit cost $ 27,566 $ 24,675 $ 7,580 $ 8,861
Schedule of Target Asset Allocation	The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 41.6 % 30% - 100% Debt securities 48.6 % 20% - 60% Other 9.8 % 0% - 20% 100 % The fair values of investments as of December 31, 2023, by asset category, are as follows: Asset class 2023 Percentage Equity securities $ 376,158 47 % Debt securities 377,272 47 % Other 51,180 6 % $ 804,610 100 %
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, 2023 $ 21,904 Contributions into funds 4,603 Return on assets 2,205 Distributions (2,331) Balance, December 31, 2023 $ 26,381
Schedule of Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2024 2025 2026 2027 2028 2029-2033 Pension plan $ 48,271 $ 49,652 $ 49,389 $ 50,443 $ 50,751 $ 255,465 OPEB $ 11,718 $ 12,303 $ 12,623 $ 13,105 $ 13,487 $ 71,230

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2023
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of Other Assets	Other assets consist of the following: 2023 2022 Restricted cash $ 19,997 $ 43,562 Pension and OPEB plan assets (note 10(a)) 48,477 26,482 Long-term deposits and cash collateral 19,336 22,537 Income taxes recoverable 9,988 7,100 Deferred financing costs (a) 27,176 28,586 Insurance recoveries (note 22(a)) 66,000 — Other (b) 31,080 21,596 $ 222,054 $ 149,863 Less: current portion (23,061) (22,564) $ 198,993 $ 127,299 (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 that will be recorded against the common shares when issued. 11. Other assets (continued) (b) Other

Other long-term liabilities (Ta

Other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Schedule Of Other Long Term Liabilities	Other long-term liabilities consist of the following: 2023 2022 Contract adjustment payments (a) $ 39,590 $ 113,876 Asset retirement obligations (b) 115,611 116,584 Advances in aid of construction (c) 88,135 88,546 Environmental remediation obligation (d) 40,772 42,457 Customer deposits (e) 36,294 34,675 Unamortized investment tax credits (f) 17,255 17,649 Deferred credits and contingent consideration (g) 40,945 39,498 Preferred shares, Series C (h) — 12,072 Hook-up fees (i) 7,425 32,463 Lease liabilities 20,493 21,834 Contingent development support obligations (j) 12,666 8,824 Note payable to related party (k) 25,808 25,808 Contingent liability (note 22(a)) 66,000 — Other 35,338 41,156 $ 546,332 $ 595,442 Less: current portion (80,458) (134,212) $ 465,874 $ 461,230 (a) Contract adjustment payment In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The 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. 12. Other long-term liabilities (continued) (b) Asset retirement obligations (continued) Changes in the asset retirement obligations are as follows: 2023 2022 Opening balance $ 116,584 $ 142,147 Obligation assumed 1,077 793 Retirement activities (6,902) (27,980) Accretion 4,440 4,589 Change in cash flow estimates 412 (2,965) Closing balance $ 115,611 $ 116,584 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 2023, $238 (2022 - $1,299) 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 $46,187 (2022 - $48,346), which at discount rates ranging from 3.4% to 4.3% represents the recorded accrual of $40,772 as of December 31, 2023 (2022 - $42,457). Approximately $25,713 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 27 years. Changes in the environmental remediation obligation are as follows: 2023 2022 Opening balance $ 42,457 $ 55,224 Remediation activities (3,687) (5,243) Accretion 1,616 2,167 Changes in cash flow estimates 1,395 1,344 Revision in assumptions (1,009) (11,035) Closing balance $ 40,772 $ 42,457 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 seven years and, accordingly, as of December 31, 2023, the Company has reflected a regulatory asset o f $66,779 (2022 - $70,529) for the MGP and re lated sites (note 7(g)) . 12. Other long-term liabilities (continued) (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. (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. (h) Preferred shares, Series C During the year ended December 31, 2023, 100 Series C preferred shares of AQN that had previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP, were redeemed for $14,515, and a loss on settlement of $2,377 was recorded in other net losses (note 19(f)) in the consolidated statements of operations. As a result of the redemption, no Series C preferred shares of AQN remain outstanding. (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)). (k) Note payable to related party 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. 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, 2023
Equity [Abstract]
Schedule of Number of Common Shares	Number of common shares 2023 2022 Common shares, beginning of year 683,614,803 671,960,276 Public offering — 2,861,709 Dividend reinvestment plan 4,370,289 7,676,666 Exercise of share-based awards (c) 1,284,532 1,115,398 Conversion of convertible debentures 1,415 754 Common shares, end of year 689,271,039 683,614,803 13. Shareholders’ capital (continued) (a) Common shares (continued) 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) At-the-market equity program On August 15, 2022, AQN re-established its at-the-market equity program (“ATM Program”) that allowed 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, 2023, the Company did not issue any common shares under its ATM Program. The ATM Program terminated in accordance with its terms on December 19, 2023. The Company has issued, since the inception of its initial 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 $4,843. (ii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the dividend reinvestment plan began receiving cash dividends. If the Company elects to reinstate the dividend reinvestment plan in the future, shareholders who were enrolled in the dividend reinvestment plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the dividend reinvestment plan. (b) Preferred shares
Schedule of Shares Issued and Outstanding	The Company has the following Cumulative Rate Reset Preferred Shares, Series A (the “Series A Shares”) and Cumulative Rate Reset Preferred Shares, Series D (the “Series D Shares”) issued and outstanding as of December 31, 2023 and 2022: Number of shares Price per share Carrying amount C$ Carrying amount $ Series A Shares 4,800,000 C$25.00 C$ 116,546 $ 100,463 Series D Shares 4,000,000 C$25.00 C$ 97,259 $ 83,836 $ 184,299
Schedule of Share-based Compensation Expense	For the year ended December 31, 2023, AQN recorded $11,293 (2022 - $10,920) in total share-based compensation expense as follows: 2023 2022 Share options $ 1,325 $ 980 Director deferred share units 949 960 Employee share purchase 897 562 Performance and restricted share units 8,122 8,418 Total share-based compensation $ 11,293 $ 10,920
Schedule of Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2023 2022 Risk-free interest rate 3.4 % 1.9 % Expected volatility 27 % 23 % Expected dividend yield 8.6 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option $ 1.04 $ 2.44
Schedule of Stock Option Activity	Share option activity during the years is as follows: Number of Weighted Weighted Aggregate Balance, January 1, 2022 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$ — Granted 1,368,744 10.76 7.24 — Exercised — — — — Forfeited (1,327,799) 16.55 — — Balance, December 31, 2023 2,667,725 C$ 14.71 5.18 C$ — Exercisable, December 31, 2023 2,621,420 C$ 17.11 4.50 C$ —
Schedule of Performance Stock Units	A summary of the PSUs and RSUs follows: Number of awards Weighted Weighted Aggregate Balance, January 1, 2022 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 Granted, including dividends 2,841,967 10.98 2.02 25,329 Exercised (922,883) 18.73 — 10,125 Forfeited (451,047) 15.07 — 3,771 Balance, December 31, 2023 3,577,747 C$ 18.38 1.76 C$ 29,910 Exercisable, December 31, 2023 597,363 C$ 19.98 0.22 C$ 4,994

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2022 $ (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) Other comprehensive income (loss) (3,788) 57,351 8,395 61,958 Amounts reclassified from AOCI to the consolidated statement of operations (1,598) 2,136 (3,702) (3,164) Net current period OCI $ (5,386) $ 59,487 $ 4,693 $ 58,794 OCI attributable to the non-controlling interests (1,017) — — (1,017) Net current period OCI attributable to shareholders of AQN $ (6,403) $ 59,487 $ 4,693 $ 57,777 Balance, December 31, 2023 $ (104,870) $ (38,322) $ 40,906 $ (102,286)

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2023
Disclosure Cash Dividends [Abstract]
Schedule of Dividends	Dividends declared were as follows: 2023 2022 Dividend Dividend per share Dividend Dividend per share Common shares $ 301,771 $ 0.4340 $ 486,043 $ 0.7130 Series A Shares C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905 Series D Shares 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, 2023
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: 2023 2022 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ 114,141 $ 108,695 Non-controlling interests - redeemable tax equity partnership units 1,324 6,298 Other net earnings attributable to: Non-controlling interests (27,564) (3,670) $ 87,901 $ 111,323 Redeemable non-controlling interest, held by related party (25,922) (15,157) Net effect of non-controlling interests $ 61,979 $ 96,166 Non-controlling interests - tax equity partnership units (a) Other non-controlling interests (b) Non-controlling interests held by related parties (c) 2023 2022 2023 2022 2023 2022 Opening balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158 Net earnings (loss) attributable to NCI (114,141) (108,695) 27,564 3,670 — — Contributions received, net 107,933 6,182 — 267,515 — — Dividends and distributions declared (22,743) (36,736) (14,497) (3,350) (17,082) (20,978) Repurchase of non-controlling interest — (12,249) — — — — OCI 63 (11) 909 720 45 (2,358) Closing balance $ 1,196,720 $ 1,225,608 $ 347,338 $ 333,362 $ 40,785 $ 57,822 (a) Non-controlling interests - tax equity partnership units The Company obtained control of the Deerfield II Wind Facility during the year (note 3). Post-acquisition, third-party tax equity investors funded $98,955 in exchange for Class A partnership units in the entity. In addition, the Company received $9,084 (2022 - $6,182) of production based cash contributions during the year relating to other projects. (b) Other non-controlling interests On December 29, 2022, the Company s old 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. (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. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2023 2022 2023 2022 Opening balance $ 307,856 $ 306,537 $ 11,520 $ 12,989 Net earnings (loss) attributable to NCI 25,922 15,157 (1,324) (6,298) Contributions, net of costs — — — 5,000 Dividends and distributions declared (25,428) (13,838) (183) (171) Closing balance $ 308,350 $ 307,856 $ 10,013 $ 11,520

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The differences are as follows: 2023 2022 Expected income tax recovery at Canadian statutory rate $ (31,696) $ (97,962) Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (46,628) (55,315) Adjustments from investments carried at fair value 16,128 51,314 Non-controlling interests share of income 24,677 30,025 Change in valuation allowance 10,786 41,702 Acquisition related state deferred tax adjustments — 5,998 Capital gain rate differential on disposal of renewable assets — (7,340) Tax credits (54,788) (18,440) Amortization and settlement of excess deferred income tax (12,785) (14,855) Deferred income taxes on regulated income recorded as regulatory assets (878) (1,986) Other permanent differences 5,341 4,591 Other 3,543 755 Income tax recovery $ (86,300) $ (61,513)
Schedule of Income (Loss) Before Taxes	For the years ended December 31, 2023 and 2022, earnings (loss) before income taxes consist of the following: 2023 2022 Canada (1) $ (259,141) $ (363,050) U.S. 102,469 (37,322) Other regions 37,067 30,704 $ (119,605) $ (369,668) (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, 2023 Canada $ 4,352 $ (59,488) $ (55,136) United States (14,820) (23,099) (37,919) Other regions 728 6,027 6,755 $ (9,740) $ (76,560) $ (86,300) 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)
Schedule of Tax Effect of Temporary Difference Between Assets and Liability	The tax effect of temporary differences between the consolidated 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, 2023 and 2022 are presented below: 2023 2022 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 1,030,801 $ 878,000 Pension and OPEB 7,370 16,845 Environmental obligation 11,692 12,118 Regulatory liabilities 180,371 156,285 Other 72,109 61,917 Total deferred income tax assets $ 1,302,343 $ 1,125,165 Less: valuation allowance (97,344) (107,583) Total deferred tax assets $ 1,204,999 $ 1,017,582 Deferred tax liabilities: Property, plant and equipment $ 883,447 $ 846,331 Outside basis differentials 364,511 315,581 Regulatory accounts 317,820 303,059 Other 59,640 33,834 Total deferred tax liabilities $ 1,625,418 $ 1,498,805 Net deferred tax liabilities $ (420,419) $ (481,223) Consolidated balance sheets classification: Deferred tax assets $ 158,483 $ 84,416 Deferred tax liabilities (578,902) (565,639) Net deferred tax liabilities $ (420,419) $ (481,223)
Summary of Valuation Allowance	The following table illustrates the annual movement in the deferred tax valuation allowance: 2023 2022 Beginning balance $ 107,583 $ 27,471 Charged to income tax expense 10,786 41,702 Charged (reduction) to OCI (16,696) 40,613 Reductions to other accounts (4,329) (2,203) Ending balance $ 97,344 $ 107,583
Schedule of Non Capital Losses Carry Forwards	As of December 31, 2023, 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 2024—2028 2029+ Total Canada $ 3,339 $ 913,781 $ 917,120 US 8,441 1,897,609 1,906,050 Total non-capital loss carryforward $ 11,780 $ 2,811,390 $ 2,823,170 Tax credits $ 3,359 $ 200,772 $ 204,131

Other net losses (Tables)

Other net losses (Tables)	12 Months Ended
	Dec. 31, 2023
Other Income and Expenses [Abstract]
Schedule of Other Net Losses (Gains)	Other net losses consist of the following: 2023 2022 Acquisition and transition-related costs $ — $ 6,834 Kentucky termination costs (a) 46,527 10,608 Acquisition-related settlement payment (b) (11,983) — Securitization write-off (c) 63,495 — Renewable energy business sale costs (d) 12,506 — Loss on redemption of long-term note (e) 8,532 — Other (f) 13,812 3,949 $ 132,889 $ 21,391 (a) Kentucky termination costs The loss related to the termination of the Kentucky Power Transaction includes $38,795 for the write-off of capitalized costs, which are primarily related to the implementation of an enterprise software solution. The remaining amount relates to the transaction costs, severance costs and other termination costs. In 2022, the Company incurred $10,608 in anticipation of the Kentucky Power Transaction. (b) Acquisition-related settlement payment During the year, the Company received $12,814 as an acquisition-related settlement payment in connection with the Suralis acquisition. The Company also incurred legal fees of $831 in relation to this settlement. 19. Other net losses (continued) (c) Securitization write-off During the year, the Company has written off $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute (note 7(a)). (d) Renewable energy business sale costs The Company announced that it is pursuing a sale of its renewable energy business. The Company incurred costs of $12,506 related to this process in 2023. (e) Loss on redemption of long-term note During Q4, 2023, the Company redeemed subordinated unsecured long-term note (note 9(f)) and incurred loss on redemption of $8,532. (f) Other Other losses for the year consist primarily of provisions on litigation matters, executive severance costs, the Series C preferred share redemption loss and other miscellaneous write-offs.

Basic and diluted net earning_2

Basic and diluted net earnings (loss) per share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share, Basic and Diluted EPS [Abstract]
Schedule of Reconciliation of Net Earnings (Loss) and Weighted Average Shares Used in Computation of Basic and Diluted Earnings (Loss) per Share	The reconciliation of the net earnings (loss) and the weighted average shares used in the computation of basic and diluted earnings (loss) per share are as follows: 2023 2022 Net earnings (loss) attributable to shareholders of AQN $ 28,674 $ (211,989) Preferred shares, Series A dividend 4,586 4,786 Preferred shares, Series D dividend 3,770 3,934 Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ 20,318 $ (220,709) Weighted average number of shares Basic 688,738,717 677,862,207 Effect of dilutive securities 2,024,509 — Diluted 690,763,226 677,862,207

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Results of Operations and Assets for Segments	Year ended December 31, 2023 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,315,722 $ 296,314 $ — $ 2,612,036 Other revenue 51,137 33,395 1,447 85,979 Fuel, power and water purchased 716,446 19,499 — 735,945 Net revenue 1,650,413 310,210 1,447 1,962,070 Operating expenses 786,608 119,013 1,364 906,985 Administrative expenses 46,386 36,554 7,419 90,359 Depreciation and amortization 346,188 119,576 1,232 466,996 Asset impairment charge — 23,492 — 23,492 Loss on foreign exchange — — 8,359 8,359 Operating income (loss) 471,231 11,575 (16,927) 465,879 Interest expense (160,998) (61,261) (131,397) (353,656) Income (loss) from long-term investments 44,953 102,188 (230,705) (83,564) Other expenses (121,146) (4,002) (23,116) (148,264) Earnings (loss) before income taxes $ 234,040 $ 48,500 $ (402,145) $ (119,605) Property, plant and equipment $ 8,945,637 $ 3,539,069 $ 32,744 $ 12,517,450 Investments carried at fair value 1,962 1,113,767 — 1,115,729 Equity-method investees 112,180 343,712 501 456,393 Total assets 12,658,955 5,367,011 347,995 18,373,961 Capital expenditures $ 816,788 $ 209,383 $ — $ 1,026,171 (1) Renewable Energy Group revenue includes $5,695 related to net hedging gain from energy derivative contracts and availability credits for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $32,839 related to alternative revenue programs for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2022 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 2,330,039 $ 350,797 $ — $ 2,680,836 Other revenue 54,229 28,447 1,501 84,177 Fuel and power purchased 824,670 41,684 — 866,354 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 charge — 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 expenses (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 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.
Schedule of Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2023 2022 Revenue United States $ 2,169,239 $ 2,232,817 Canada 162,740 175,005 Other regions 366,036 357,191 $ 2,698,015 $ 2,765,013 Property, plant and equipment United States $ 10,826,738 $ 10,351,736 Canada 924,389 848,560 Other regions 766,323 744,589 $ 12,517,450 $ 11,944,885 Intangible assets United States $ 18,666 $ 18,818 Canada 18,111 19,038 Other regions 57,161 58,827 $ 93,938 $ 96,683

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
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 (1) $ 55,312 $ 33,869 $ 12,274 $ 12,520 $ 12,768 $ 129,818 $ 256,561 Natural gas supply and service agreements (2) 121,188 71,949 42,643 33,215 30,803 154,757 454,555 Service agreements 73,687 61,889 56,591 53,140 52,898 259,510 557,715 Capital projects 5,598 — — — — — 5,598 Land easements and other 16,437 15,057 15,269 15,425 15,639 536,129 613,956 Total $ 272,222 $ 182,764 $ 126,777 $ 114,300 $ 112,108 $ 1,080,214 $ 1,888,385 (1) 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, 2023. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (2) 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, 2023
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: 2023 2022 Accounts receivable $ 3,863 $ (124,631) Fuel and natural gas in storage 46,368 (21,140) Supplies and consumables inventory (48,539) (24,088) Income taxes recoverable (2,889) 549 Prepaid expenses (13,218) (4,269) Accounts payable 23,847 24,395 Accrued liabilities (488) 127,076 Current income tax liability 1,096 (2,741) Asset retirements and environmental obligations (1,015) (22,342) Net regulatory assets and liabilities (95,361) (174,427) $ (86,336) $ (221,618)

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Financial Instruments	Fair value of financial instruments December 31, 2023 Carrying Fair Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,115,729 $ 1,115,729 $ 1,054,665 $ — $ 61,064 Development loans and other receivables 158,110 155,735 — 155,735 — Derivative instruments: Interest rate swap designated as a hedge 72,936 72,936 — 72,936 — Interest rate cap not designated as a hedge 1,854 1,854 — 1,854 — Congestion revenue rights not designated as a cash flow hedge 8,458 8,458 — — 8,458 Total derivative instruments 83,248 83,248 — 74,790 8,458 Total financial assets $ 1,357,087 $ 1,354,712 $ 1,054,665 $ 230,525 $ 69,522 Long-term debt $ 8,516,030 $ 7,423,318 $ 2,532,608 $ 4,890,710 $ — Notes payable to related party 25,808 15,320 — 15,320 — Convertible debentures 230 276 276 — — Derivative instruments: Energy contracts designated as a cash flow hedge 68,070 68,070 — — 68,070 Energy contracts not designated as a cash flow hedge 5,593 5,593 — — 5,593 Cross-currency swap designated as a net investment hedge 10,533 10,533 — 10,533 — Currency forward contract designated as hedge 6,779 6,779 — 6,779 — Interest rate swaps designated as a hedge 11,790 11,790 — 11,790 — Cross currency swap designated as a cash flow hedge 5,547 5,547 — 5,547 — Commodity contracts for regulated operations 2,564 2,564 — 2,564 — Total derivative instruments 110,876 110,876 — 37,213 73,663 Total financial liabilities $ 8,652,944 $ 7,549,790 $ 2,532,884 $ 4,943,243 $ 73,663 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) December 31, 2022 Carrying Fair Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 1,344,207 $ 1,344,221 $ 1,270,138 $ — $ 74,083 Development loans and other receivables 53,680 50,300 — 50,300 — Derivative instruments: Energy contracts not designated as a cash flow hedge 393 393 — — 393 Interest rate swap designated as a hedge 69,188 69,188 — 69,188 — Currency forward contract 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 $ 1,478,421 $ 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
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. Notional quantity Expiry Receive average Pay floating price 353,597 December 2028 $29.19 PJM Western HUB 1,492,926 December 2027 $21.34 NI HUB 1,332,645 December 2027 $36.46 ERCOT North HUB 3,534,802 September 2030 $24.54 Illinois Hub
Schedule of Derivative Instruments Designated as Amortized into Hedged Activity Disclosure	Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt. Derivative Notional quantity Expiry Hedged item Forward-starting interest rate swap $ 350,000 July 2029 $350,000 subordinated unsecured notes Cross-currency interest rate swap C$ 400,000 January 2032 C$400,000 subordinated unsecured notes Forward-starting interest rate swap $ 750,000 April 2032 $750,000 subordinated unsecured notes Forward-starting interest rate swap $ 575,000 June 2026 First $575,000 of the expected $1,150,000 senior unsecured notes issuance
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: 2023 2022 Effective portion of cash flow hedge $ 57,351 $ (128,838) Amortization of cash flow hedge (6,173) (12,180) Amounts reclassified from AOCI 8,309 46,723 OCI attributable to shareholders of AQN $ 59,487 $ (94,295)
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: 2023 2022 Unrealized gain (loss) on derivative financial instruments: Energy derivative contracts $ (372) $ (945) Commodity contracts 411 185 Total unrealized gain (loss) on derivative financial instruments $ 39 $ (760) Realized gain (loss) on derivative financial instruments: Energy derivative contracts $ (4,896) $ 6,939 Interest rate swaps — (7,185) Total realized loss on derivative financial instruments $ (4,896) $ (246) Loss on derivative financial instruments not accounted for as hedges (4,857) (1,006) Amortization of AOCI gains frozen as a result of hedge dedesignation 3,989 3,465 $ (868) $ 2,459 Consolidated statements of operations classification: Gain on derivative financial instruments $ 4,564 $ 4,408 Renewable energy sales (5,432) 5,236 Reduction to gain on sale of renewable assets — (7,185) $ (868) $ 2,459
Schedule of Outstanding Obligations	The roll forwards of the Company's outstanding obligations confirmed as valid under its supplier finance programs for years ended December 31, 2023 and 2022, are as follows: 2023 2022 Confirmed obligations outstanding at the beginning of the year $ 16,785 $ 49,910 Invoices confirmed during the year 90,780 16,785 Confirmed invoices paid during the year (45,392) (49,910) Confirmed obligations outstanding at the end of the year $ 62,173 $ 16,785
Schedule of Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2023, the Company’s maximum exposure to credit risk for these financial instruments is as follows: 2023 Cash and cash equivalents and restricted cash $ 76,145 Accounts receivable 554,438 Allowance for doubtful accounts (30,244) Notes receivable 158,836 $ 759,175
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 $ 621,856 $ 1,333,772 $ 2,099,968 $ 4,481,961 $ 8,537,557 Interest on long-term debt 391,493 602,761 419,950 3,496,032 4,910,236 Purchase obligations 767,287 — — — 767,287 Environmental obligation 3,136 22,577 1,820 18,654 46,187 Advances in aid of construction 3,640 — — 84,495 88,135 Derivative financial instruments: Cross-currency swap 2,419 4,243 144 9,623 16,429 Interest rate forwards 11,790 — — — 11,790 Energy derivative and commodity contracts 14,276 29,273 20,550 12,127 76,226 Contract adjustment payments on Green Equity Units 39,590 — — — 39,590 Other obligations 27,796 2,901 2,304 247,480 280,481 Total obligations $ 1,883,283 $ 1,995,527 $ 2,544,736 $ 8,350,372 $ 14,773,918

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 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	12 Months Ended
	Dec. 31, 2023 USD ($) facility	Dec. 31, 2022 USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities | facility	3
Cost of plant in service	$ 552,701	$ 559,630
Accumulated depreciation related to commonly owned facilities	83,283	75,820
Expenditures	$ 72,584	110,268
Number of power generating facilities | facility	2
Generating assets of Long Sault	$ 18,373,961	17,627,613
Non-regulated energy sales	2,698,015	2,765,013
Interest expense on long-term debt and others	353,656	278,574
Non-Regulated Energy
Significant Accounting Policies [Line Items]
Non-regulated energy sales	296,314	350,797
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	57,740	57,241
Long-term debt of Long Sault	12,738	15,024
Operating expenses and amortization	5,986	5,834
Interest expense on long-term debt and others	1,384	1,723
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	$ 17,317	$ 19,752
Minimum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities	7.52%
Lease renewal term	1 year
Maximum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities	60%
Lease renewal term	5 years
Power sales contracts | Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	6 years
Power sales contracts | Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	25 years
Interconnection agreements
Significant Accounting Policies [Line Items]
Intangible asset, useful life	40 years
Customer relationships | Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	25 years
Customer relationships | Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life	40 years

Significant accounting polici_5

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	Dec. 31, 2023	Dec. 31, 2022
Generation | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years	3 years
Generation | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	60 years	60 years
Generation | Weighted average useful lives
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	33 years	33 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	1 year	1 year
Distribution | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	100 years	100 years
Distribution | Weighted average useful lives
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	40 years	39 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	54 years
Equipment | Weighted average useful lives
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	15 years	11 years

Business acquisitions, develo_3

Business acquisitions, development projects and disposition transactions - Additional Information (Detail) $ in Thousands, $ in Thousands					12 Months Ended
	Feb. 15, 2024 USD ($)	Jun. 15, 2023 USD ($)	Dec. 29, 2022 USD ($) wind_project MWac	Jan. 01, 2022 USD ($) country	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2020 MWac	Dec. 29, 2022 CAD ($)
Business Acquisition [Line Items]
Other net losses					$ 132,889	$ 21,391
Gain on sale of renewable assets					0	64,028
Operating Wind Facilities in the United States
Business Acquisition [Line Items]
Equity interest (percent)			49%					49%
Number of ownership interests in wind facilities | wind_project			3
Wind power capacity (megawatt AC) | MWac			551				551
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 Company and AEP Kentucky Transmission Company, Inc.
Business Acquisition [Line Items]
Other net losses					$ 46,527
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
Algonquin Power Fund (America) Inc | Deerfield II
Business Acquisition [Line Items]
Debt repaid upon maturity		$ 158,550
Ownership interest acquired (percent)		50%
Total purchase price		$ 23,142
Tax equity funding		$ 98,955
Algonquin Power Fund (America) Inc | Sandy Ridge II Wind Facility | Subsequent Event
Business Acquisition [Line Items]
Debt repaid upon maturity	$ 162,805
Ownership interest acquired (percent)	50%
Total purchase price	$ 8,456
Tax equity funding	$ 60,545

Business acquisitions, develo_4

Business acquisitions, development projects and disposition transactions - Schedule of Preliminary Allocation Of The Acquisition Prices Of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Jun. 15, 2023	Dec. 31, 2022	Jan. 01, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Goodwill (note 6)	$ 1,324,062		$ 1,320,579		$ 1,201,244
Deerfield II
Business Acquisition [Line Items]
Working capital		$ (10,709)
Property, plant and equipment		194,419
Long-term debt		(157,935)
Asset retirement obligation		(1,030)
Deferred tax liability		(1,603)
Total net assets acquired		23,142
Cash and cash equivalents		1,662
Net assets acquired, net of cash and cash equivalents		$ 21,480
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

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 30,244	$ 24,857
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 107,001	$ 149,015

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Cost	$ 14,900,781	$ 14,003,548
Accumulated depreciation	2,383,331	2,058,663
Net book value	12,517,450	11,944,885
Land
Property, Plant and Equipment [Line Items]
Cost	133,483	113,153
Accumulated depreciation	0	0
Net book value	133,483	113,153
Equipment
Property, Plant and Equipment [Line Items]
Cost	122,929	111,707
Accumulated depreciation	53,181	50,904
Net book value	69,748	60,803
Generation
Property, Plant and Equipment [Line Items]
Cost	4,200,559	4,119,514
Accumulated depreciation	1,139,137	1,016,784
Net book value	3,061,422	3,102,730
Generation | Construction-in-progress
Property, Plant and Equipment [Line Items]
Cost	378,043	196,287
Accumulated depreciation	0	0
Net book value	378,043	196,287
Utility plant
Property, Plant and Equipment [Line Items]
Cost	9,332,092	8,640,224
Accumulated depreciation	1,191,013	990,975
Net book value	8,141,079	7,649,249
Distribution and transmission | Construction-in-progress
Property, Plant and Equipment [Line Items]
Cost	733,675	822,663
Accumulated depreciation	0	0
Net book value	$ 733,675	$ 822,663

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Property, Plant, and Equipment Disclosure [Line Items]
U.S. Tax reform	$ 159,568
Contribution received		$ 238	$ 1,299
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	111,192	117,556	111,192
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	46,666	52,506	46,666
Depreciation expense		537	1,489
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,270	3,076
Accumulated depreciation	2,041	2,455	2,041
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	1,922,844	2,033,391
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	133,644	$ 141,466	$ 133,644
Maximum
Property, Plant, and Equipment Disclosure [Line Items]
U.S. Tax reform	259,942
Minimum
Property, Plant, and Equipment Disclosure [Line Items]
U.S. Tax reform	$ 100,374

Property, plant and equipment_3

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Schedule of Capitalization [Line Items]
Total	$ 18,051	$ 12,703
Allowance for borrowed funds
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	8,305	6,040
Allowance for equity funds
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	3,372	1,901
Interest capitalized on non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	$ 6,374	$ 4,762

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Cost	$ 155,985	$ 155,212
Accumulated amortization	62,047	58,529
Net book value	93,938	96,683
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	58,200	56,926
Accumulated amortization	43,938	42,818
Net book value	14,262	14,108
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	77,104	77,850
Accumulated amortization	14,625	13,709
Net book value	62,479	64,141
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	10,329	10,098
Accumulated amortization	1,977	1,851
Net book value	8,352	8,247
Other
Finite-Lived Intangible Assets [Line Items]
Cost	10,352	10,338
Accumulated amortization	1,507	151
Net book value	$ 8,845	$ 10,187

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 2,674
Estimated amortization expense for intangibles in year 2	2,674
Estimated amortization expense for intangibles in year 3	2,674
Estimated amortization expense for intangibles in year 4	2,674
Estimated amortization expense for intangibles in year 5	$ 2,674

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 1,320,579	$ 1,201,244
Business acquisitions	4,195	123,751
Foreign exchange	(712)	(4,416)
Goodwill end of the period	$ 1,324,062	$ 1,320,579

Regulatory Matters - Regulatory

Regulatory Matters - Regulatory Proceedings (Details) - USD ($) $ in Thousands							1 Months Ended		3 Months Ended
	Dec. 07, 2023	Sep. 21, 2023	Aug. 01, 2023	Jun. 22, 2023	Apr. 27, 2023	Feb. 03, 2023	Aug. 24, 2023	Feb. 28, 2021	Sep. 30, 2023
Apple Valley Water System
Regulatory Liabilities [Line Items]
Approved revenue increase						$ 1,494
Park Water System
Regulatory Liabilities [Line Items]
Approved revenue increase						$ 1,105
CalPeco Electric System
Regulatory Liabilities [Line Items]
Approved revenue increase					$ 26,979
St. Lawrence Gas
Regulatory Liabilities [Line Items]
Approved revenue increase				$ 5,249
Pine Bluff Water
Regulatory Liabilities [Line Items]
Approved revenue increase							$ 3,400
Gas New Brunswick
Regulatory Liabilities [Line Items]
Approved revenue increase		$ 700
Empire Electric
Regulatory Liabilities [Line Items]
Approved revenue increase	$ 5,300
Securitization of qualified extraordinary costs affirmed			$ 290,383
Public utilities, incurred cost one-time net gain (loss)								$ 63,495	$ 48,452

Regulatory matters - Regulato_2

Regulatory matters - Regulatory Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 1,327,683	$ 1,271,501
Less: current regulatory assets	(142,970)	(190,393)
Non-current regulatory assets	1,184,713	1,081,108
Total regulatory liabilities	734,296	628,182
Less: current regulatory liabilities	(99,850)	(69,865)
Non-current regulatory liabilities	634,446	558,317
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities	290,121	312,671
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	185,786	191,173
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	104,636	68,085
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	42,850	24,991
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12,730	11,572
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2,078	343
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	96,095	19,347
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Total regulatory assets	326,418	388,294
Retired generating plant
Regulatory Liabilities [Line Items]
Total regulatory assets	183,732	174,609
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets	192,880	136,198
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory assets	101,939	97,414
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Total regulatory assets	124,517	90,121
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets	68,822	80,736
Environmental costs
Regulatory Liabilities [Line Items]
Total regulatory assets	66,779	70,529
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Total regulatory assets	64,146	66,156
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets	37,214	28,145
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets	26,620	27,172
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets	18,995	24,888
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory assets	11,084	11,084
Rate review costs
Regulatory Liabilities [Line Items]
Total regulatory assets	8,815	9,481
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets	4,932	6,504
Other
Regulatory Liabilities [Line Items]
Total regulatory assets	$ 90,790	$ 60,170

Regulatory Matters - Narrative

Regulatory Matters - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Regulated Operations [Abstract]
Other income (note 7)	$ 41,410	$ 18,179

Regulatory Matters - Regulato_3

Regulatory Matters - Regulatory Assets and Liabilities - Footnote (Details) $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
	Aug. 01, 2023 USD ($)	Feb. 28, 2021 USD ($)	Sep. 30, 2023 USD ($)	Dec. 31, 2023 USD ($)	Jan. 30, 2024 USD ($)	Dec. 31, 2022 USD ($)	Mar. 01, 2020 MWac
Regulatory Liabilities [Line Items]
Regulatory asset, amortization period				26 years
Regulatory assets				$ 1,327,683		$ 1,271,501
Capital expenditure shortfall refundable to customers (percent)				80%
Retroactive rate adjustment collection period				24 months
Regulatory liability, disallowed securitization costs				$ 63,495
Empire Electric
Regulatory Liabilities [Line Items]
Public utilities, incurred cost one-time net gain (loss)		$ 63,495	$ 48,452
Minimum | Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period				1 year
Maximum | Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period				5 years
Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Asset retirement obligation						21,283
Regulatory assets				$ 326,418		388,294
Fuel and commodity cost adjustments | Minimum
Regulatory Liabilities [Line Items]
Regulatory asset, amortization period				6 months
Fuel and commodity cost adjustments | Maximum
Regulatory Liabilities [Line Items]
Regulatory asset, amortization period				24 months
Retired generating plant
Regulatory Liabilities [Line Items]
Regulatory assets				$ 183,732		174,609
Coal generation capacity (MW) | MWac							200
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Regulatory asset, amortization period				20 years
Regulatory assets				$ 124,517		90,121
Capitalized operating and maintenance costs, recovery rate, (percent)				2.43%
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Regulatory assets				$ 68,822		80,736
Future service years of employees				10 years
Pension and post-employment benefits | Minimum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period				3 years
Pension and post-employment benefits | Maximum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period				8 years
Environmental costs
Regulatory Liabilities [Line Items]
Regulatory assets				$ 66,779		70,529
Environmental remediation, rate recovery period				7 years
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Regulatory assets				$ 64,146		66,156
Regulatory assets, recovery period				2 years
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Regulatory assets				$ 37,214		28,145
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]
Regulatory assets				$ 8,815		9,481
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]
Regulatory assets				$ 4,932		6,504
Regulatory assets, recovery period				5 years
Midwest Extreme Weather Event | Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount						221,646
Public utilities, incurred cost one-time net gain (loss)	$ 63,495
Public utilities, incurred cost one-time net gain (loss), net of tax			$ 48,452
Energy Transistion Costs | Fuel and commodity cost adjustments
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount						$ 140,774
Securitized Utility Tariff Bonds due January 1, 2035 | Fuel and commodity cost adjustments | Subsequent Event
Regulatory Liabilities [Line Items]
Regulatory assets					$ 180,500
Percentage of public utilities, issuance of securitized tariff bonds					0.04943
Securitized Utility Tariff Bonds due January 1, 2039 | Fuel and commodity cost adjustments | Subsequent Event
Regulatory Liabilities [Line Items]
Regulatory assets					$ 125,000
Percentage of public utilities, issuance of securitized tariff bonds					0.05091

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,115,729	$ 1,344,207
Equity-method investees	456,393	381,802
Other	27,417	27,600
Long-term investments	641,920	462,325
Notes Receivable | Development loans
Schedule of Equity Method Investments [Line Items]
Development loans receivable from equity-method investees	158,110	52,923
Atlantica
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	1,052,703	1,268,140
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	61,064	74,083
Other
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,962	$ 1,984

Long-term investments - Income

Long-term investments - Income from Long-term Investments (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Fair value loss on investments carried at fair value		$ (229,988)	$ (499,125)
Dividend and interest income from investments carried at fair value		103,807	107,143
Equity method loss		(5,936)	(21,416)
Impairment of equity-method investee	$ 0		(75,910)
Interest and other income		7,143	5,923
Income (loss) from other long-term investments		1,207	(91,403)
Loss from long-term investments		(124,974)	(483,385)
Atlantica
Schedule of Equity Method Investments [Line Items]
Fair value loss on investments carried at fair value		(215,437)	(482,774)
Dividend and interest income from investments carried at fair value		87,154	86,664
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Fair value loss on investments carried at fair value		(14,684)	(16,018)
Dividend and interest income from investments carried at fair value		16,604	20,443
Other
Schedule of Equity Method Investments [Line Items]
Fair value loss on investments carried at fair value		133	(333)
Dividend and interest income from investments carried at fair value		49	36
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Equity method loss		$ (5,936)	(21,416)
Impairment of equity-method investee			$ (75,910)

Long-term investments - Narrati

Long-term investments - Narrative (Detail) $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
	Jul. 05, 2023 USD ($)	May 31, 2020 shares	Dec. 31, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) wind_project	Jan. 04, 2024	Nov. 30, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity-method investees			$ 381,802	$ 456,393	$ 381,802
Investments carried at fair value			1,344,207	1,115,729	1,344,207
Number of wind development projects | wind_project						4
Impairment			0		(75,910)
Guarantor obligations			113,630	113,630	113,630
Impairment of assets (notes 5 and 8(c))				23,492	235,478
Fair value of support provided				12,666	8,824
Operating Segments | Renewable Energy Group
Schedule of Equity Method Investments [Line Items]
Equity-method investees			310,103	343,712	310,103
Investments carried at fair value			1,342,223	1,113,767	1,342,223
Operating Segments | Regulated Services Group
Schedule of Equity Method Investments [Line Items]
Equity-method investees			56,199	112,180	56,199
Investments carried at fair value			1,984	1,962	1,984
Corporate | Corporate
Schedule of Equity Method Investments [Line Items]
Equity-method investees			15,500	501	15,500
Investments carried at fair value			$ 0	$ 0	$ 0
Atlantica
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			42%	42%	42%
Equity interest, maximum (percent)				48.50%
Equity-method investees			$ 1,167,444	$ 1,167,444	$ 1,167,444
Investments carried at fair value			1,268,140	$ 1,052,703	1,268,140
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	$ 61,064	74,083
Texas Coastal Wind Facilities
Schedule of Equity Method Investments [Line Items]
Equity-method investees						$ 344,883
Equity method investment acquired (percent)				51%		51%
Texas Coastal Wind Facilities | Maximum
Schedule of Equity Method Investments [Line Items]
Equity-method investees			282,726		282,726
Texas Coastal Wind Facilities | Minimum
Schedule of Equity Method Investments [Line Items]
Equity-method investees						$ 206,816
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Equity-method investees			381,802	$ 456,393	381,802	$ 433,850
Impairment					(75,910)
Liberty Development JV Inc
Schedule of Equity Method Investments [Line Items]
Equity-method investees								$ 19,688
Noninterest bearing loan	$ 35,000
Proceeds from equity	17,500
Impairment of assets (notes 5 and 8(c))	$ 18,911
Liberty Development JV Inc | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)							50%
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]
Aggregate cost			$ 25,634	$ 25,634	$ 25,634

Long-term investments - Operati

Long-term investments - Operating entities (Detail) - $ / MWh	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2021
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	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investment [Roll Forward]
Carrying value, January 1		$ 381,802
Net loss attributable to AQN		(5,936)	$ (21,416)
Impairment	$ 0		(75,910)
Carrying value, December 31	381,802	456,393	381,802
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment [Roll Forward]
Carrying value, January 1		381,802	433,850
Additional investments		91,205	110,441
Net loss attributable to AQN		(5,936)	(21,416)
OCI attributable to AQN		7,693	(67,110)
Dividend received		(4,600)	(1,183)
Impairment			(75,910)
Other		(13,771)	3,130
Carrying value, December 31	$ 381,802	$ 456,393	$ 381,802

Long-term investments - Investm

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investment, Summarized Financial Information [Abstract]
Total assets	$ 18,373,961	$ 17,627,613
AQN's investment carrying amount for the entities	456,393	381,802
Income Statement [Abstract]
Revenue	2,698,015	2,765,013
Net loss	(33,305)	(308,155)
OCI	58,794	(90,036)
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment, Summarized Financial Information [Abstract]
Total assets	3,235,474	2,740,132
Total liabilities	1,962,115	1,507,079
Net assets	1,273,359	1,233,053
Income Statement [Abstract]
Revenue	111,446	65,025
Net loss	(3,633)	(31,070)
OCI	12,026	(130,729)
Investments in Significant Partnerships and Joint Ventures | APUC
Income Statement [Abstract]
Net loss	(5,936)	(21,416)
OCI	7,693	(67,110)
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment, Summarized Financial Information [Abstract]
AQN's investment carrying amount for the entities	456,393	381,802	$ 433,850
Investments in Significant Partnerships and Joint Ventures | APUC
Equity Method Investment, Summarized Financial Information [Abstract]
AQN's ownership interest in the entities	388,993	332,663
Difference between investment carrying amount and underlying equity in net assets	67,400	49,139
AQN's investment carrying amount for the entities	$ 456,393	$ 381,802

Long-term investments - Combine

Long-term investments - Combined Information for APUC's interest in VIE's (Details) - Variable Interest Entity, Not Primary Beneficiary - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Carrying amount	$ 179,728	$ 122,752
Development loans receivable	158,110	52,923
Indirect guarantees of debt on behalf of VIEs	740,866	436,790
Other indirect guarantees and commitments on behalf of VIEs	303,641	221,433
APUC's maximum exposure in regard to VIE's	$ 1,382,345	$ 833,898

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 CLP ($)	Dec. 31, 2022 USD ($)	Jun. 30, 2021
Debt Instrument [Line Items]
Long-term debt	$ 8,516,030,000			$ 7,512,017,000
Less: current portion	(621,856,000)			(423,274,000)
Long-term debt, excluding current portion	$ 7,894,174,000			7,088,743,000
Senior Unsecured Notes | 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	$ 1,144,897,000			1,142,814,000
Senior Unsecured Notes | Senior unsecured notes
Debt Instrument [Line Items]
Weighted average coupon	3.36%	3.36%	3.36%
Par value	$ 1,415,000,000
Long-term debt	$ 1,406,278,000			1,496,101,000
Senior Unsecured Notes | Senior unsecured utility notes
Debt Instrument [Line Items]
Weighted average coupon	6.30%	6.30%	6.30%
Par value	$ 137,000,000
Long-term debt	$ 147,589,000			154,271,000
Senior Unsecured Notes | Senior secured utility bonds
Debt Instrument [Line Items]
Weighted average coupon	4.71%	4.71%	4.71%
Par value	$ 556,199,000
Long-term debt	$ 551,166,000			554,822,000
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
Long-term debt	$ 904,604,000			882,899,000
Senior Unsecured Notes | Senior secured project notes
Debt Instrument [Line Items]
Weighted average coupon	10.21%	10.21%	10.21%
Par value		$ 16,848,000
Long-term debt	$ 12,738,000			15,024,000
Senior Unsecured Notes | Senior unsecured utility bonds
Debt Instrument [Line Items]
Weighted average coupon	3.90%	3.90%	3.90%
Par value			$ 1,521,000
Long-term debt	$ 70,967,000			77,206,000
Senior Unsecured Notes | Senior Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 7,131,107,000			5,855,566,000
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	$ 298,382,000			291,238,000
Senior Unsecured Notes | 5.56%, U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	5.21%	5.21%	5.21%
Par value	$ 1,100,000,000
Long-term debt	1,086,541,000			1,365,213,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured revolving credit facilities
Debt Instrument [Line Items]
Long-term debt	1,624,186,000			351,786,000
Revolving Credit Facility | Senior Unsecured Notes | Senior unsecured bank credit facilities and delayed draw term facility
Debt Instrument [Line Items]
Long-term debt	786,962,000			773,643,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial paper
Debt Instrument [Line Items]
Long-term debt	$ 481,720,000			$ 407,000,000

Long-term debt - Additional Inf

Long-term debt - Additional Information (Detail)

Nov. 06, 2023 USD ($)

Nov. 01, 2023 USD ($)

Jul. 31, 2023 USD ($)

Mar. 13, 2023 USD ($)

Jan. 30, 2024 USD ($)

Jan. 12, 2024 USD ($)

Dec. 31, 2023 USD ($)

Oct. 27, 2023 USD ($)

Jun. 01, 2023 USD ($)

Apr. 25, 2023 USD ($)

Mar. 31, 2023 USD ($)

Mar. 30, 2023 USD ($)

Dec. 31, 2022 USD ($)

Debt Instrument [Line Items]

Short-term debt

$ 766,886,000

Letters of credit issued

469,100,000

$ 465,200,000

Interest on long-term debt

74,493,000

$ 70,274,000

Senior Unsecured Notes

Debt Instrument [Line Items]

Debt repaid upon maturity

$ 75,000,000

$ 15,000,000

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

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

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

Debt Instrument [Line Items]

Par value

$ 610,400,000

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

Debt Instrument [Line Items]

Par value

$ 489,600,000

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

Debt Instrument [Line Items]

Par value

$ 1,100,000,000

2029 Notes | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 500,000,000

Interest rate (percent)

5.577%

2029 Notes | Senior Unsecured Notes | Subsequent Event

Debt Instrument [Line Items]

Interest rate (percent)

99.996%

2034 Notes | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 350,000,000

Interest rate (percent)

5.869%

2034 Notes | Senior Unsecured Notes | Subsequent Event

Debt Instrument [Line Items]

Interest rate (percent)

99.995%

Securitized Utility Tariff Bonds due January 1, 2035 | Senior Unsecured Notes | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 180,500,000

Percentage of public utilities, issuance of securitized tariff bonds

0.04943

Securitized Utility Tariff Bonds due January 1, 2039 | Senior Unsecured Notes | Subsequent Event

Debt Instrument [Line Items]

Par value

$ 125,000,000

Percentage of public utilities, issuance of securitized tariff bonds

0.05091

Senior unsecured utility notes | Senior Unsecured Notes

Debt Instrument [Line Items]

Par value

$ 137,000,000

Debt repaid upon maturity

$ 5,000,000

Fixed-to-Floating Subordinated Notes - Series 2018

Debt Instrument [Line Items]

Interest rate (percent)

6.875%

Debt instrument, redeemed amount

$ 287,500,000

Redemption price (percent)

100%

Revolving Credit Facility | Senior Unsecured Syndicated Revolving Credit Facility Maturing On March 31, 2028 | Senior Unsecured Notes

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 1,000,000,000

$ 500,000,000

Letter of Credit | Renewable Energy Group

Debt Instrument [Line Items]

Letters of credit issued

$ 50,000,000

$ 75,000,000

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, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Revolving and term credit facilities	$ 4,562,000	$ 4,513,300
Funds drawn on facilities/commercial paper issued	(2,892,900)	(1,532,500)
Letters of credit issued	(469,100)	(465,200)
Liquidity available under the facilities	1,200,000	2,515,600
Undrawn portion of uncommitted letter of credit facilities	(254,100)	(226,900)
Cash on hand	56,142	57,623
Total liquidity and capital reserves	$ 1,002,042	$ 2,346,323

Long-term debt - Schedule of In

Long-term debt - Schedule of Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-term debt	$ 251,539	$ 258,084
Commercial paper, credit facility draws and related fees	134,678	46,466
Accretion of fair value adjustments	(23,834)	(16,547)
Capitalized interest and AFUDC capitalized on regulated property	(14,679)	(10,802)
Other	5,952	1,373
Interest expense	$ 353,656	$ 278,574

Long-term debt - Principal Paym

Long-term debt - Principal Payments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2024	$ 621,856
2025	140,241
2026	1,193,531
2027	1,280,846
2028	819,122
Thereafter	4,481,961
Total	$ 8,537,557

Pension and other post-retireme

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	$ 14,521	$ 12,126
Accumulated benefit obligation for pension plan	827,559	815,589
Pension benefits
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	610,828	569,255	$ 648,864
Expected employer contributions for next year	23,248
OPEB
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	193,782	172,167	$ 192,375
Expected employer contributions for next year	3,583
Private Equity Funds | Level 3
Employee Benefits Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 26,381	$ 21,904

Pension and other post-retire_2

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, 2023	Dec. 31, 2022
Change in plan assets
Non-current assets (note 11)	$ 48,477	$ 26,482
Pension benefits
Change in projected benefit obligation
Projected benefit obligation, beginning of year	628,135	765,618
Projected benefit obligation assumed from business combination	0	87,933
Plan settlements	(3,226)	(112)
Service cost	11,954	16,309
Interest cost	33,687	24,787
Actuarial loss (gain)	20,172	(198,074)
Contributions from retirees	0	0
Plan amendments	0	0
Medicare Part D	0	0
Benefits paid	(42,801)	(68,197)
Foreign exchange	(53)	(129)
Projected benefit obligation, end of year	647,868	628,135
Change in plan assets
Fair value of plan assets, beginning of year	569,255	648,864
Plan assets acquired in business combination	0	74,532
Actual return on plan assets	65,272	(109,118)
Employer contributions	22,326	23,296
Plan settlements	(3,226)	(112)
Contributions from retirees	0	0
Medicare Part D subsidy receipts	0	0
Benefits paid	(42,801)	(68,197)
Foreign exchange	2	(10)
Fair value of plan assets, end of year	610,828	569,255
Unfunded status	(37,040)	(58,880)
Non-current assets (note 11)	12,598	12,264
Current liabilities	(1,416)	(1,907)
Non-current liabilities	(48,222)	(69,237)
Net amount recognized	(37,040)	(58,880)
OPEB
Change in projected benefit obligation
Projected benefit obligation, beginning of year	217,330	292,646
Projected benefit obligation assumed from business combination	0	5,195
Plan settlements	0	0
Service cost	3,253	6,277
Interest cost	11,510	9,146
Actuarial loss (gain)	(10,913)	(82,991)
Contributions from retirees	2,189	2,220
Plan amendments	0	(2,452)
Medicare Part D	355	367
Benefits paid	(14,226)	(13,078)
Foreign exchange	0	0
Projected benefit obligation, end of year	209,498	217,330
Change in plan assets
Fair value of plan assets, beginning of year	172,167	192,375
Plan assets acquired in business combination	0	8,577
Actual return on plan assets	22,620	(30,105)
Employer contributions	10,677	11,811
Plan settlements	0	0
Contributions from retirees	2,189	2,220
Medicare Part D subsidy receipts	355	367
Benefits paid	(14,226)	(13,078)
Foreign exchange	0	0
Fair value of plan assets, end of year	193,782	172,167
Unfunded status	(15,716)	(45,163)
Non-current assets (note 11)	35,879	14,218
Current liabilities	(3,164)	(3,039)
Non-current liabilities	(48,431)	(56,342)
Net amount recognized	$ (15,716)	$ (45,163)

Pension and other post-retire_3

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 425,842	$ 413,041
Fair value of plan assets	393,857	364,229
Projected benefit obligation	507,612	489,140
Fair value of plan assets	458,497	417,994
OPEB
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	71,089	198,463
Fair value of plan assets	18,793	139,368
Projected benefit obligation	71,089	198,463
Fair value of plan assets	$ 18,793	$ 139,368

Pension and other post-retire_4

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension benefits
Actuarial losses (gains)
Balance, January 1	$ (671)	$ 15,807
Additions to AOCI	(12,600)	(47,473)
Amortization in current period	617	(3,429)
Amortization due to plan settlements		15
Recognition of settlement gain	235
Reclassification to regulatory accounts	5,517	34,409
Ending balance, December 31	(6,902)	(671)
Past service losses (gains)
Beginning balance, January 1	(3,363)	(4,195)
Additions to AOCI	0	0
Amortization in current period	1,491	1,584
Amortization due to plan settlements		0
Reclassification to regulatory accounts	(755)	(752)
Recognition of settlement gain	0
Ending balance, December 31	(2,627)	(3,363)
OPEB
Actuarial losses (gains)
Balance, January 1	(33,550)	(15,630)
Additions to AOCI	(23,797)	(41,527)
Amortization in current period	2,554	56
Amortization due to plan settlements		0
Recognition of settlement gain	0
Reclassification to regulatory accounts	19,518	23,551
Ending balance, December 31	(35,275)	(33,550)
Past service losses (gains)
Beginning balance, January 1	(2,190)	310
Additions to AOCI	853	(24)
Amortization in current period	0	(2,476)
Amortization due to plan settlements		0
Reclassification to regulatory accounts	0	0
Recognition of settlement gain	0
Ending balance, December 31	$ (1,337)	$ (2,190)

Pension and other post-retire_5

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.19%	5.48%
Interest crediting rate (for cash balance plans)	4.48%	4.50%
Rate of compensation increase	3.60%	3.70%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.22%	5.49%
Health care cost trend rate
Before age 65	7%	6%
Age 65 and after	6%	6%
Assumed ultimate medical inflation rate	4.50%	4.75%
Year in which ultimate rate is reached	2034	2033

Pension and other post-retire_6

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.35%	2.94%
Expected return on assets	6.38%	6.19%
Rate of compensation increase	3.99%	3.91%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.49%	3%
Expected return on assets	6.45%	6.48%
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-employ_3

Pension and other post-employment 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, 2023	Dec. 31, 2022
Non-service costs
Non-service costs	$ 19,939	$ 10,950
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	11,954	16,309
Non-service costs
Interest cost	33,687	24,787
Expected return on plan assets	(31,990)	(41,226)
Amortization of net actuarial losses (gains)	(852)	3,452
Amortization of prior service credits	(1,491)	(1,584)
Amortization due to plan settlements	0	(15)
Impact of regulatory accounts	16,258	22,952
Non-service costs	15,612	8,366
Net benefit cost	27,566	24,675
OPEB
Defined Benefit Plan Disclosure [Line Items]
Service cost	3,253	6,277
Non-service costs
Interest cost	11,510	9,146
Expected return on plan assets	(9,736)	(11,359)
Amortization of net actuarial losses (gains)	(3,559)	(56)
Amortization of prior service credits	(853)	24
Amortization due to plan settlements	0	0
Impact of regulatory accounts	6,965	4,829
Non-service costs	4,327	2,584
Net benefit cost	$ 7,580	$ 8,861

Pension and other post-retire_7

Pension and other post-retirement benefits - Target Plan Asset Allocation (Detail)	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	41.60%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	48.60%
Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	9.80%
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-retire_8

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Detail) - Level 1 $ in Thousands	Dec. 31, 2023 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2023	$ 804,610
Percentage	100%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
2023	$ 376,158
Percentage	47%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
2023	$ 377,272
Percentage	47%
Other
Defined Benefit Plan Disclosure [Line Items]
2023	$ 51,180
Percentage	6%

Pension and other post-retire_9

Pension and other post-retirement benefits- Change in Plan Assets (Detail) - Level 3 - Private Equity Funds $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets, beginning of year	$ 21,904
Contributions into funds	4,603
Return on assets	2,205
Distributions	(2,331)
Fair value of plan assets, end of year	$ 26,381

Pension and other post-retir_10

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Pension plan
Defined Benefit Plan Disclosure [Line Items]
2024	$ 48,271
2025	49,652
2026	49,389
2027	50,443
2028	50,751
2029-2033	255,465
OPEB
Defined Benefit Plan Disclosure [Line Items]
2024	11,718
2025	12,303
2026	12,623
2027	13,105
2028	13,487
2029-2033	$ 71,230

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	$ 19,997	$ 43,562
Pension and OPEB plan assets (note 10)	48,477	26,482
Long-term deposits and cash collateral	19,336	22,537
Income taxes recoverable	9,988	7,100
Deferred financing costs	27,176	28,586
Insurance recoveries (note 22(a))	66,000	0
Other	31,080	21,596
Total other assets	222,054	149,863
Less: current portion	(23,061)	(22,564)
Other assets (note 11)	$ 198,993	$ 127,299

Other long-term liabilities - S

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Transactions with Third Party [Line Items]
Contract adjustment payments	$ 39,590	$ 113,876
Asset retirement obligations	115,611	116,584	$ 142,147
Advances in aid of construction	88,135	88,546
Environmental remediation obligation	40,772	42,457	$ 55,224
Customer deposits	36,294	34,675
Unamortized investment tax credits	17,255	17,649
Deferred credits and contingent consideration	40,945	39,498
Preferred shares, Series C	0	12,072
Hook-up fees	7,425	32,463
Lease liabilities	20,493	21,834
Contingent development support obligations	12,666	8,824
Contingent liability (note 22(a))	66,000	0
Other	35,338	41,156
Other long-term liabilities	546,332	595,442
Less: current portion	(80,458)	(134,212)
Other long-term liabilities, excluding current	465,874	461,230
Related Party
Transactions with Third Party [Line Items]
Note payable to related party	$ 25,808	$ 25,808

Other long-term liabilities - A

Other long-term liabilities - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Green Equity Units issued (in 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
Contract adjustment payments, accretion period	3 years
Transfers from advances in aid of construction to contributions in aid of construction		$ 238	$ 1,299
Undiscounted, unescalated cost of environmental cleanup activities		46,187	48,346
Environmental remediation obligation		40,772	42,457	$ 55,224
Accrual for environmental loss contingencies to be incurred over next three years		$ 25,713
Remaining period to incur cash flows for environmental cleanup		27 years
Regulatory assets		$ 1,327,683	1,271,501
Equity Method Investee
Debt Instrument [Line Items]
Note payable to related party				$ 25,808
Related Party
Debt Instrument [Line Items]
Note payable to related party		$ 25,808	25,808
Note payable to related party
Debt Instrument [Line Items]
Interest rate (percent)				4%
Preferred shares, Series C | St. Leon Wind Energy LP
Debt Instrument [Line Items]
Redeemable preferred stock issued (in shares)		100
Debt instrument, redeemed amount		$ 14,515
Gain (loss) on settlement		$ 2,377
Environmental costs
Debt Instrument [Line Items]
Environmental remediation, rate recovery period		7 years
Regulatory assets		$ 66,779	$ 70,529
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)		4.30%
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 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 116,584	$ 142,147
Obligation assumed	1,077	793
Retirement activities	(6,902)	(27,980)
Accretion	4,440	4,589
Change in cash flow estimates	412	(2,965)
Closing balance	$ 115,611	$ 116,584

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 42,457	$ 55,224
Remediation activities	(3,687)	(5,243)
Accretion	1,616	2,167
Changes in cash flow estimates	1,395	1,344
Revision in assumptions	(1,009)	(11,035)
Closing balance	$ 40,772	$ 42,457

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Common Shares Rollforward
Beginning balance (in shares)	683,614,803	671,960,276
Public offering (in shares)	0	2,861,709
Dividend reinvestment plan (in shares)	4,370,289	7,676,666
Exercise of share-based awards (in shares)	1,284,532	1,115,398
Conversion of convertible debentures (in shares)	1,415	754
Ending balance (in shares)	689,271,039	683,614,803

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ in Thousands			2 Months Ended	12 Months Ended				61 Months Ended
	Mar. 08, 2024 USD ($)	Mar. 03, 2022	Mar. 02, 2022	Dec. 31, 2023 USD ($) vote right shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2022 $ / shares	Mar. 08, 2024 USD ($) $ / shares shares	Dec. 31, 2023 $ / shares	Aug. 15, 2022 USD ($)
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%
Dividend declared per preferred share (USD per share) | $ / shares					$ 1.6440
Preferred dividend rate reset period				5 years
Total share-based compensation | $				$ 11,293		$ 10,920
Unrecognized compensation costs, non-vested awards | $				$ 23,883	$ 23,883
Unrecognized compensation costs, non-vested options, period of recognition				1 year 9 months 18 days
Common shares issued from treasury (in shares)				50,677
Share based awards settled for cash value as payment for tax withholding (in shares)				51,783
Company Match, First $5,000 Contributed by Employee
Stockholders Equity Note [Line Items]
Employer matching contribution (percent)				20%
Employee contribution eligible for 20% Company match | $				$ 5
Maximum employee contribution eligible for partial Company match | $				$ 10
Company Match, Employee Contributions $5,001 to $10,000
Stockholders Equity Note [Line Items]
Employer matching contribution (percent)				10%
Share options
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)				752,582		414,338
Total share-based compensation | $				$ 1,325		$ 980
Percentage of shares reserved under the plan (must not exceed)				8%
ESPP
Stockholders Equity Note [Line Items]
Vesting period of matching contribution shares				1 year
Maximum aggregate number of shares reserved for future issuance (in shares)				4,000,000	4,000,000
Deferred Share Units
Stockholders Equity Note [Line Items]
Maximum aggregate number of shares reserved for future issuance (in shares)				1,000,000	1,000,000
Exercise of share-based awards settled (in shares)				181,328		120,513
Shares issued during period (in shares)				724,583		645,714
Performance and restricted share units
Stockholders Equity Note [Line Items]
Maximum aggregate number of shares reserved for future issuance (in shares)				7,000,000	7,000,000
Award vesting period				3 years
Series A Shares
Stockholders Equity Note [Line Items]
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%
Shares issued, price per share (USD and CAD per share) | $ / shares									$ 25
Series D Shares
Stockholders Equity Note [Line Items]
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%
Shares issued, price per share (USD and CAD per share) | $ / shares									$ 25
Common shares
Stockholders Equity Note [Line Items]
Discount rate on share purchases under dividend reinvestment plan (percent)		3%	5%
Common shares | Public Stock Offering
Stockholders Equity Note [Line Items]
Exercise of share-based awards settled (in shares)				102,460		5,176
ATM Equity Program
Stockholders Equity Note [Line Items]
Treasury stock, amount reserved for issuance under the plan | $										$ 500,000
ATM Equity Program | Subsequent Event
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering (in shares)								36,814,536
Sale of stock, average price per share (in USD) | $ / shares								$ 15
Sale of stock, other related costs | $	$ 4,843							$ 551,086
Proceeds from sale of stock, net of commissions | $								$ 544,295
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, 2023 USD ($) shares	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2022 USD ($)
Stockholders Equity Note [Line Items]
Preferred shares | $	$ 184,299		$ 184,299
Series A Shares
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 Shares
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, 2023	Dec. 31, 2022
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 11,293	$ 10,920
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	1,325	980
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	949	960
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	897	562
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Total share-based compensation	$ 8,122	$ 8,418

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Equity [Abstract]
Risk-free interest rate	3.40%	1.90%
Expected volatility	27%	23%
Expected dividend yield	8.60%	4.30%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (in USD per share)	$ 1.04	$ 2.44

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2021 CAD ($) $ / shares shares
Number of awards
Beginning balance (in shares) | shares	2,626,780	2,040,528
Granted (in shares) | shares	1,368,744	646,090
Exercised (in shares) | shares	0	(40,074)
Forfeited (in shares) | shares	(1,327,799)	(19,764)
Ending balance (in shares) | shares	2,667,725	2,626,780	2,040,528
Exercisable (in shares) | shares	2,621,420
Weighted average exercise price
Beginning balance (in USD per share) | $ / shares	$ 16.02	$ 15.45
Granted (in USD per share) | $ / shares	10.76	19.11
Exercised (in USD per share) | $ / shares	0	13.92
Forfeited (in USD per share) | $ / shares	16.55	19.11
Ending balance (in USD per share) | $ / shares	14.71	$ 16.02	$ 15.45
Exercisable (in USD per share) | $ / shares	$ 17.11
Weighted average remaining contractual term (years)
Outstanding shares, weighted average remaining contractual term	5 years 2 months 4 days	5 years 7 months 17 days	6 years 1 month 9 days
Granted, weighted average remaining contractual term	7 years 2 months 26 days	7 years 2 months 19 days
Exercised, weighted average remaining contractual term		5 years 11 months 12 days
Beginning balance, aggregate intrinsic value | $	$ 0	$ 3,145
Granted, aggregate intrinsic value | $	0	0
Exercised, aggregate intrinsic value | $	0	103
Forfeited, aggregate intrinsic value | $	0	0
Ending balance, aggregate intrinsic value | $	$ 0	$ 0	$ 3,145
Exercisable , weighted average remaining contractual term	4 years 6 months
Exercisable, aggregate intrinsic value | $	$ 0

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted average remaining contractual term (years)
Exercisable , weighted average remaining contractual term	4 years 6 months
PSUs and RSUs
Number of awards
Beginning balance (in shares)	2,109,710	2,443,672
Granted, including dividends (in shares)	2,841,967	1,090,457
Exercised (in shares)	(922,883)	(1,221,620)
Forfeited (in shares)	(451,047)	(202,799)
Ending balance (in shares)	3,577,747	2,109,710	2,443,672
Exercisable (in shares)	597,363
Weighted average grant-date fair value
Beginning balance (in USD per share)	$ 18.38	$ 18.07
Granted, including dividends (in USD per share)	10.98	17.99
Exercised (in USD per share)	18.73	12.62
Forfeited (in USD per share)	15.07	18.94
Ending balance (in USD per share)	18.38	$ 18.38	$ 18.07
Exercisable (in USD per share)	$ 19.98
Weighted average remaining contractual term (years)
Outstanding, weighted average remaining contractual term	1 year 9 months 3 days	1 year 9 months 3 days	1 year 8 months 19 days
Granted, including dividends, weighted average remaining contractual term	2 years 7 days	2 years
Outstanding, aggregate intrinsic value	$ 29,910	$ 18,608	$ 44,646
Granted, including dividends, aggregate intrinsic value	25,329	17,524
Exercised, aggregate intrinsic value	10,125	23,636
Forfeited, aggregate intrinsic value	$ 3,771	$ 418
Exercisable , weighted average remaining contractual term	2 months 19 days
Exercisable, aggregate intrinsic value	$ 4,994

Shareholder's capital - Bonus D

Shareholder's capital - Bonus Deferral RSUs (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
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)	31,455	82,886
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)	37,660	95,482
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)	77,981	55,445
Deferred Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued during period (in shares)	724,583	645,714
Common stock, shares issued (in shares)	69,115	178,368
Awards outstanding (in shares)	167,352	158,486

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, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 6,836,439	$ 7,382,079
Other comprehensive income (loss)	61,958	(123,129)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	(3,164)	33,093
OCI, net of tax	58,794	(90,036)
OCI attributable to the non-controlling interests	(1,017)	1,650
Net current period OCI attributable to shareholders of AQN	57,777	(88,386)
Ending Balance	6,624,408	6,836,439
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(160,063)	(71,677)
OCI, net of tax	57,777	(88,386)
Ending Balance	(102,286)	(160,063)
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(98,467)	(76,615)
Other comprehensive income (loss)	(3,788)	(18,013)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	(1,598)	(5,489)
OCI, net of tax	(5,386)	(23,502)
OCI attributable to the non-controlling interests	(1,017)	1,650
Net current period OCI attributable to shareholders of AQN	(6,403)	(21,852)
Ending Balance	(104,870)	(98,467)
Unrealized gain (loss) on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(97,809)	(3,514)
Other comprehensive income (loss)	57,351	(128,838)
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	2,136	34,543
OCI, net of tax	59,487	(94,295)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	59,487	(94,295)
Ending Balance	(38,322)	(97,809)
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	36,213	8,452
Other comprehensive income (loss)	8,395	23,722
Amounts reclassified from AOCI to the unaudited interim consolidated statements of operations	(3,702)	4,039
OCI, net of tax	4,693	27,761
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of AQN	4,693	27,761
Ending Balance	$ 40,906	$ 36,213

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2023 CAD ($) $ / shares	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2022 CAD ($) $ / shares
Dividends [Line Items]
Dividend declared for common share holders | $	$ 301,771		$ 486,043
Cash dividend declared per common share (USD per share)	$ 0.4340		$ 0.7130
Dividend declared per preferred share (CAD per share)		$ 1.6440
Series A Shares
Dividends [Line Items]
Dividends declared for preferred share holders | $		$ 6,194		$ 6,194
Dividend declared per preferred share (CAD per share)		$ 1.2905		$ 1.2905
Series D Shares
Dividends [Line Items]
Dividends declared for preferred share holders | $		$ 5,091		$ 5,091
Dividend declared per preferred share (CAD per share)		$ 1.2728		$ 1.2728

Related party transactions (Det

Related party transactions (Detail) - USD ($) $ in Thousands		12 Months Ended
	Dec. 28, 2023	Dec. 31, 2023	Dec. 31, 2022	Jan. 04, 2024
Liberty Development JV Inc | Subsequent Event
Transactions with Third Party [Line Items]
Equity interest (percent)				50%
Equity Method Investee
Transactions with Third Party [Line Items]
Development fees		$ 27,933	$ 12,628
Equity Method Investee | Administrative Service
Transactions with Third Party [Line Items]
Reimbursement of incurred costs		34,733	38,215
Equity Method Investee | Development Service
Transactions with Third Party [Line Items]
Reimbursement of incurred costs		$ 37,802	$ 25,645
Atlantica | Related Party
Transactions with Third Party [Line Items]
Impairment loss	$ 1,481
Atlantica | Liberty Jimena, S.L. and Liberty Caparacena, S.L. | Related Party
Transactions with Third Party [Line Items]
Equity interest (percent)	100%
Atlantica | Liberty Infraestructuras, S.L. | Related Party
Transactions with Third Party [Line Items]
Equity interest (percent)	80%

Non-controlling interests and_3

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Noncontrolling Interest [Line Items]
Net earnings (loss) attributable to NCI	$ 87,901	$ 111,323
Redeemable non-controlling interest, held by related party	(25,922)	(15,157)
Net effect of non-controlling interests	61,979	96,166
Non-controlling interests - tax equity partnership units
Noncontrolling Interest [Line Items]
Net earnings (loss) attributable to NCI	114,141	108,695
Non-controlling interests - redeemable tax equity partnership units
Noncontrolling Interest [Line Items]
Net earnings (loss) attributable to NCI	1,324	6,298
Non-controlling interests
Noncontrolling Interest [Line Items]
Net earnings (loss) attributable to NCI	$ (27,564)	$ (3,670)

Non-controlling interests and_4

Non-controlling interests and redeemable non-controlling interests - Change in Non-Controlling Interests (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	$ 1,616,792
Net earnings (loss) attributable to NCI	87,901	$ 111,323
Contributions received, net	0	5,000
OCI	(1,017)	1,650
Closing balance	1,584,843	1,616,792
Atlantica Yield Energy Solutions Canada Inc.
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	57,822	81,158
Net earnings (loss) attributable to NCI	0	0
Contributions received, net	0	0
Dividends and distributions declared	(17,082)	(20,978)
Dividends and distributions declared	0	0
OCI	45	(2,358)
Closing balance	40,785	57,822
Non-controlling interests
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	333,362	64,807
Net earnings (loss) attributable to NCI	27,564	3,670
Contributions received, net	0	267,515
Dividends and distributions declared	(14,497)	(3,350)
Dividends and distributions declared	0	0
OCI	909	720
Closing balance	347,338	333,362
Class A Units | Class A Partnership Units
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Opening balance	1,225,608	1,377,117
Net earnings (loss) attributable to NCI	(114,141)	(108,695)
Contributions received, net	107,933	6,182
Dividends and distributions declared	(22,743)	(36,736)
Dividends and distributions declared	0	(12,249)
OCI	63	(11)
Closing balance	$ 1,196,720	$ 1,225,608

Non-controlling interests and_5

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest - Additional Information (Detail) $ in Thousands		12 Months Ended
	Dec. 29, 2022 USD ($) wind_project MWac	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2020 MWac	Dec. 29, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Nov. 30, 2021 USD ($)	May 31, 2019 USD ($)	May 31, 2019 CAD ($)
Noncontrolling Interest [Line Items]
Contributions from non-controlling interests and redeemable non-controlling interests (note 3)		$ 98,955,000	$ 272,515,000
Production-based cash contributions from non-controlling interest		9,084,000	6,182,000
Redeemable non-controlling interests	$ 5,000,000	10,013,000	11,520,000			$ 12,989,000
AQN's investment carrying amount for the entities		456,393,000	381,802,000
Non-controlling interests		1,584,843,000	1,616,792,000
Equity Method Investee | Liberty Development Energy Solutions | Senior Secured Utility Bonds
Noncontrolling Interest [Line Items]
Line of credit facility, maximum borrowing capacity		$ 306,500,000
Threshold debt amount as percentage of collateral value to trigger sale of collateral (percent)		50%
Atlantica Yield Energy Solutions Canada Inc.
Noncontrolling Interest [Line Items]
Non-controlling interests		$ 40,785,000	$ 57,822,000			$ 81,158,000
Atlantica Yield Energy Solutions Canada Inc. | Related Party
Noncontrolling Interest [Line Items]
Non-controlling interests								$ 96,752,000	$ 130,103
Operating Wind Facilities in the United States
Noncontrolling Interest [Line Items]
Equity interest (percent)	49%				49%
Number of ownership interests in wind facilities | wind_project	3
Wind power capacity (megawatt AC) | MWac	551			551
Blue Hill Wind Facility
Noncontrolling Interest [Line Items]
Equity interest (percent)	80%				80%
Wind power capacity (megawatt AC) | MWac	175
Proceeds from sale of renewable assets	$ 277,500,000				$ 108,610
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 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 11,520	$ 12,989
Net earnings (loss) attributable to NCI	(1,324)	(6,298)
Contributions, net of costs	0	5,000
Dividends and distributions declared	(183)	(171)
Closing balance	10,013	11,520
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	307,856	306,537
Net earnings (loss) attributable to NCI	25,922	15,157
Contributions, net of costs	0	0
Dividends and distributions declared	(25,428)	(13,838)
Closing balance	$ 308,350	$ 307,856

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Expenses [Line Items]
Canadian enacted statutory rate (percent)	26.50%	26.50%
Valuation allowance for deferred tax assets	$ 97,344	$ 107,583	$ 27,471
Undistributed earnings of foreign subsidiaries	908,449
Minimum
Income Tax Expenses [Line Items]
Deferred tax asset, increase (decrease), amount	83,434
Maximum
Income Tax Expenses [Line Items]
Deferred tax asset, increase (decrease), amount	$ 151,759

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Expected income tax recovery at Canadian statutory rate	$ (31,696)	$ (97,962)
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(46,628)	(55,315)
Adjustments from investments carried at fair value	16,128	51,314
Non-controlling interests share of income	24,677	30,025
Change in valuation allowance	10,786	41,702
Acquisition-related state deferred tax adjustments	0	5,998
Capital gain rate differential on disposal of renewable assets	0	(7,340)
Tax credits	(54,788)	(18,440)
Amortization and settlement of excess deferred income tax	(12,785)	(14,855)
Deferred income taxes on regulated income recorded as regulatory assets	(878)	(1,986)
Other permanent differences	5,341	4,591
Other	3,543	755
Total	$ (86,300)	$ (61,513)

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ (119,605)	$ (369,668)
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	(259,141)	(363,050)
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	102,469	(37,322)
Other regions
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 37,067	$ 30,704

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax Expenses [Line Items]
Current	$ (9,740)	$ 7,843
Deferred	(76,560)	(69,356)
Total	(86,300)	(61,513)
Canada
Income Tax Expenses [Line Items]
Current	4,352	4,184
Deferred	(59,488)	(74,595)
Total	(55,136)	(70,411)
United States
Income Tax Expenses [Line Items]
Current	(14,820)	1,579
Deferred	(23,099)	6,183
Total	(37,919)	7,762
Other regions
Income Tax Expenses [Line Items]
Current	728	2,080
Deferred	6,027	(944)
Total	$ 6,755	$ 1,136

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 1,030,801	$ 878,000
Pension and OPEB	7,370	16,845
Environmental obligation	11,692	12,118
Regulatory liabilities	180,371	156,285
Other	72,109	61,917
Total deferred income tax assets	1,302,343	1,125,165
Less: valuation allowance	(97,344)	(107,583)	$ (27,471)
Total deferred tax assets	1,204,999	1,017,582
Deferred tax liabilities:
Property, plant and equipment	883,447	846,331
Outside basis differentials	364,511	315,581
Regulatory accounts	317,820	303,059
Other	59,640	33,834
Total deferred tax liabilities	1,625,418	1,498,805
Net deferred tax liabilities	(420,419)	(481,223)
Deferred tax assets	158,483	84,416
Deferred tax liabilities	$ (578,902)	$ (565,639)

Income taxes - Summary of Valua

Income taxes - Summary of Valuation Allowance for Deferred Tax Assets (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Deferred Tax Assets, Valuation Allowance [Roll Forward]
Beginning balance	$ 107,583	$ 27,471
Charged to income tax expense	10,786	41,702
Charged (reduction) to OCI	(16,696)	40,613
Reductions to other accounts	(4,329)	(2,203)
Ending balance	$ 97,344	$ 107,583

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 2,823,170
Tax credits	204,131
Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	917,120
U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	1,906,050
2024—2028
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	11,780
Tax credits	3,359
2024—2028 | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	3,339
2024—2028 | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	8,441
2029+
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	2,811,390
Tax credits	200,772
2029+ | Canada
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	913,781
2029+ | U.S.
Capital Loss Carryforwards [Line Items]
Total non-capital loss carryforward	$ 1,897,609

Other net losses - Other Net Lo

Other net losses - Other Net Losses (Gains) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Other Income and Expenses [Abstract]
Acquisition and transition-related costs	$ 0	$ 6,834
Kentucky termination costs	46,527	10,608
Acquisition-related settlement payment	(11,983)	0
Securitization write-off	63,495	0
Renewable energy business sale costs	12,506	0
Loss on redemption of long-term note	8,532	0
Other	13,812	3,949
Other net losses	$ 132,889	$ 21,391

Other net losses - Additional I

Other net losses - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Other Income and Expenses [Abstract]
Kentucky termination costs	$ 38,795
Business combination, incurred costs	46,527	$ 10,608
Acquisition-related settlement payment	12,814
Legal fees	831
Additional securitization costs, written off	63,495
Incurred costs	$ 12,506

Basic and diluted net earning_3

Basic and diluted net earnings (loss) per share - Schedule of Earnings (Loss) per Share (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Net earnings (loss) attributable to shareholders of AQN	$ 28,674,000	$ (211,989,000)
Series A and D Preferred shares dividend	8,356,000	8,720,000
Net earnings (loss) attributable to common shareholders of AQN – basic (in shares)	20,318,000	(220,709,000)
Net earnings (loss) attributable to common shareholders of AQN – diluted (in shares)	$ 20,318,000	$ (220,709,000)
Weighted average number of shares
Basic (in shares)	688,738,717	677,862,207
Effect of dilutive securities (in shares)	2,024,509	0
Diluted (in shares)	690,763,226	677,862,207
Series A preferred shares
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,586,000	$ 4,786,000
Series D preferred shares
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 3,770,000	$ 3,934,000

Basic and diluted net earning_4

Basic and diluted net earnings (loss) per share - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 shares
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures (in shares)	5,699,593

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 business_unit segment
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, 2023	Dec. 31, 2022
Revenue
Revenue	$ 2,612,036	$ 2,680,836
Other revenue	2,698,015	2,765,013
Fuel, power and water purchased	735,945	866,354
Net revenue	1,962,070	1,898,659
Operating expenses	906,985	851,489
Administrative expenses (recovery)	90,359	80,232
Depreciation and amortization	466,996	455,520
Asset impairment charge	23,492	159,568
Loss on foreign exchange	8,359	13,833
Operating income (loss), before gain on sale of renewable assets		338,017
Gain on sale of renewable assets	0	64,028
Operating income	465,879	402,045
Interest expense	(353,656)	(278,574)
Income (loss) from long-term investments	(83,564)	(465,206)
Other expenses	(148,264)	(27,933)
Loss before income taxes	(119,605)	(369,668)
Property, plant and equipment	12,517,450	11,944,885
Investments carried at fair value	1,115,729	1,344,207
Equity-method investees	456,393	381,802
Total assets	18,373,961	17,627,613
Capital expenditures	1,026,171	1,089,024
Revenue related to net hedging loss, not recognized as revenue from contract with customers	5,695	63,717
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	32,839	21,640
Other revenue
Revenue
Other revenue	85,979	84,177
Regulated Services Group | Operating Segments
Revenue
Revenue	2,315,722	2,330,039
Fuel, power and water purchased	716,446	824,670
Net revenue	1,650,413	1,559,598
Operating expenses	786,608	736,515
Administrative expenses (recovery)	46,386	46,484
Depreciation and amortization	346,188	317,300
Asset impairment charge	0	0
Loss on foreign exchange	0	0
Operating income (loss), before gain on sale of renewable assets		459,299
Gain on sale of renewable assets		0
Operating income	471,231	459,299
Interest expense	(160,998)	(113,482)
Income (loss) from long-term investments	44,953	21,884
Other expenses	(121,146)	(14,765)
Loss before income taxes	234,040	352,936
Property, plant and equipment	8,945,637	8,554,938
Investments carried at fair value	1,962	1,984
Equity-method investees	112,180	56,199
Total assets	12,658,955	12,109,575
Capital expenditures	816,788	908,676
Regulated Services Group | Operating Segments | Other revenue
Revenue
Other revenue	51,137	54,229
Renewable Energy Group | Operating Segments
Revenue
Revenue	296,314	350,797
Fuel, power and water purchased	19,499	41,684
Net revenue	310,210	337,560
Operating expenses	119,013	114,463
Administrative expenses (recovery)	36,554	26,424
Depreciation and amortization	119,576	137,203
Asset impairment charge	23,492	159,568
Loss on foreign exchange	0	0
Operating income (loss), before gain on sale of renewable assets		(100,098)
Gain on sale of renewable assets		64,028
Operating income	11,575	(36,070)
Interest expense	(61,261)	(64,285)
Income (loss) from long-term investments	102,188	15,254
Other expenses	(4,002)	(570)
Loss before income taxes	48,500	(85,671)
Property, plant and equipment	3,539,069	3,360,687
Investments carried at fair value	1,113,767	1,342,223
Equity-method investees	343,712	310,103
Total assets	5,367,011	5,251,933
Capital expenditures	209,383	180,348
Renewable Energy Group | Operating Segments | Other revenue
Revenue
Other revenue	33,395	28,447
Corporate | Corporate
Revenue
Revenue	0	0
Fuel, power and water purchased	0	0
Net revenue	1,447	1,501
Operating expenses	1,364	511
Administrative expenses (recovery)	7,419	7,324
Depreciation and amortization	1,232	1,017
Asset impairment charge	0	0
Loss on foreign exchange	8,359	13,833
Operating income (loss), before gain on sale of renewable assets		(21,184)
Gain on sale of renewable assets		0
Operating income	(16,927)	(21,184)
Interest expense	(131,397)	(100,807)
Income (loss) from long-term investments	(230,705)	(502,344)
Other expenses	(23,116)	(12,598)
Loss before income taxes	(402,145)	(636,933)
Property, plant and equipment	32,744	29,260
Investments carried at fair value	0	0
Equity-method investees	501	15,500
Total assets	347,995	266,105
Capital expenditures	0	0
Corporate | Corporate | Other revenue
Revenue
Other revenue	$ 1,447	$ 1,501

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Revenue	$ 2,698,015	$ 2,765,013
Property, plant and equipment	12,517,450	11,944,885
Intangible assets	93,938	96,683
United States
Segment Reporting Information [Line Items]
Revenue	2,169,239	2,232,817
Property, plant and equipment	10,826,738	10,351,736
Intangible assets	18,666	18,818
Canada
Segment Reporting Information [Line Items]
Revenue	162,740	175,005
Property, plant and equipment	924,389	848,560
Intangible assets	18,111	19,038
Other regions
Segment Reporting Information [Line Items]
Revenue	366,036	357,191
Property, plant and equipment	766,323	744,589
Intangible assets	$ 57,161	$ 58,827

Commitments and contingencies -

Commitments and contingencies - Additional Information (Detail) $ in Thousands	Mar. 06, 2024 business_unit	Dec. 31, 2023 USD ($) lawsuit claim	Dec. 31, 2022 USD ($)
Commitments Disclosure [Line Items]
Estimated insurance recoveries | $		$ 66,000	$ 0
Mountain View Fire
Commitments Disclosure [Line Items]
Number of active lawsuits		21
Number of non-litigation claims | claim		1
Number of lawsuits filed by groups of individual plaintiffs		14
Number of wrongful death lawsuits		1
Number of lawsuits filed by insurance companies		6
Accrued estimated losses | $		$ 66,000
Estimated insurance recoveries | $		$ 66,000
Mountain View Fire | Subsequent Event
Commitments Disclosure [Line Items]
Number of bellwether cases | business_unit	4

Commitments and contingencies_2

Commitments and contingencies - Estimates of Future Commitments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Commitments Disclosure [Line Items]
Year 1	$ 272,222
Year 2	182,764
Year 3	126,777
Year 4	114,300
Year 5	112,108
Thereafter	1,080,214
Total	1,888,385
Power purchase
Commitments Disclosure [Line Items]
Year 1	55,312
Year 2	33,869
Year 3	12,274
Year 4	12,520
Year 5	12,768
Thereafter	129,818
Total	256,561
Natural gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1	121,188
Year 2	71,949
Year 3	42,643
Year 4	33,215
Year 5	30,803
Thereafter	154,757
Total	454,555
Service agreements
Commitments Disclosure [Line Items]
Year 1	73,687
Year 2	61,889
Year 3	56,591
Year 4	53,140
Year 5	52,898
Thereafter	259,510
Total	557,715
Capital projects
Commitments Disclosure [Line Items]
Year 1	5,598
Year 2	0
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total	5,598
Land easements and other
Commitments Disclosure [Line Items]
Year 1	16,437
Year 2	15,057
Year 3	15,269
Year 4	15,425
Year 5	15,639
Thereafter	536,129
Total	$ 613,956

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ 3,863	$ (124,631)
Fuel and natural gas in storage	46,368	(21,140)
Supplies and consumables inventory	(48,539)	(24,088)
Income taxes recoverable	(2,889)	549
Prepaid expenses	(13,218)	(4,269)
Accounts payable	23,847	24,395
Accrued liabilities	(488)	127,076
Current income tax liability	1,096	(2,741)
Asset retirements and environmental obligations	(1,015)	(22,342)
Net regulatory assets and liabilities	(95,361)	(174,427)
Changes in non-cash operating items	$ (86,336)	$ (221,618)

Financial instruments - Fair Va

Financial instruments - Fair Value of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Interest rate forwards
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	$ 11,790
Cross-currency interest rate swap
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	16,429
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,054,665	$ 1,270,138
Development loans and other receivables	0	0
Total derivative instruments	0	0
Total financial assets	1,054,665	1,270,138
Long-term debt	2,532,608	2,623,628
Convertible debentures	276	276
Total derivative instruments	0	0
Total financial liabilities	2,532,884	2,623,904
Level 1 | Related Party
Fair Value of Financial Instruments [Line Items]
Note payable to related party	0	0
Level 1 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
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	0
Level 1 | Interest rate forwards | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Total derivative instruments	0
Level 1 | Interest rate forwards | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
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 | Congestion revenue rights | Not designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Level 1 | Cross-currency interest rate swap | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Level 1 | Cross-currency interest rate swap | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 1 | Cross-currency interest rate swap | 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 | Cross-currency interest rate swap | 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 | Preferred shares, Series C
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	155,735	50,300
Total derivative instruments	74,790	73,397
Total financial assets	230,525	123,697
Long-term debt	4,890,710	4,075,403
Convertible debentures	0	0
Total derivative instruments	37,213	41,420
Total financial liabilities	4,943,243	4,143,678
Level 2 | Related Party
Fair Value of Financial Instruments [Line Items]
Note payable to related party	15,320	15,180
Level 2 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 2 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
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	0
Level 2 | Interest rate forwards | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	72,936	69,188
Total derivative instruments	11,790
Level 2 | Interest rate forwards | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,854
Level 2 | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 2 | Congestion revenue rights | Not designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
Level 2 | Cross-currency interest rate swap | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	6,779	15,435
Level 2 | Cross-currency interest rate swap | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	5,547
Level 2 | Cross-currency interest rate swap | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,267
Total derivative instruments	10,533	24,371
Level 2 | Cross-currency interest rate swap | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		2,659
Level 2 | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		283
Total derivative instruments		1,614
Level 2 | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	2,564
Level 2 | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C		11,675
Level 3
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	61,064	74,083
Development loans and other receivables	0	0
Total derivative instruments	8,458	10,503
Total financial assets	69,522	84,586
Long-term debt	0	0
Convertible debentures	0	0
Total derivative instruments	73,663	128,901
Total financial liabilities	73,663	128,901
Level 3 | Related Party
Fair Value of Financial Instruments [Line Items]
Note payable to related party	0	0
Level 3 | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	68,070
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		120,284
Level 3 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		393
Total derivative instruments	5,593	8,617
Level 3 | Interest rate forwards | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Total derivative instruments	0
Level 3 | Interest rate forwards | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 3 | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	8,458
Level 3 | Congestion revenue rights | Not designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		10,110
Level 3 | Cross-currency interest rate swap | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0	0
Level 3 | Cross-currency interest rate swap | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	0
Level 3 | Cross-currency interest rate swap | 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 | Cross-currency interest rate swap | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		0
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 | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C		0
Carrying amount
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,115,729	1,344,207
Development loans and other receivables	158,110	53,680
Total derivative instruments	83,248	83,900
Total financial assets	1,357,087	1,481,787
Long-term debt	8,516,030	7,512,017
Convertible debentures	230	245
Total derivative instruments	110,876	170,321
Total financial liabilities	8,652,944	7,720,463
Carrying amount | Related Party
Fair Value of Financial Instruments [Line Items]
Note payable to related party	25,808	25,808
Carrying amount | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	68,070
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		120,284
Carrying amount | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	5,593	8,617
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		393
Carrying amount | Interest rate forwards | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	72,936	69,188
Total derivative instruments	11,790
Carrying amount | Interest rate forwards | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,854
Carrying amount | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	8,458	10,110
Carrying amount | Cross-currency interest rate swap | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	6,779	15,435
Carrying amount | Cross-currency interest rate swap | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	5,547
Carrying amount | Cross-currency interest rate swap | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,267
Total derivative instruments	10,533	24,371
Carrying amount | Cross-currency interest rate swap | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		2,659
Carrying amount | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		283
Total derivative instruments		1,614
Carrying amount | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	2,564
Carrying amount | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C		12,072
Fair value
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,115,729	1,344,221
Development loans and other receivables	155,735	50,300
Total derivative instruments	83,248	83,900
Total financial assets	1,354,712	1,478,421
Long-term debt	7,423,318	6,699,031
Convertible debentures	276	276
Total derivative instruments	110,876	170,321
Total financial liabilities	7,549,790	6,896,483
Fair value | Related Party
Fair Value of Financial Instruments [Line Items]
Note payable to related party	15,320	15,180
Fair value | Energy contracts | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	68,070
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		120,284
Fair value | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	5,593	8,617
Fair value | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		393
Fair value | Interest rate forwards | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	72,936	69,188
Total derivative instruments	11,790
Fair value | Interest rate forwards | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	1,854
Fair value | Congestion revenue rights | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	8,458	10,110
Fair value | Cross-currency interest rate swap | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	6,779	15,435
Fair value | Cross-currency interest rate swap | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	5,547
Fair value | Cross-currency interest rate swap | Designated as a hedge | Net investment hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		1,267
Total derivative instruments	10,533	24,371
Fair value | Cross-currency interest rate swap | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		2,659
Fair value | Commodity contracts | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments		283
Total derivative instruments		1,614
Fair value | Commodity contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Total derivative instruments	$ 2,564
Fair value | Preferred shares, Series C
Fair Value of Financial Instruments [Line Items]
Preferred shares, Series C		$ 11,675

Financial instruments - Additio

Financial instruments - Additional Information (Detail)

12 Months Ended

Jul. 31, 2023 USD ($)

Mar. 13, 2023 USD ($)

Dec. 31, 2023 USD ($) MWh MMBTU $ / MWh $ / shares

Dec. 31, 2023 CAD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2022 CAD ($)

Dec. 31, 2023 CAD ($) MWh MMBTU

Sep. 29, 2023 USD ($)

Dec. 31, 2022 CAD ($)

Dec. 17, 2022 MWh $ / MWh

Apr. 09, 2021 CAD ($)

May 23, 2019 USD ($)

Fair Value of Financial Instruments [Line Items]

Foreign currency gain (loss)

$ (5,386,000)

$ (23,502,000)

Revenue collection period

45 days

45 days

Accounts receivable

$ 554,438,000

Cash on hand

56,147,000

Liquidity available under the facilities

1,200,000,000

2,515,600,000

Revolving and Term Credit Facilities

Fair Value of Financial Instruments [Line Items]

Liquidity available under the facilities

945,853,000

Regulated Services Group

Fair Value of Financial Instruments [Line Items]

Accounts receivable

364,084,000

Designated as a hedge

Fair Value of Financial Instruments [Line Items]

Amortization of AOCI gains frozen as a result of hedge dedesignation

606,000

(18,561,000)

Senior Unsecured Notes

Fair Value of Financial Instruments [Line Items]

Debt repaid upon maturity

$ 75,000,000

$ 15,000,000

U.S. dollar Subordinated unsecured notes | Senior Unsecured Notes

Fair Value of Financial Instruments [Line Items]

Par value

$ 300,000,000

$ 300,000,000

$ 350,000,000

Canadian dollar Senior unsecured notes | Blue Hill Wind Facility

Fair Value of Financial Instruments [Line Items]

Cross-currency interest rate swap

$ 489,506,000

Gain (loss) on sale of derivatives

$ 9,732,000

Canadian dollar Senior unsecured notes | Senior Unsecured Notes

Fair Value of Financial Instruments [Line Items]

Par value

$ 1,200,000,000

Non-regulated Energy Sales

Fair Value of Financial Instruments [Line Items]

Unrealized gains (loss) in AOCI to be reclassified

$ (25,895,000)

Swap

Fair Value of Financial Instruments [Line Items]

Commodity volumes, gas | MMBTU

2,117,039

2,117,039

Canadian Investments and Subsidiaries

Fair Value of Financial Instruments [Line Items]

Foreign currency gain (loss)

$ (12,330,000)

2,262,000

Foreign exchange contract

Fair Value of Financial Instruments [Line Items]

Foreign currency gain (loss)

6,976,000

22,091,000

Cross-currency interest rate swap

Fair Value of Financial Instruments [Line Items]

Debt repaid upon maturity

$ 200,000,000

$ 150,000,000

Currency Swap

Fair Value of Financial Instruments [Line Items]

Foreign currency gain (loss)

5,959,000

(11,082,000)

Currency Swap | U.S. dollar Subordinated unsecured notes | Senior Unsecured Notes

Fair Value of Financial Instruments [Line Items]

Foreign currency gain (loss)

$ 8,420,000

$ (13,374,000)

Currency Swap | Canadian dollar Senior unsecured notes | Senior Unsecured Notes

Fair Value of Financial Instruments [Line Items]

Par value

$ 400,000,000

Interest rate swaps designated as a hedge

Fair Value of Financial Instruments [Line Items]

Notional quantity

$ 390,000,000

Transmission congestion rights

Fair Value of Financial Instruments [Line Items]

Notional quantity (MW-hrs) | MWh

5,486,961

5,486,961

Interest Rate Cap

Fair Value of Financial Instruments [Line Items]

Notional quantity (MW-hrs) | MWh

516,202

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

25.15

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

Fair Value of Financial Instruments [Line Items]

Alternative investment, measurement input (percent)

0.0800

0.0800

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

Fair Value of Financial Instruments [Line Items]

Alternative investment, measurement input (percent)

0.2747

0.2747

Minimum | Energy contracts

Fair Value of Financial Instruments [Line Items]

Forward price | $ / MWh

26.32

Derivative auction price (in USD per share) | $ / shares

$ 0

Minimum | Transmission congestion rights

Fair Value of Financial Instruments [Line Items]

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

0.55

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

Fair Value of Financial Instruments [Line Items]

Alternative investment, measurement input (percent)

0.0850

0.0850

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

Fair Value of Financial Instruments [Line Items]

Alternative investment, measurement input (percent)

0.3319

0.3319

Maximum | Energy contracts

Fair Value of Financial Instruments [Line Items]

Forward price | $ / MWh

144.02

Derivative auction price (in USD per share) | $ / shares

$ 52.02

Maximum | Transmission congestion rights

Fair Value of Financial Instruments [Line Items]

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

24.88

Weighted average useful lives | Atlantica Yield Energy Solutions Canada Inc. (b) | Measurement Input, Discount Rate

Fair Value of Financial Instruments [Line Items]

Alternative investment, measurement input (percent)

0.0827

0.0827

Weighted average useful lives | Energy contracts

Fair Value of Financial Instruments [Line Items]

Forward price | $ / MWh

38.44

Derivative auction price (in USD per share) | $ / MWh

$ 5.69

Weighted average useful lives | Transmission congestion rights

Fair Value of Financial Instruments [Line Items]

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

5.16

Financial instruments - Long-te

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2023 MWh $ / MWh
PJM Western HUB, Expiry December 2028
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	353,597
Receive average prices (per MW-hr) | $ / MWh	29.19
NI HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	1,492,926
Receive average prices (per MW-hr) | $ / MWh	21.34
ERCOT North HUB, Expiry December 2027
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	1,332,645
Receive average prices (per MW-hr) | $ / MWh	36.46
Illinois Hub, Expiry September 2030
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	3,534,802
Receive average prices (per MW-hr) | $ / MWh	24.54

Financial instruments - Derivat

Financial instruments - Derivative Instruments Designated as Amortized into Hedged Activity (Detail) $ in Thousands	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Sep. 29, 2023 USD ($)
Forward-starting interest rate swap
Derivative [Line Items]
Notional quantity			$ 390,000,000
U.S. dollar Subordinated unsecured notes | Forward-starting interest rate swap | $350,000 subordinated unsecured notes | Designated as a hedge
Derivative [Line Items]
Notional quantity	$ 350,000,000
Par value	350,000,000
U.S. dollar Subordinated unsecured notes | Forward-starting interest rate swap | $750,000 subordinated unsecured notes | Designated as a hedge
Derivative [Line Items]
Notional quantity	750,000,000
Par value	750,000,000
U.S. dollar Subordinated unsecured notes | Forward-starting interest rate swap | $1,150,000 senior unsecured notes | Designated as a hedge
Derivative [Line Items]
Notional quantity	1,150,000,000
U.S. dollar Subordinated unsecured notes | Forward-starting interest rate swap | First $575,000 of the $1,150,000 senior unsecured notes issuance | Designated as a hedge
Derivative [Line Items]
Notional quantity	575,000,000
Par value	$ 575,000,000
Canadian dollar Senior unsecured notes | Cross-currency interest rate swap | C$400,000 subordinated unsecured notes | Designated as a hedge
Derivative [Line Items]
Cross-currency interest rate swap		$ 400,000
Par value		$ 400,000

Financial instruments - Deriv_2

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge	$ 57,351	$ (128,838)
Amortization of cash flow hedge	(6,173)	(12,180)
Amounts reclassified from AOCI	8,309	46,723
OCI attributable to shareholders of AQN	$ 59,487	$ (94,295)

Financial instruments - Effects

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value of Financial Instruments [Line Items]
Total unrealized gain (loss) on derivative financial instruments	$ 15,502	$ (2,462)
Gain on derivative financial instruments	4,564	4,408
Renewable energy sales	(5,432)	5,236
Reduction to gain on sale of renewable assets	0	(7,185)
Gain (loss) on derivative instruments	(868)	2,459
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total unrealized gain (loss) on derivative financial instruments	39	(760)
Total realized loss on derivative financial instruments	(4,896)	(246)
Loss on derivative financial instruments not accounted for as hedges	(4,857)	(1,006)
Amortization of AOCI gains frozen as a result of hedge dedesignation	3,989	3,465
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total unrealized gain (loss) on derivative financial instruments	(372)	(945)
Total realized loss on derivative financial instruments	(4,896)	6,939
Not Designated as Hedging Instrument | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total unrealized gain (loss) on derivative financial instruments	411	185
Not Designated as Hedging Instrument | Interest rate forwards
Fair Value of Financial Instruments [Line Items]
Total realized loss on derivative financial instruments	$ 0	$ (7,185)

Financial instruments - Outstan

Financial instruments - Outstanding Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Supplier Finance Program, Obligation [Roll Forward]
Beginning balance	$ 16,785	$ 49,910
Invoices confirmed during the year	90,780	16,785
Confirmed invoices paid during the year	(45,392)	(49,910)
Ending balance	$ 62,173	$ 16,785

Financial instruments - Maximum

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Fair Value Disclosures [Abstract]
Cash and cash equivalents and restricted cash	$ 76,145
Accounts receivable	554,438
Allowance for doubtful accounts	(30,244)
Notes receivable	158,836
Maximum exposure to credit risk for financial instruments	$ 759,175

Financial instruments - Liabili

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Long-term debt obligations	$ 8,537,557
Interest on long-term debt	4,910,236
Purchase obligations	767,287
Environmental obligation	46,187
Advances in aid of construction	88,135	$ 88,546
Contract adjustment payments	39,590	$ 113,876
Other obligations	280,481
Total obligations	14,773,918
Cross-currency swap
Derivative [Line Items]
Total derivative instruments	16,429
Interest rate forwards
Derivative [Line Items]
Total derivative instruments	11,790
Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	76,226
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	621,856
Interest on long-term debt	391,493
Purchase obligations	767,287
Environmental obligation	3,136
Advances in aid of construction	3,640
Contract adjustment payments	39,590
Other obligations	27,796
Total obligations	1,883,283
Due less than 1 year | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	2,419
Due less than 1 year | Interest rate forwards
Derivative [Line Items]
Total derivative instruments	11,790
Due less than 1 year | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	14,276
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	1,333,772
Interest on long-term debt	602,761
Purchase obligations	0
Environmental obligation	22,577
Advances in aid of construction	0
Contract adjustment payments	0
Other obligations	2,901
Total obligations	1,995,527
Due 2 to 3 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	4,243
Due 2 to 3 years | Interest rate forwards
Derivative [Line Items]
Total derivative instruments	0
Due 2 to 3 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	29,273
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	2,099,968
Interest on long-term debt	419,950
Purchase obligations	0
Environmental obligation	1,820
Advances in aid of construction	0
Contract adjustment payments	0
Other obligations	2,304
Total obligations	2,544,736
Due 4 to 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	144
Due 4 to 5 years | Interest rate forwards
Derivative [Line Items]
Total derivative instruments	0
Due 4 to 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	20,550
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	4,481,961
Interest on long-term debt	3,496,032
Purchase obligations	0
Environmental obligation	18,654
Advances in aid of construction	84,495
Contract adjustment payments	0
Other obligations	247,480
Total obligations	8,350,372
Due after 5 years | Cross-currency swap
Derivative [Line Items]
Total derivative instruments	9,623
Due after 5 years | Interest rate forwards
Derivative [Line Items]
Total derivative instruments	0
Due after 5 years | Energy derivative and commodity contracts
Derivative [Line Items]
Total derivative instruments	$ 12,127