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 |