Algonquin Power & Utilities (AQN) 40-F 28 Feb 20 2019 FY Annual report (Canada) Financial data

Cover Page Document

Cover Page Document	12 Months Ended
	Dec. 31, 2019shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Entity File Number	001-37946
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Incorporation, State or Country Code	Z4
Entity Primary SIC Number	4911
Entity Address, Address Line One	354 Davis Road
Entity Address, City or Town	Oakville
Entity Address, State or Province	ON
Entity Address, Postal Zip Code	L6J 2X1
Entity Address, Country	CA
City Area Code	905
Local Phone Number	465-4500
Security Reporting Obligation	15(d)
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	524,223,323
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001174169
Current Fiscal Year End Date	--12-31
Business Contact
Entity Information [Line Items]
Contact Personnel Name	CT Corporation System
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
NEW YORK STOCK EXCHANGE, INC.
Entity Information [Line Items]
Title of 12(b) Security	Rights to Purchase One Common Share of the Company
Common Stock | NEW YORK STOCK EXCHANGE, INC.
Entity Information [Line Items]
Title of 12(b) Security	Common shares, no par value
Trading Symbol	AQN
Security Exchange Name	NYSE
6.875% Fixed-to-Floating Subordinated Notes | NEW YORK STOCK EXCHANGE, INC.
Entity Information [Line Items]
Title of 12(b) Security	6.875% Fixed-to-Floating Subordinated Notes – Series 2018-A due October 17, 2078
Trading Symbol	AQNA
Security Exchange Name	NYSE
6.20% Fixed-to-Floating Subordinated Notes | NEW YORK STOCK EXCHANGE, INC.
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
Rights to Purchase One Common Share of the Company | NEW YORK STOCK EXCHANGE, INC.
Entity Information [Line Items]
Security Exchange Name	NYSE
No Trading Symbol Flag

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2019shares
Document Documentand Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Central Index Key	0001174169
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	524,223,323

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue
Total revenue	$ 1,624,921	$ 1,648,463
Expenses
Expenses	471,989	472,466
Administrative expenses	56,802	52,710
Depreciation and amortization	284,304	260,772
Loss (gain) on foreign exchange	3,146	(58)
Costs and Expenses, Total	1,259,545	1,270,028
Operating income	365,376	378,435
Interest expense on long-term debt and others	(181,488)	(152,118)
Income (loss) from long-term investments (note 8)	(399,092)	84,818
Other losses	(44,026)	(8,402)
Other net losses (note 19)	15,085	2,725
Gain (loss) on derivative financial instruments (note 24(b)(iv))	(16,113)	636
Nonoperating Income (Expense)	189,691	(245,974)
Earnings before income taxes	555,067	132,461
Income tax expense (note 18)
Current	(16,431)	(11,347)
Deferred	(53,686)	(42,025)
Income tax expense	(70,117)	(53,372)
Net earnings	484,950	79,089
Net effect of non-controlling interests	62,416	108,521
Net effect of non-controlling interests held by related party	(16,482)	(2,622)
Net Income (Loss) Attributable To Noncontrolling Interest, Net Of Related Party	45,934	105,899
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	530,884	184,988
Series A and D Preferred shares dividend (note 15)	8,486	8,027
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$ 522,398	$ 176,961
Basic net earnings per share (USD per share)	$ 1.05	$ 0.38
Diluted net earnings per share (USD per share)	$ 1.04	$ 0.38
Regulated electricity distribution
Revenue
Total revenue	$ 784,396	$ 831,196
Expenses
Expenses	247,417	265,166
Regulated gas distribution
Revenue
Total revenue	439,153	431,453
Expenses
Expenses	170,487	183,012
Regulated water reclamation and distribution
Revenue
Total revenue	130,488	128,437
Expenses
Expenses	8,142	8,796
Non-regulated energy sales
Revenue
Total revenue	246,601	235,359
Expenses
Expenses	17,258	27,164
Other revenue
Revenue
Total revenue	$ 24,283	$ 22,018

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net earnings	$ 484,950	$ 79,089
Other comprehensive income (loss):
Foreign currency translation adjustment, net of tax recovery of $289 and $4,532, respectively (notes 1(u), 24(b)(iii) and 24(b)(iv))	7,795	(27,969)
Change in fair value of cash flow hedges, net of tax expense and tax recovery of $3,862 and $952, respectively (note 24(b)(ii))	10,580	(2,690)
Change in pension and other post-employment benefits, net of tax recovery and tax expense of $2,735 and $696, respectively (note 10)	(6,509)	1,960
Other comprehensive income (loss), net of tax	11,866	(28,699)
Comprehensive income	496,816	50,390
Comprehensive loss attributable to the non-controlling interests	(43,506)	(107,380)
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$ 540,322	$ 157,770

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, tax recovery	$ (289)	$ (4,532)
Change in fair value of cash flow hedge, tax recovery and (expense)	3,862	(952)
Change in unrealized pension and other post-employment expense, tax expense	$ (2,735)	$ 696

Consolidated Balance Sheets

Consolidated Balance Sheets $ in Thousands, $ in Thousands	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Current assets:
Cash and cash equivalents	$ 62,485	$ 46,819
Accounts receivable, net (note 4)	259,144	245,728
Fuel and natural gas in storage	30,804	43,063
Supplies and consumables inventory	60,295	52,537
Regulatory assets (note 7)	50,213	59,037
Prepaid expenses	29,003	27,283
Derivative instruments (note 24)	13,483	9,616
Other assets and long-term investments (notes 8 and 11)	7,764	7,522
Assets, current, total	513,191	491,605
Property, plant and equipment, net (note 5)	7,231,664	6,393,558
Intangible assets, net (note 6)	47,616	54,994
Goodwill (note 6)	1,031,696	954,282
Regulatory assets (note 7)	509,674	401,058
Long-term investments (note 8)
Investments carried at fair value	1,294,147	814,530
Other long-term investments	121,968	134,371
Derivative instruments (note 24)	72,221	53,192
Deferred income taxes (note 18)	30,585	72,415
Other assets (note 11)	58,708	28,584
Assets	10,911,470	9,398,589
Current liabilities:
Accounts payable	150,336	89,740
Accrued liabilities	307,952	235,586
Dividends payable (note 15)	73,945	62,613
Regulatory liabilities (note 7)	41,683	39,005
Long-term debt (note 9)	225,013	13,048
Other long-term liabilities (note 12)	57,939	42,337
Derivative instruments (note 24)	5,898	14,339
Other liabilities	9,300	2,313
Liabilities, current, total	872,066	498,981
Long-term debt (note 9)	3,706,855	3,323,747
Regulatory liabilities (note 7)	556,379	549,208
Deferred income taxes (note 18)	491,538	444,145
Derivative instruments (note 24)	78,766	88,503
Pension and other post-employment benefits obligation (note 10)	224,094	199,829
Other long-term liabilities (note 12)	243,401	255,668
Liabilities, noncurrent, total	5,301,033	4,861,100
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party (note 16(b))	305,863	307,622
Redeemable non-controlling interests	25,913	33,364
Equity:
Preferred shares (note 13(b))	184,299	184,299
Common shares (note 13(a))	4,017,044	3,562,418
Additional paid-in capital	50,579	45,553
Deficit	(367,107)	(595,259)
Accumulated other comprehensive loss (note 14)	(9,761)	(19,385)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	3,875,054	3,177,626
Non-controlling interests	457,834	519,896
Non-controlling interest, held by related party (note 16(c))	73,707	0
Non-controlling interests	531,541	519,896
Total equity	4,406,595	3,697,522
Commitments and contingencies (note 22)
Liabilities and equity, total	$ 10,911,470	$ 9,398,589

Consolidated Statement of Equit

Consolidated Statement of Equity - USD ($) $ in Thousands	Total	Common shares	Preferred shares	Additional paid-in capital	Accumulated deficit	Accumulated OCI	Non- controlling interests
Beginning Balance at Dec. 31, 2017	$ 3,320,100	$ 3,021,699	$ 184,299	$ 38,569	$ (524,311)	$ (2,792)	$ 602,636
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	79,089				184,988		(105,899)
Redeemable non-controlling interests not included in equity (note 17)	4,923						4,923
Other comprehensive income	(28,699)					(27,218)	(1,481)
Dividends declared and distributions to non-controlling interests	(197,283)				(187,890)		(9,393)
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii))	0	55,442			(55,442)
Share-based compensation	29,110						29,110
Issuance of subscription receipts	472,180	472,180
Issuance of common shares under employee share purchase plan	11,011			11,011
Common shares issued upon public offering, net of cost	4,784	12,650		(4,027)	(3,839)
Common shares issued upon conversion of convertible debentures (note 12(h))	447	447
Ending Balance at Dec. 31, 2018	3,697,522	3,562,418	184,299	45,553	(595,259)	(19,385)	519,896
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	484,950				530,884		(45,934)
Redeemable non-controlling interests not included in equity (note 17)	(7,476)						(7,476)
Other comprehensive income	11,866					9,438	2,428
Dividends declared and distributions to non-controlling interests	(255,155)				(217,464)		(37,691)
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii))	0	68,856			(68,856)
Share-based compensation	100,318						100,318
Common shares issued upon conversion of convertible debentures	148
Issuance of subscription receipts	364,211	364,211
Issuance of common shares under employee share purchase plan	2,853	2,853
Issuance of common shares under employee share purchase plan	12,974			12,974
Common shares issued upon public offering, net of cost	(5,616)	18,558		(7,948)	(16,226)
Ending Balance at Dec. 31, 2019	$ 4,406,595	$ 4,017,044	$ 184,299	$ 50,579	$ (367,107)	$ (9,761)	$ 531,541

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating Activities
Net earnings	$ 484,950	$ 79,089
Adjustments and items not affecting cash:
Depreciation and amortization	284,304	260,772
Deferred taxes	53,686	42,025
Unrealized gain on derivative financial instruments	(15,237)	(1,781)
Share-based compensation expense	11,042	7,495
Cost of equity funds used for construction purposes	(4,896)	(2,728)
Change in value of investments carried at fair value	(276,458)	137,957
Pension and post-employment contributions in excess of expense	(8,952)	(6,354)
Distributions received from equity investments, net of income	7,487	5,698
Others	15,031	16,305
Changes in non-cash operating items (note 23)	60,303	(8,126)
Net Cash Provided by (Used in) Operating Activities, Total	611,260	530,352
Financing Activities
Increase in long-term debt	3,614,758	2,015,533
Decrease in long-term debt	(3,048,008)	(1,699,592)
Issuance of common shares, net of costs	362,364	473,911
Cash dividends on common shares	(196,391)	(166,384)
Dividends on preferred shares	(8,486)	(8,027)
Contributions from non-controlling interests, related party (note 17)	96,752	305,000
Contributions from non-controlling interests and redeemable non-controlling interests (note 17)	3,403	15,250
Production-based cash contributions from non-controlling interest	3,565	13,860
Distributions to non-controlling interests, related party (note 16(b) and (c))	(38,718)	0
Distributions to non-controlling interests	(12,251)	(9,289)
Settlement of derivatives	(8,732)	0
Proceeds from exercise of share options	0	4,504
Shares surrendered to fund withholding taxes on exercised share options	(5,282)	(2,088)
Increase in other long-term liabilities	10,175	9,403
Decrease in other long-term liabilities	(39,783)	(20,144)
Net Cash Provided by (Used in) Financing Activities, Total	733,366	931,937
Investing Activities
Additions to property, plant and equipment and intangible assets	(581,332)	(466,369)
Increase in long-term investments	(669,832)	(1,005,072)
Acquisitions of operating entities	(308,423)	0
Increase in other assets	(16,690)	(5,912)
Receipt of principal on development loans receivable	251,118	17,950
Decrease in long-term investments	1,000	1,158
Proceeds from sale of long-lived assets	0	2,912
Net Cash Provided by (Used in) Investing Activities, Total	(1,324,159)	(1,455,333)
Effect of exchange rate differences on cash and restricted cash	1,032	(606)
Increase in cash, cash equivalents and restricted cash	21,499	6,350
Cash, cash equivalents and restricted cash, beginning of year	65,773	59,423
Cash, cash equivalents and restricted cash, end of year	87,272	65,773
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	171,548	155,309
Cash paid during the year for income taxes	14,543	9,652
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	98,231	45,154
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	87,414	65,767
Sale of property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	57,753	13,092
Convertible Debentures
Non-cash financing and investing activities:
Issuance of common shares upon conversion of convertible debentures	$ 155	$ 468

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Notes to the Consolidated Financial Statements	Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act . APUC's operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group . The Regulated Services Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States and Canada; the Renewable Energy Group

Significant accounting policies

Significant accounting policies	12 Months Ended
	Dec. 31, 2019
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 APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)). (c) Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years. 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. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. 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. (d) Accounting for rate regulated operations The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the public utility commission of the states and provinces in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’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”). 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations (continued) Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations. The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the Regulator and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation. (e) Cash and cash equivalents Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less. (f) Restricted cash Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC. (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, 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. (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 (note 7(e)) 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. 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 become 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. 1. Significant accounting policies (continued) (j) Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest . The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. 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 2019 2018 2019 2018 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 42 40 Equipment 5 - 44 5 - 43 10 10 The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. (k) Commonly owned facilities The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. (l) Impairment of long-lived assets APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. (m) Variable interest entities The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC 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. APUC has determined that both 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 APUC 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 entity, the Company is considered the primary beneficiary. Total net book value of generating assets and long-term debt of these facilities amounts to $60,230 (2018 - $59,288 ) and $21,754 (2018 - $22,263 ), respectively. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,108 (2018 - $17,232 ), operating expenses and amortization of $4,930 (2018 - $4,634 ) and interest expense of $2,340 (2018 - $2,557 ). (n) Long-term investments and notes receivable Investments in which APUC 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. APUC 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. APUC 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. 1. Significant accounting policies (continued) (n) Long-term investments and notes receivable (continued) 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 for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. (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 in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations.The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations. (p) Asset retirement obligations The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation. (q) Leases The Company adopted ASU 2016-02, Leases (Topic 842) ("ASC 842") during 2019 using a modified retrospective approach. The Company leases 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 to five years . As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised. 1. Significant accounting policies (continued) (q) Leases (continued) 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 Regulated Services Group enters into easement agreements for the operation of its utilities. For all easements that existed or were expired as of January 1, 2019, the practical expedient was taken to not change the legacy accounting for these easement contracts. For new easement contracts entered into subsequent to January 1, 2019, the Company considers whether they contain a lease. The implementation of ASC 842 did not have an impact on the Company's existing finance leases. The weighted-average discount rate as of December 31, 2019 for the Company's finance lease assets and liabilities is 6.45% and the weighted-average remaining lease term of the Company's finance leases is 5.55 years . New right-of-use assets and lease liabilities of $8,295 were recognized for the Company's operating leases as at January 1, 2019. As a result of the acquisition of Enbridge Gas New Brunswick Limited Partnership ("New Brunswick Gas") on October 1, 2019 (note 3(a)), the Company acquired new right-of-use assets and assumed lease liabilities of $1,316 . The weighted-average discount rate as of December 31, 2019 for the Company's operating lease assets and liabilities is 3.95% and the weighted-average remaining lease term is 13.49 years . 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 Company's operating leases payments for the next five years and thereafter are as follows: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total $ 2,115 $ 1,138 $ 688 $ 659 $ 642 $ 5,195 $ 10,437 The lease payments for the Company's finance leases are expected to be approximately $539 annually for the next five years, and $318 thereafter. (r) Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; a restricted share unit (“RSU”) plan and a performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares. (s) Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. 1. Significant accounting policies (continued) (s) Non-controlling interests (continued) Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Tax Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments. Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’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 The Company accounts for revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers , which was adopted on January 1, 2018 using the modified retrospective method, applied to contracts that were not completed at the date of initial application. The adoption of the new standard resulted in an adjustment of $2,488 or $1,860 net of taxes to increase opening retained earnings for previously deferred revenue related to the Empire fiber business. Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, "Segmented information" for details of revenue disaggregation by business units. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Regulated Services Group revenue Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water. Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant. Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, "Segmented information" and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset. Renewable Energy Group revenue Renewable Energy Group 's revenue consists primarily of the sale of electricity, capacity, and renewable energy credits. Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer. 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

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently issued accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued accounting standards update ("ASU") 2018-15, Intangibles — Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract to provide additional guidance to address diversity in practice. This update aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted this update prospectively as at the beginning of the third quarter. There were no significant impacts to the consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (" SOFR ") Overnight Index Swap (" OIS ") Rate as a Benchmark Interest Rate for Hedge Accounting Purposes to identify a suitable alternative to the U.S. dollar LIBOR that is more firmly based on actual transactions in a robust market. This update permits the use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. This update was adopted concurrently with ASU 2017-12. The Company will follow the pronouncements prospectively for qualifying new or redesignated hedging relationships. The FASB issued ASU 2018-07, Compensation — Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting to expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. This update changes the measurement basis and date of non-employee share-based payment awards and also makes amendments to how to measure non-employee awards with performance conditions. The adoption of this update in 2019 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities , to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The FASB also issued ASU 2019-04 that contains further codification improvements to ASU 2017-12. The adoption of these updates in 2019 resulted in a reclassification of $186 from retained earnings to accumulated other comprehensive income for previous hedge ineffectiveness recognized in earnings for outstanding hedging contracts. The Company has also made certain amendments and simplifications to hedge effectiveness testing procedures and documentation to be followed prospectively where applicable in accordance with the pronouncements in the update. 2. Recently issued accounting pronouncements (continued) (a) Recently adopted accounting pronouncements (continued) The FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception to address narrow issues with applying U.S. GAAP for certain financial instruments with characteristics of liabilities and equity. The adoption of this update in 2019 had no impact on the consolidated financial statements. The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The FASB also issued subsequent amendments to ASC 842 that provide further practical expedients as well as codification clarifications and improvements. The adoption of this new lease standard in 2019 using a modified retrospective approach resulted in an adjustment of $8,295 to right-of-use assets and operating lease liabilities included in other long-term liabilities on the consolidated balance sheets, with no restatement of the comparative period. The Company implemented new processes and procedures for the identification, analysis, and measurement of new lease contracts. A new software solution was implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company elected the following practical expedients as part of its adoption: 1. "Package of three" practical expedient that permits the Company not to reassess the scope, classification and initial direct costs of its expired and existing leases; 2. Land easements practical expedient that permits the Company not to reassess the accounting for land easements previously not accounted for under Leases ASC 840; and 3. Hindsight practical expedient that allows the Company to use hindsight in determining the lease term for existing contracts. In addition, the Company made an accounting policy election to not recognize a lease liability or right-of-use asset on its consolidated balance sheets for short-term leases (lease term less than 12 months). (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2020-01, Investments - Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to reduce diversity in practice and increase comparability of accounting for certain transactions. The amendments clarify when to consider observable price changes for the measurement of certain equity securities without a readily determinable fair value. They also clarify the scope of forward contracts and purchased options on these certain securities. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, including early adoption in any interim period. The Company currently does not have any transactions that would be within the scope of this update but will continue to assess the impact of this update in the future. The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes as part of its initiative to reduce complexity in the accounting standards. The amendments remove certain exceptions to the general principles in Topic 740 and improve consistent application for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, but all amendments must be early adopted simultaneously. The Company is currently assessing the impact of this update. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The update clarifies that the arrangement should be accounted for under ASC 606 when a participant is a customer in the context of a unit of account, adds unit of account guidance in ASC 808 that is consistent with ASC 606, and precludes the recognition of revenue from a collaborative arrangement with ASC 606 revenue if the participant is not directly related to sales to third parties. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those years. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The amendments in the update are effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years. The amendments are required to be applied retrospectively with a cumulative-effect adjustment to retained earnings. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current U.S. GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued codification improvements to ASC Topic 326 in ASU 2018-19 to provide guidance on scoping of operating lease assets and further specific clarifications and corrections in ASU 2019-04 and ASU 2019-11. The FASB issued further updates to Topic 326 in ASU 2019-05 and ASU 2020-02 to provide transition relief that allows companies to irrevocably elect the fair value option for certain instruments held at amortized cost, and to provide certain updates to the SEC paragraphs of the topic. The Company is finalizing its analysis on the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

Business acquisitions and devel

Business acquisitions and development projects	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Business acquisitions and development projects	Business acquisitions and development projects (a) Acquisition of Enbridge Gas New Brunswick Limited Partnership & St. Lawrence Gas Company Inc. The Company completed the acquisition of New Brunswick Gas on October 1, 2019, and St. Lawrence Gas Company, Inc. ("St. Lawrence Gas") on November 1, 2019. New Brunswick Gas is a regulated utility that provides natural gas. The purchase price is approximately $256,011 ( C$339,036 ). St. Lawrence Gas is a regulated utility that provides natural gas in northern New York State. The total purchase price for the transaction is $61,820 , and subject to certain closing adjustments. The costs related to the acquisitions have been expensed through the consolidated statements of operations. The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date: New Brunswick Gas St. Lawrence Gas Working capital $ 8,782 $ 3,403 Property, plant and equipment 137,668 49,936 Goodwill 56,054 20,259 Regulatory assets 94,827 3,562 Deferred income tax assets, net — 1,614 Other assets 125 6,418 Regulatory liabilities (2,076 ) (10,412 ) Pension and post-employment benefits — (12,376 ) Deferred income tax liability, net (38,053 ) — Other liabilities (1,316 ) (584 ) Total net assets acquired $ 256,011 $ 61,820 Cash and cash equivalent 7,248 1,225 Total net assets acquired, net of cash and cash equivalent $ 248,763 $ 60,595 The determination of the fair value of assets acquired and liabilities assumed is based upon management's preliminary estimates and certain assumptions. Due to the timing of the acquisitions, the Company has not finalized the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of assets acquired and liabilities assumed. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost savings in the delivery of certain shared administrative and other services. Property, plant and equipment, exclusive of computer software, are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of New Brunswick Gas and St. Lawrence Gas' assets is 47 years and 49 years, respectively. 3. Business acquisitions and development projects (continued) (b) Acquisition of Turquoise Solar Facility Liberty Utilities (Turquoise Holdings) LLC (“Turquoise Holdings”) is owned by Liberty Utilities (Calpeco Electric) LLC ("Calpeco Electric System"). The 10 MWac solar generating facility is located in Washoe County, Nevada ("Turquoise Solar Facility"). On May 24, 2019, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded $1,403 on the execution date and $2,000 on December 31, 2019. The final instalments are expected to be made in 2020. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Turquoise Solar Facility. Because the Class A tax equity investor has the right to withdraw from Turquoise Holdings and require the Company to redeem its remaining interests for cash, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets (note 17). Redemption is not considered probable as of December 31, 2019. On December 31, 2019, as the Turquoise Solar Facility was placed in service, Turquoise Holdings obtained control of the property, plant and equipment for a total purchase price of $20,830 . (c) Agreement to acquire Mid-West Wind Development Project The Empire District Electric Company ("Empire Electric System"), a wholly owned subsidiary of the Company, entered into purchase agreements to acquire, once completed, three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri ("Missouri Wind Projects") and in Neosho County, Kansas ("Kansas Wind Project"). The agreements contain development milestones and termination provisions that primarily apply prior to the commencement of construction. Total costs are estimated at $1,100,000 and the acquisitions are anticipated to close following completion of the respective projects. These assets, net of third-party tax equity investment, are expected to be included in the rate base of the Empire Electric System. In November 2019, Liberty Utilities Co, a wholly owned subsidiary of the Company, acquired an interest in the entities that own the two Missouri Wind Projects and, in partnership with a third-party developer, will continue development and construction of such projects until they are acquired by the Empire Electric System following completion. As part of the investment in the joint ventures, Liberty Utilities Co. entered into guarantee agreements for obligations under letters of credit, engineering and procurement contracts, and turbine supply agreements for the two projects. The Company accounts for its interest in these two projects using the equity method (note 8(d)). In November 2019, a tax equity agreement was executed for the Kansas Wind Project. The Class A partnership units will be owned by two third-party tax equity investors who have committed to fund on a future date. With their interests, the tax equity investors will receive the majority of the tax attributes associated with the Kansas Wind Project. Initial tax equity funding is expected to be received in Q1 2021. (d) Agreement to acquire New York American Water On November 20, 2019, the Company entered into an agreement to acquire American Water's regulated operations in the State of New York ("New York American Water"). New York American Water is a regulated water and wastewater utility serving customers across seven counties in southeastern New York. The total purchase price for the transaction is approximately $608,000 , subject to certain closing adjustments. The transaction is expected to close sometime in 2021 and remains subject to regulatory approval and other typical closing conditions. (e) Agreement to acquire Bermuda Electric Light Company On June 3, 2019, the Company entered into an agreement to acquire the Ascendant Group Limited ("Ascendant"), parent company of Bermuda Electric Light Company. Bermuda Electric Light Company is the sole electric utility providing regulated electrical generation, transmission and distribution services to Bermuda's residents and businesses. The total purchase price for the transaction is approximately $365,000 . Closing of the transaction remains subject to shareholder and regulatory approvals and is expected in 2020. 3. Business acquisitions and development projects (continued) (f) Approval to acquire the Perris Water Distribution System On August 10, 2017, the Company agreed to acquire two water distribution systems serving customers from the City of Perris, California. The anticipated purchase price of $11,500 is expected to be established as rate base during the regulatory approval process. The City of Perris residents voted to approve the sale on November 7, 2017. The Regulated Services Group filed an application requesting approval for the acquisition of the assets of the water utilities with the California Public Utility Commission on May 8, 2018. Final approval is expected in 2020. (g) Great Bay Solar Facilities The Great Bay Solar I and II Facilities are 75 and 40 MWac solar powered generating facilities in Somerset County, Maryland. Commercial operations as defined by the power purchase agreement was reached for all sites at the Great Bay Solar I Facility by March 29, 2018. As of December 31, 2019, one site at the Great Gay Solar II Facility has been fully synchronized with the power grid, while the remaining site is expected to be placed in service in early 2020. The Great Bay Solar I Facility is controlled by a subsidiary of APUC (Great Bay Holdings, LLC). The Class A partnership units are owned by a third-party tax equity investor who funded $42,750 in 2017 with the remaining amount of $15,250 received in 2018. Through its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as "Non-controlling interest" on the consolidated balance sheets. The Great Bay Solar II Facility is controlled by Great Bay Holdings, LLC. Liberty Utilities (America) Holdco, a subsidiary of APUC, is the tax equity investor for the facility and contributed initial funding of $11,281 in December 2019. The facility generated an investment tax credit of $8,526 during the year, which was recorded by the Company as a reduction to income tax expense in the consolidated statement of operations.

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivable Accounts receivable as of December 31, 2019 include unbilled revenue of $80,295 ( 2018 - $79,742 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2019 are presented net of allowance for doubtful accounts of $4,939 ( 2018 - $5,281 ).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2019 Cost Accumulated depreciation Net book value Generation $ 2,816,611 $ 540,118 $ 2,276,493 Distribution and transmission 4,988,297 598,449 4,389,848 Land 74,517 — 74,517 Equipment and other 94,583 47,541 47,042 Construction in progress Generation 140,235 — 140,235 Distribution and transmission 303,529 — 303,529 $ 8,417,772 $ 1,186,108 $ 7,231,664 5. Property, plant and equipment (continued) 2018 Cost Accumulated Net book Generation $ 2,470,279 $ 450,230 $ 2,020,049 Distribution and transmission 4,455,935 521,236 3,934,699 Land 73,773 — 73,773 Equipment and other 88,757 41,295 47,462 Construction in progress Generation 104,996 — 104,996 Distribution and transmission 212,579 — 212,579 $ 7,406,319 $ 1,012,761 $ 6,393,558 Generation assets include cost of $109,653 ( 2018 - $104,107 ) and accumulated depreciation of $39,638 ( 2018 - $34,916 ) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,615 ( 2018 - $1,987 ). Distribution and transmission assets include the following: • Cost of $ 1,450,946 ( 2018 - $1,383,960 ) and accumulated depreciation of $ 97,080 ( 2018 - $69,960 ) related to regulated generation and transmission assets. • Cost of $514,709 ( 2018 - $503,664 ) and accumulated depreciation of $31,349 ( 2018 - $21,697 ) related to commonly owned facilities (note 1(k)). Total expenditures incurred on these facilities for the year ended December 31, 2019 were $69,210 ( 2018 - $75,427 ). • Cost of $3,076 ( 2018 - $3,076 ) and accumulated depreciation of $1,003 ( 2018 - $669 ) related to assets under finance lease. • Expansion costs of $1,000 on which the Company does not currently earn a return. For the year ended December 31, 2019, contributions received in aid of construction of $7,137 ( 2018 - $6,057 ) have been credited to the cost of the assets. Interest and AFUDC capitalized to the cost of the assets in 2019 and 2018 are as follows: 2019 2018 Interest capitalized on non-regulated property $ 4,538 $ 2,268 AFUDC capitalized on regulated property: Allowance for borrowed funds 2,745 1,684 Allowance for equity funds 4,896 2,728 Total $ 12,179 $ 6,680

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2019 Cost Accumulated amortization Net book value Power sales contracts $ 56,206 $ 38,931 $ 17,275 Customer relationships 26,797 10,104 16,693 Interconnection agreements 14,827 1,179 13,648 $ 97,830 $ 50,214 $ 47,616 6. Intangible assets and goodwill (continued) 2018 Cost Accumulated Net book Power sales contracts $ 60,775 $ 36,063 $ 24,712 Customer relationships 26,795 9,476 17,319 Interconnection agreements 13,847 — 884 12,963 $ 101,417 $ 46,423 $ 54,994 Estimated amortization expense for intangible assets for the next year is $2,018 , $2,190 in year two, $2,350 in year three, $1,910 in year four and $1,780 in year five. All goodwill pertains to the Regulated Services Group . Balance, December 31, 2018 and 2017 $ 954,282 Business acquisitions (note 3(a)) 76,313 Foreign exchange 1,101 Balance, December 31, 2019 $ 1,031,696

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory matters	Regulatory matters The operating companies within the Regulated Services Group are subject to regulation by the public utility commissions of the states and provinces in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. 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. During 2019, the Company completed the acquisition of New Brunswick Gas and St. Lawrence Gas, operating public utilities engaged in the distribution of natural gas in the Province of New Brunswick and the state of New York, respectively. New Brunswick Gas is subject to regulation by the New Brunswick Energy and Utilities Board. St. Lawrence Gas is subject to regulation by the New York Public Service Commission. In general, the commissions set rates at a level that allows the utilities to collect total revenues or revenue requirements equal to the cost of providing service, plus an appropriate return on invested capital. At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed: Utility State Regulatory proceeding type Annual revenue increase Effective date Peach State Gas System Georgia Georgia Rate Adjustment mechanism $2,367 February 1, 2019 New England Natural Gas System Massachusetts Gas System Enhancement Plan $2,413 May 1, 2019 Empire Electric System Kansas General Rate Review $2,449 August 1, 2019 Empire Electric System Oklahoma General Rate Review $1,400 October 1, 2019 CalPeco Electric System California Catastrophic Events Memorandum Account $3,525 January 1, 2020 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2019 2018 Regulatory assets Environmental remediation (a) $ 82,300 $ 82,295 Pension and post-employment benefits (b) 143,292 135,580 Income taxes (c) 71,506 34,822 Debt premium (d) 42,150 48,847 Fuel and commodity cost adjustments (e) 23,433 26,310 Rate adjustment mechanism (f) 69,121 37,202 Clean Energy and other customer programs (g) 26,369 24,095 Deferred capitalized costs (h) 38,833 13,986 Asset retirement obligation (i) 23,841 21,048 Long-term maintenance contract (j) 13,264 8,283 Rate review costs (k) 6,695 6,164 Other 19,083 21,463 Total regulatory assets $ 559,887 $ 460,095 Less: current regulatory assets (50,213 ) (59,037 ) Non-current regulatory assets $ 509,674 $ 401,058 Regulatory liabilities Income taxes (c) $ 321,960 $ 323,384 Cost of removal (l) 196,423 193,564 Rate base offset (m) 8,719 10,900 Fuel and commodity costs adjustments (e) 16,645 21,352 Rate adjustment mechanism (f) 10,446 4,210 Deferred capitalized costs - fuel related (h) 7,097 7,258 Pension and post-employment benefits (b) 22,256 11,791 Other 14,516 15,754 Total regulatory liabilities $ 598,062 $ 588,213 Less: current regulatory liabilities (41,683 ) (39,005 ) Non-current regulatory liabilities $ 556,379 $ 549,208 7. Regulatory matters (continued) (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems' and St. Lawrence Gas system's pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods. (c) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. On June 1, 2018, the State of Missouri enacted legislation that, effective for tax years beginning on or after January 1, 2020, reduces the corporate income tax rate from 6.25% to 4% , among other legislative changes. A reduction of regulatory asset and an increase to regulatory liability were recorded for excess deferred taxes probable of being refunded to customers of $15,586 . (d) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (e) Fuel and commodity cost adjustments The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. (f) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, and EnergyNorth Natural Gas System is subject to a revenue decoupling mechanism approved by their respective regulator, which requires charging 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 recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 25 years . (g) Clean Energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. 7. Regulatory matters (continued) (h) Deferred capitalized costs Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years . (i) 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. (j) Long-term maintenance contract To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. (k) Rate review costs The costs to file, prosecute and defend rate review applications are referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (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 tracks the amounts that have been collected from customers net of costs incurred to date. (m) Rate base offset The regulators imposed a rate base offset that will reduce the revenue requirement at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years. As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate review costs.

Long-term investments

Long-term investments	12 Months Ended
	Dec. 31, 2019
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: 2019 2018 Long-term investments carried at fair value Atlantica (a) $ 1,178,581 $ 814,530 AYES Canada (b) 88,494 — San Antonio Water System (c) 27,072 — $ 1,294,147 $ 814,530 Other long-term investments Equity-method investees (d) $ 83,770 $ 29,588 Development loans receivable from equity-method investees (e) 36,204 101,417 Other 1,994 4,773 Total other long-term investments $ 121,968 $ 135,778 Less: current portion — (1,407 ) $ 121,968 $ 134,371 8. Long-term investments (continued) Income (loss) from long-term investments from the years ended December 31, 2019 and 2018 is as follows: Year ended December 31 2019 2018 Fair value gain (loss) on investments carried at fair value Atlantica $ 290,740 $ (137,957 ) AYES Canada (6,649 ) — San Antonio Water System (6,007 ) — $ 278,084 $ (137,957 ) Dividend and interest income from investments carried at fair value Atlantica $ 69,307 $ 39,263 AYES Canada 25,572 — San Antonio Water System 6,007 — $ 100,886 $ 39,263 Other long-term investments Equity method loss (9,108 ) (3,082 ) Interest and other income 29,230 16,958 $ 399,092 $ (84,818 ) (a) Investment in Atlantica AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by APUC, has a share ownership in Atlantica Yield plc ("Atlantica") of approximately 44.2% (December 31, 2018 - 41.5% ). APUC has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5% . In 2019, the Company purchased 1,384,402 treasury shares of Atlantica for cash consideration of $30,000 . In addition, 2,000,000 shares were received pursuant to a prepayment of $53,750 . Subsequent to year-end, the prepayment purchase agreement settled with no material cash difference. During 2018, APUC purchased from Abengoa S.A. ("Abengoa") a 41.5% equity interest in Atlantica through two transactions for a total purchase price of $952,567 , with a holdback of $40,000 of which $29,100 was settled in 2019 with the balance payable at a later date, subject to certain conditions. 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. On November 28, 2018 , Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”), an equity investee of the Company, obtained a three -year secured credit facility in the amount of $306,500 and subscribed to a $305,000 preference share ownership interest in AY Holdings. The subscription proceeds were distributed by AY Holdings to the Company and used by the Company to repay the $305,000 of temporary financing used for the 2018 investment in Atlantica. The AAGES B.V. secured credit facility is collateralized through a pledge of the Atlantica shares held by AY Holdings. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the lenders would have the right to sell Atlantica stock to eliminate the collateral shortfall. The AAGES B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest held by related party (note 17). 8. Long-term investments (continued) (b) Investment in AYES Canada On May 24, 2019 , APUC and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. ("AYES Canada"), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. ("Windlectric"). APUC invested $ 91,918 (C$ 123,603 ) and Atlantica invested $ 4,834 (C$ 6,500 ) in AYES Canada, which in turn invested those funds in Amherst Island Partnership ("AIP"), the holding company of Windlectric. APUC continues to control and consolidate AIP and Windlectric. The investment of $ 96,752 (C$ 130,103 ) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. The Company incurred non-controlling interest calculated using the HLBV method of accounting of $ nil and recorded distributions of $26,465 ( C$34,373 ) during the year. AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, APUC's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, APUC has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment. For the year, APUC recorded dividend income of $ 25,572 and a fair value loss of $ 6,649 on its investment in AYES Canada. As at December 31, 2019 , the Company's maximum exposure to loss is $ 88,494 , which represents the fair value of the investment. (c) San Antonio Water System On May 1, 2019 , APUC invested $ 17,000 by way of a secured loan into AWUSA VR Holding LLC ("AWUSA"), a wholly owned subsidiary of Abengoa. An additional amount of $ 5,000 plus interest is payable at a later date, subject to certain conditions. The loan is secured by AWUSA's investment in the Vista Ridge water pipeline project. The Vista Ridge water pipeline project is a 140 mile water pipeline from Burleson County, Texas, to San Antonio, Texas. Since APUC has the power to direct the activities of AWUSA and benefits from the economics of this entity, the Company consolidates AWUSA. AWUSA's 20% interest in Vista Ridge is accounted for using the equity method. On December 30, 2019 , the Company and a third-party developer each contributed C $1,500 to the capital of a new joint venture, created for the purpose of developing infrastructure investment opportunities. The Company sold its investment in AWUSA to the joint venture in exchange for a loan receivable of $30,293 . A note payable to AWUSA of $13,293 was recognized by the Company upon deconsolidation of AWUSA. The Company holds an option exercisable at any time to acquire the remaining interest at a pre-agreed price. The sale was accounted for in accordance with ASC 860, Transfers and Servicing and no gain or loss was recognized. The joint venture is considered to be a VIE due to insufficient equity at risk to finance its operations with additional subordinated financial support. Neither APUC nor the third-party developer is considered to be the primary beneficiary since each party holds 50% voting and economic interests. Accordingly, APUC's investment in the joint venture is considered an equity method investment. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach was used to estimate the fair value of the investment. For the year, APUC recorded interest income of $6,007 and a fair value loss of $6,007 on its investment in the joint venture. As of December 31, 2019 , the Company’s maximum exposure to loss is $27,072 , which represents the fair value of the investment. 8. Long-term investments (continued) (d) Equity-method investees The Company has non-controlling interests in various partnerships and joint ventures with a total carrying value of $83,770 (2018 - $29,588 ) including investments in VIEs of $59,091 (2018 - $9,581 ). The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method. The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa in 2018; Sugar Creek, a 202 MW wind power development project in Logan County, Illinois; Maverick, a 490 MW wind project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia, and two approximately 150 MW wind projects in southwestern Missouri. On April 16, 2019, the Company acquired the remaining 50% interest in Windlectric which owns a 75 MW wind generating facility ("Amherst Island Wind Facility") in the Province of Ontario for $6,362 . Prior to this acquisition, APUC's 50% interest in Windlectric was recorded as an equity investment. As a result of obtaining control of the facility, the transaction was treated as an asset acquisition. APUC recorded the fair value on that date for property, plant and equipment acquired of $311,175 , deferred tax asset of $3,015 , working capital of $14,280 and liabilities of $1,600 for asset retirement obligation assumed; and, derecognized the existing development loan between the two parties of $316,786 (note 8(e)). Summarized combined information for APUC's investments in significant partnerships and joint ventures is as follows: 2019 2018 Total assets $ 833,791 $ 360,372 Total liabilities 697,751 335,331 Net assets 136,040 25,041 APUC's ownership interest in the entities 63,624 18,042 Difference between investment carrying amount and underlying equity in net assets (a) 18,487 11,048 APUC's investment carrying amount for the entities $ 82,111 $ 29,090 (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 and transaction costs. Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances (note 8(e)) and credit support in amounts necessary for the continued development and construction of the equity investees' projects. As of December 31, 2019 , the Company had issued letters of credit and guarantees of obligations under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; equity capital contribution agreements; landowner agreements; and bridge loan agreements. The fair value of the support provided recorded as at December 31, 2019 amounts to $9,493 (2018 - $1,682 ). The Company is not considered the primary beneficiary of these entities as the partners have joint control and all decisions must be unanimous. Therefore, the Company accounts for its interest in these VIEs using the equity method. 8. Long-term investments (continued) (d) Equity-method investees (continued) Summarized combined information for APUC's VIEs is as follows: 2019 2018 APUC's maximum exposure in regards to VIEs Carrying amount $ 59,091 $ 9,581 Development loans receivable (e) 35,000 101,417 Commitments on behalf of VIEs 1,364,871 120,669 $ 1,458,962 $ 231,667 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. (e) Development loans receivable from equity investees The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated 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 bear interest at a weighted average annual rate of 7.66% ( 2018 - 9.90% ) on outstanding principal and generally mature on the commercial operation date.

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-term debt	Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2019 2018 Senior unsecured revolving credit facilities (a) — 2023-2024 N/A $ 141,577 $ 97,000 Senior unsecured bank credit facilities (b) — 2020 N/A 75,000 321,807 Commercial paper (c) — 2020 N/A 218,000 6,000 U.S. dollar borrowings Senior unsecured notes 4.09 % 2020-2047 $ 1,225,000 1,219,579 1,218,680 Senior unsecured utility notes 6.00 % 2020-2035 $ 217,000 233,686 240,161 Senior secured utility bonds 4.75 % 2020-2044 $ 662,500 672,337 676,697 Canadian dollar borrowings Senior unsecured notes (d) 4.48 % 2021-2029 C$ 950,669 728,679 474,764 Senior secured project notes 10.22 % 2020-2027 C$ 28,503 21,961 22,915 $ 3,310,819 $ 3,058,024 Subordinated U.S. dollar borrowings Subordinated unsecured notes (e) 6.50 % 2078-2079 $ 637,500 621,049 278,771 $ 3,931,868 $ 3,336,795 Less: current portion (225,013 ) (13,048 ) $ 3,706,855 $ 3,323,747 Short-term obligations of $377,015 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. 9. Long-term debt (continued) Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities. Recent financing activities: (a) Senior unsecured revolving credit facilities On October 24, 2019 , the Company entered into a new $75,000 uncommitted bilateral letter of credit facility. The facility matures on October 24, 2020 . On July 12, 2019 , the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024 . The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread. The existing C $165,000 credit facility was canceled. On February 23, 2018 , the Regulated Services Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023 . Concurrent with this amendment, the Regulated Services Group closed Empire's credit facility. The Regulated Services Group's credit facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire. During 2018 , the Renewable Energy Group extended the maturity of its senior unsecured revolving bank credit facility from October 6, 2022 to October 6, 2023 . On February 16, 2018 , the Renewable Energy Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 202 1. Subsequent to year-end, on February 24, 2020, the Renewable Energy Group increased its uncommitted Renewable Energy LC Facility to $350,000 and extended the maturity to June 30, 2021. (b) Senior unsecured bank credit facilities On June 27, 2019 , the Regulated Services Group extended the maturity of its $135,000 term loan to July 6, 2020 . During the year, the Company repaid $60,000 of the facility. On March 7, 2018 , the Company drew $600,000 under a new term credit facility. The balance was repaid in 2018 except for a balance of $186,807 , which was repaid on May 23, 2019 . (c) Commercial paper On July 1, 2019 , the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group's bank credit facility. (d) Canadian dollar senior unsecured notes Subsequent to year-end, on February 14, 2020 , the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050 . The debentures are redeemable at the option of the Company at any time at a predetermined price. On January 29, 2019 , the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029 . The notes were sold at a price of C$99.952 per C$100.00 principal amount. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C $135,000 (note 24(b)(ii)). On July 25, 2018 , the Company repaid, upon its maturity, a C $135,000 unsecured note. (e) Subordinated unsecured notes On May 23, 2019 , the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes ("subordinated notes") maturing on July 1, 2079 . Concurrent with the offering, the Company entered into a cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars. 9. Long-term debt (continued) (e) Subordinated unsecured notes (continued) Beginning on July 1, 2024 , and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01% , payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029 , and on every interest reset date until July 1, 2049 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26% , payable in arrears. Beginning on July 1, 2049 , and on every interest reset date until July 1, 2079 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01% , payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024 , the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. On October 17, 2018 , the Company completed the issuance of $287,500 unsecured, 6.875% fixed-to-floating subordinated notes (“subordinated notes”) maturing on October 17, 2078 . Beginning on October 17, 2023 , and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until October 17, 2028 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.677% , payable in arrears. Beginning on October 17, 2028 , and on every interest reset date until October 17, 2043, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.927% , payable in arrears. Beginning on October 17, 2043 , and on every interest reset date until October 17, 2078 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.677% , payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after October 17, 2023 , the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. As of December 31, 2019 , the Company had accrued $44,229 in interest expense ( 2018 - $33,822 ). Interest expense on the long-term debt, net of capitalized interest, in 2019 was $175,664 ( 2018 - $146,310 ). Principal payments due in the next five years and thereafter are as follows: 2020 2021 2022 2023 2024 Thereafter Total $ 602,028 $ 117,513 $ 351,227 $ 97,478 $ 215,743 $ 2,547,916 $ 3,931,905

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Pension and other post-retirement benefits	Pension and other post-employment benefits The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2019 were $8,798 ( 2018 - $8,446 ). In conjunction with the utility acquisitions, the Company assumes defined benefit pension, supplemental executive retirement plans and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2019 2018 2019 2018 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 484,707 $ 531,694 $ 168,325 $ 176,975 Projected benefit obligation assumed from business combination 20,196 — 11,646 — Modifications to plans (7,705 ) — — — Service cost 12,351 15,481 4,587 5,791 Interest cost 20,222 19,077 7,575 6,727 Actuarial (gain) loss 65,443 (29,986 ) 33,605 (14,800 ) Contributions from retirees — — 1,913 1,878 Gain on curtailment — (1,875 ) — — Medicare Part D — — 414 42 Benefits paid (30,244 ) (49,684 ) (8,848 ) (8,288 ) Projected benefit obligation, end of year $ 564,970 $ 484,707 $ 219,217 $ 168,325 Change in plan assets Fair value of plan assets, beginning of year 339,099 403,945 115,542 130,487 Plan assets acquired in business combination 8,004 — 15,688 — Actual return on plan assets 68,025 (36,987 ) 25,464 (10,603 ) Employer contributions 22,190 21,825 8,628 2,026 Medicare Part D subsidy receipts — — 414 42 Benefits paid (30,244 ) (49,684 ) (6,863 ) (6,410 ) Fair value of plan assets, end of year $ 407,074 $ 339,099 $ 158,873 $ 115,542 Unfunded status $ (157,896 ) $ (145,608 ) $ (60,344 ) $ (52,783 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) — — 8,437 3,161 Current liabilities (1,415 ) (873 ) (1,168 ) (850 ) Non-current liabilities (156,481 ) (144,735 ) (67,613 ) (55,094 ) Net amount recognized $ (157,896 ) $ (145,608 ) $ (60,344 ) $ (52,783 ) The accumulated benefit obligation for the pension plans was $526,517 and $439,458 as of December 31, 2019 and 2018 , 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 2019 2018 2019 2018 Accumulated benefit obligation $ 504,403 $ 439,458 $ 202,422 $ 163,375 Fair value of plan assets $ 407,074 $ 339,099 $ 133,711 $ 107,430 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2019 2018 2019 2018 Projected benefit obligation $ 564,971 $ 476,791 $ 202,422 $ 163,375 Fair value of plan assets $ 407,074 $ 339,099 $ 133,711 $ 107,430 In 2019, the Company merged the Empire pension plan into the Company's cash balance plan and defined benefit plans, and changed benefits for certain Empire participants. The total impact of these plan amendments resulted in a decrease to the projected benefit obligation of $7,798 , which is recorded as a prior service credit in OCI. In 2018, the Company permanently froze the accrual of benefits for participants in the Park Water System's existing pension plan. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of $1,875 , which is recorded as a prior service credit in OCI. (b) Pension and post-employment actuarial changes Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2018 $ 25,128 $ (4,995 ) $ (3,182 ) $ (470 ) Additions to AOCI 34,916 (1,875 ) 3,254 — Amortization in current period (1,074 ) 649 272 262 Loss on plan settlements $ (2,547 ) $ — $ — $ — Reclassification to regulatory accounts (note 7(b)) (22,166 ) — (14,232 ) — Balance, December 31, 2018 $ 34,257 $ (6,221 ) $ (13,888 ) $ (208 ) AOCI from business acquisition — (285 ) — — Additions to AOCI 17,905 (7,705 ) 14,871 — Amortization in current period (3,530 ) 784 409 208 Reclassification to regulatory accounts (note 7(b)) (10,122 ) 7,247 (10,538 ) — Balance, December 31, 2019 $ 38,510 $ (6,180 ) $ (9,146 ) $ — The movements in AOCI for Empire's and St. Lawrence Gas' pension and OPEB plans are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(b)). 10. Pension and other post-employment benefits (continued) (c) Assumptions Weighted average assumptions used to determine net benefit obligation for 2019 and 2018 were as follows: Pension benefits OPEB 2019 2018 2019 2018 Discount rate 3.19 % 4.19 % 3.29 % 4.26 % Interest crediting rate (for cash balance plans) 4.48 % 4.43 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.125 % 6.25 % Age 65 and after 6.125 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031 The mortality assumption for December 31, 2019 was updated to Pri-2012 mortality table and to the projected generationally scale MP-2019, adjusted to reflect the ultimate improvement rates in the 2019 Social Security Administration intermediate assumptions. In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate. The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations. Weighted average assumptions used to determine net benefit cost for 2019 and 2018 were as follows: Pension benefits OPEB 2019 2018 2019 2018 Discount rate 4.19 % 3.57 % 4.25 % 3.60 % Expected return on assets 6.87 % 7.13 % 6.51 % 6.52 % Rate of compensation increase 4.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.25 % Age 65 and after 6.25 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2024 10. Pension and other post-employment benefits (continued) (d) Benefit costs The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2019 2018 2019 2018 Service cost $ 12,351 $ 15,481 $ 4,587 $ 5,791 Non-service costs Interest cost 20,222 19,077 7,575 6,727 Expected return on plan assets (20,485 ) (27,820 ) (6,725 ) (7,451 ) Amortization of net actuarial loss (gain) 3,530 1,074 (409 ) (272 ) Amortization of prior service credits (784 ) (649 ) (208 ) (262 ) Amortization of regulatory assets/liabilities 12,082 10,584 2,534 3,982 $ 14,565 $ 2,266 $ 2,767 $ 2,724 Net benefit cost $ 26,916 $ 17,747 $ 7,354 $ 8,515 (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 68 % 50% - 78% Debt securities 32 % 22% - 50% 100 % The fair values of investments as of December 31, 2019 , by asset category, are as follows: Asset class Level 1 Percentage Equity securities $ 414,985 73 % Debt securities 141,229 25 % Other 9,732 2 % $ 565,946 100 % As of December 31, 2019 , the funds do not hold any material investments in APUC. (f) Cash flows The Company expects to contribute $24,140 to its pension plans and $5,736 to its post-employment benefit plans in 2020. The expected benefit payments over the next ten years are as follows: 2020 2021 2022 2023 2024 2025 — 2029 Pension plan $ 34,461 $ 34,385 $ 35,383 $ 36,897 $ 37,848 $ 192,648 OPEB 7,469 7,867 8,379 8,903 9,361 52,864

Other assets

Other assets	12 Months Ended
	Dec. 31, 2019
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2019 2018 Restricted cash $ 24,787 $ 18,954 OPEB plan assets (note 10(a)) 8,437 3,161 Atlantica related prepaid amount (note 8(a)) 8,844 — Long-term deposits 6,319 1,207 Income taxes recoverable 4,416 1,961 Deferred financing costs 5,477 4,449 Other 8,192 4,967 $ 66,472 $ 34,699 Less: current portion (7,764 ) (6,115 ) $ 58,708 $ 28,584

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2019 2018 Advances in aid of construction (a) $ 60,828 $ 63,703 Environmental remediation obligation (b) 58,061 55,621 Asset retirement obligations (c) 53,879 43,291 Customer deposits (d) 31,946 29,974 Unamortized investment tax credits (e) 18,234 17,491 Deferred credits (f) 18,952 42,711 Preferred shares, Series C (g) 13,793 13,418 Lease liabilities (note 1(q)) 9,695 3,436 Other (h) 35,952 28,360 $ 301,340 $ 298,005 Less: current portion (57,939 ) (42,337 ) $ 243,401 $ 255,668 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2019, $5,465 (2018 - $3,687 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. 12. Other long-term liabilities (continued) (b) Environmental remediation obligation (continued) The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $58,484 (2018 - $59,181 ), which at discount rates ranging from 1.7% to 2.1% represents the recorded accrual of $58,061 as of December 31, 2019 (2018 - $55,621 ). Approximately $36,382 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years. Changes in the environmental remediation obligation are as follows: 2019 2018 Opening balance $ 55,621 $ 54,322 Remediation activities (1,678 ) (2,163 ) Accretion 1,065 1,479 Changes in cash flow estimates 981 4,051 Revision in assumptions 2,072 (2,068 ) Closing balance $ 58,061 $ 55,621 By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2019, the Company has reflected a regulatory asset of $82,300 (2018 - $82,295 ) for the MGP and related sites (note 7(a)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and Polychlorinated Biphenyls "PCB" contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants and (vi) remove asbestos upon major renovation or demolition of structures and facilities. Changes in the asset retirement obligations are as follows: 2019 2018 Opening balance $ 43,291 $ 44,166 Obligation assumed from business acquisition and constructed projects 3,226 225 Retirement activities (443 ) (5,130 ) Accretion 2,148 1,974 Change in cash flow estimates 5,657 2,056 Closing balance $ 53,879 $ 43,291 As the cost of retirement of utility assets, liability accretion and asset depreciation expense are expected to be recovered through rates, a corresponding regulatory asset is recorded (note 7(j)). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. 12. Other long-term liabilities (continued) (f) Deferred credits During the year, the Company settled $29,100 of contingent consideration related to the Company's investment in Atlantica (note 8(a)), and recorded an additional $ 5,000 contingent consideration related to the Company's investment in the San Antonio Water System (note 8(c)). (g) Preferred shares, Series C APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share. As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2020 $ 1,035 2021 1,050 2022 1,070 2023 1,243 2024 1,454 Thereafter to 2031 9,439 Redemption amount 4,111 $ 19,402 Less: amounts representing interest (5,609 ) $ 13,793 Less current portion (1,035 ) $ 12,758 (h) Other Convertible debentures As at December 31, 2019, the carrying value of the convertible debentures was $342 (2018 - $470 ). The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per C$1,000 principal amount of convertible debentures. The debentures are convertible at a price of C $10.60 per share into up to 44,130 common shares. During the year ended December 31, 2019 , $148 (2018 - $447 ) of principal converted to 19,429 (2018 - 56,926

Shareholders' capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2019 2018 Common shares, beginning of year 488,851,433 431,765,935 Public offering (a)(i) and (a)(ii) 28,009,341 50,041,624 Dividend reinvestment plan (a)(iii) 6,068,465 5,880,843 Exercise of share-based awards (c) 1,274,655 1,106,105 Conversion of convertible debentures (note 12(h)) 19,429 56,926 Common shares, end of year 524,223,323 488,851,433 Authorized APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares. The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2022. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan. (i) Public offering In October 2019, APUC issued 26,252,542 common shares at $13.50 per share pursuant to a public offering for proceeds of $354,409 before issuance costs of $14,418 . On December 20, 2018, APUC issued 12,536,350 common shares at $10.09 (C $13.76 ) per share pursuant to a public offering for proceeds of $126,485 ( C$172,500 ) before issuance costs of $366 ( C$492 ). On April 24, 2018, APUC issued 37,505,274 common shares at $9.23 (C $11.85 ) per share pursuant to a public offering for gross proceeds of $346,458 (C $444,437 ) before issuance costs of $590 ( C$765 ). (ii) At-the-market equity program On February 28, 2019, APUC established an at-the-market equity program ("ATM program") that allows the Company to issue up to $250,000 of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. During the year, the Company issued 1,756,799 common shares under the ATM program at an average price of $12.54 per common share for gross proceeds of $22,034 ( $21,704 net of commissions). Other related costs, primarily related to the establishment of the ATM program, were $2,122 . (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 1,244,696 common shares under the dividend reinvestment plan. 13. Shareholders’ capital (continued) (b) Preferred shares APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2019 and 2018 : Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $ Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463 Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836 $ 184,299 The holders of Series A and Series D preferred shares had the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. Neither the Series A nor the Series B preferred shares were converted on December 31, 2018 and March 31, 2019 respectively. The holders of Series A preferred shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2018 was an annual amount of C $1.125 per share. The dividend rate for the five-year period from and including December 31, 2018 to but excluding December 31, 2023 will be $1.2905 . The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five -year Government of Canada bond yield plus 2.94% . The Series A preferred shares are redeemable at C $25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter. The holders of Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C $1.25 per share for each year up to, but excluding, March 31, 2019. The dividend for the five-year period from and including March 31, 2019 to, but excluding, March 31, 2024 will be C $1.2728 . The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five -year Government of Canada bond plus 3.28% . The Series D preferred shares are redeemable at C $25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter. The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(g)). (c) Share-based compensation For the year ended December 31, 2019 , APUC recorded $10,553 (2018 - $9,458 ) in total share-based compensation expense detailed as follows: 2019 2018 Share options $ 1,288 $ 2,054 Director deferred share units 798 714 Employee share purchase 322 312 Performance and restricted share units 8,145 6,378 Total share-based compensation $ 10,553 $ 9,458 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) The compensation expense is recorded as part of administrative 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, 2019 , total unrecognized compensation costs related to non-vested options and PSUs were $1,252 and $12,750 , respectively, and are expected to be recognized over a period of 1.68 and 1.86 years, respectively. (i) Share option plan The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted. The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or 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 shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on APUC shares. The following assumptions were used in determining the fair value of share options granted: 2019 2018 Risk-free interest rate 1.9 % 2.1 % Expected volatility 20 % 21 % Expected dividend yield 4.3 % 4.8 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 1.66 C$ 1.41 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (i) Share option plan (continued) Share option activity during the years is as follows: Number of awards Weighted average exercise price Weighted average remaining contractual term (years) Aggregate intrinsic value Balance, January 1, 2018 6,738,856 C$ 11.18 6.32 C$ 19,380 Granted 1,166,717 12.80 8.00 — Exercised (1,589,211 ) 10.66 5.02 5,059 Forfeited (23,720 ) 12.80 — — Balance, December 31, 2018 6,292,642 C$ 11.61 5.75 C$ 13,342 Granted 1,113,775 14.96 8.00 — Exercised (3,882,505 ) 11.23 4.45 6,225 Forfeited — — — — Balance, December 31, 2019 3,523,912 C$ 13.09 5.87 C$ 18,609 Exercisable, December 31, 2019 1,735,241 C$ 12.57 5.43 C$ 14,559 Subsequent to year-end, on February 19, 2020, 394,939 stock options were exercised at a weighted average price of C $12.77 in exchange for 115,517 common shares issued from treasury, and 279,422 options settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options. (ii) Employee share purchase plan Under the Company’s employee share purchase plan (“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 APUC under the ESPP shall not exceed 2,000,000 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, 2019 , a total of 253,538 common shares ( 2018 - 252,698 ) were issued to employees under the ESPP. (iii) Director's deferred share units Under the Company’s deferred share unit plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2019 , 460,418 ( 2018 - 380,656 ) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by APUC under the DSU plan shall not exceed 1,000,000 common shares. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (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 will be calculated based on established performance criteria. At the end of the three -year performance periods, the number of common shares issued can range from 2.0% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by APUC under the PSU and RSU Plan shall not exceed 7,000,000 common shares. Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date. A summary of the PSUs and RSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance, January 1, 2018 955,028 C$ 12.30 1.84 C$ 13,428 Granted, including dividends 791,524 12.41 2.00 10,098 Exercised (285,551 ) 10.02 — 3,691 Forfeited (68,869 ) 13.02 — — Balance, December 31, 2018 1,392,132 C$ 12.75 1.60 C$ 19,114 Granted, including dividends 1,471,442 14.69 2.00 16,302 Exercised (344,340 ) 11.55 — 5,148 Forfeited (107,191 ) 13.84 — — Balance, December 31, 2019 2,412,043 C$ 14.00 1.86 C$ 44,309 Exercisable, December 31, 2019 743,787 C$ 13.21 — C$ 13,663 (v) Bonus deferral RSUs During 2018, the Company introduced a new bonus deferral RSU program to certain of its employees. Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. The RSUs granted are 100% vested and therefore, compensation expense associated with RSUs is recognized immediately upon issuance. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (vi) Bonus deferral RSUs A summary of the bonus deferral RSUs follows: Number of awards Weighted average grant-date fair value Aggregate intrinsic value Balance, December 31, 2017 — C$ — C$ — Granted, including dividends 131,611 12.82 1,683 Exercised (4,545 ) 12.82 61 Balance, December 31, 2018 127,066 C$ 12.82 C$ 1,745 Granted, including dividends 135,324 15.40 2,084 Balance and exercisable, December 31, 2019 262,390 C$ 14.15 C$ 4,820

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2019
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, 2018 $ (47,701 ) $ 55,366 $ (10,457 ) $ (2,792 ) Adoption of ASU 2018-02 on tax effects in AOCI — 11,657 (1,032 ) 10,625 Other comprehensive income (loss) (27,969 ) 1,567 2,046 (24,356 ) Amounts reclassified from AOCI to the consolidated statement of operations — (4,257 ) (86 ) (4,343 ) Net current period OCI $ (27,969 ) $ (2,690 ) $ 1,960 $ (28,699 ) OCI attributable to the non-controlling interests 1,481 — — 1,481 Net current period OCI attributable to shareholders of APUC $ (26,488 ) $ (2,690 ) $ 1,960 $ (27,218 ) Balance, December 31, 2018 $ (74,189 ) $ 64,333 $ (9,529 ) $ (19,385 ) Adoption of ASU 2017-12 on hedging (note 2(a)) — 186 — 186 Other comprehensive income (loss) 7,795 19,177 (7,999 ) 18,973 Amounts reclassified from AOCI to the consolidated statement of operations — (8,597 ) — 1,490 (7,107 ) Net current period OCI $ 7,795 $ 10,580 $ (6,509 ) $ 11,866 OCI attributable to the non-controlling interests (2,428 ) — — (2,428 ) Net current period OCI attributable to shareholders of APUC $ 5,367 $ 10,580 $ (6,509 ) $ 9,438 Balance, December 31, 2019 $ (68,822 ) $ 75,099 $ (16,038 ) $ (9,761 ) Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

Dividends

Dividends	12 Months Ended
	Dec. 31, 2019
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 during the year were as follows: 2019 2018 Dividend Dividend per share Dividend Dividend per share Common shares $ 277,835 $ 0.5512 $ 235,440 $ 0.5011 Series A preferred shares C$ 6,194 C$ 1.2905 C$ 5,400 C$ 1.1250 Series D preferred shares C$ 5,068 C$ 1.2671 C$ 5,000 C$ 1.2500

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2019
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 2019 , the Company charged its equity-method investees $12,374 ( 2018 - $11,390 ). On December 30, 2019 , the Company sold its interest in AWUSA to a joint venture entity in exchange for a note receivable of $30,293 (note 8(c)). No gain or loss was recognized on the sale. For the year, APUC recorded interest income of $6,007 , and a fair value loss of $6,007 on its investment in the joint venture. During the year, the Company sold the Sugar Creek Wind Project to AAGES Sugar Creek in exchange for a note receivable of $21,107 , subject to certain adjustments. No gain was recorded on deconsolidation of the Sugar Creek net assets. However, an amount of $15,765 , or $11,412 , net of tax, was reclassified from AOCI into earnings as a result of the discontinuation of hedge accounting on energy derivatives put in place early in the development of Sugar Creek (note 24(b)(ii)). During the year, the Company entered into an enhanced cooperation agreement with Atlantica to, among other things, provide a framework for evaluating mutually advantageous transactions. For a period of one year from the date of the agreement, Atlantica has an exclusive right of first offer for interests in certain Renewable Energy assets. (b) Redeemable non-controlling interest held by related party Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by AAGES B.V. in 2018 for $305,000 (note 8(a)). Redemption is not considered probable as at December 31, 2019 . The Company incurred non-controlling interest attributable to AAGES B.V. of $ 16,482 ( 2018 - $ 2,622 ) and recorded distributions of $ 18,241 ( 2018 - $ nil ) during the year (note 17). (c) Non-controlling interest held by related party Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by AYES Canada in May 2019 for $ 96,752 (note 8(b)). The Company recorded distributions of $ 26,465 during the year. (d) Long Sault Hydro Facility Effective December 31, 2013 , APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”), which was partially owned by Senior Executives. APC owns the partnership interest in the 18 MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction remains outstanding. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Non-controlling Interests and R

Non-controlling Interests and Redeemable non-controlling Interest	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
Non-controlling Interests and Redeemable non-controlling Interest	-controlling interests and redeemable non-controlling interests Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2019 2018 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ (55,963 ) $ (103,150 ) Non-controlling interests - redeemable tax equity partnership units (9,006 ) (7,545 ) Other net earnings attributable to: Non-controlling interests 2,553 2,174 $ (62,416 ) $ (108,521 ) Redeemable non-controlling interest, held by related party 16,482 2,622 Net effect of non-controlling interests $ (45,934 ) $ (105,899 ) The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s). The terms of the arrangement refer to the tax rate in effect when the benefits are delivered. As such, the U.S. federal corporate tax rate of 35% was used to calculate HLBV as at December 31, 2017 . The reduced U.S. federal corporate tax rate of 21% and other certain measures included in the Tax Act effective January 1, 2018 were reflected in the calculation of HLBV in 2018. The changes accelerated HLBV income from future years to the first quarter of 2018 in the amount of $55,900 . Non-controlling interests As of December 31, 2019 , non-controlling interests of $457,834 ( 2018 - $519,896 ) include partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $457,000 ( 2018 - 519,100 ) and other non-controlling interests of $834 ( 2018 - $ 796 ). Contributions from tax equity investors of $15,250 were received for the Great Bay Solar I Facility in 2018 (note 3(g)). Non-controlling interest held by related party Non-controlling interest was issued to AYES Canada in May 2019 for $ 96,752 (note 8(b)). The balance as of December 31, 2019 was $73,707 . Redeemable non-controlling interests Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within APUC’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, 2019 . Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2019 2018 2019 2018 Opening balance $ 307,622 $ — $ 33,364 $ 41,553 Net effect from operations 16,482 2,622 (9,006 ) (7,545 ) Contributions, net of costs — 305,000 3,403 — Dividends and distributions declared (18,241 ) — (1,848 ) (644 ) Closing balance $ 305,863 $ 307,622 $ 25,913 $ 33,364 During 2019, contributions from tax equity partnership investors of $3,403 were received for the Turquoise Solar Facility (note 3(b)). During 2018, contributions of $305,000

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2019
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% ( 2018 - 26.5% ). The differences are as follows: 2019 2018 Expected income tax expense at Canadian statutory rate $ 147,093 $ 35,102 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,703 ) (28,064 ) Adjustments from investments carried at fair value (60,730 ) 25,870 Non-controlling interests share of income 16,991 29,637 Non-deductible acquisition costs 2,500 4,267 Tax credits (9,332 ) (1,419 ) Adjustment relating to prior periods (1,240 ) 3,673 U.S. Tax reform and related deferred tax adjustments (1) — (18,363 ) Other 2,538 2,669 Income tax expense $ 70,117 $ 53,372 (1) In 2017, the Tax Cuts and Jobs Act ("Tax Act") implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Company’s U.S. entities were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. In 2018, an adjustment related to the implementation of U.S. Tax Reform resulted in a non-cash accounting benefit of $18,363 , which was recorded in the Company's 2018 consolidated statement of operations. For the years ended December 31, 2019 and 2018 , earnings before income taxes consist of the following: 2019 2018 Canada $ 351,908 $ (109,537 ) U.S. 203,159 241,998 $ 555,067 $ 132,461 Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2019 Canada $ 6,695 $ 17,607 $ 24,302 United States 9,736 36,079 45,815 $ 16,431 $ 53,686 $ 70,117 Year ended December 31, 2018 Canada $ 2,872 $ (14,197 ) $ (11,325 ) United States 8,475 56,222 64,697 $ 11,347 $ 42,025 $ 53,372 18. Income taxes (continued) The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are presented below: 2019 2018 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 382,448 $ 329,099 Pension and OPEB 54,113 48,586 Environmental obligation 15,541 14,790 Regulatory liabilities 160,200 161,560 Other 59,103 45,193 Total deferred income tax assets $ 671,405 $ 599,228 Less: valuation allowance (29,447 ) (28,018 ) Total deferred tax assets $ 641,958 $ 571,210 Deferred tax liabilities: Property, plant and equipment $ 707,185 $ 653,962 Outside basis in partnership 235,063 167,659 Regulatory accounts 145,852 113,758 Other 14,811 7,561 Total deferred tax liabilities $ 1,102,911 $ 942,940 Net deferred tax liabilities $ (460,953 ) $ (371,730 ) Consolidated balance sheets classification: Deferred tax assets $ 30,585 $ 72,415 Deferred tax liabilities (491,538 ) (444,145 ) Net deferred tax liabilities $ (460,953 ) $ (371,730 ) The valuation allowance for deferred tax assets as at December 31, 2019 was $ 29,447 ( 2018 - $28,018 ). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment. As of December 31, 2019 , the Company had non-capital losses carried forward available to reduce future years' taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2020 and onwards $ 1,091,322 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 approximately $370,682 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 Losses

Other Losses	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Other Losses	Other losses Other losses consist of the following: 2019 2018 Pension and other post-employment non-service costs (note 10) $ (17,332 ) $ (4,990 ) Acquisition and transition-related costs (note 3) (11,609 ) (687 ) Other (15,085 ) (2,725 ) $ (44,026 ) $ (8,402 )

Basic and diluted net earnings

Basic and diluted net earnings per share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted [Abstract]
Basic and diluted net earnings per share	Basic and diluted net earnings per share Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options and additional shares issued subsequent to quarter-end under the dividend reinvestment plan. The convertible debentures (note 12(h)) are convertible into common shares at any time prior to maturity or redemption by the Company. The shares issuable upon conversion of the convertible debentures are included in diluted earnings per share. The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2019 2018 Net earnings attributable to shareholders of APUC $ 530,884 $ 184,988 Series A preferred shares dividend 4,666 4,169 Series D preferred shares dividend 3,820 3,858 Net earnings attributable to common shareholders of APUC from continuing operations – basic and diluted $ 522,398 $ 176,961 Weighted average number of shares Basic 499,910,876 461,818,023 Effect of dilutive securities 4,828,678 4,227,595 Diluted 504,739,554 466,045,618 The shares potentially issuable as a result of 1,113,775 share options ( 2018 - 3,380,184

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segmented information	Segmented information The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company. The Regulated Services Group, the Company's regulated operating unit, owns and operates a portfolio of electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States and Canada; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates a diversified portfolio of renewable and thermal electric generation assets in North America and internationally. For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group while interest income from San Antonio Water System is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate. Year ended December 31, 2019 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,366,971 $ 257,950 $ — $ 1,624,921 Fuel, power and water purchased 426,046 17,258 — 443,304 Net revenue 940,925 240,692 — 1,181,617 Operating expenses 396,559 75,209 221 471,989 Administrative expenses 36,628 19,405 769 56,802 Depreciation and amortization 194,498 88,825 981 284,304 Loss on foreign exchange — — 3,146 3,146 Operating income (loss) 313,240 57,253 (5,117 ) 365,376 Interest expense (101,518 ) (61,039 ) (18,931 ) (181,488 ) Income from long-term investments 9,334 104,025 285,733 399,092 Other income (expenses) (32,292 ) 15,946 (11,567 ) (27,913 ) Earnings before income taxes $ 188,764 $ 116,185 $ 250,118 $ 555,067 Property, plant and equipment $ 4,754,373 $ 2,444,382 $ 32,909 $ 7,231,664 Investments carried at fair value 27,072 1,267,075 — 1,294,147 Equity-method investees 29,827 53,670 273 83,770 Total assets 6,816,063 4,014,067 81,340 10,911,470 Capital expenditures $ 478,936 $ 102,396 $ — $ 581,332 (1) Revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2018 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,401,240 $ 247,223 $ — $ 1,648,463 Fuel and power purchased 456,974 27,164 — 484,138 Net revenue 944,266 220,059 — 1,164,325 Operating expenses 401,486 70,980 — 472,466 Administrative expenses 33,234 18,539 937 52,710 Depreciation and amortization 177,719 82,044 1,009 260,772 Gain on foreign exchange — — (58 ) (58 ) Operating income (loss) 331,827 48,496 (1,888 ) 378,435 Interest expense (99,063 ) (50,920 ) (2,135 ) (152,118 ) Income (loss) from long-term investments 5,558 45,741 (136,117 ) (84,818 ) Other expenses (6,775 ) (1,576 ) (687 ) (9,038 ) Earnings (loss) before income taxes $ 231,547 $ 41,741 $ (140,827 ) $ 132,461 Property, plant and equipment $ 4,210,115 $ 2,152,420 $ 31,023 $ 6,393,558 Investment carried at fair value — 814,530 — 814,530 Equity-method investees 55 29,273 260 29,588 Total assets 6,022,262 3,269,786 106,541 9,398,589 Capital expenditures $ 370,221 $ 96,148 $ — $ 466,369 (1) Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $7,425 related to alternative revenue programs for the year ended December 31, 2018 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 mitigated its credit risk to the extent possible 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) APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows: 2019 2018 Revenue Canada $ 87,226 $ 70,358 United States 1,537,695 1,578,105 $ 1,624,921 $ 1,648,463 Property, plant and equipment Canada $ 752,016 $ 415,979 United States 6,479,648 5,977,579 $ 7,231,664 $ 6,393,558 Intangible assets Canada $ 23,795 $ 23,994 United States 23,821 31,000 $ 47,616 $ 54,994 Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies (a) Contingencies APUC 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 APUC’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable. Claim by Gaia Power Inc. On October 30, 2018 , Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against APUC and certain of its subsidiaries, claiming damages of not less than $345,000 and punitive damages in the sum of $25,000 . The action arises from Gaia’s 2010 sale, to a subsidiary of APUC, of Gaia’s interest in certain proposed wind farm projects in Canada. Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets. It is too early to determine the likelihood of success in this lawsuit; however, APUC intends to vigorously defend it. Condemnation expropriation proceedings Liberty Utilities (Apple Valley Ranchos Water) Corp. is the subject of a condemnation lawsuit filed by the town of Apple Valley. A court will determine the necessity of the taking by Apple Valley and, if established, a jury will determine the fair market value of the assets being condemned. Resolution of the condemnation proceedings is expected to take two to three years. Any taking by government entities would legally require fair compensation to be paid; however, there is no assurance that the value received as a result of the condemnation will be sufficient to recover the Company's net book value of the utility assets taken. 22. Commitments and contingencies (continued) (b) Commitments In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2019 . APUC has outstanding purchase commitments for power purchases, gas supply and service agreements, service agreements, capital project commitments and land easements. Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 30,672 $ 11,422 $ 11,338 $ 11,566 $ 11,796 $ 179,412 $ 256,206 Gas supply and service agreements (ii) 83,083 60,699 49,217 46,406 41,538 135,926 416,869 Service agreements 47,950 40,456 41,554 45,611 47,005 293,436 516,012 Capital projects 104,809 114,806 — — — — 219,615 Land easements 6,603 6,673 6,744 6,835 6,918 200,891 234,664 Total $ 273,117 $ 234,056 $ 108,853 $ 110,418 $ 107,257 $ 809,665 $ 1,643,366 (i) Power purchase: APUC’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, 2019 . However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Non-cash operating items

Non-cash operating items	12 Months Ended
	Dec. 31, 2019
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: 2019 2018 Accounts receivable $ (20,857 ) $ 3,005 Fuel and natural gas in storage 13,985 1,351 Supplies and consumables inventory (6,028 ) (7,189 ) Income taxes recoverable 17,796 (763 ) Prepaid expenses (7,501 ) 2,907 Accounts payable 63,854 (22,915 ) Accrued liabilities 8,872 28,687 Current income tax liability (5,016 ) 2,974 Asset retirements and environmental obligations (2,494 ) (7,293 ) Net regulatory assets and liabilities (2,308 ) (8,890 ) $ 60,303 $ (8,126 )

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments 2019 Carrying amount Fair value Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,294,147 $ 1,294,147 1,178,581 $ 27,072 $ 88,494 Development loans and other receivables 37,050 37,984 — 37,984 — Derivative instruments: Energy contracts designated as a cash flow hedge 65,304 65,304 — — 65,304 Energy contracts not designated as a hedge 20,384 20,384 — — 20,384 Commodity contracts for regulated operations 16 16 — 16 — Total derivative instruments 85,704 85,704 — 16 85,688 Total financial assets $ 1,416,901 $ 1,417,835 $ 1,178,581 $ 65,072 $ 174,182 Long-term debt $ 3,931,868 $ 4,284,068 $ 1,495,153 $ 2,788,915 $ — Convertible debentures 342 623 623 — — Preferred shares, Series C 13,793 15,120 — 15,120 — Derivative instruments: Energy contracts designated as a cash flow hedge 789 789 — — 789 Energy contracts not designated as a hedge 38 38 — — 38 Cross-currency swap designated as a net investment hedge 81,765 81,765 — 81,765 — Commodity contracts for regulated operations 2,072 2,072 — 2,072 — Total derivative instruments 84,664 84,664 — 83,837 827 Total financial liabilities $ 4,030,667 $ 4,384,475 $ 1,495,776 $ 2,887,872 $ 827 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2018 Carrying amount Fair value Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 814,530 $ 814,530 $ 814,530 $ — $ — Development loans and other receivables 103,696 110,019 — 110,019 — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 61,838 61,838 — — 61,838 Currency forward contract not designated as a hedge 869 869 — 869 — Commodity contracts for regulatory operations 101 101 — 101 — Total derivative instruments 62,808 62,808 — 970 61,838 Total financial assets $ 981,034 $ 987,357 $ 814,530 $ 110,989 $ 61,838 Long-term debt $ 3,336,795 $ 3,356,773 $ 768,400 $ 2,588,373 $ — Convertible debentures 470 639 639 — — Preferred shares, Series C 13,418 13,703 — 13,703 — Derivative instruments: Energy contracts designated as a cash flow hedge 57 57 — — 57 Cross-currency swap designated as a net investment hedge 93,198 93,198 — 93,198 — Interest rate swaps designated as a hedge 8,473 8,473 — 8,473 — Commodity contracts for regulated operations 1,114 1,114 — 1,114 — Total derivative instruments 102,842 102,842 — 102,785 57 Total financial liabilities $ 3,453,525 $ 3,473,957 $ 769,039 $ 2,704,861 $ 57 (1) Balance of $441 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2019 and 2018 due to the short-term maturity of these instruments. The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange adjusted for the impact of the expected settlement under the purchase agreement pursuant to the prepayment of $53,750 (note 8(a)). 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The Company’s level 1 fair value of long-term debt is measured at the closing price on the 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 Series C preferred shares has been determined using a discounted cash flow method and current interest rates. The Company's level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of APUC's common shares on a converted basis. The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace. The Company’s level 3 instruments consist of energy contracts for electricity sales and the fair value of the Company's investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $13.33 to $178.65 with a weighted average of $23.66 as of December 31, 2019 . The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of the Company's AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.75% to 9.50% with a weighted average of 9.42% , and the expected volatility of Atlantica's share price ranging from 18% to 22% as of December 31, 2019 . Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement. (b) Derivative instruments Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period. (i) Commodity derivatives – regulated accounting The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas and electric service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers. The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2019 Financial contracts: Swaps 2,134,739 Options 150,000 Forward contracts 2,500,000 4,784,739 The accounting for these derivative instruments is subject to guidance for rate regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(e)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact. 24. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 2019 2018 Regulatory assets: Swap contracts $ 28 $ 66 Option contracts 38 — Forward contracts $ 1,830 $ — Regulatory liabilities: Swap contracts $ 743 $ 218 Option contracts — 134 Forward contracts $ — $ 1,259 (ii) Cash flow hedges The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. Notional quantity (MW-hrs) Expiry Receive average prices (per MW-hr) Pay floating price (per MW-hr) 757,075 December 2028 35.35 PJM Western HUB 3,443,530 December 2027 25.54 PJM NI HUB 2,665,068 December 2027 36.46 ERCOT North HUB In January 2019 , the Company entered into a long-term energy derivative contract to reduce the price risk on the expected future sale of power generation at Sugar Creek. On September 30, 2019 , the Company sold the derivative contract together with 100% of its ownership interest in Sugar Creek to AAGES Sugar Creek. The novation and transfer of the derivative contract was subject to counterparty approval, which was received subsequent to year-end in Q1 2020. As a result, the hedge relationship for the Sugar Creek energy derivative was discontinued. Amounts in AOCI of $15,765 and related tax were reclassified from AOCI into earnings in 2019 (note 24(b)(iv)). During the year, the Company entered into an energy derivative contract to reduce the price risk on the expected future purchase of power on the open market at its Tinker Hydroelectric Facility with a notional quantity of 151,680 MW-hours and a price of $38.95 per MW-hr. The contract expires February 2022. The Company was party to a 10 -year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10 -year C$135,000 bond. During 2018 , the Company amended and extended the forward-starting date of the interest rate swap to begin on March 29, 2019 . During the year, the Company settled the forward-starting interest rate swap contract as it issued C $300,000 10 -year senior unsecured notes with an interest rate of 4.60% (note 9(d)). On May 23, 2019 , the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes (note 9(e)), to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. The gain or loss related to the fair value changes of the swap is first reported in OCI and a portion of the change is then reclassified from AOCI into earnings at each reporting date to offset the foreign exchange transaction gain or loss on the notes. 24. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) In September 2019 , the Company entered into a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the subordinated unsecured notes (note 9(e)). The Company designated the entire notional amount of the three pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes. The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2019 2018 Effective portion of cash flow hedge $ 19,177 $ 1,567 Amortization of cash flow hedge (33 ) (33 ) Amounts reclassified from AOCI (8,564 ) (4,224 ) OCI attributable to shareholders of APUC $ 10,580 $ (2,690 ) The Company expects $8,704 and $2,203 of unrealized gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales and interest expense, respectively, within the next twelve months, as the underlying hedged transactions settle. (iii) Foreign exchange hedge of net investment in foreign operation The Company is exposed to currency fluctuations from its Canadian-based operations. APUC 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. APUC only enters into foreign exchange forward contracts with major North American financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts. 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 the amounts drawn on its revolving and bank credit facilities 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 are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $35,277 for the year ended December 31, 2019 ( 2018 - loss of $28,705 ) was recorded in OCI. Concurrent with its C $150,000 , C $200,000 and C $300,000 debenture offerings in December 2012, January 2014, and January 2017, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $15,946 ( 2018 - loss of $ 41,244 ) was recorded in OCI in 2019 . 24. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility is expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy. This risk is mitigated through the use of short-term financial forward energy purchase contracts that are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur. The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, including certain project-specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand. The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk is mitigated through the use of currency forward contracts. For the year ended December 31, 2019 , a foreign exchange loss of $983 ( 2018 - gain of $1,115 ) was recorded in the consolidated statements of operations. These currency forward contracts are not accounted for as a hedge. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings. The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2019 2018 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ (530 ) $ 77 Currency forward contract 904 (1,230 ) Total change in unrealized loss (gain) on derivative financial instruments $ 374 $ (1,153 ) Realized loss (gain) on derivative financial instruments: Energy derivative contracts 227 (73 ) Currency forward contract (147 ) 115 Total realized loss on derivative financial instruments $ 80 $ 42 Loss (gain) on derivative financial instruments not accounted for as hedges 454 (1,111 ) Discontinued hedge accounting (note 24(b)(ii)) and other (15,810 ) 632 $ (15,356 ) $ (479 ) Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (16,113 ) $ 636 Loss (gain) on foreign exchange 757 (1,115 ) $ (15,356 ) $ (479 ) 24. Financial instruments (continued) (c) Risk management In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks. Credit risk Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the Renewable Energy Group accounts receivable to be significant as over 87% 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 water and wastewater, electric and gas utilities in the United States and Canada. In this regard, the credit risk related to the Regulated Services Group accounts receivable balances of $200,594 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, 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, 2019 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2019 Canadian $ US $ Cash and cash equivalents and restricted cash $ 53,619 $ 45,989 Accounts receivable 42,987 231,006 Allowance for doubtful accounts (89 ) (4,850 ) Notes receivable 15,963 50,680 $ 112,480 $ 322,825 In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Liquidity risk Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2019 , in addition to cash on hand of $62,485 , the Company had $1,047,216 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn. 24. Financial instruments (continued) (c) Risk management (continued) Liquidity risk (continued) The Company’s liabilities mature as follows: Due less than 1 year Due 2 to 3 years Due 4 to 5 years Due after 5 years Total Long-term debt obligations $ 602,028 $ 468,740 $ 600,721 $ 2,260,416 $ 3,931,905 Convertible debentures — — — — 346 346 Advances in aid of construction 1,165 — — 59,663 60,828 Interest on long-term debt 185,231 318,469 257,443 992,116 1,753,259 Purchase obligations 458,288 — — — 458,288 Environmental obligation 14,970 20,850 1,128 21,536 58,484 Derivative financial instruments: Cross-currency swap 4,149 69,099 3,851 4,666 81,765 Energy derivative and commodity contracts 1,631 909 — 359 2,899 Other obligations 39,115 2,120 2,696 109,094 153,025 Total obligations $ 1,306,577 $ 880,187 $ 865,839 $ 3,448,196 $ 6,500,799

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Comparative figures	Comparative figures Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.

Significant accounting polici_2

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of preparation	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.
Basis of consolidation	Basis of consolidation The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).
Business combinations, intangible assets and goodwill	Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years. 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. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. 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 public utility commission of the states and provinces in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’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”). 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations (continued) Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.
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 APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.
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, 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 (note 7(e)) 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. 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 become 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	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. It also includes amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest . The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations. Range of useful lives Weighted average useful lives 2019 2018 2019 2018 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 42 40 Equipment 5 - 44 5 - 43 10 10 The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group
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. The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense.
Impairment of long-lived assets	Impairment of long-lived assets APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.
Variable interest entities	Variable interest 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 APUC 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. APUC has determined that both 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 APUC 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 entity, the Company is considered the primary beneficiary.
Long-term investments and notes receivable	Long-term investments and notes receivable Investments in which APUC 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. APUC 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. APUC 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. 1. Significant accounting policies (continued) (n) Long-term investments and notes receivable (continued) 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 for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.
Pension and other post employment plans	Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations.The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.
Asset retirement obligations	Asset retirement 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	(q) Leases The Company adopted ASU 2016-02, Leases (Topic 842) ("ASC 842") during 2019 using a modified retrospective approach. The Company leases 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 to five years . As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised. 1. Significant accounting policies (continued) (q) Leases (continued) 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 Regulated Services Group enters into easement agreements for the operation of its utilities. For all easements that existed or were expired as of January 1, 2019, the practical expedient was taken to not change the legacy accounting for these easement contracts. For new easement contracts entered into subsequent to January 1, 2019, the Company considers whether they contain a lease. The implementation of ASC 842 did not have an impact on the Company's existing finance leases. The weighted-average discount rate as of December 31, 2019 for the Company's finance lease assets and liabilities is 6.45% and the weighted-average remaining lease term of the Company's finance leases is 5.55 years . New right-of-use assets and lease liabilities of $8,295 were recognized for the Company's operating leases as at January 1, 2019. As a result of the acquisition of Enbridge Gas New Brunswick Limited Partnership ("New Brunswick Gas") on October 1, 2019 (note 3(a)), the Company acquired new right-of-use assets and assumed lease liabilities of $1,316 . The weighted-average discount rate as of December 31, 2019 for the Company's operating lease assets and liabilities is 3.95% and the weighted-average remaining lease term is 13.49 years .
Share-based compensation	(r) Share-based compensation
Noncontrolling interests	(s) Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. 1. Significant accounting policies (continued) (s) Non-controlling interests (continued) Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Tax Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments.
Recognition of revenue	(t) Recognition of revenue The Company accounts for revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers , which was adopted on January 1, 2018 using the modified retrospective method, applied to contracts that were not completed at the date of initial application. The adoption of the new standard resulted in an adjustment of $2,488 or $1,860 net of taxes to increase opening retained earnings for previously deferred revenue related to the Empire fiber business. Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, "Segmented information" for details of revenue disaggregation by business units. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Regulated Services Group revenue Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water. Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant. Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, "Segmented information" and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset. Renewable Energy Group revenue Renewable Energy Group 's revenue consists primarily of the sale of electricity, capacity, and renewable energy credits. Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer. 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. 1. Significant accounting policies (continued) (t) Recognition of revenue (continued) Renewable Energy Group revenue (continued) The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Renewable Energy Group contracts. The Company does not disclose the value of unsatisfied performance obligations for these contracts as revenue is recognized at the amount to which the Company has the right to invoice for services performed.
Foreign currency translation	(u) Foreign currency translation APUC’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount. The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.
Income taxes	(v) Income taxes Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment (note 18). 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 APUC 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%
Financial instruments and derivatives	(w) Financial instruments and derivatives Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts. 1. Significant accounting policies (continued) (w) Financial instruments and derivatives (continued) Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument. The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity. For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings. Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment.
Fair value measurements	(x) 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. •
Commitments and contingencies	(y) Commitments and contingencies
Use of estimates	(z) Use of estimates
Recently adopted accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued accounting standards update ("ASU") 2018-15, Intangibles — Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract to provide additional guidance to address diversity in practice. This update aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted this update prospectively as at the beginning of the third quarter. There were no significant impacts to the consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (" SOFR ") Overnight Index Swap (" OIS ") Rate as a Benchmark Interest Rate for Hedge Accounting Purposes to identify a suitable alternative to the U.S. dollar LIBOR that is more firmly based on actual transactions in a robust market. This update permits the use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. This update was adopted concurrently with ASU 2017-12. The Company will follow the pronouncements prospectively for qualifying new or redesignated hedging relationships. The FASB issued ASU 2018-07, Compensation — Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting to expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. This update changes the measurement basis and date of non-employee share-based payment awards and also makes amendments to how to measure non-employee awards with performance conditions. The adoption of this update in 2019 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities , to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The FASB also issued ASU 2019-04 that contains further codification improvements to ASU 2017-12. The adoption of these updates in 2019 resulted in a reclassification of $186 from retained earnings to accumulated other comprehensive income for previous hedge ineffectiveness recognized in earnings for outstanding hedging contracts. The Company has also made certain amendments and simplifications to hedge effectiveness testing procedures and documentation to be followed prospectively where applicable in accordance with the pronouncements in the update. 2. Recently issued accounting pronouncements (continued) (a) Recently adopted accounting pronouncements (continued) The FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception to address narrow issues with applying U.S. GAAP for certain financial instruments with characteristics of liabilities and equity. The adoption of this update in 2019 had no impact on the consolidated financial statements. The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The FASB also issued subsequent amendments to ASC 842 that provide further practical expedients as well as codification clarifications and improvements. The adoption of this new lease standard in 2019 using a modified retrospective approach resulted in an adjustment of $8,295 to right-of-use assets and operating lease liabilities included in other long-term liabilities on the consolidated balance sheets, with no restatement of the comparative period. The Company implemented new processes and procedures for the identification, analysis, and measurement of new lease contracts. A new software solution was implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company elected the following practical expedients as part of its adoption: 1. "Package of three" practical expedient that permits the Company not to reassess the scope, classification and initial direct costs of its expired and existing leases; 2. Land easements practical expedient that permits the Company not to reassess the accounting for land easements previously not accounted for under Leases ASC 840; and 3. Hindsight practical expedient that allows the Company to use hindsight in determining the lease term for existing contracts. In addition, the Company made an accounting policy election to not recognize a lease liability or right-of-use asset on its consolidated balance sheets for short-term leases (lease term less than 12 months). (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2020-01, Investments - Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to reduce diversity in practice and increase comparability of accounting for certain transactions. The amendments clarify when to consider observable price changes for the measurement of certain equity securities without a readily determinable fair value. They also clarify the scope of forward contracts and purchased options on these certain securities. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, including early adoption in any interim period. The Company currently does not have any transactions that would be within the scope of this update but will continue to assess the impact of this update in the future. The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes as part of its initiative to reduce complexity in the accounting standards. The amendments remove certain exceptions to the general principles in Topic 740 and improve consistent application for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, but all amendments must be early adopted simultaneously. The Company is currently assessing the impact of this update. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The update clarifies that the arrangement should be accounted for under ASC 606 when a participant is a customer in the context of a unit of account, adds unit of account guidance in ASC 808 that is consistent with ASC 606, and precludes the recognition of revenue from a collaborative arrangement with ASC 606 revenue if the participant is not directly related to sales to third parties. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those years. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The amendments in the update are effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years. The amendments are required to be applied retrospectively with a cumulative-effect adjustment to retained earnings. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update. The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current U.S. GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued codification improvements to ASC Topic 326 in ASU 2018-19 to provide guidance on scoping of operating lease assets and further specific clarifications and corrections in ASU 2019-04 and ASU 2019-11. The FASB issued further updates to Topic 326 in ASU 2019-05 and ASU 2020-02 to provide transition relief that allows companies to irrevocably elect the fair value option for certain instruments held at amortized cost, and to provide certain updates to the SEC paragraphs of the topic. The Company is finalizing its analysis on the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

Significant accounting polici_3

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Estimated Useful Lives of Depreciable Assets	The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2019 2018 2019 2018 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 42 40 Equipment 5 - 44 5 - 43 10 10
Schedule of Operating Leases Schedule	s. The Company's operating leases payments for the next five years and thereafter are as follows: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total $ 2,115 $ 1,138 $ 688 $ 659 $ 642 $ 5,195 $ 10,437 The lease payments for the Company's finance leases are expected to be approximately $539 annually for the next five years, and $318

Business acquisitions and dev_2

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date: New Brunswick Gas St. Lawrence Gas Working capital $ 8,782 $ 3,403 Property, plant and equipment 137,668 49,936 Goodwill 56,054 20,259 Regulatory assets 94,827 3,562 Deferred income tax assets, net — 1,614 Other assets 125 6,418 Regulatory liabilities (2,076 ) (10,412 ) Pension and post-employment benefits — (12,376 ) Deferred income tax liability, net (38,053 ) — Other liabilities (1,316 ) (584 ) Total net assets acquired $ 256,011 $ 61,820 Cash and cash equivalent 7,248 1,225 Total net assets acquired, net of cash and cash equivalent $ 248,763 $ 60,595

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Capitalization of Interest	Interest and AFUDC capitalized to the cost of the assets in 2019 and 2018 are as follows: 2019 2018 Interest capitalized on non-regulated property $ 4,538 $ 2,268 AFUDC capitalized on regulated property: Allowance for borrowed funds 2,745 1,684 Allowance for equity funds 4,896 2,728 Total $ 12,179 $ 6,680
Property, Plant and Equipment	Property, plant and equipment consist of the following: 2019 Cost Accumulated depreciation Net book value Generation $ 2,816,611 $ 540,118 $ 2,276,493 Distribution and transmission 4,988,297 598,449 4,389,848 Land 74,517 — 74,517 Equipment and other 94,583 47,541 47,042 Construction in progress Generation 140,235 — 140,235 Distribution and transmission 303,529 — 303,529 $ 8,417,772 $ 1,186,108 $ 7,231,664 5. Property, plant and equipment (continued) 2018 Cost Accumulated Net book Generation $ 2,470,279 $ 450,230 $ 2,020,049 Distribution and transmission 4,455,935 521,236 3,934,699 Land 73,773 — 73,773 Equipment and other 88,757 41,295 47,462 Construction in progress Generation 104,996 — 104,996 Distribution and transmission 212,579 — 212,579 $ 7,406,319 $ 1,012,761 $ 6,393,558

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible assets consist of the following: 2019 Cost Accumulated amortization Net book value Power sales contracts $ 56,206 $ 38,931 $ 17,275 Customer relationships 26,797 10,104 16,693 Interconnection agreements 14,827 1,179 13,648 $ 97,830 $ 50,214 $ 47,616 6. Intangible assets and goodwill (continued) 2018 Cost Accumulated Net book Power sales contracts $ 60,775 $ 36,063 $ 24,712 Customer relationships 26,795 9,476 17,319 Interconnection agreements 13,847 — 884 12,963 $ 101,417 $ 46,423 $ 54,994
Goodwill	Regulated Services Group . Balance, December 31, 2018 and 2017 $ 954,282 Business acquisitions (note 3(a)) 76,313 Foreign exchange 1,101 Balance, December 31, 2019 $ 1,031,696

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed: Utility State Regulatory proceeding type Annual revenue increase Effective date Peach State Gas System Georgia Georgia Rate Adjustment mechanism $2,367 February 1, 2019 New England Natural Gas System Massachusetts Gas System Enhancement Plan $2,413 May 1, 2019 Empire Electric System Kansas General Rate Review $2,449 August 1, 2019 Empire Electric System Oklahoma General Rate Review $1,400 October 1, 2019 CalPeco Electric System California Catastrophic Events Memorandum Account $3,525 January 1, 2020 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2019 2018 Regulatory assets Environmental remediation (a) $ 82,300 $ 82,295 Pension and post-employment benefits (b) 143,292 135,580 Income taxes (c) 71,506 34,822 Debt premium (d) 42,150 48,847 Fuel and commodity cost adjustments (e) 23,433 26,310 Rate adjustment mechanism (f) 69,121 37,202 Clean Energy and other customer programs (g) 26,369 24,095 Deferred capitalized costs (h) 38,833 13,986 Asset retirement obligation (i) 23,841 21,048 Long-term maintenance contract (j) 13,264 8,283 Rate review costs (k) 6,695 6,164 Other 19,083 21,463 Total regulatory assets $ 559,887 $ 460,095 Less: current regulatory assets (50,213 ) (59,037 ) Non-current regulatory assets $ 509,674 $ 401,058 Regulatory liabilities Income taxes (c) $ 321,960 $ 323,384 Cost of removal (l) 196,423 193,564 Rate base offset (m) 8,719 10,900 Fuel and commodity costs adjustments (e) 16,645 21,352 Rate adjustment mechanism (f) 10,446 4,210 Deferred capitalized costs - fuel related (h) 7,097 7,258 Pension and post-employment benefits (b) 22,256 11,791 Other 14,516 15,754 Total regulatory liabilities $ 598,062 $ 588,213 Less: current regulatory liabilities (41,683 ) (39,005 ) Non-current regulatory liabilities $ 556,379 $ 549,208 7. Regulatory matters (continued) (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems' and St. Lawrence Gas system's pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods. (c) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. On June 1, 2018, the State of Missouri enacted legislation that, effective for tax years beginning on or after January 1, 2020, reduces the corporate income tax rate from 6.25% to 4% , among other legislative changes. A reduction of regulatory asset and an increase to regulatory liability were recorded for excess deferred taxes probable of being refunded to customers of $15,586 . (d) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (e) Fuel and commodity cost adjustments The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. (f) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, and EnergyNorth Natural Gas System is subject to a revenue decoupling mechanism approved by their respective regulator, which requires charging 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 recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 25 years . (g) Clean Energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. 7. Regulatory matters (continued) (h) Deferred capitalized costs Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years . (i) 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. (j) Long-term maintenance contract To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. (k) Rate review costs The costs to file, prosecute and defend rate review applications are referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (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 tracks the amounts that have been collected from customers net of costs incurred to date. (m) Rate base offset The regulators imposed a rate base offset that will reduce the revenue requirement at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term Investments	Long-term investments consist of the following: 2019 2018 Long-term investments carried at fair value Atlantica (a) $ 1,178,581 $ 814,530 AYES Canada (b) 88,494 — San Antonio Water System (c) 27,072 — $ 1,294,147 $ 814,530 Other long-term investments Equity-method investees (d) $ 83,770 $ 29,588 Development loans receivable from equity-method investees (e) 36,204 101,417 Other 1,994 4,773 Total other long-term investments $ 121,968 $ 135,778 Less: current portion — (1,407 ) $ 121,968 $ 134,371 8. Long-term investments (continued) Income (loss) from long-term investments from the years ended December 31, 2019 and 2018 is as follows: Year ended December 31 2019 2018 Fair value gain (loss) on investments carried at fair value Atlantica $ 290,740 $ (137,957 ) AYES Canada (6,649 ) — San Antonio Water System (6,007 ) — $ 278,084 $ (137,957 ) Dividend and interest income from investments carried at fair value Atlantica $ 69,307 $ 39,263 AYES Canada 25,572 — San Antonio Water System 6,007 — $ 100,886 $ 39,263 Other long-term investments Equity method loss (9,108 ) (3,082 ) Interest and other income 29,230 16,958 $ 399,092 $ (84,818 ) (a) Investment in Atlantica AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by APUC, has a share ownership in Atlantica Yield plc ("Atlantica") of approximately 44.2% (December 31, 2018 - 41.5% ). APUC has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5% . In 2019, the Company purchased 1,384,402 treasury shares of Atlantica for cash consideration of $30,000 . In addition, 2,000,000 shares were received pursuant to a prepayment of $53,750 . Subsequent to year-end, the prepayment purchase agreement settled with no material cash difference. During 2018, APUC purchased from Abengoa S.A. ("Abengoa") a 41.5% equity interest in Atlantica through two transactions for a total purchase price of $952,567 , with a holdback of $40,000 of which $29,100 was settled in 2019 with the balance payable at a later date, subject to certain conditions. 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. On November 28, 2018 , Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”), an equity investee of the Company, obtained a three -year secured credit facility in the amount of $306,500 and subscribed to a $305,000 preference share ownership interest in AY Holdings. The subscription proceeds were distributed by AY Holdings to the Company and used by the Company to repay the $305,000 of temporary financing used for the 2018 investment in Atlantica. The AAGES B.V. secured credit facility is collateralized through a pledge of the Atlantica shares held by AY Holdings. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the lenders would have the right to sell Atlantica stock to eliminate the collateral shortfall. The AAGES B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest held by related party (note 17). 8. Long-term investments (continued) (b) Investment in AYES Canada On May 24, 2019 , APUC and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. ("AYES Canada"), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. ("Windlectric"). APUC invested $ 91,918 (C$ 123,603 ) and Atlantica invested $ 4,834 (C$ 6,500 ) in AYES Canada, which in turn invested those funds in Amherst Island Partnership ("AIP"), the holding company of Windlectric. APUC continues to control and consolidate AIP and Windlectric. The investment of $ 96,752 (C$ 130,103 ) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. The Company incurred non-controlling interest calculated using the HLBV method of accounting of $ nil and recorded distributions of $26,465 ( C$34,373 ) during the year. AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, APUC's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, APUC has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment. For the year, APUC recorded dividend income of $ 25,572 and a fair value loss of $ 6,649 on its investment in AYES Canada. As at December 31, 2019 , the Company's maximum exposure to loss is $ 88,494 , which represents the fair value of the investment. (c) San Antonio Water System On May 1, 2019 , APUC invested $ 17,000 by way of a secured loan into AWUSA VR Holding LLC ("AWUSA"), a wholly owned subsidiary of Abengoa. An additional amount of $ 5,000 plus interest is payable at a later date, subject to certain conditions. The loan is secured by AWUSA's investment in the Vista Ridge water pipeline project. The Vista Ridge water pipeline project is a 140 mile water pipeline from Burleson County, Texas, to San Antonio, Texas. Since APUC has the power to direct the activities of AWUSA and benefits from the economics of this entity, the Company consolidates AWUSA. AWUSA's 20% interest in Vista Ridge is accounted for using the equity method. On December 30, 2019 , the Company and a third-party developer each contributed C $1,500 to the capital of a new joint venture, created for the purpose of developing infrastructure investment opportunities. The Company sold its investment in AWUSA to the joint venture in exchange for a loan receivable of $30,293 . A note payable to AWUSA of $13,293 was recognized by the Company upon deconsolidation of AWUSA. The Company holds an option exercisable at any time to acquire the remaining interest at a pre-agreed price. The sale was accounted for in accordance with ASC 860, Transfers and Servicing and no gain or loss was recognized. The joint venture is considered to be a VIE due to insufficient equity at risk to finance its operations with additional subordinated financial support. Neither APUC nor the third-party developer is considered to be the primary beneficiary since each party holds 50% voting and economic interests. Accordingly, APUC's investment in the joint venture is considered an equity method investment. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach was used to estimate the fair value of the investment. For the year, APUC recorded interest income of $6,007 and a fair value loss of $6,007 on its investment in the joint venture. As of December 31, 2019 , the Company’s maximum exposure to loss is $27,072 , which represents the fair value of the investment. 8. Long-term investments (continued) (d) Equity-method investees The Company has non-controlling interests in various partnerships and joint ventures with a total carrying value of $83,770 (2018 - $29,588 ) including investments in VIEs of $59,091 (2018 - $9,581 ). The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method. The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa in 2018; Sugar Creek, a 202 MW wind power development project in Logan County, Illinois; Maverick, a 490 MW wind project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia, and two approximately 150 MW wind projects in southwestern Missouri. On April 16, 2019, the Company acquired the remaining 50% interest in Windlectric which owns a 75 MW wind generating facility ("Amherst Island Wind Facility") in the Province of Ontario for $6,362 . Prior to this acquisition, APUC's 50% interest in Windlectric was recorded as an equity investment. As a result of obtaining control of the facility, the transaction was treated as an asset acquisition. APUC recorded the fair value on that date for property, plant and equipment acquired of $311,175 , deferred tax asset of $3,015 , working capital of $14,280 and liabilities of $1,600 for asset retirement obligation assumed; and, derecognized the existing development loan between the two parties of $316,786 (note 8(e)). Summarized combined information for APUC's investments in significant partnerships and joint ventures is as follows: 2019 2018 Total assets $ 833,791 $ 360,372 Total liabilities 697,751 335,331 Net assets 136,040 25,041 APUC's ownership interest in the entities 63,624 18,042 Difference between investment carrying amount and underlying equity in net assets (a) 18,487 11,048 APUC's investment carrying amount for the entities $ 82,111 $ 29,090 (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 and transaction costs. Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances (note 8(e)) and credit support in amounts necessary for the continued development and construction of the equity investees' projects. As of December 31, 2019 , the Company had issued letters of credit and guarantees of obligations under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; equity capital contribution agreements; landowner agreements; and bridge loan agreements. The fair value of the support provided recorded as at December 31, 2019 amounts to $9,493 (2018 - $1,682 ). The Company is not considered the primary beneficiary of these entities as the partners have joint control and all decisions must be unanimous. Therefore, the Company accounts for its interest in these VIEs using the equity method. 8. Long-term investments (continued) (d) Equity-method investees (continued) Summarized combined information for APUC's VIEs is as follows: 2019 2018 APUC's maximum exposure in regards to VIEs Carrying amount $ 59,091 $ 9,581 Development loans receivable (e) 35,000 101,417 Commitments on behalf of VIEs 1,364,871 120,669 $ 1,458,962 $ 231,667 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. (e) Development loans receivable from equity investees The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated 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 bear interest at a weighted average annual rate of 7.66% ( 2018 - 9.90% ) on outstanding principal and generally mature on the commercial operation date.
Income from Long-term Investments	Income (loss) from long-term investments from the years ended December 31, 2019 and 2018 is as follows: Year ended December 31 2019 2018 Fair value gain (loss) on investments carried at fair value Atlantica $ 290,740 $ (137,957 ) AYES Canada (6,649 ) — San Antonio Water System (6,007 ) — $ 278,084 $ (137,957 ) Dividend and interest income from investments carried at fair value Atlantica $ 69,307 $ 39,263 AYES Canada 25,572 — San Antonio Water System 6,007 — $ 100,886 $ 39,263 Other long-term investments Equity method loss (9,108 ) (3,082 ) Interest and other income 29,230 16,958 $ 399,092 $ (84,818 )
Investments in Partnerships and Joint Ventures	Summarized combined information for APUC's investments in significant partnerships and joint ventures is as follows: 2019 2018 Total assets $ 833,791 $ 360,372 Total liabilities 697,751 335,331 Net assets 136,040 25,041 APUC's ownership interest in the entities 63,624 18,042 Difference between investment carrying amount and underlying equity in net assets (a) 18,487 11,048 APUC's investment carrying amount for the entities $ 82,111 $ 29,090
Schedule of Variable Interest Entities	Summarized combined information for APUC's VIEs is as follows: 2019 2018 APUC's maximum exposure in regards to VIEs Carrying amount $ 59,091 $ 9,581 Development loans receivable (e) 35,000 101,417 Commitments on behalf of VIEs 1,364,871 120,669 $ 1,458,962 $ 231,667

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long Term Debt	. Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2019 2018 Senior unsecured revolving credit facilities (a) — 2023-2024 N/A $ 141,577 $ 97,000 Senior unsecured bank credit facilities (b) — 2020 N/A 75,000 321,807 Commercial paper (c) — 2020 N/A 218,000 6,000 U.S. dollar borrowings Senior unsecured notes 4.09 % 2020-2047 $ 1,225,000 1,219,579 1,218,680 Senior unsecured utility notes 6.00 % 2020-2035 $ 217,000 233,686 240,161 Senior secured utility bonds 4.75 % 2020-2044 $ 662,500 672,337 676,697 Canadian dollar borrowings Senior unsecured notes (d) 4.48 % 2021-2029 C$ 950,669 728,679 474,764 Senior secured project notes 10.22 % 2020-2027 C$ 28,503 21,961 22,915 $ 3,310,819 $ 3,058,024 Subordinated U.S. dollar borrowings Subordinated unsecured notes (e) 6.50 % 2078-2079 $ 637,500 621,049 278,771 $ 3,931,868 $ 3,336,795 Less: current portion (225,013 ) (13,048 ) $ 3,706,855 $ 3,323,747 Short-term obligations of $377,015 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. 9. Long-term debt (continued) Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities. Recent financing activities: (a) Senior unsecured revolving credit facilities On October 24, 2019 , the Company entered into a new $75,000 uncommitted bilateral letter of credit facility. The facility matures on October 24, 2020 . On July 12, 2019 , the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024 . The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread. The existing C $165,000 credit facility was canceled. On February 23, 2018 , the Regulated Services Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023 . Concurrent with this amendment, the Regulated Services Group closed Empire's credit facility. The Regulated Services Group's credit facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire. During 2018 , the Renewable Energy Group extended the maturity of its senior unsecured revolving bank credit facility from October 6, 2022 to October 6, 2023 . On February 16, 2018 , the Renewable Energy Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 202 1. Subsequent to year-end, on February 24, 2020, the Renewable Energy Group increased its uncommitted Renewable Energy LC Facility to $350,000 and extended the maturity to June 30, 2021. (b) Senior unsecured bank credit facilities On June 27, 2019 , the Regulated Services Group extended the maturity of its $135,000 term loan to July 6, 2020 . During the year, the Company repaid $60,000 of the facility. On March 7, 2018 , the Company drew $600,000 under a new term credit facility. The balance was repaid in 2018 except for a balance of $186,807 , which was repaid on May 23, 2019 . (c) Commercial paper On July 1, 2019 , the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group's bank credit facility. (d) Canadian dollar senior unsecured notes Subsequent to year-end, on February 14, 2020 , the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050 . The debentures are redeemable at the option of the Company at any time at a predetermined price. On January 29, 2019 , the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029 . The notes were sold at a price of C$99.952 per C$100.00 principal amount. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C $135,000 (note 24(b)(ii)). On July 25, 2018 , the Company repaid, upon its maturity, a C $135,000 unsecured note. (e) Subordinated unsecured notes On May 23, 2019 , the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes ("subordinated notes") maturing on July 1, 2079 . Concurrent with the offering, the Company entered into a cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars. 9. Long-term debt (continued) (e) Subordinated unsecured notes (continued) Beginning on July 1, 2024 , and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01% , payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029 , and on every interest reset date until July 1, 2049 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26% , payable in arrears. Beginning on July 1, 2049 , and on every interest reset date until July 1, 2079 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01% , payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024 , the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest. On October 17, 2018 , the Company completed the issuance of $287,500 unsecured, 6.875% fixed-to-floating subordinated notes (“subordinated notes”) maturing on October 17, 2078 . Beginning on October 17, 2023 , and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until October 17, 2028 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.677% , payable in arrears. Beginning on October 17, 2028 , and on every interest reset date until October 17, 2043, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.927% , payable in arrears. Beginning on October 17, 2043 , and on every interest reset date until October 17, 2078 , the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.677% , payable in arrears. The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after October 17, 2023 , the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
Principal Payments	Principal payments due in the next five years and thereafter are as follows: 2020 2021 2022 2023 2024 Thereafter Total $ 602,028 $ 117,513 $ 351,227 $ 97,478 $ 215,743 $ 2,547,916 $ 3,931,905 Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2020 $ 1,035 2021 1,050 2022 1,070 2023 1,243 2024 1,454 Thereafter to 2031 9,439 Redemption amount 4,111 $ 19,402 Less: amounts representing interest (5,609 ) $ 13,793 Less current portion (1,035 ) $ 12,758

Pension and other post-retire_2

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Benefit Obligations Fair Value of Plan Assets and Funded Status	The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2019 2018 2019 2018 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 484,707 $ 531,694 $ 168,325 $ 176,975 Projected benefit obligation assumed from business combination 20,196 — 11,646 — Modifications to plans (7,705 ) — — — Service cost 12,351 15,481 4,587 5,791 Interest cost 20,222 19,077 7,575 6,727 Actuarial (gain) loss 65,443 (29,986 ) 33,605 (14,800 ) Contributions from retirees — — 1,913 1,878 Gain on curtailment — (1,875 ) — — Medicare Part D — — 414 42 Benefits paid (30,244 ) (49,684 ) (8,848 ) (8,288 ) Projected benefit obligation, end of year $ 564,970 $ 484,707 $ 219,217 $ 168,325 Change in plan assets Fair value of plan assets, beginning of year 339,099 403,945 115,542 130,487 Plan assets acquired in business combination 8,004 — 15,688 — Actual return on plan assets 68,025 (36,987 ) 25,464 (10,603 ) Employer contributions 22,190 21,825 8,628 2,026 Medicare Part D subsidy receipts — — 414 42 Benefits paid (30,244 ) (49,684 ) (6,863 ) (6,410 ) Fair value of plan assets, end of year $ 407,074 $ 339,099 $ 158,873 $ 115,542 Unfunded status $ (157,896 ) $ (145,608 ) $ (60,344 ) $ (52,783 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets (note 11) — — 8,437 3,161 Current liabilities (1,415 ) (873 ) (1,168 ) (850 ) Non-current liabilities (156,481 ) (144,735 ) (67,613 ) (55,094 ) Net amount recognized $ (157,896 ) $ (145,608 ) $ (60,344 ) $ (52,783 ) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2019 2018 2019 2018 Accumulated benefit obligation $ 504,403 $ 439,458 $ 202,422 $ 163,375 Fair value of plan assets $ 407,074 $ 339,099 $ 133,711 $ 107,430 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2019 2018 2019 2018 Projected benefit obligation $ 564,971 $ 476,791 $ 202,422 $ 163,375 Fair value of plan assets $ 407,074 $ 339,099 $ 133,711 $ 107,430
Amounts Recognized in Accumulated Other Comprehensive loss	Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2018 $ 25,128 $ (4,995 ) $ (3,182 ) $ (470 ) Additions to AOCI 34,916 (1,875 ) 3,254 — Amortization in current period (1,074 ) 649 272 262 Loss on plan settlements $ (2,547 ) $ — $ — $ — Reclassification to regulatory accounts (note 7(b)) (22,166 ) — (14,232 ) — Balance, December 31, 2018 $ 34,257 $ (6,221 ) $ (13,888 ) $ (208 ) AOCI from business acquisition — (285 ) — — Additions to AOCI 17,905 (7,705 ) 14,871 — Amortization in current period (3,530 ) 784 409 208 Reclassification to regulatory accounts (note 7(b)) (10,122 ) 7,247 (10,538 ) — Balance, December 31, 2019 $ 38,510 $ (6,180 ) $ (9,146 ) $ —
Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2019 and 2018 were as follows: Pension benefits OPEB 2019 2018 2019 2018 Discount rate 3.19 % 4.19 % 3.29 % 4.26 % Interest crediting rate (for cash balance plans) 4.48 % 4.43 % N/A N/A Rate of compensation increase 4.00 % 4.00 % N/A N/A Health care cost trend rate Before age 65 6.125 % 6.25 % Age 65 and after 6.125 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2031
Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR)	Weighted average assumptions used to determine net benefit cost for 2019 and 2018 were as follows: Pension benefits OPEB 2019 2018 2019 2018 Discount rate 4.19 % 3.57 % 4.25 % 3.60 % Expected return on assets 6.87 % 7.13 % 6.51 % 6.52 % Rate of compensation increase 4.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.25 % Age 65 and after 6.25 % 6.25 % Assumed ultimate medical inflation rate 4.75 % 4.75 % Year in which ultimate rate is reached 2031 2024
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses	The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2019 2018 2019 2018 Service cost $ 12,351 $ 15,481 $ 4,587 $ 5,791 Non-service costs Interest cost 20,222 19,077 7,575 6,727 Expected return on plan assets (20,485 ) (27,820 ) (6,725 ) (7,451 ) Amortization of net actuarial loss (gain) 3,530 1,074 (409 ) (272 ) Amortization of prior service credits (784 ) (649 ) (208 ) (262 ) Amortization of regulatory assets/liabilities 12,082 10,584 2,534 3,982 $ 14,565 $ 2,266 $ 2,767 $ 2,724 Net benefit cost $ 26,916 $ 17,747 $ 7,354 $ 8,515
Target Asset Allocation	The Company’s target asset allocation is as follows: Asset class Target (%) Range (%) Equity securities 68 % 50% - 78% Debt securities 32 % 22% - 50% 100 % The fair values of investments as of December 31, 2019 , by asset category, are as follows: Asset class Level 1 Percentage Equity securities $ 414,985 73 % Debt securities 141,229 25 % Other 9,732 2 % $ 565,946 100 %
Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2020 2021 2022 2023 2024 2025 — 2029 Pension plan $ 34,461 $ 34,385 $ 35,383 $ 36,897 $ 37,848 $ 192,648 OPEB 7,469 7,867 8,379 8,903 9,361 52,864

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2019
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other Assets	Other assets consist of the following: 2019 2018 Restricted cash $ 24,787 $ 18,954 OPEB plan assets (note 10(a)) 8,437 3,161 Atlantica related prepaid amount (note 8(a)) 8,844 — Long-term deposits 6,319 1,207 Income taxes recoverable 4,416 1,961 Deferred financing costs 5,477 4,449 Other 8,192 4,967 $ 66,472 $ 34,699 Less: current portion (7,764 ) (6,115 ) $ 58,708 $ 28,584

Other long-term liabilities and

Other long-term liabilities and deferred credits (Tables)	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other Long Term Liabilities	Other long-term liabilities consist of the following: 2019 2018 Advances in aid of construction (a) $ 60,828 $ 63,703 Environmental remediation obligation (b) 58,061 55,621 Asset retirement obligations (c) 53,879 43,291 Customer deposits (d) 31,946 29,974 Unamortized investment tax credits (e) 18,234 17,491 Deferred credits (f) 18,952 42,711 Preferred shares, Series C (g) 13,793 13,418 Lease liabilities (note 1(q)) 9,695 3,436 Other (h) 35,952 28,360 $ 301,340 $ 298,005 Less: current portion (57,939 ) (42,337 ) $ 243,401 $ 255,668 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2019, $5,465 (2018 - $3,687 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. 12. Other long-term liabilities (continued) (b) Environmental remediation obligation (continued) The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $58,484 (2018 - $59,181 ), which at discount rates ranging from 1.7% to 2.1% represents the recorded accrual of $58,061 as of December 31, 2019 (2018 - $55,621 ). Approximately $36,382 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years. Changes in the environmental remediation obligation are as follows: 2019 2018 Opening balance $ 55,621 $ 54,322 Remediation activities (1,678 ) (2,163 ) Accretion 1,065 1,479 Changes in cash flow estimates 981 4,051 Revision in assumptions 2,072 (2,068 ) Closing balance $ 58,061 $ 55,621 By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2019, the Company has reflected a regulatory asset of $82,300 (2018 - $82,295 ) for the MGP and related sites (note 7(a)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and Polychlorinated Biphenyls "PCB" contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants and (vi) remove asbestos upon major renovation or demolition of structures and facilities. Changes in the asset retirement obligations are as follows: 2019 2018 Opening balance $ 43,291 $ 44,166 Obligation assumed from business acquisition and constructed projects 3,226 225 Retirement activities (443 ) (5,130 ) Accretion 2,148 1,974 Change in cash flow estimates 5,657 2,056 Closing balance $ 53,879 $ 43,291 As the cost of retirement of utility assets, liability accretion and asset depreciation expense are expected to be recovered through rates, a corresponding regulatory asset is recorded (note 7(j)). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. 12. Other long-term liabilities (continued) (f) Deferred credits During the year, the Company settled $29,100 of contingent consideration related to the Company's investment in Atlantica (note 8(a)), and recorded an additional $ 5,000 contingent consideration related to the Company's investment in the San Antonio Water System (note 8(c)). (g) Preferred shares, Series C APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share. As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2020 $ 1,035 2021 1,050 2022 1,070 2023 1,243 2024 1,454 Thereafter to 2031 9,439 Redemption amount 4,111 $ 19,402 Less: amounts representing interest (5,609 ) $ 13,793 Less current portion (1,035 ) $ 12,758 (h) Other Convertible debentures As at December 31, 2019, the carrying value of the convertible debentures was $342 (2018 - $470 ). The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per C$1,000 principal amount of convertible debentures. The debentures are convertible at a price of C $10.60 per share into up to 44,130 common shares. During the year ended December 31, 2019 , $148 (2018 - $447 ) of principal converted to 19,429 (2018 - 56,926
Changes in Environmental Remediation Obligation	Changes in the environmental remediation obligation are as follows: 2019 2018 Opening balance $ 55,621 $ 54,322 Remediation activities (1,678 ) (2,163 ) Accretion 1,065 1,479 Changes in cash flow estimates 981 4,051 Revision in assumptions 2,072 (2,068 ) Closing balance $ 58,061 $ 55,621
Schedule of Asset Retirement Obligations	Changes in the asset retirement obligations are as follows: 2019 2018 Opening balance $ 43,291 $ 44,166 Obligation assumed from business acquisition and constructed projects 3,226 225 Retirement activities (443 ) (5,130 ) Accretion 2,148 1,974 Change in cash flow estimates 5,657 2,056 Closing balance $ 53,879 $ 43,291
Principal Payments	Principal payments due in the next five years and thereafter are as follows: 2020 2021 2022 2023 2024 Thereafter Total $ 602,028 $ 117,513 $ 351,227 $ 97,478 $ 215,743 $ 2,547,916 $ 3,931,905 Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows: 2020 $ 1,035 2021 1,050 2022 1,070 2023 1,243 2024 1,454 Thereafter to 2031 9,439 Redemption amount 4,111 $ 19,402 Less: amounts representing interest (5,609 ) $ 13,793 Less current portion (1,035 ) $ 12,758

Shareholders' capital (Tables)

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Number of Common Shares	Number of common shares 2019 2018 Common shares, beginning of year 488,851,433 431,765,935 Public offering (a)(i) and (a)(ii) 28,009,341 50,041,624 Dividend reinvestment plan (a)(iii) 6,068,465 5,880,843 Exercise of share-based awards (c) 1,274,655 1,106,105 Conversion of convertible debentures (note 12(h)) 19,429 56,926 Common shares, end of year 524,223,323 488,851,433
Schedule of Shares Issued and Outstanding	The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2019 and 2018 : Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $ Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463 Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836 $ 184,299
Share-Based Compensation Expense	For the year ended December 31, 2019 , APUC recorded $10,553 (2018 - $9,458 ) in total share-based compensation expense detailed as follows: 2019 2018 Share options $ 1,288 $ 2,054 Director deferred share units 798 714 Employee share purchase 322 312 Performance and restricted share units 8,145 6,378 Total share-based compensation $ 10,553 $ 9,458
Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2019 2018 Risk-free interest rate 1.9 % 2.1 % Expected volatility 20 % 21 % Expected dividend yield 4.3 % 4.8 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 1.66 C$ 1.41
Stock Option Activity	Share option activity during the years is as follows: Number of awards Weighted average exercise price Weighted average remaining contractual term (years) Aggregate intrinsic value Balance, January 1, 2018 6,738,856 C$ 11.18 6.32 C$ 19,380 Granted 1,166,717 12.80 8.00 — Exercised (1,589,211 ) 10.66 5.02 5,059 Forfeited (23,720 ) 12.80 — — Balance, December 31, 2018 6,292,642 C$ 11.61 5.75 C$ 13,342 Granted 1,113,775 14.96 8.00 — Exercised (3,882,505 ) 11.23 4.45 6,225 Forfeited — — — — Balance, December 31, 2019 3,523,912 C$ 13.09 5.87 C$ 18,609 Exercisable, December 31, 2019 1,735,241 C$ 12.57 5.43 C$ 14,559
Performance Stock Units	. A summary of the PSUs and RSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance, January 1, 2018 955,028 C$ 12.30 1.84 C$ 13,428 Granted, including dividends 791,524 12.41 2.00 10,098 Exercised (285,551 ) 10.02 — 3,691 Forfeited (68,869 ) 13.02 — — Balance, December 31, 2018 1,392,132 C$ 12.75 1.60 C$ 19,114 Granted, including dividends 1,471,442 14.69 2.00 16,302 Exercised (344,340 ) 11.55 — 5,148 Forfeited (107,191 ) 13.84 — — Balance, December 31, 2019 2,412,043 C$ 14.00 1.86 C$ 44,309 Exercisable, December 31, 2019 743,787 C$ 13.21 — C$ 13,663 (v) Bonus deferral RSUs During 2018, the Company introduced a new bonus deferral RSU program to certain of its employees. Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. The RSUs granted are 100% vested and therefore, compensation expense associated with RSUs is recognized immediately upon issuance. 13. Shareholders’ capital (continued) (c) Share-based compensation (continued) (vi) Bonus deferral RSUs

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated other comprehensive income (loss)	AOCI consists of the following balances, net of tax: Foreign currency cumulative translation Unrealized gain on cash flow hedges Pension and post-employment actuarial changes Total Balance, January 1, 2018 $ (47,701 ) $ 55,366 $ (10,457 ) $ (2,792 ) Adoption of ASU 2018-02 on tax effects in AOCI — 11,657 (1,032 ) 10,625 Other comprehensive income (loss) (27,969 ) 1,567 2,046 (24,356 ) Amounts reclassified from AOCI to the consolidated statement of operations — (4,257 ) (86 ) (4,343 ) Net current period OCI $ (27,969 ) $ (2,690 ) $ 1,960 $ (28,699 ) OCI attributable to the non-controlling interests 1,481 — — 1,481 Net current period OCI attributable to shareholders of APUC $ (26,488 ) $ (2,690 ) $ 1,960 $ (27,218 ) Balance, December 31, 2018 $ (74,189 ) $ 64,333 $ (9,529 ) $ (19,385 ) Adoption of ASU 2017-12 on hedging (note 2(a)) — 186 — 186 Other comprehensive income (loss) 7,795 19,177 (7,999 ) 18,973 Amounts reclassified from AOCI to the consolidated statement of operations — (8,597 ) — 1,490 (7,107 ) Net current period OCI $ 7,795 $ 10,580 $ (6,509 ) $ 11,866 OCI attributable to the non-controlling interests (2,428 ) — — (2,428 ) Net current period OCI attributable to shareholders of APUC $ 5,367 $ 10,580 $ (6,509 ) $ 9,438 Balance, December 31, 2019 $ (68,822 ) $ 75,099 $ (16,038 ) $ (9,761 )

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Cash Dividends [Abstract]
Dividends	Dividends declared during the year were as follows: 2019 2018 Dividend Dividend per share Dividend Dividend per share Common shares $ 277,835 $ 0.5512 $ 235,440 $ 0.5011 Series A preferred shares C$ 6,194 C$ 1.2905 C$ 5,400 C$ 1.1250 Series D preferred shares C$ 5,068 C$ 1.2671 C$ 5,000 C$ 1.2500

Non-controlling Interests and_2

Non-controlling Interests and Redeemable non-controlling Interest (Tables)	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
Net Loss Attributable to Non-controlling Interests	effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2019 2018 HLBV and other adjustments attributable to: Non-controlling interests - tax equity partnership units $ (55,963 ) $ (103,150 ) Non-controlling interests - redeemable tax equity partnership units (9,006 ) (7,545 ) Other net earnings attributable to: Non-controlling interests 2,553 2,174 $ (62,416 ) $ (108,521 ) Redeemable non-controlling interest, held by related party 16,482 2,622 Net effect of non-controlling interests $ (45,934 ) $ (105,899 )
Changes in Redeemable Non-Controlling Interest	s in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2019 2018 2019 2018 Opening balance $ 307,622 $ — $ 33,364 $ 41,553 Net effect from operations 16,482 2,622 (9,006 ) (7,545 ) Contributions, net of costs — 305,000 3,403 — Dividends and distributions declared (18,241 ) — (1,848 ) (644 ) Closing balance $ 305,863 $ 307,622 $ 25,913 $ 33,364

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Provision for 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% ( 2018 - 26.5% ). The differences are as follows: 2019 2018 Expected income tax expense at Canadian statutory rate $ 147,093 $ 35,102 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,703 ) (28,064 ) Adjustments from investments carried at fair value (60,730 ) 25,870 Non-controlling interests share of income 16,991 29,637 Non-deductible acquisition costs 2,500 4,267 Tax credits (9,332 ) (1,419 ) Adjustment relating to prior periods (1,240 ) 3,673 U.S. Tax reform and related deferred tax adjustments (1) — (18,363 ) Other 2,538 2,669 Income tax expense $ 70,117 $ 53,372
Income (Loss) Before Taxes	For the years ended December 31, 2019 and 2018 , earnings before income taxes consist of the following: 2019 2018 Canada $ 351,908 $ (109,537 ) U.S. 203,159 241,998 $ 555,067 $ 132,461
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, 2019 Canada $ 6,695 $ 17,607 $ 24,302 United States 9,736 36,079 45,815 $ 16,431 $ 53,686 $ 70,117 Year ended December 31, 2018 Canada $ 2,872 $ (14,197 ) $ (11,325 ) United States 8,475 56,222 64,697 $ 11,347 $ 42,025 $ 53,372
Tax Effect of Temporary Difference Between Assets and Liability	The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are presented below: 2019 2018 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 382,448 $ 329,099 Pension and OPEB 54,113 48,586 Environmental obligation 15,541 14,790 Regulatory liabilities 160,200 161,560 Other 59,103 45,193 Total deferred income tax assets $ 671,405 $ 599,228 Less: valuation allowance (29,447 ) (28,018 ) Total deferred tax assets $ 641,958 $ 571,210 Deferred tax liabilities: Property, plant and equipment $ 707,185 $ 653,962 Outside basis in partnership 235,063 167,659 Regulatory accounts 145,852 113,758 Other 14,811 7,561 Total deferred tax liabilities $ 1,102,911 $ 942,940 Net deferred tax liabilities $ (460,953 ) $ (371,730 ) Consolidated balance sheets classification: Deferred tax assets $ 30,585 $ 72,415 Deferred tax liabilities (491,538 ) (444,145 ) Net deferred tax liabilities $ (460,953 ) $ (371,730 )
Non Capital Losses Carry Forwards	As of December 31, 2019 , the Company had non-capital losses carried forward available to reduce future years' taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2020 and onwards $ 1,091,322

Other Losses (Tables)

Other Losses (Tables)	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Schedule of Other Losses	Other losses consist of the following: 2019 2018 Pension and other post-employment non-service costs (note 10) $ (17,332 ) $ (4,990 ) Acquisition and transition-related costs (note 3) (11,609 ) (687 ) Other (15,085 ) (2,725 ) $ (44,026 ) $ (8,402 )

Basic and diluted net earning_2

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share, Basic and Diluted [Abstract]
Reconciliation of Net Income and Weighted Average Shares Used in Computation of Basic and Diluted Earnings per Share	The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2019 2018 Net earnings attributable to shareholders of APUC $ 530,884 $ 184,988 Series A preferred shares dividend 4,666 4,169 Series D preferred shares dividend 3,820 3,858 Net earnings attributable to common shareholders of APUC from continuing operations – basic and diluted $ 522,398 $ 176,961 Weighted average number of shares Basic 499,910,876 461,818,023 Effect of dilutive securities 4,828,678 4,227,595 Diluted 504,739,554 466,045,618

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Results of Operations and Assets for Segments	Year ended December 31, 2019 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,366,971 $ 257,950 $ — $ 1,624,921 Fuel, power and water purchased 426,046 17,258 — 443,304 Net revenue 940,925 240,692 — 1,181,617 Operating expenses 396,559 75,209 221 471,989 Administrative expenses 36,628 19,405 769 56,802 Depreciation and amortization 194,498 88,825 981 284,304 Loss on foreign exchange — — 3,146 3,146 Operating income (loss) 313,240 57,253 (5,117 ) 365,376 Interest expense (101,518 ) (61,039 ) (18,931 ) (181,488 ) Income from long-term investments 9,334 104,025 285,733 399,092 Other income (expenses) (32,292 ) 15,946 (11,567 ) (27,913 ) Earnings before income taxes $ 188,764 $ 116,185 $ 250,118 $ 555,067 Property, plant and equipment $ 4,754,373 $ 2,444,382 $ 32,909 $ 7,231,664 Investments carried at fair value 27,072 1,267,075 — 1,294,147 Equity-method investees 29,827 53,670 273 83,770 Total assets 6,816,063 4,014,067 81,340 10,911,470 Capital expenditures $ 478,936 $ 102,396 $ — $ 581,332 (1) Revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers. 21. Segmented information (continued) Year ended December 31, 2018 Regulated Services Group Renewable Energy Group Corporate Total Revenue (1)(2) $ 1,401,240 $ 247,223 $ — $ 1,648,463 Fuel and power purchased 456,974 27,164 — 484,138 Net revenue 944,266 220,059 — 1,164,325 Operating expenses 401,486 70,980 — 472,466 Administrative expenses 33,234 18,539 937 52,710 Depreciation and amortization 177,719 82,044 1,009 260,772 Gain on foreign exchange — — (58 ) (58 ) Operating income (loss) 331,827 48,496 (1,888 ) 378,435 Interest expense (99,063 ) (50,920 ) (2,135 ) (152,118 ) Income (loss) from long-term investments 5,558 45,741 (136,117 ) (84,818 ) Other expenses (6,775 ) (1,576 ) (687 ) (9,038 ) Earnings (loss) before income taxes $ 231,547 $ 41,741 $ (140,827 ) $ 132,461 Property, plant and equipment $ 4,210,115 $ 2,152,420 $ 31,023 $ 6,393,558 Investment carried at fair value — 814,530 — 814,530 Equity-method investees 55 29,273 260 29,588 Total assets 6,022,262 3,269,786 106,541 9,398,589 Capital expenditures $ 370,221 $ 96,148 $ — $ 466,369 (1) Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers. (2) Regulated Services Group revenue includes $7,425 related to alternative revenue programs for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers.
Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2019 2018 Revenue Canada $ 87,226 $ 70,358 United States 1,537,695 1,578,105 $ 1,624,921 $ 1,648,463 Property, plant and equipment Canada $ 752,016 $ 415,979 United States 6,479,648 5,977,579 $ 7,231,664 $ 6,393,558 Intangible assets Canada $ 23,795 $ 23,994 United States 23,821 31,000 $ 47,616 $ 54,994

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Estimates of Future Commitments	Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 30,672 $ 11,422 $ 11,338 $ 11,566 $ 11,796 $ 179,412 $ 256,206 Gas supply and service agreements (ii) 83,083 60,699 49,217 46,406 41,538 135,926 416,869 Service agreements 47,950 40,456 41,554 45,611 47,005 293,436 516,012 Capital projects 104,809 114,806 — — — — 219,615 Land easements 6,603 6,673 6,744 6,835 6,918 200,891 234,664 Total $ 273,117 $ 234,056 $ 108,853 $ 110,418 $ 107,257 $ 809,665 $ 1,643,366 (i) Power purchase: APUC’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, 2019 . However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Non-cash operating items (Table

Non-cash operating items (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Changes In Non Cash Operating Items [Abstract]
Changes in Non-Cash Operating Items	The changes in non-cash operating items consist of the following: 2019 2018 Accounts receivable $ (20,857 ) $ 3,005 Fuel and natural gas in storage 13,985 1,351 Supplies and consumables inventory (6,028 ) (7,189 ) Income taxes recoverable 17,796 (763 ) Prepaid expenses (7,501 ) 2,907 Accounts payable 63,854 (22,915 ) Accrued liabilities 8,872 28,687 Current income tax liability (5,016 ) 2,974 Asset retirements and environmental obligations (2,494 ) (7,293 ) Net regulatory assets and liabilities (2,308 ) (8,890 ) $ 60,303 $ (8,126 )

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair value of financial instruments 2019 Carrying amount Fair value Level 1 Level 2 Level 3 Long-term investments carried at fair value $ 1,294,147 $ 1,294,147 1,178,581 $ 27,072 $ 88,494 Development loans and other receivables 37,050 37,984 — 37,984 — Derivative instruments: Energy contracts designated as a cash flow hedge 65,304 65,304 — — 65,304 Energy contracts not designated as a hedge 20,384 20,384 — — 20,384 Commodity contracts for regulated operations 16 16 — 16 — Total derivative instruments 85,704 85,704 — 16 85,688 Total financial assets $ 1,416,901 $ 1,417,835 $ 1,178,581 $ 65,072 $ 174,182 Long-term debt $ 3,931,868 $ 4,284,068 $ 1,495,153 $ 2,788,915 $ — Convertible debentures 342 623 623 — — Preferred shares, Series C 13,793 15,120 — 15,120 — Derivative instruments: Energy contracts designated as a cash flow hedge 789 789 — — 789 Energy contracts not designated as a hedge 38 38 — — 38 Cross-currency swap designated as a net investment hedge 81,765 81,765 — 81,765 — Commodity contracts for regulated operations 2,072 2,072 — 2,072 — Total derivative instruments 84,664 84,664 — 83,837 827 Total financial liabilities $ 4,030,667 $ 4,384,475 $ 1,495,776 $ 2,887,872 $ 827 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2018 Carrying amount Fair value Level 1 Level 2 Level 3 Long-term investment carried at fair value $ 814,530 $ 814,530 $ 814,530 $ — $ — Development loans and other receivables 103,696 110,019 — 110,019 — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 61,838 61,838 — — 61,838 Currency forward contract not designated as a hedge 869 869 — 869 — Commodity contracts for regulatory operations 101 101 — 101 — Total derivative instruments 62,808 62,808 — 970 61,838 Total financial assets $ 981,034 $ 987,357 $ 814,530 $ 110,989 $ 61,838 Long-term debt $ 3,336,795 $ 3,356,773 $ 768,400 $ 2,588,373 $ — Convertible debentures 470 639 639 — — Preferred shares, Series C 13,418 13,703 — 13,703 — Derivative instruments: Energy contracts designated as a cash flow hedge 57 57 — — 57 Cross-currency swap designated as a net investment hedge 93,198 93,198 — 93,198 — Interest rate swaps designated as a hedge 8,473 8,473 — 8,473 — Commodity contracts for regulated operations 1,114 1,114 — 1,114 — Total derivative instruments 102,842 102,842 — 102,785 57 Total financial liabilities $ 3,453,525 $ 3,473,957 $ 769,039 $ 2,704,861 $ 57 (1) Balance of $441 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
Summary of Commodity Volumes Associated with Derivative Contracts	The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2019 Financial contracts: Swaps 2,134,739 Options 150,000 Forward contracts 2,500,000 4,784,739
Impact of Change in Fair Value of Natural Gas Derivative Contracts	The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 2019 2018 Regulatory assets: Swap contracts $ 28 $ 66 Option contracts 38 — Forward contracts $ 1,830 $ — Regulatory liabilities: Swap contracts $ 743 $ 218 Option contracts — 134 Forward contracts $ — $ 1,259
Long-Term Energy Derivative Contracts	The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. Notional quantity (MW-hrs) Expiry Receive average prices (per MW-hr) Pay floating price (per MW-hr) 757,075 December 2028 35.35 PJM Western HUB 3,443,530 December 2027 25.54 PJM NI HUB 2,665,068 December 2027 36.46 ERCOT North HUB
Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Consolidated Statement of Operations	The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2019 2018 Effective portion of cash flow hedge $ 19,177 $ 1,567 Amortization of cash flow hedge (33 ) (33 ) Amounts reclassified from AOCI (8,564 ) (4,224 ) OCI attributable to shareholders of APUC $ 10,580 $ (2,690 )
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: 2019 2018 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ (530 ) $ 77 Currency forward contract 904 (1,230 ) Total change in unrealized loss (gain) on derivative financial instruments $ 374 $ (1,153 ) Realized loss (gain) on derivative financial instruments: Energy derivative contracts 227 (73 ) Currency forward contract (147 ) 115 Total realized loss on derivative financial instruments $ 80 $ 42 Loss (gain) on derivative financial instruments not accounted for as hedges 454 (1,111 ) Discontinued hedge accounting (note 24(b)(ii)) and other (15,810 ) 632 $ (15,356 ) $ (479 ) Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (16,113 ) $ 636 Loss (gain) on foreign exchange 757 (1,115 ) $ (15,356 ) $ (479 )
Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2019 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2019 Canadian $ US $ Cash and cash equivalents and restricted cash $ 53,619 $ 45,989 Accounts receivable 42,987 231,006 Allowance for doubtful accounts (89 ) (4,850 ) Notes receivable 15,963 50,680 $ 112,480 $ 322,825
Liabilities Maturity Profile	The Company’s liabilities mature as follows: Due less than 1 year Due 2 to 3 years Due 4 to 5 years Due after 5 years Total Long-term debt obligations $ 602,028 $ 468,740 $ 600,721 $ 2,260,416 $ 3,931,905 Convertible debentures — — — — 346 346 Advances in aid of construction 1,165 — — 59,663 60,828 Interest on long-term debt 185,231 318,469 257,443 992,116 1,753,259 Purchase obligations 458,288 — — — 458,288 Environmental obligation 14,970 20,850 1,128 21,536 58,484 Derivative financial instruments: Cross-currency swap 4,149 69,099 3,851 4,666 81,765 Energy derivative and commodity contracts 1,631 909 — 359 2,899 Other obligations 39,115 2,120 2,696 109,094 153,025 Total obligations $ 1,306,577 $ 880,187 $ 865,839 $ 3,448,196 $ 6,500,799

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements - Narrative (Details)	12 Months Ended
	Dec. 31, 2019business_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	Jan. 01, 2018USD ($)	Dec. 31, 2019USD ($)MWhFacility	Dec. 31, 2018USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities | Facility		3
Number of power generating facilities | Facility		2
Non-regulated energy sales		$ 1,624,921	$ 1,648,463
Interest expense on long-term debt and others		$ 181,488	152,118
Electricity generated from an eligible energy source (megawatt) | MWh		1
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault		$ 60,230	59,288
Long-term debt of Long Sault		21,754	22,263
Operating expenses and amortization		4,930	4,634
Interest expense on long-term debt and others		$ 2,340	2,557
Minimum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		7.52%
Maximum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		60.00%
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
Significant Accounting Policies [Line Items]
Intangible asset, useful life		40 years
Accounting Standards Update 2014-09
Significant Accounting Policies [Line Items]
Adjustment to retained earnings, for previously deferred revenue, before tax	$ 2,488
Adjustment to retained earnings, for previously deferred revenue, net of tax	$ 1,860
Non-regulated energy sales
Significant Accounting Policies [Line Items]
Non-regulated energy sales		$ 246,601	235,359
Non-regulated energy sales | Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Non-regulated energy sales		$ 17,108	$ 17,232

Significant accounting polici_5

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Generation | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years	3 years
Generation | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	60 years	60 years
Generation | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	33 years	33 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Distribution | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	100 years	100 years
Distribution | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	42 years	40 years
Equipment and other | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Equipment and other | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	44 years	43 years
Equipment and other | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years	10 years

Significant accounting polici_6

Significant accounting policies - Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Nov. 01, 2019	Oct. 01, 2019	Jun. 30, 2019	Jan. 01, 2019
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
Year 1	$ 2,115
Year 2	1,138
Year 3	688
Year 4	659
Year 5	642
Thereafter	5,195
Total	10,437
Finance Lease, Liability, Payment, Due [Abstract]
Year 1	539
Year 2	537
Year 3	537
Year 4	537
Year 5	537
Thereafter	$ 318
Weighted-average discount rate, finance lease (percent)	6.45%
Weighted-average remaining term, finance lease	5 years 6 months 18 days
Right of use asset		$ 1,316			$ 8,295
Lease liabilities (note 1(q))	$ 9,695		$ 1,316		$ 8,295
Weighted-average discount rate, operating lease (percent)	3.95%
Weighted-average remaining term, operating lease	13 years 5 months 26 days
Minimum
Finance Lease, Liability, Payment, Due [Abstract]
Lease renewal term				1 year
Maximum
Finance Lease, Liability, Payment, Due [Abstract]
Lease renewal term	5 years			5 years

Recently issued accounting pr_2

Recently issued accounting pronouncements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Nov. 01, 2019	Oct. 01, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right of use asset		$ 1,316		$ 8,295
Operating lease liability	$ 9,695		$ 1,316	8,295
Accounting Standards Update 2017-12
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI				186
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right of use asset				8,295
Operating lease liability				8,295
Accumulated OCI | Accounting Standards Update 2017-12
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI				$ 186

Business acquisitions and dev_3

Business acquisitions and development projects - Additional Information (Details) $ in Thousands, $ in Thousands	Dec. 31, 2019USD ($)	Nov. 20, 2019USD ($)	Jun. 03, 2019USD ($)	May 24, 2019USD ($)	Aug. 10, 2017USD ($)water_utility	Dec. 31, 2019USD ($)MWwind_projectMWac	Dec. 31, 2019CAD ($)MWwind_projectMWac	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Number of wind farms | wind_project						3	3
Mid-west Wind Development Project
Business Acquisition [Line Items]
Wind power capacity (megawatt) | MW						600	600
Total purchase price							$ 1,100,000
Ascendant Group Limited
Business Acquisition [Line Items]
Total purchase price			$ 365,000
American Water Works Company
Business Acquisition [Line Items]
Total purchase price		$ 608,000
Perris Water Distribution System
Business Acquisition [Line Items]
Total purchase price					$ 11,500
Number of water distribution systems acquired | water_utility					2
Turquoise Solar Facility
Business Acquisition [Line Items]
Solar power capacity (megawatt ac) | MWac						10	10
Total purchase price	$ 20,830
Great Bay Solar Facility I
Business Acquisition [Line Items]
Solar power capacity (megawatt ac) | MWac						75	75
Great Bay Solar Facility II
Business Acquisition [Line Items]
Solar power capacity (megawatt ac) | MWac						40	40
Tax equity funding	11,281					$ 11,281
Investment tax credit						$ 8,526
Partnership | Turquoise Solar Facility
Business Acquisition [Line Items]
Partnership agreement, funded amount	$ 2,000			$ 1,403
Partnership | Great Bay Solar Facility I
Business Acquisition [Line Items]
Partnership agreement, funded amount								$ 15,250	$ 42,750

Business acquisitions and dev_4

Business acquisitions and development projects - Acquisition of New Brunswick Gas and St. Lawrence Gas Company, Inc. (Details) $ in Thousands, $ in Thousands	Nov. 01, 2019USD ($)	Oct. 01, 2019USD ($)	Oct. 01, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Goodwill				$ 1,031,696	$ 954,282	$ 954,282	$ 954,282
New Brunswick Gas
Business Acquisition [Line Items]
Total purchase price		$ 256,011	$ 339,036
Working capital		8,782
Property, plant and equipment		137,668
Goodwill		56,054
Regulatory assets		94,827
Deferred income tax assets, net		0
Other assets		125
Regulatory liabilities		(2,076)
Pension and post-employment benefits		0
Deferred income tax liability, net		(38,053)
Other liabilities		(1,316)
Total net assets acquired		256,011
Cash and cash equivalents		7,248
Total net assets acquired, net of cash and cash equivalent		$ 248,763
Intangible asset, useful life				47 years
St. Lawrence Gas Company, Inc.
Business Acquisition [Line Items]
Total purchase price	$ 61,820
Working capital	3,403
Property, plant and equipment	49,936
Goodwill	20,259
Regulatory assets	3,562
Deferred income tax assets, net	1,614
Other assets	6,418
Regulatory liabilities	(10,412)
Pension and post-employment benefits	(12,376)
Deferred income tax liability, net	0
Other liabilities	(584)
Total net assets acquired	61,820
Cash and cash equivalents	1,225
Total net assets acquired, net of cash and cash equivalent	$ 60,595
Intangible asset, useful life				49 years

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 4,939	$ 5,281
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 80,295	$ 79,742

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Cost	$ 8,417,772	$ 7,406,319
Accumulated depreciation	1,186,108	1,012,761
Net book value	7,231,664	6,393,558
Land
Property, Plant and Equipment [Line Items]
Cost	74,517	73,773
Accumulated depreciation	0	0
Net book value	74,517	73,773
Equipment and other
Property, Plant and Equipment [Line Items]
Cost	94,583	88,757
Accumulated depreciation	47,541	41,295
Net book value	47,042	47,462
Generation
Property, Plant and Equipment [Line Items]
Cost	2,816,611	2,470,279
Accumulated depreciation	540,118	450,230
Net book value	2,276,493	2,020,049
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	140,235	104,996
Accumulated depreciation	0	0
Net book value	140,235	104,996
Liberty Utilities Group
Property, Plant and Equipment [Line Items]
Cost	4,988,297	4,455,935
Accumulated depreciation	598,449	521,236
Net book value	4,389,848	3,934,699
Liberty Utilities Group | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	303,529	212,579
Accumulated depreciation	0	0
Net book value	$ 303,529	$ 212,579

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 514,709	$ 503,664
Accumulated depreciation related to commonly owned facilities	31,349	21,697
Expenditures	69,210	75,427
Contribution received	7,137	6,057
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	109,653	104,107
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	39,638	34,916
Depreciation expense	1,615	1,987
Distribution
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	1,450,946	1,383,960
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	97,080	69,960
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	1,003	$ 669
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Expansion costs	$ 1,000

Property, plant and equipment_3

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule of Capitalization [Line Items]
Total	$ 12,179	$ 6,680
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	4,538	2,268
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	2,745	1,684
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	$ 4,896	$ 2,728

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Cost	$ 97,830	$ 101,417
Accumulated amortization	50,214	46,423
Net book value	47,616	54,994
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	56,206	60,775
Accumulated amortization	38,931	36,063
Net book value	17,275	24,712
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	26,797	26,795
Accumulated amortization	10,104	9,476
Net book value	16,693	17,319
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	14,827	13,847
Accumulated amortization	1,179	884
Net book value	$ 13,648	$ 12,963

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 2,018
Estimated amortization expense for intangibles in year 2	2,190
Estimated amortization expense for intangibles in year 3	2,350
Estimated amortization expense for intangibles in year 4	1,910
Estimated amortization expense for intangibles in year 5	$ 1,780

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) - 12 months ended Dec. 31, 2019 $ in Thousands, $ in Thousands	USD ($)	CAD ($)
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 954,282	$ 954,282
Business acquisitions (note 3(a))		76,313
Foreign exchange		$ 1,101
Goodwill end of the period	$ 1,031,696

Regulatory matters - Approved A

Regulatory matters - Approved Annual Revenue Increases (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Aug. 01, 2019	May 01, 2019	Feb. 01, 2019	Jan. 01, 2019
Peach State Gas System
Regulatory Liabilities [Line Items]
Approved revenue increase				$ 2,367
New England Natural Gas System
Regulatory Liabilities [Line Items]
Approved revenue increase			$ 2,413
Empire Electric System Kansas
Regulatory Liabilities [Line Items]
Approved revenue increase		$ 2,449
Empire Electric System Oklahoma
Regulatory Liabilities [Line Items]
Approved revenue increase	$ 1,400
CalPeco Electric System
Regulatory Liabilities [Line Items]
Approved revenue increase					$ 3,525

Regulatory matters - Regulatory

Regulatory matters - Regulatory Assets and Liabilities (Detail) - USD ($) $ in Thousands	Jun. 01, 2018	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 559,887	$ 460,095
Less: current regulatory assets		(50,213)	(59,037)
Non-current regulatory assets		509,674	401,058
Total regulatory liabilities		598,062	588,213
Less: current regulatory liabilities		(41,683)	(39,005)
Non-current regulatory liabilities		556,379	549,208
Reduction of regulatory asset	$ 15,586
Increase of regulatory liability			15,586
Income Taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities		321,960	323,384
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities		196,423	193,564
Rate-base offset
Regulatory Liabilities [Line Items]
Total regulatory liabilities		8,719	10,900
Fuel and commodity costs adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities		16,645	21,352
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 10,446	4,210
Collection period for services rendered		24 months
Deferred construction costs - fuel related
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 7,097	7,258
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities		22,256	11,791
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 14,516	15,754
Minimum | Rate-base offset
Regulatory Liabilities [Line Items]
Amortization period for regulatory liability		10 years
Maximum | Rate-base offset
Regulatory Liabilities [Line Items]
Amortization period for regulatory liability		16 years
Environmental remediation
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 82,300	82,295
Regulatory assets recovery period		7 years
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 143,292	135,580
Regulatory asset approved not yet being recovered, average recovery term		10 years
Income Taxes
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 71,506	34,822
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets		42,150	48,847
Fuel and commodity costs adjustment
Regulatory Liabilities [Line Items]
Total regulatory assets		23,433	26,310
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets		69,121	37,202
Clean Energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets		26,369	24,095
Deferred construction costs - fuel related
Regulatory Liabilities [Line Items]
Total regulatory assets		38,833	13,986
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets		23,841	21,048
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets		13,264	8,283
Rate case costs
Regulatory Liabilities [Line Items]
Total regulatory assets		6,695	6,164
Other
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 19,083	$ 21,463
New Brunswick Gas | Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Regulatory assets recovery period		25 years
New Brunswick Gas | Deferred Capitalized Costs
Regulatory Liabilities [Line Items]
Regulatory assets recovery period		29 years
Regulatory Asset Annual Recovery Rate, Percent		2.43%

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investments carried at fair value	$ 1,294,147	$ 814,530
Noncontrolling interest in partnerships and joint ventures	83,770	29,588
Other	1,994	4,773
Total other long-term investments	121,968	135,778
Less: current portion	0	(1,407)
Other long-term investments	121,968	134,371
Notes Receivable | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Development loans receivable from equity-method investees (e)	36,204	101,417
Atlantica
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investments carried at fair value	1,178,581	814,530
AYES Canada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investments carried at fair value	88,494	0
San Antonio Water System
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investments carried at fair value	$ 27,072	$ 0

Long-term investments - Income

Long-term investments - Income from Long-term Investments (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Investment [Line Items]
Fair value gain (loss) on investments	$ 278,084,000	$ (137,957,000)
Dividend and interest income from investments	100,886,000	39,263,000
Equity method loss	(9,108,000)	(3,082,000)
Interest and other income	29,230,000	16,958,000
Income from long-term investments	399,092,000	(84,818,000)
Atlantica
Investment [Line Items]
Fair value gain (loss) on investments	290,740,000	(137,957,000)
Dividend and interest income from investments	69,307,000	39,263,000
AYES Canada
Investment [Line Items]
Fair value gain (loss) on investments	(6,649,000)	0
Dividend and interest income from investments	25,572,000	0
San Antonio Water System
Investment [Line Items]
Fair value gain (loss) on investments	(6,007,000)	0
Dividend and interest income from investments	$ 6,007,000	$ 0

Long-term investments - Additio

Long-term investments - Additional Information (Detail) $ in Thousands	Dec. 30, 2019USD ($)	Apr. 16, 2019USD ($)MW	Nov. 28, 2018USD ($)	May 31, 2019USD ($)	May 31, 2019CAD ($)	Jun. 30, 2019shares	Dec. 31, 2019USD ($)MWwind_projectshares	Dec. 31, 2019CAD ($)MWwind_projectshares	Dec. 31, 2018USD ($)	May 24, 2019USD ($)	May 24, 2019CAD ($)	May 01, 2019USD ($)mi	Apr. 15, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity method investments							$ 83,770,000		$ 29,588,000
Amount drawn under credit facility			$ 305,000,000
Non-controlling interest attributable to subsidiary							16,482,000		2,622,000
Distribution from interest in noncontrolling interest							26,465,000	$ 34,373
Fair value loss							278,084,000		(137,957,000)
Investments carried at fair value							1,294,147,000		814,530,000
Capital contributed to joint venture	$ 1,500,000
Dividend and interest income from investments							100,886,000		39,263,000
Noncontrolling interest in partnerships and joint ventures							83,770,000		29,588,000
Investments in VIEs							$ 59,091,000		9,581,000
Number of wind projects | wind_project							3	3
Fair value of support provided							$ 9,493,000		1,682,000
Income (loss) from equity method investments							$ 9,108,000		$ 3,082,000
Notes receivable, weighted average interest rate (percent)							7.66%		9.90%
AWUSA VR Holding LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest												20.00%
Distance of water pipeline | mi												140
Note payable	13,293,000
San Antonio Water System
Accounts, Notes, Loans and Financing Receivable [Line Items]
Fair value loss							$ (6,007,000)		$ 0
Investments carried at fair value							27,072,000		0
Additional deferred credits related to investment in San Antonio Water System							5,000,000
Dividend and interest income from investments							$ 6,007,000		0
Atlantica Yield Energy Solutions Canada, Inc
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity method investment, treasury shares purchased (shares) | shares							1,384,402	1,384,402
Payment to acquire equity method investment							$ 30,000,000
Share received pursuant to prepayment (shares) | shares							2,000,000	2,000,000
Equity method investment, prepayment							$ 53,750,000
Option to exchange shares | shares						3,500,000
AYES Canada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Non-controlling interest attributable to subsidiary				$ 96,752,000			73,707,000
Dividend income							25,572
Fair value loss							(6,649,000)		0
Investments carried at fair value							88,494,000		0
Dividend and interest income from investments							$ 25,572,000		$ 0
Atlantica
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest							44.20%		41.50%
Equity method investments									$ 952,567,000
Holdback amount on credit facility									40,000,000
Holdback settled in 2019							$ (29,100,000)
Fair value loss							290,740,000		(137,957,000)
Investments carried at fair value							1,178,581,000		814,530,000
Dividend and interest income from investments							$ 69,307,000		$ 39,263,000
Atlantica | Maximum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest							48.50%
Maverick
Accounts, Notes, Loans and Financing Receivable [Line Items]
Wind power capacity (megawatt) | MW							490	490
Sugar Creek
Accounts, Notes, Loans and Financing Receivable [Line Items]
Wind power capacity (megawatt) | MW							202	202
75% Interest in Red Lily I Partnership
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest							75.00%
Wind power capacity (megawatt) | MW							26.4	26.4
Other Development Projects
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest							50.00%
Windlectric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest													50.00%
Equity method investments										$ 91,918,000	$ 123,603
Non-controlling interest attributable to subsidiary					$ 130,103
Non-controlling interest calculated using the HLBV method							$ 0
Wind power capacity (megawatt) | MW		75
Development loan		$ 316,786,000
Altavista
Accounts, Notes, Loans and Financing Receivable [Line Items]
Solar power capacity (megawatt ac) | MW							80	80
Southern Missouri Wind Projects
Accounts, Notes, Loans and Financing Receivable [Line Items]
Wind power capacity (megawatt) | MW							150	150
Number of wind projects | wind_project							2	2
AAGES B.V Secured Credit Facility
Accounts, Notes, Loans and Financing Receivable [Line Items]
Duration of credit facility			3 years
Secured credit facility			$ 306,500,000
Secured Loan | AWUSA VR Holding LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity method investments												$ 17,000,000
Atlantica | Windlectric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity method investments										$ 4,834,000	$ 6,500
Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Exchange of note receivable	$ 30,293
Windlectric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total purchase price		6,362,000
Property, plant and equipment		311,175,000
Deferred income tax assets, net		3,015,000
Working capital		14,280,000
Liabilities		$ 1,600,000

Long-term investments - Investm

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Assets	$ 10,911,470	$ 9,398,589
APUC's investment carrying amount for the entities	83,770	29,588
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Assets	833,791	360,372
Liabilities	697,751	335,331
Net assets	136,040	25,041
APUC | Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
Net assets	63,624	18,042
Difference between investment carrying amount and underlying equity in net assets(a)	18,487	11,048
APUC's investment carrying amount for the entities	$ 82,111	$ 29,090

Long-term investments -Combined

Long-term investments -Combined Information for APUC's interest in VIE's (Details) - Variable Interest Entity, Not Primary Beneficiary - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Carrying amount	$ 59,091	$ 9,581
Development loans receivable	35,000	101,417
Commitments on behalf of VIEs	1,364,871	120,669
APUC's maximum exposure in regard to VIE's	$ 1,458,962	$ 231,667

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail) - USD ($)	Dec. 31, 2019	Oct. 24, 2019	Jul. 12, 2019	Jul. 01, 2019	May 23, 2019	Dec. 31, 2018	Oct. 17, 2018
Debt Instrument [Line Items]
Long-term debt	$ 3,931,868,000					$ 3,336,795,000
Less: current portion	(225,013,000)					(13,048,000)
Long-term debt, excluding current portion	$ 3,706,855,000					3,323,747,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	4.09%
Par value	$ 1,225,000,000
Long-term debt	$ 1,219,579,000					1,218,680,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Utility Notes
Debt Instrument [Line Items]
Weighted average coupon	6.00%
Par value	$ 217,000,000
Long-term debt	$ 233,686,000					240,161,000
Senior Unsecured Notes | U.S Dollar Senior Secured Utility Bonds
Debt Instrument [Line Items]
Weighted average coupon	4.75%
Par value	$ 662,500,000
Long-term debt	$ 672,337,000					676,697,000
Senior Unsecured Notes | Canadian Dollar Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	4.48%
Par value	$ 950,669,000
Long-term debt	$ 728,679,000					474,764,000
Senior Unsecured Notes | Canadian Dollar Senior Secured Project Notes
Debt Instrument [Line Items]
Weighted average coupon	10.22%
Par value	$ 28,503,000
Long-term debt	21,961,000					22,915,000
Senior Unsecured Notes | Senior Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 3,310,819,000					3,058,024,000
Senior Unsecured Notes | U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	6.50%						6.875%
Par value	$ 637,500,000				$ 350,000,000		$ 287,500
Long-term debt	$ 621,049,000					278,771,000
Revolving Credit Facility | Senior Unsecured Revolving Credit Facilities
Debt Instrument [Line Items]
Par value		$ 75,000,000	$ 500,000,000
Revolving Credit Facility | Commercial Paper
Debt Instrument [Line Items]
Par value				$ 500,000,000
Revolving Credit Facility | Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	0.00%
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Revolving Credit Facilities
Debt Instrument [Line Items]
Long-term debt	$ 141,577,000					97,000,000
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Bank Credit Facilities
Debt Instrument [Line Items]
Long-term debt	75,000,000					321,807,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial Paper
Debt Instrument [Line Items]
Long-term debt	$ 218,000,000					$ 6,000,000

Long-term debt - Narrative (Det

Long-term debt - Narrative (Detail)

Jul. 12, 2019CAD ($)

Jul. 01, 2019USD ($)

May 23, 2019USD ($)

Oct. 17, 2018USD ($)

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Feb. 24, 2020USD ($)

Feb. 14, 2020CAD ($)

Dec. 31, 2019CAD ($)

Oct. 24, 2019USD ($)

Jul. 12, 2019USD ($)

Jun. 27, 2019USD ($)

Jan. 29, 2019CAD ($)

Jul. 25, 2018CAD ($)

Mar. 07, 2018USD ($)

Feb. 23, 2018USD ($)

Feb. 16, 2018USD ($)

Debt Instrument [Line Items]

Short-term debt

$ 377,015,000

Long-term debt

3,931,868,000

$ 3,336,795,000

Interest on long term debt

44,229,000

33,822,000

Interest expense during the year on long-term liabilities

175,664,000

146,310,000

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

Debt Instrument [Line Items]

Par value

$ 350,000,000

$ 287,500

$ 637,500,000

Weighted average coupon

6.875%

6.50%

6.50%

Debt Instrument, Redemption Price, Percentage

100.00%

100.00%

Long-term debt

$ 621,049,000

278,771,000

Senior Unsecured Notes | Senior Unsecured Debenture Due February 2027

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 135,000,000

Senior Unsecured Notes | Senior Unsecured Notes Due January 2029

Debt Instrument [Line Items]

Par value

$ 300,000,000

Weighted average coupon

4.60%

Debt at issuance price per C$100

$ 99.952

Debt instrument, sales price ratio

0.99952

0.99952

Bonds

Debt Instrument [Line Items]

Long-term debt

$ 135,000,000

Revolving Credit Facility | Senior Unsecured Revolving Credit Facilities

Debt Instrument [Line Items]

Par value

$ 75,000,000

$ 500,000,000

Credit facility, amount canceled

$ 165,000,000

Revolving Credit Facility | Commercial Paper

Debt Instrument [Line Items]

Par value

$ 500,000,000

Maximum maturity of amounts drawn under the commercial paper program

270 days

Revolving Credit Facility | Senior Unsecured Notes

Debt Instrument [Line Items]

Weighted average coupon

0.00%

0.00%

Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Revolving Credit Facilities

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

Long-term debt

$ 141,577,000

97,000,000

Revolving Credit Facility | Senior Unsecured Notes | Algonquin Power Senior Unsecured Revolving Facility Maturing July 2019 [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 600,000,000

$ 200,000,000

Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Bank Credit Facilities

Debt Instrument [Line Items]

Long-term debt

75,000,000

321,807,000

Revolving Credit Facility | Senior Unsecured Notes | Commercial Paper

Debt Instrument [Line Items]

Long-term debt

218,000,000

$ 6,000,000

Line of Credit | Senior Unsecured Bank Credit Facilities

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 135,000,000

Repayment of debt

$ 186,807,000

$ 60,000,000

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

Debt Instrument [Line Items]

Basis spread on variable rate

4.01%

3.677%

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

Debt Instrument [Line Items]

Basis spread on variable rate

4.26%

3.927%

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

Debt Instrument [Line Items]

Basis spread on variable rate

5.01%

4.677%

Subsequent Event | Senior Unsecured Notes | Senior Unsecured Debentures Due February 2050

Debt Instrument [Line Items]

Par value

$ 200,000,000

Weighted average coupon

3.315%

Subsequent Event | Revolving Credit Facility | Senior Unsecured Notes | Algonquin Power Senior Unsecured Revolving Facility Maturing June 2021 [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 350,000,000

Long-term debt - Principal Paym

Long-term debt - Principal Payments (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2020	$ 602,028
2021	117,513
2022	351,227
2023	97,478
2024	215,743
Thereafter	2,547,916
Total, including adjustment	$ 3,931,905

Pension and other post-retire_3

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	$ 8,798	$ 8,446
Accumulated benefit obligation for pension plan	526,517	439,458
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit)	(7,798)	$ (1,875)
Pension Plans
Employee Benefits Disclosure [Line Items]
Expected employer contributions for next year	24,140
Other Postretirement Benefit Plans, Defined Benefit
Employee Benefits Disclosure [Line Items]
Expected employer contributions for next year	$ 5,736

Pension and other post-retire_4

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Change in plan assets
Non-current assets (note 11)	$ 8,437		$ 3,161
Pension Plans
Change in projected benefit obligation
Projected benefit obligation, beginning of year	484,707		531,694
Projected benefit obligation assumed from business combination	20,196		0
Modifications to plans		$ (7,705)		$ 0
Service cost	12,351		15,481
Interest cost	20,222		19,077
Actuarial (gain) loss	65,443		(29,986)
Contributions from retirees	0		0
Gain on curtailment	0		(1,875)
Medicare Part D	0		0
Benefits paid	(30,244)		(49,684)
Projected benefit obligation, end of year	564,970		484,707
Change in plan assets
Fair value of plan assets, beginning of year	339,099		403,945
Plan assets acquired in business combination	8,004		0
Actual return on plan assets	68,025		(36,987)
Employer contributions	22,190		21,825
Medicare Part D subsidy receipts	0		0
Benefits paid	(30,244)		(49,684)
Fair value of plan assets, end of year	407,074		339,099
Unfunded status	(157,896)		(145,608)
Non-current assets (note 11)	0		0
Current liabilities	(1,415)		(873)
Non-current liabilities	(156,481)		(144,735)
Net amount recognized	(157,896)		(145,608)
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation
Projected benefit obligation, beginning of year	168,325		176,975
Projected benefit obligation assumed from business combination	11,646		0
Modifications to plans		$ 0		$ 0
Service cost	4,587		5,791
Interest cost	7,575		6,727
Actuarial (gain) loss	33,605		(14,800)
Contributions from retirees	1,913		1,878
Gain on curtailment	0		0
Medicare Part D	414		42
Benefits paid	(8,848)		(8,288)
Projected benefit obligation, end of year	219,217		168,325
Change in plan assets
Fair value of plan assets, beginning of year	115,542		130,487
Plan assets acquired in business combination	15,688		0
Actual return on plan assets	25,464		(10,603)
Employer contributions	8,628		2,026
Medicare Part D subsidy receipts	414		42
Benefits paid	(6,863)		(6,410)
Fair value of plan assets, end of year	158,873		115,542
Unfunded status	(60,344)		(52,783)
Non-current assets (note 11)	8,437		3,161
Current liabilities	(1,168)		(850)
Non-current liabilities	(67,613)		(55,094)
Net amount recognized	$ (60,344)		$ (52,783)

Pension and other post-retire_5

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 504,403	$ 439,458
Fair value of plan assets	407,074	339,099
Projected benefit obligation	564,971	476,791
Fair value of plan assets	407,074	339,099
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	202,422	163,375
Fair value of plan assets	133,711	107,430
Projected benefit obligation	202,422	163,375
Fair value of plan assets	$ 133,711	$ 107,430

Pension and other post-retire_6

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plans
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	$ 34,257	$ 25,128
AOCI from business acquisition	0
Additions to AOCI	17,905	34,916
Amortization in current period	(3,530)	(1,074)
Loss on plan settlements		(2,547)
Reclassification to regulatory accounts (note 7(b))	(10,122)	(22,166)
Ending balance, December 31	38,510	34,257
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	(6,221)	(4,995)
AOCI from business acquisition	(285)
Additions to AOCI	(7,705)	(1,875)
Amortization in current period	784	649
Gain (loss) on plan settlements		0
Reclassification to regulatory accounts (note 7(b))	7,247	0
Ending balance, December 31	(6,180)	(6,221)
Other Postretirement Benefit Plans, Defined Benefit
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	(13,888)	(3,182)
AOCI from business acquisition	0
Additions to AOCI	14,871	3,254
Amortization in current period	409	272
Loss on plan settlements		0
Reclassification to regulatory accounts (note 7(b))	(10,538)	(14,232)
Ending balance, December 31	(9,146)	(13,888)
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	(208)	(470)
AOCI from business acquisition	0
Additions to AOCI	0	0
Amortization in current period	208	262
Gain (loss) on plan settlements		0
Reclassification to regulatory accounts (note 7(b))	0	0
Ending balance, December 31	$ 0	$ (208)

Pension and other post-retire_7

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.19%	4.19%
Interest crediting rate (for cash balance plans)	4.48%	4.43%
Rate of compensation increase	4.00%	4.00%
Rate of compensation increase	4.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.29%	4.26%
Health care cost trend rate
Before age 65	6.125%	6.25%
Age 65 and after	6.125%	6.25%
Assumed ultimate medical inflation rate	4.75%	4.75%
Year in which ultimate rate is reached	2031	2031

Pension and other post-retire_8

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.19%	3.57%
Expected return on assets	6.87%	7.13%
Rate of compensation increase	4.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	3.60%
Expected return on assets	6.51%	6.52%
Health care cost trend rate
Before Age 65	6.25%	6.25%
Age 65 and after	6.25%	6.25%
Assumed Ultimate Medical Inflation Rate	4.75%	4.75%
Year in which Ultimate Rate is reached	2031	2024

Pension and other post-retire_9

Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 12,351	$ 15,481
Interest cost	20,222	19,077
Expected return on plan assets	(20,485)	(27,820)
Amortization of net actuarial loss (gain)	3,530	1,074
Amortization of prior service credits	(784)	(649)
Amortization of regulatory assets/liabilities	12,082	10,584
Defined Benefit Plan, Non-service Costs, Total	14,565	2,266
Net benefit cost	26,916	17,747
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	4,587	5,791
Interest cost	7,575	6,727
Expected return on plan assets	(6,725)	(7,451)
Amortization of net actuarial loss (gain)	(409)	(272)
Amortization of prior service credits	(208)	(262)
Amortization of regulatory assets/liabilities	2,534	3,982
Defined Benefit Plan, Non-service Costs, Total	2,767	2,724
Net benefit cost	$ 7,354	$ 8,515

Pension and other post-retir_10

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	68.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	32.00%
Minimum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	50.00%
Minimum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	22.00%
Maximum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	78.00%
Maximum | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	50.00%

Pension and other post-retir_11

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) $ in Thousands	Dec. 31, 2019USD ($)
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	100.00%
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 565,946
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	73.00%
Equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 414,985
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	25.00%
Debt securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 141,229
Other
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	2.00%
Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 9,732

Pension and other post-retir_12

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2020	$ 34,461
2021	34,385
2022	35,383
2023	36,897
2024	37,848
2025-2029	192,648
Post Retirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
2020	7,469
2021	7,867
2022	8,379
2023	8,903
2024	9,361
2025-2029	$ 52,864

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	$ 24,787	$ 18,954
OPEB plan assets	8,437	3,161
Atlantica related prepaid amount	8,844	0
Long-term deposits	6,319	1,207
Income taxes recoverable	4,416	1,961
Deferred financing costs	5,477	4,449
Other	8,192	4,967
Total other assets	66,472	34,699
Less: current portion	(7,764)	(6,115)
Other assets, noncurrent	$ 58,708	$ 28,584

Other long-term liabilities - S

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Oct. 01, 2019	Jan. 01, 2019	Dec. 31, 2017
Other Long-term Liabilities
Advances in aid of construction (a)	$ 60,828	$ 63,703
Environmental remediation obligation (b)	58,061	55,621			$ 54,322
Asset retirement obligations (c)	53,879	43,291			$ 44,166
Customer deposits (d)	31,946	29,974
Unamortized investment tax credits (e)	18,234	17,491
Deferred credits (f)	18,952	42,711
Preferred shares, Series C (g)	13,793	13,418
Lease liabilities (note 1(q))	9,695		$ 1,316	$ 8,295
Lease liabilities (note 1(q))		3,436
Other (h)	35,952	28,360
Other Liabilities	301,340	298,005
Less: current portion	(57,939)	(42,337)
Other long-term liabilities	243,401	255,668
Transfers from advances in aid of construction to contributions in aid of construction	5,465	3,687
Estimated environmental remediation costs	58,484	59,181
Accrual for environmental loss contingencies to be incurred over next four years	$ 36,382
Accrual for environmental loss contingencies, payment period	31 years
Amount of regulatory assets	$ 559,887	460,095
Minimum
Other Long-term Liabilities
Other liability repayment period	5 years
Accrual environmental cost	1.70%
Maximum
Other Long-term Liabilities
Other liability repayment period	40 years
Accrual environmental cost	2.10%
Environmental costs
Other Long-term Liabilities
Regulatory asset, expenditure recovery provided by regulator, time period	7 years
Amount of regulatory assets	$ 82,300	$ 82,295
Series C Preferred Stock
Other Long-term Liabilities
Preferred shares, Series C (g)	$ 13,793

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 55,621	$ 54,322
Remediation activities	(1,678)	(2,163)
Accretion	1,065	1,479
Changes in cash flow estimates	981	4,051
Revision in assumptions	2,072	(2,068)
Closing balance	$ 58,061	$ 55,621

Other long-term liabilities - A

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 43,291	$ 44,166
Obligation assumed from business acquisition and constructed projects	3,226	225
Retirement activities	(443)	(5,130)
Accretion	2,148	1,974
Change in cash flow estimates	5,657	2,056
Closing balance	$ 53,879	$ 43,291

Other long-term liabilities - P

Other long-term liabilities - Preferred Shares, Series C (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Dec. 31, 2019$ / shares
Class of Stock [Line Items]
Debt conversion, shares issued (in shares) | shares	19,429	56,926
Preferred stock redemption price per share (in USD per share) | $ / shares			$ 25
2020	$ 602,028
2021	117,513
2022	351,227
2023	97,478
2024	215,743
Thereafter to 2031	2,547,916
Total Preferred shares series C	$ 13,793	$ 13,418
Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares | shares	100
Preferred stock redemption price per share (in USD per share) | $ / shares			$ 53,400
Less amounts representing interest	$ (5,609)
Total Preferred shares series C	13,793
Less current portion	(1,035)
Preferred shares series C, noncurrent	12,758
Series C Preferred Stock | Dividends Payable
Class of Stock [Line Items]
2020	1,035
2021	1,050
2022	1,070
2023	1,243
2024	1,454
Thereafter to 2031	9,439
Redemption amount	4,111
Estimated dividend and redemption payments	$ 19,402
Executives of company | Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares | shares	36
Convertible Unsecured Subordinated Debentures | Convertible Subordinated Debt
Class of Stock [Line Items]
Principle converted amount	$ 148	$ 447
Atlantica
Class of Stock [Line Items]
Contingent consideration related to prior acquisition	29,100
San Antonio Water System
Class of Stock [Line Items]
Additional deferred credits related to investment in San Antonio Water System	$ 5,000

Other long-term liabilities -_2

Other long-term liabilities - Convertible Debentures (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Dec. 31, 2019$ / shares
Debt Instrument [Line Items]
Long-term debt	$ 3,931,868	$ 3,336,795
Debt instrument, convertible, number of equity instruments (in shares) | shares	44,130
Debt conversion, shares issued (in shares) | shares	19,429	56,926
Convertible Unsecured Subordinated Debentures | Convertible Subordinated Debt
Debt Instrument [Line Items]
Long-term debt	$ 342	$ 470
Debt instrument, effective interest rate	0.00%
Conversion price (CAD per share) | $ / shares			$ 10.60
Principle converted amount	$ 148	$ 447

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Common Shares Rollforward
Beginning balance (in shares)	488,851,433	431,765,935
Public offering and subscription receipts (in shares)	28,009,341	50,041,624
Dividend reinvestment plan (in shares)	6,068,465	5,880,843
Exercise of share-based awards	1,274,655	1,106,105
Conversion of convertible debentures (in shares)	19,429	56,926
Ending balance (in shares)	524,223,323	488,851,433

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands	Mar. 31, 2024$ / shares	Feb. 19, 2020$ / sharesshares	Dec. 20, 2018USD ($)$ / sharesshares	Dec. 20, 2018CAD ($)shares	Apr. 24, 2018USD ($)$ / sharesshares	Apr. 24, 2018CAD ($)shares	Oct. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2019USD ($)Rightvote$ / sharesshares	Dec. 31, 2019USD ($)$ / shares$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / shares$ / sharesshares	Dec. 31, 2019CAD ($)$ / sharesshares	Feb. 28, 2019USD ($)	Dec. 31, 2018$ / shares	Dec. 20, 2018$ / shares	Apr. 24, 2018$ / shares
Stockholders Equity Note [Line Items]
Number of entitled votes per common share | vote								1
Number of voting rights per share | Right								1
Discount rate on share purchases								50.00%
Discount rate on share purchases under dividend reinvestment plan								5.00%
Dividend reinvestment plan shares issued (in shares)								1,244,696
Carrying amount C$								$ 184,299,000	$ 184,299,000	$ 184,299,000	$ 184,299,000
Preferred stock redemption price per share (in CAD per share) | $ / shares												$ 25
Total share-based compensation expense | $								$ 10,553,000		$ 9,458,000
Options exercised (in shares)								3,882,505		1,589,211
Options exercised (CAD per share) | $ / shares									$ 11.23		$ 10.66
Minimum
Stockholders Equity Note [Line Items]
Percentage of outstanding stock to be purchased to acquire discount (or more)								20.00%
Employee Stock Option
Stockholders Equity Note [Line Items]
Total share-based compensation expense | $								$ 1,288,000		$ 2,054,000
Unrecognized compensation costs, non-vested options | $								$ 1,252,000	$ 1,252,000
Unrecognized compensation costs, non-vested options, period of recognition								1 year 8 months 4 days
Stock Option Plans | Maximum
Stockholders Equity Note [Line Items]
Percentage of shares reserves under plan (must not exceed)								8.00%
Performance Share Units
Stockholders Equity Note [Line Items]
Maximum aggregate number of shares reserved for future issuance (in shares)								7,000,000	7,000,000			7,000,000
Performance share units granting period								3 years
Percentage of shares issued on number of PSU grants, minimum								2.00%
Percentage of shares issued on number of PSU grants, maximum								237.00%
Employee share purchase
Stockholders Equity Note [Line Items]
Total share-based compensation expense | $								$ 322,000		$ 312,000
Vesting period of matching contribution shares								1 year
Maximum aggregate number of shares reserved for future issuance (in shares)								2,000,000	2,000,000			2,000,000
Common stock, shares issued (in shares)								253,538	253,538	252,698	252,698	253,538
Deferred Share Units
Stockholders Equity Note [Line Items]
Maximum aggregate number of shares reserved for future issuance (in shares)								1,000,000	1,000,000			1,000,000
Shares issued during period (in shares)								460,418		380,656
Performance and restricted share units
Stockholders Equity Note [Line Items]
Total share-based compensation expense | $								$ 8,145,000		$ 6,378,000
Unrecognized compensation costs, non-vested awards | $								$ 12,750,000	$ 12,750,000
Unrecognized compensation costs, non-vested options, period of recognition								1 year 10 months 9 days
Series A Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares)								4,800,000	4,800,000	4,800,000	4,800,000	4,800,000
Shares issued, price per share (CAD per share) | (per share)										$ 25	$ 25	$ 25
Carrying amount C$								$ 100,463,000	$ 100,463,000	$ 100,463,000	$ 100,463,000	$ 116,546
Fixed cumulative annual dividend per share (CAD per share) | (per share)								$ 1.2905	$ 1.2905					$ 1.125
Subsequent yield period								5 years
Preferred stock, Subsequent redemption period								5 years
Series C Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock redemption price per share (in CAD per share) | $ / shares												$ 53,400
Redeemable preferred stock issued (in shares)								100	100			100
Series D Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares)								4,000,000	4,000,000	4,000,000	4,000,000	4,000,000
Shares issued, price per share (CAD per share) | (per share)										$ 25	$ 25	$ 25
Carrying amount C$								$ 83,836,000	$ 83,836,000	$ 83,836,000	$ 83,836,000	$ 97,259
Fixed cumulative annual dividend per share (CAD per share) | $ / shares												$ 1.25
Preferred stock, Subsequent redemption period								5 years
Government of Canada Bond Yield | Series A Preferred Stock
Stockholders Equity Note [Line Items]
Dividend variable interest rate								2.94%
Range One | Employee share purchase
Stockholders Equity Note [Line Items]
Employer matching contribution, percent								20.00%
Range Two | Employee share purchase
Stockholders Equity Note [Line Items]
Employer matching contribution, percent								10.00%
Public Stock Offering
Stockholders Equity Note [Line Items]
Sale of stock, price per share | (per share)			$ 10.09		$ 9.23		$ 13.50								$ 13.76	$ 11.85
Issuance cost			$ 366,000	$ 492	$ 590,000	$ 765	$ 14,418,000
Public Stock Offering | Common shares
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering			12,536,350	12,536,350	37,505,274	37,505,274	26,252,542
Cash proceeds from issuance of shares			$ 126,485,000	$ 172,500	$ 346,458,000	$ 444,437	$ 354,409,000
ATM Equity Program
Stockholders Equity Note [Line Items]
Number of shares issued pursuant to public offering								1,756,799
Cash proceeds from issuance of shares | $								$ 21,704,000
Sale of stock, program costs | $								2,122,000
Sale Of Stock, Consideration Received On Transaction, Gross | $								$ 22,034,000
Sale of Stock, Value of Shares Issued in Transaction | $													$ 250,000
Shares issued, price per share (CAD per share) | $ / shares								$ 12.54	$ 12.54
Forecast | Series D Preferred Stock
Stockholders Equity Note [Line Items]
Fixed cumulative annual dividend per share (CAD per share) | $ / shares	$ 1.2728
Preferred stock redemption price per share (in CAD per share) | $ / shares	$ 25
Forecast | Government of Canada Bond Yield | Series D Preferred Stock
Stockholders Equity Note [Line Items]
Basis spread on variable rate	3.28%
Subsequent Event
Stockholders Equity Note [Line Items]
Options exercised (in shares)		394,939
Options exercised (CAD per share) | $ / shares		$ 12.77
Subsequent Event | Common shares
Stockholders Equity Note [Line Items]
Options settled at cash value for payment of the exercise price and for tax withholdings (in shares)		279,422
Subsequent Event | Treasury Stock, Common
Stockholders Equity Note [Line Items]
Shares issued from treasury for option exercise (in shares)		115,517

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 10,553	$ 9,458
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	1,288	2,054
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	798	714
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	322	312
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 8,145	$ 6,378

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Equity [Abstract]
Risk-free interest rate	1.90%	2.10%
Expected volatility	20.00%	21.00%
Expected dividend yield	4.30%	4.80%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (CAD per share)	$ 1.66	$ 1.41

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2018CAD ($)$ / sharesshares	Dec. 31, 2017CAD ($)$ / sharesshares
Number of awards
Beginning balance (in shares) | shares	6,292,642	6,738,856	6,738,856
Granted (in shares) | shares	1,113,775	1,166,717	1,166,717
Exercised (in shares) | shares	(3,882,505)	(1,589,211)	(1,589,211)
Forfeited (in shares) | shares	0	(23,720)	(23,720)
Ending balance (in shares) | shares	3,523,912	6,292,642	6,292,642	6,738,856
Exercisable (in shares) | shares	1,735,241
Weighted average exercise price
Beginning balance (CAD per share) | $ / shares	$ 11.61		$ 11.18
Granted (CAD per share) | $ / shares	14.96		12.80
Exercised (CAD per share) | $ / shares	11.23		10.66
Forfeited (CAD per share) | $ / shares	0		12.80
Ending balance (CAD per share) | $ / shares	13.09		$ 11.61	$ 11.18
Exercisable (CAD per share) | $ / shares	$ 12.57
Additional Disclosures
Outstanding shares, weighted average remaining contractual term	5 years 10 months 13 days	5 years 9 months	5 years 9 months	6 years 3 months 25 days
Granted, weighted average remaining contractual term	8 years	8 years	8 years
Exercised shares, weighted average remaining contractual term	4 years 5 months 12 days	5 years 7 days	5 years 7 days
Exercisable , weighted average remaining contractual term	5 years 5 months 4 days
Beginning balance, aggregate intrinsic value | $	$ 13,342		$ 19,380
Granted, aggregate intrinsic value | $	0		0
Exercised, aggregate intrinsic value	6,225	$ 5,059
Ending balance, aggregate intrinsic value | $	18,609		$ 13,342	$ 19,380
Exercisable, aggregate intrinsic value | $	$ 14,559

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - Performance and restricted share units - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of awards
Beginning balance (in shares)	1,392,132	955,028
Granted, including dividends (in shares)	1,471,442	791,524
Exercised (in shares)	(344,340)	(285,551)
Forfeited (in shares)	(107,191)	(68,869)
Ending balance (in shares)	2,412,043	1,392,132	955,028
Exercisable (in shares)	743,787
Weighted average grant-date fair value
Beginning balance (CAD per share)	$ 12.75	$ 12.30
Granted, including dividends (CAD per share)	14.69	12.41
Exercised (CAD per share)	11.55	10.02
Forfeited (CAD per share)	13.84	13.02
Ending balance (CAD per share)	14	$ 12.75	$ 12.30
Exercisable (CAD per share)	$ 13.21
Additional Disclosures
Outstanding, Weighted average remaining contractual term	1 year 10 months 9 days	1 year 7 months 6 days	1 year 10 months 2 days
Granted, including dividends, Weighted average remaining contractual term	2 years	2 years
Outstanding, aggregate intrinsic value	$ 44,309	$ 19,114	$ 13,428
Granted, including dividends, aggregate intrinsic value	16,302	10,098
Exercised, aggregate intrinsic value	5,148	3,691
Forfeited, aggregate intrinsic value	0	$ 0
Exercisable, aggregate intrinsic value	$ 13,663

Shareholders' capital Sharehold

Shareholders' capital Shareholders' Capital - Bonus Deferral RSUs (Details) - Bonus Deferral Restricted Stock Units $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)shares	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2018CAD ($)$ / sharesshares	Dec. 31, 2017CAD ($)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Beginning balance (in shares) | shares	127,066		0
Granted, including dividends (in shares) | shares	135,324		131,611
Exercised (in shares) | shares			(4,545)
Ending balance (in shares) | shares	262,390		127,066
Weighted average grant-date fair value
Beginning balance (CAD per share) | $ / shares		$ 12.82	$ 0
Granted, including dividends (CAD per share) | $ / shares		15.40	12.82
Exercised (CAD per share) | $ / shares			12.82
Ending balance (CAD per share) | $ / shares		$ 14.15	$ 12.82
Outstanding, aggregate intrinsic value | $		$ 4,820	$ 1,745	$ 0
Granted, including dividends, aggregate intrinsic value	$ 2,084		1,683
Exercised, aggregate intrinsic value | $			$ 61

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, 2019	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 3,697,522	$ 3,320,100
Other comprehensive income (loss)	18,973	(24,356)
Amounts reclassified from AOCI to the consolidated statement of operations	(7,107)	(4,343)
Other comprehensive income (loss), net of tax	11,866	(28,699)
OCI attributable to the non-controlling interests	(2,428)	1,481
Net current period OCI attributable to shareholders of APUC	9,438	(27,218)
Ending Balance	4,406,595	3,697,522
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(74,189)	(47,701)
Other comprehensive income (loss)	7,795	(27,969)
Amounts reclassified from AOCI to the consolidated statement of operations	0	0
Other comprehensive income (loss), net of tax	7,795	(27,969)
OCI attributable to the non-controlling interests	(2,428)	1,481
Net current period OCI attributable to shareholders of APUC	5,367	(26,488)
Ending Balance	(68,822)	(74,189)
Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	64,333	55,366
Other comprehensive income (loss)	19,177	1,567
Amounts reclassified from AOCI to the consolidated statement of operations	(8,597)	(4,257)
Other comprehensive income (loss), net of tax	10,580	(2,690)
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of APUC	10,580	(2,690)
Ending Balance	75,099	64,333
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(9,529)	(10,457)
Other comprehensive income (loss)	(7,999)	2,046
Amounts reclassified from AOCI to the consolidated statement of operations	1,490	(86)
Other comprehensive income (loss), net of tax	(6,509)	1,960
OCI attributable to the non-controlling interests	0	0
Net current period OCI attributable to shareholders of APUC	(6,509)	1,960
Ending Balance	(16,038)	(9,529)
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(19,385)	(2,792)
Ending Balance	$ (9,761)	$ (19,385)
Accounting Standards Update 2018-02
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))				$ 10,625
Accounting Standards Update 2018-02 | Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))				0
Accounting Standards Update 2018-02 | Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))				11,657
Accounting Standards Update 2018-02 | Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))				$ (1,032)
Accounting Standards Update 2017-12
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))			$ 186
Accounting Standards Update 2017-12 | Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))			0
Accounting Standards Update 2017-12 | Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))			186
Accounting Standards Update 2017-12 | Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2017-12 on hedging (note 2(a))			$ 0

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2018CAD ($)$ / shares
Dividends [Line Items]
Dividend declared for common share holders | $	$ 277,835		$ 235,440
Cash dividend declared per common share (USD per share) | $ / shares	$ 0.5512		$ 0.5011
Series A Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders | $		$ 6,194		$ 5,400
Dividend declared per preferred share (CAD per share) | $ / shares		$ 1.2905		$ 1.1250
Series D Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders | $		$ 5,068		$ 5,000
Dividend declared per preferred share (CAD per share) | $ / shares		$ 1.2671		$ 1.2500

Related party transactions (Det

Related party transactions (Detail) $ in Thousands	Dec. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2019USD ($)MW	Dec. 31, 2019CAD ($)MW	Dec. 31, 2018USD ($)	Sep. 30, 2019USD ($)
Transactions with Third Party [Line Items]
Interest income			$ 100,886,000		$ 39,263,000
Fair value loss			278,084,000		(137,957,000)
Amounts reclassified from AOCI to the statement of operations			7,107,000		4,343,000
Non-controlling interest attributable to subsidiary			16,482,000		2,622,000
Distribution from interest in noncontrolling interest			26,465,000	$ 34,373
Contributions from redeemable non-controlling interests			3,403,000		0
Non-controlling interest incurred			(9,006,000)		(7,545,000)
Redeemable Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders			1,848,000		644,000
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses			12,374,000		11,390,000
Affiliated Entity
Transactions with Third Party [Line Items]
Exchange of note receivable	$ 30,293
Gain (loss) on sale of investments	$ 0
Non-controlling interest incurred			16,482,000		2,622,000
Related Party
Transactions with Third Party [Line Items]
Amount reclassified from AOCI into earnings before tax			15,765,000
Amounts reclassified from AOCI to the statement of operations			11,412,000
Contributions from redeemable non-controlling interests					$ 305,000,000
Related Party | Equity Method Investee
Transactions with Third Party [Line Items]
Exchange of note receivable						$ 21,107,000
Redeemable Non-Controlling Interest | Affiliated Entity
Transactions with Third Party [Line Items]
Distribution from interest in noncontrolling interest		$ 0
Redeemable Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders			$ 18,241,000
Long Sault Hydro Facility
Transactions with Third Party [Line Items]
Hydro power capacity (megawatt) | MW			18	18

Non-controlling Interests and_3

Non-controlling Interests and Redeemable non-controlling Interest - Net Loss Attributable to Non-Controlling Interest (Details) - USD ($) $ in Thousands	Dec. 31, 2019	May 24, 2019	May 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests				$ (62,416)	$ (108,521)
Non-controlling interests - redeemable tax equity partnership units				(9,006)	(7,545)
Redeemable non-controlling interest, held by related party				16,482	2,622
Net effect of non-controlling interests				(45,934)	(105,899)
Change in tax attributes, accelerated income				55,900
Non-controlling interests	$ 457,834			457,834	519,896
Non-controlling interests	531,541			531,541	519,896
Contributions from redeemable non-controlling interests				3,403	0
Non-controlling interest attributable to subsidiary				16,482	2,622
Other Noncontrolling Interests
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests				2,553	2,174
Non-controlling interests	834			834	796
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests				(55,963)	(103,150)
Non-controlling interests - redeemable tax equity partnership units				(9,006)	(7,545)
Non-controlling interests	457,000			457,000	519,100
Great Bay Solar Facility | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount					15,250
Turquoise Solar Facility
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests				3,403
Turquoise Solar Facility | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount	$ 2,000	$ 1,403
Abengoa-Algonquin Global Energy Solution B.V.
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests					$ 305,000
AYES Canada
Noncontrolling Interest [Line Items]
Non-controlling interest attributable to subsidiary			$ 96,752	$ 73,707

Non-controlling Interests and_4

Non-controlling Interests and Redeemable non-controlling Interest - Change in Redeemable non-controlling Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 33,364	$ 41,553
Net effect from operations	(9,006)	(7,545)
Contributions, net of costs	3,403	0
Dividends and distributions declared	(1,848)	(644)
Closing balance	25,913	33,364
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	307,622	0
Contributions, net of costs	0	305,000
Dividends and distributions declared		0
Closing balance	$ 305,863	$ 307,622

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Canadian enacted statutory rate	26.50%	26.50%
U.S. Tax reform and related deferred tax adjustments	$ 0	$ 18,363
Valuation allowance for deferred tax assets	29,447	$ 28,018
Deferred income taxes, undistributed earnings of foreign subsidiaries	$ 370,682

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Expected income tax expense at Canadian statutory rate	$ 147,093	$ 35,102
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(27,703)	(28,064)
Adjustments from investments carried at fair value	(60,730)	25,870
Non-controlling interests share of income	16,991	29,637
Non-deductible acquisition costs	2,500	4,267
Tax credits	(9,332)	(1,419)
Adjustment relating to prior periods	(1,240)	3,673
U.S. Tax reform and related deferred tax adjustments (1)	0	(18,363)
Other	2,538	2,669
Income tax expense	$ 70,117	$ 53,372

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 555,067	$ 132,461
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	351,908	(109,537)
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 203,159	$ 241,998

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Expenses [Line Items]
Income tax expenses, current	$ 16,431	$ 11,347
Income tax expenses, deferred	53,686	42,025
Income tax expense	70,117	53,372
Canada
Income Tax Expenses [Line Items]
Income tax expenses, current	6,695	2,872
Income tax expenses, deferred	17,607	(14,197)
Income tax expense	24,302	(11,325)
United States
Income Tax Expenses [Line Items]
Income tax expenses, current	9,736	8,475
Income tax expenses, deferred	36,079	56,222
Income tax expense	$ 45,815	$ 64,697

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, 2019	Dec. 31, 2018
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 382,448	$ 329,099
Pension and OPEB	54,113	48,586
Environmental obligation	15,541	14,790
Regulatory liabilities	160,200	161,560
Other	59,103	45,193
Total deferred income tax assets	671,405	599,228
Less: valuation allowance	(29,447)	(28,018)
Total deferred tax assets	641,958	571,210
Deferred tax liabilities:
Property, plant and equipment	(707,185)	(653,962)
Outside basis in partnership	235,063	167,659
Regulatory accounts	145,852	113,758
Other	14,811	7,561
Total deferred tax liabilities	1,102,911	942,940
Net deferred tax liabilities	(460,953)	(371,730)
Deferred tax assets	30,585	72,415
Deferred tax liabilities	$ (491,538)	$ (444,145)

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2019USD ($)
2020 and onwards
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	$ 1,091,322

Other Losses Other Losses (Deta

Other Losses Other Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Income and Expenses [Abstract]
Pension and other post-employment non-service costs (note 10)	$ (17,332)	$ (4,990)
Acquisition and transition-related costs (note 3)	(11,609)	(687)
Other	15,085	2,725
Other losses	$ (44,026)	$ (8,402)

Basic and diluted net earning_3

Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Class of Stock [Line Items]
Net earnings attributable to shareholders of APUC	$ 530,884	$ 184,988
Series A and D Preferred shares dividend	8,486	8,027
Net earnings attributable to common shareholders of APUC from continuing operations – basic and diluted	$ 522,398	$ 176,961
Weighted average number of shares
Basic (in shares)	499,910,876	461,818,023
Effect of dilutive securities (in shares)	4,828,678	4,227,595
Diluted (in shares)	504,739,554	466,045,618
Series A Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,666	$ 4,169
Series D Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 3,820	$ 3,858

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019business_unitsegmentcountry
Segment Reporting [Abstract]
Number of business units | business_unit	2
Number of Reportable Segments | segment	2
Number of countries in which entity operates | country	2

Basic and diluted net earning_4

Basic and diluted net earnings per share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures (in shares)	1,113,775	3,380,184

Segmented information - Results

Segmented information - Results of Operations and Assets for Segments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue
Revenue	$ 1,624,921	$ 1,648,463
Fuel, power and water purchased	443,304	484,138
Net revenue	1,181,617	1,164,325
Operating expenses	471,989	472,466
Administrative expenses	56,802	52,710
Depreciation and amortization	284,304	260,772
Loss on foreign exchange	3,146	(58)
Operating income	365,376	378,435
Interest expense	(181,488)	(152,118)
Income (loss) from long-term investments	(399,092)	84,818
Other income (expenses)	(27,913)	(9,038)
Earnings before income taxes	555,067	132,461
Property, plant and equipment	7,231,664	6,393,558
Investments carried at fair value	1,294,147	814,530
Equity-method investees (d)	83,770	29,588
Total assets	10,911,470	9,398,589
Capital expenditures	581,332	466,369
Revenue related to net hedging gains, not recognized as revenue from contract with customers	22,282	14,953
Regulated Services Group
Revenue
Revenue	1,366,971	1,401,240
Fuel, power and water purchased	426,046	456,974
Net revenue	940,925	944,266
Operating expenses	396,559	401,486
Administrative expenses	36,628	33,234
Depreciation and amortization	194,498	177,719
Loss on foreign exchange	0	0
Operating income	313,240	331,827
Interest expense	(101,518)	(99,063)
Income (loss) from long-term investments	(9,334)	(5,558)
Other income (expenses)	(32,292)	(6,775)
Earnings before income taxes	188,764	231,547
Property, plant and equipment	4,754,373	4,210,115
Investments carried at fair value	27,072	0
Equity-method investees (d)	29,827	55
Total assets	6,816,063	6,022,262
Capital expenditures	478,936	370,221
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	(4,405)	7,425
Renewable Energy Group
Revenue
Revenue	257,950	247,223
Fuel, power and water purchased	17,258	27,164
Net revenue	240,692	220,059
Operating expenses	75,209	70,980
Administrative expenses	19,405	18,539
Depreciation and amortization	88,825	82,044
Loss on foreign exchange	0	0
Operating income	57,253	48,496
Interest expense	(61,039)	(50,920)
Income (loss) from long-term investments	(104,025)	(45,741)
Other income (expenses)	15,946	(1,576)
Earnings before income taxes	116,185	41,741
Property, plant and equipment	2,444,382	2,152,420
Investments carried at fair value	1,267,075	814,530
Equity-method investees (d)	53,670	29,273
Total assets	4,014,067	3,269,786
Capital expenditures	102,396	96,148
Corporate
Revenue
Revenue	0	0
Fuel, power and water purchased	0	0
Net revenue	0	0
Operating expenses	221	0
Administrative expenses	769	937
Depreciation and amortization	981	1,009
Loss on foreign exchange	3,146	(58)
Operating income	(5,117)	(1,888)
Interest expense	(18,931)	(2,135)
Income (loss) from long-term investments	(285,733)	136,117
Other income (expenses)	(11,567)	(687)
Earnings before income taxes	250,118	(140,827)
Property, plant and equipment	32,909	31,023
Investments carried at fair value	0	0
Equity-method investees (d)	273	260
Total assets	81,340	106,541
Capital expenditures	$ 0	$ 0

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenue	$ 1,624,921	$ 1,648,463
Property, plant and equipment	7,231,664	6,393,558
Intangible assets	47,616	54,994
Canada
Segment Reporting Information [Line Items]
Revenue	87,226	70,358
Property, plant and equipment	752,016	415,979
Intangible assets	23,795	23,994
United States
Segment Reporting Information [Line Items]
Revenue	1,537,695	1,578,105
Property, plant and equipment	6,479,648	5,977,579
Intangible assets	$ 23,821	$ 31,000

Commitments and contingencies -

Commitments and contingencies - Estimates of Future Commitments (Detail) - USD ($) $ in Thousands	Oct. 30, 2018	Dec. 31, 2019
Commitments Disclosure [Line Items]
Year 1		$ 273,117
Year 2		234,056
Year 3		108,853
Year 4		110,418
Year 5		107,257
Thereafter		809,665
Total		1,643,366
Power purchase
Commitments Disclosure [Line Items]
Year 1		30,672
Year 2		11,422
Year 3		11,338
Year 4		11,566
Year 5		11,796
Thereafter		179,412
Total		256,206
Gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1		83,083
Year 2		60,699
Year 3		49,217
Year 4		46,406
Year 5		41,538
Thereafter		135,926
Total		416,869
Service agreements
Commitments Disclosure [Line Items]
Year 1		47,950
Year 2		40,456
Year 3		41,554
Year 4		45,611
Year 5		47,005
Thereafter		293,436
Total		516,012
Capital projects
Commitments Disclosure [Line Items]
Year 1		104,809
Year 2		114,806
Year 3		0
Year 4		0
Year 5		0
Thereafter		0
Total		219,615
Land easements
Commitments Disclosure [Line Items]
Year 1		6,603
Year 2		6,673
Year 3		6,744
Year 4		6,835
Year 5		6,918
Thereafter		200,891
Total		$ 234,664
Gaia Power Inc. vs APUC
Commitments Disclosure [Line Items]
Damages claimed by other party in lawsuit	$ 345,000
Punitive damages claimed by other party in lawsuit	$ 25,000

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ (20,857)	$ 3,005
Fuel and natural gas in storage	13,985	1,351
Supplies and consumables inventory	(6,028)	(7,189)
Income taxes recoverable	17,796	(763)
Prepaid expenses	(7,501)	2,907
Accounts payable	63,854	(22,915)
Accrued liabilities	8,872	28,687
Current income tax liability	(5,016)	2,974
Asset retirements and environmental obligations	(2,494)	(7,293)
Net regulatory assets and liabilities	(2,308)	(8,890)
Changes in non-cash operating items	$ 60,303	$ (8,126)

Financial instruments - Fair V

Financial instruments - Fair Value of Financial Instruments (Detail) $ in Thousands, $ in Thousands	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	$ 2,899
Cross currency swap | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	81,765
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,178,581			$ 814,530
Total financial assets	1,178,581		$ 814,530
Long-term debt	1,495,153		768,400
Convertible debentures	623		639
Total financial liabilities	1,495,776		769,039
Level 2
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	27,072			0
Development loans and other receivables	37,984		110,019
Derivative Asset	16		970
Total financial assets	65,072		110,989
Long-term debt	2,788,915		2,588,373
Convertible debentures	0
Derivative financial instruments, liabilities	83,837		102,785
Total financial liabilities	2,887,872		2,704,861
Level 2 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		$ 0
Level 2 | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset				869
Level 2 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	16		101
Derivative financial instruments, liabilities	2,072		1,114
Level 2 | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	81,765		93,198
Level 2 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities			8,473
Level 2 | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures			13,703
Preferred shares, Series C	15,120
Level 3
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	88,494			0
Development loans and other receivables	0		0
Derivative Asset	85,688		61,838
Total financial assets	174,182		61,838
Derivative financial instruments, liabilities	827		57
Total financial liabilities	827		57
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	65,304		61,838
Derivative financial instruments, liabilities	789		57
Level 3 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		20,384
Derivative financial instruments, liabilities	38
Level 3 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	0
Carrying amount
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,294,147		814,530
Development loans and other receivables	37,050		103,696
Derivative Asset	85,704		62,808
Total financial assets	1,416,901		981,034
Long-term debt	3,931,868		3,336,795
Convertible debentures	342		470
Derivative financial instruments, liabilities	84,664		102,842
Total financial liabilities	4,030,667		3,453,525
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	65,304		61,838
Derivative financial instruments, liabilities	789		57
Carrying amount | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		20,384
Derivative financial instruments, liabilities	38
Carrying amount | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset				869
Carrying amount | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	16		101
Derivative financial instruments, liabilities	2,072		1,114
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	81,765		93,198
Carrying amount | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities			8,473
Carrying amount | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures			13,418
Preferred shares, Series C	13,793
Fair value
Fair Value of Financial Instruments [Line Items]
Long-term investments carried at fair value	1,294,147		814,530
Development loans and other receivables	37,984		110,019
Derivative Asset	85,704		62,808
Total financial assets	1,417,835		987,357
Long-term debt	4,284,068		3,356,773
Convertible debentures	623		639
Derivative financial instruments, liabilities	84,664		102,842
Total financial liabilities	4,384,475		3,473,957
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset	65,304		61,838
Derivative financial instruments, liabilities	789		57
Fair value | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset		$ 20,384
Derivative financial instruments, liabilities	38
Fair value | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative Asset				$ 869
Fair value | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset	16		101
Derivative financial instruments, liabilities	2,072		1,114
Fair value | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	81,765		93,198
Fair value | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities			8,473
Fair value | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures			13,703
Preferred shares, Series C	$ 15,120
Intrinsic Value | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative Asset			$ 441

Financial instruments - Additi

Financial instruments - Additional Information (Detail)

Jul. 25, 2018USD ($)

Jun. 30, 2019

Dec. 31, 2019USD ($)$ / MWhMWh

Dec. 31, 2018USD ($)

Dec. 31, 2019CAD ($)$ / MWh

May 23, 2019USD ($)

Mar. 31, 2019

Jan. 29, 2019CAD ($)

Oct. 17, 2018USD ($)

Jan. 31, 2017USD ($)

Jan. 31, 2014USD ($)

Dec. 31, 2012USD ($)

Derivative [Line Items]

Derivative, Nonmonetary Notional Amount, Energy Measure | MWh

151,680

Cost per Megawatt Hour | $ / MWh

38.95

Long-term debt

$ 3,931,868,000

$ 3,336,795,000

Realized gain/(loss) in OCI from foreign exchange forward contract

$ 7,795,000

(27,969,000)

Revenue collection period

45 days

Cash on hand

$ 62,485,000

Available for drawn on senior debt facilities

1,047,216,000

Utility Services

Derivative [Line Items]

Accounts receivable balances

200,594,000

Liberty Power Group

Derivative [Line Items]

Realized gain/(loss) in OCI from foreign exchange forward contract

(15,946,000)

41,244,000

Bonds

Derivative [Line Items]

Long-term debt

$ 135,000,000

Bonds | Plan

Derivative [Line Items]

Debt instrument, term

10 years

Long-term debt

$ 135,000,000

Senior Unsecured Notes | Senior Unsecured Notes Due January 2029

Derivative [Line Items]

Debt instrument, term

10 years

Interest Rate

4.60%

Par value

$ 300,000,000

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

Derivative [Line Items]

Long-term debt

621,049,000

278,771,000

Interest Rate

6.20%

Par value

637,500,000

$ 350,000,000

$ 287,500

Senior Unsecured Notes | Liberty Power Group | 4.82% Senior Unsecured Notes

Derivative [Line Items]

Par value

$ 150,000,000

Senior Unsecured Notes | Liberty Power Group | 4.65% Senior Unsecured Notes

Derivative [Line Items]

Par value

$ 200,000,000

Senior Unsecured Notes | Liberty Power Group | Convertible Unsecured Subordinated Debentures

Derivative [Line Items]

Par value

$ 300,000,000

Forward contracts

Derivative [Line Items]

Realized gain/(loss) in OCI from foreign exchange forward contract

983,000

(1,115,000)

Foreign exchange contract

Derivative [Line Items]

Realized gain/(loss) in OCI from foreign exchange forward contract

$ 35,277,000

$ (28,705,000)

Cash flow hedge | Interest rate swaps

Derivative [Line Items]

Term of forward-starting interest rate swap

10 years

Minimum

Derivative [Line Items]

Forward price | $ / MWh

13.33

13.33

Maximum

Derivative [Line Items]

Forward price | $ / MWh

178.65

178.65

Weighted Average

Derivative [Line Items]

Forward price | $ / MWh

23.66

23.66

Non-regulated Energy Sales

Derivative [Line Items]

Unrealized gains in AOCI to be reclassified

$ 8,704,000

Interest expense

Derivative [Line Items]

Unrealized gains in AOCI to be reclassified

$ 2,203,000

Accounts Receivable | Credit Concentration Risk | Liberty Power Group

Derivative [Line Items]

Percentage of revenue contributed

87.00%

Atlantica Yield Energy Solutions Canada, Inc

Derivative [Line Items]

Equity method investment, prepayment

$ 53,750,000

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

Derivative [Line Items]

Alternative Investment, Measurement Input

0.18

0.18

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

Derivative [Line Items]

Alternative Investment, Measurement Input

0.22

0.22

AYES Canada | Measurement Input, Discount Rate | Minimum

Derivative [Line Items]

Alternative Investment, Measurement Input

0.0875

0.0875

AYES Canada | Measurement Input, Discount Rate | Maximum

Derivative [Line Items]

Alternative Investment, Measurement Input

0.0950

0.0950

AYES Canada | Measurement Input, Discount Rate | Weighted Average

Derivative [Line Items]

Alternative Investment, Measurement Input

0.0942

0.0942

Sugar Creek

Derivative [Line Items]

Reclassification from AOCI, Current Period, before Tax, Attributable to Parent

$ 15,765

Financial instruments - Summar

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2019MMBTU
Derivative [Line Items]
Commodity volumes, Gas	4,784,739
Swap
Derivative [Line Items]
Commodity volumes, Gas	2,134,739
Options
Derivative [Line Items]
Commodity volumes, Gas	150,000
Forward contracts
Derivative [Line Items]
Commodity volumes, Gas	2,500,000

Financial instruments - Impact

Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	$ 559,887	$ 460,095
Regulatory liabilities, natural gas derivative contracts	598,062	588,213
Swap
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	28	66
Regulatory liabilities, natural gas derivative contracts	743	218
Options
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	38	0
Regulatory liabilities, natural gas derivative contracts	0	134
Forward contracts
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	1,830	0
Regulatory liabilities, natural gas derivative contracts	$ 0	$ 1,259

Financial instruments - Long-t

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2019MWh$ / MWh
PJM Western HUB
Derivative [Line Items]
Receive average prices (per MW-hr) | $ / MWh	35.35
Notional quantity (MW-hrs) | MWh	757,075
PJM NI HUB
Derivative [Line Items]
Receive average prices (per MW-hr) | $ / MWh	25.54
Notional quantity (MW-hrs) | MWh	3,443,530
ERCOT North HUB
Derivative [Line Items]
Receive average prices (per MW-hr) | $ / MWh	36.46
Notional quantity (MW-hrs) | MWh	2,665,068

Financial instruments - Deriva

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge, gain (loss)	$ 19,177	$ 1,567
Amortization of cash flow hedge	(33)	(33)
Amounts reclassified from AOCI	(8,564)	(4,224)
Change in fair value of cash flow hedges, net of tax expense and tax recovery of $3,862 and $952, respectively (note 24(b)(ii))	$ 10,580	$ (2,690)

Financial instruments - Effect

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	$ (15,237)	$ (1,781)
Total realized loss on derivative financial instruments	757	(1,115)
Discontinued hedge accounting (note 24(b)(ii)) and other	33	33
Loss (gain) on derivative financial instruments	(16,113)	636
Gain (loss) on derivative instruments	(15,356)	(479)
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	374	(1,153)
Total realized loss on derivative financial instruments	80	42
Loss (gain) on derivative financial instruments not accounted for as hedges	454	(1,111)
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	(530)	77
Total realized loss on derivative financial instruments	227	(73)
Not Designated as Hedging Instrument | Foreign exchange forward
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	904	(1,230)
Total realized loss on derivative financial instruments	(147)	115
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Discontinued hedge accounting (note 24(b)(ii)) and other	$ (15,810)	$ 632

Financial instruments - Maximu

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2019 $ in Thousands, $ in Thousands	USD ($)	CAD ($)
Fair Value Disclosures [Abstract]
Cash and cash equivalents and restricted cash	$ 45,989	$ 53,619
Accounts receivable	231,006	42,987
Allowance for doubtful accounts	(4,850)	(89)
Notes receivable	50,680	15,963
Maximum exposure to credit risk for financial instruments	$ 322,825	$ 112,480

Financial instruments - Liabil

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Long-term debt obligations	$ 3,931,905
Convertible debentures	346
Advances in aid of construction	60,828
Interest on long-term debt	1,753,259
Purchase obligations	458,288
Environmental obligation	58,484	$ 59,181
Other obligations	153,025
Total obligations	6,500,799
Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	81,765
Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	2,899
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	602,028
Convertible debentures	0
Advances in aid of construction	1,165
Interest on long-term debt	185,231
Purchase obligations	458,288
Environmental obligation	14,970
Other obligations	39,115
Total obligations	1,306,577
Due less than 1 year | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	4,149
Due less than 1 year | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	1,631
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	468,740
Interest on long-term debt	318,469
Environmental obligation	20,850
Other obligations	2,120
Total obligations	880,187
Due 2 to 3 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	69,099
Due 2 to 3 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	909
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	600,721
Interest on long-term debt	257,443
Environmental obligation	1,128
Other obligations	2,696
Total obligations	865,839
Due 4 to 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	3,851
Due 4 to 5 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	2,260,416
Convertible debentures	346
Advances in aid of construction	59,663
Interest on long-term debt	992,116
Environmental obligation	21,536
Other obligations	109,094
Total obligations	3,448,196
Due after 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	4,666
Due after 5 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	$ 359

Uncategorized Items - _IXDS

Label	Element	Value
Accounting Standards Update 2014-09 [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 1,860,000
Accounting Standards Update 2014-09 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	1,860,000
Accounting Standards Update 2017-12 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(186,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(186,000)
Accounting Standards Update 2018-02 [Member] | AOCI Attributable to Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	10,625,000
Accounting Standards Update 2018-02 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (10,625,000)