Algonquin Power & Utilities (AQN) 40-F 28 Feb 19 2018 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2018shares
Document Documentand Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Trading Symbol	AQUNF
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Central Index Key	1,174,169
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	488,851,433

Consolidated Balance Sheets

Consolidated Balance Sheets $ in Thousands	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Current assets:
Cash and cash equivalents	$ 46,819	$ 43,484
Accounts receivable, net (note 4)	245,728	244,617
Fuel and natural gas in storage	43,063	44,414
Supplies and consumables inventory	52,537	45,074
Regulatory assets (note 7)	59,037	66,567
Prepaid expenses	27,283	31,005
Derivative instruments (note 23)	9,616	16,099
Other assets and long-term investments (notes 8 and 11)	7,522	7,110
Assets, current, total	491,605	498,370
Property, plant and equipment, net (note 5)	6,393,558	6,304,897
Intangible assets, net (note 6)	54,994	51,103
Goodwill (note 6)	954,282	954,282
Regulatory assets (note 7)	391,437	374,959
Derivative instruments (note 23)	53,192	54,115
Long-term investments (note 8)
Investment carried at fair value	814,530	0
Notes receivable from equity investees	101,416	30,060
Other long-term investments	32,955	37,271
Deferred income taxes (note 18)	72,415	61,357
Other assets (note 11)	28,584	29,153
Assets	9,388,968	8,395,567
Current liabilities:
Accounts payable	89,740	119,887
Accrued liabilities	235,586	280,144
Dividends payable (note 15)	62,613	50,445
Regulatory liabilities (note 7)	39,005	37,687
Long-term debt (note 9)	13,048	12,364
Other long-term liabilities (note 12)	42,337	46,754
Derivative instruments (note 23)	14,339	14,126
Other liabilities	2,313	2,623
Liabilities, current, total	498,981	564,030
Long-term debt (note 9)	3,323,747	3,067,187
Regulatory liabilities (note 7)	539,587	538,437
Deferred income taxes (note 18)	444,145	399,148
Derivative instruments (note 23)	88,503	54,818
Pension and other post-employment benefits obligation (note 10)	191,915	168,189
Other long-term liabilities (note 12)	263,582	242,105
Liabilities, noncurrent, total	4,851,479	4,469,884
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interests, held by related party	307,622	0
Redeemable non-controlling interests	33,364	41,553
Equity:
Preferred shares (note 13(b))	184,299	184,299
Common shares (note 13(a))	3,562,418	3,021,699
Additional paid-in capital	45,553	38,569
Deficit	(595,259)	(524,311)
Accumulated other comprehensive loss (note 14)	(19,385)	(2,792)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	3,177,626	2,717,464
Non-controlling interests (note 17)	519,896	602,636
Total equity	3,697,522	3,320,100
Commitments and contingencies (note 21)
Liabilities and equity, total	$ 9,388,968	$ 8,395,567

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue
Total revenue	$ 1,647,387	$ 1,521,938
Expenses
Expenses	472,466	450,231
Administrative expenses	52,710	49,640
Depreciation and amortization	260,772	251,314
Loss (gain) on foreign exchange	(58)	323
Costs and Expenses, Total	1,270,028	1,144,733
Operating income	377,359	377,205
Interest expense on long-term debt and others	152,118	142,439
Interest expense on convertible debentures and amortization of acquisition financing (notes 9(b) and 12(h))	0	13,383
Change in value of investments carried at fair value	137,957	0
Interest, dividend, equity and other income (note 8)	(53,139)	(9,238)
Pension and post-employment non-service costs (note 10)	3,914	9,035
Other net losses	2,725	664
Acquisition-related costs, net (note 12(f))	687	47,708
Loss (gain) on derivative financial instruments (note 23(b)(iv))	636	(1,918)
Nonoperating Income (Expense)	244,898	202,073
Earnings (loss) before income taxes	132,461	175,132
Income tax expense (note 18)
Current	11,347	7,517
Deferred	42,025	65,910
Income tax expense	53,372	73,427
Net earnings	79,089	101,705
Net effect of non-controlling interests	108,521	47,770
Net effect of non-controlling interests held by related party	(2,622)	0
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	184,988	149,475
Series A and D Preferred shares dividend (note 15)	8,027	8,020
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$ 176,961	$ 141,455
Basic and diluted net earnings per share (USD per share)	$ 0.38	$ 0.37
Regulated electricity distribution
Revenue
Total revenue	$ 831,196	$ 763,501
Expenses
Expenses	265,166	222,443
Regulated gas distribution
Revenue
Total revenue	430,377	376,806
Expenses
Expenses	183,012	141,689
Regulated water reclamation and distribution
Revenue
Total revenue	128,437	140,082
Expenses
Expenses	8,796	9,503
Non-regulated energy sales
Revenue
Total revenue	235,359	217,542
Expenses
Expenses	27,164	19,590
Other revenue
Revenue
Total revenue	$ 22,018	$ 24,007

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net earnings	$ 79,089	$ 101,705
Other comprehensive income (loss):
Foreign currency translation adjustment, net of tax recovery of $4,532 and $169, respectively (notes 1(v), 23(b)(iii) and 23(b)(iv))	(27,969)	(21,753)
Change in fair value of cash flow hedges, net of tax recovery of $952 and expense of $599, respectively (note 23(b)(ii))	(2,690)	1,626
Change in value of available-for-sale investments	0	(65)
Change in pension and other post-employment benefits, net of tax expense of $696 and $512, respectively (note 10)	1,960	376
Other comprehensive loss, net of tax	(28,699)	(19,816)
Comprehensive income	50,390	81,889
Comprehensive loss attributable to the non-controlling interests	(107,380)	(47,743)
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$ 157,770	$ 129,632

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, tax recovery	$ 4,532	$ 169
Change in fair value of cash flow hedge, tax recovery and (expense)	952	(599)
Change in pension and other post-employment benefit, tax expense	$ 696	$ 512

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, 2016	$ 1,851,316	$ 1,674,591	$ 184,299	$ 34,892	$ (478,343)	$ 17,051	$ 418,826
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	101,705				149,475		(47,770)
Redeemable non-controlling interests not included in equity (note 17)	10,358						10,358
Other comprehensive loss	(19,816)					(19,843)	27
Dividends declared and distributions to non-controlling interests	(161,924)				(158,064)		(3,860)
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(ii))	0	35,873			(35,873)
Common shares issued pursuant to public offering, net of costs (note 13(a)(i))	440,024	440,024
Common shares issued upon conversion of convertible debentures (note 12(h))	855,691	855,691
Common shares issued pursuant to share-based awards (note 13(c))	9,104	15,520		(4,910)	(1,506)
Share-based compensation (note 13(c))	8,587			8,587
Contributions received from non-controlling interests (notes 3(d))	225,055						225,055
Ending 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 loss	(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)(ii))	0	55,442			(55,442)
Common shares issued pursuant to public offering, net of costs (note 13(a)(i))	472,180	472,180
Common shares issued upon conversion of convertible debentures (note 12(h))	447	447
Common shares issued pursuant to share-based awards (note 13(c))	4,784	12,650		(4,027)	(3,839)
Share-based compensation (note 13(c))	11,011			11,011
Contributions received from non-controlling interests (notes 3(d))	29,110						29,110
Ending Balance at Dec. 31, 2018	$ 3,697,522	$ 3,562,418	$ 184,299	$ 45,553	$ (595,259)	$ (19,385)	$ 519,896

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Operating Activities
Net earnings from continuing operations	$ 79,089	$ 101,705
Adjustments and items not affecting cash:
Depreciation and amortization	281,163	256,775
Deferred taxes	42,025	65,910
Unrealized (gain) loss on derivative financial instruments	(1,781)	1,466
Share-based compensation expense	7,495	8,292
Cost of equity funds used for construction purposes	(2,728)	(2,335)
Change in value of investments carried at fair value	137,957	0
Pension and post-employment contributions in excess of expense	(6,354)	(20,687)
Distributions received from equity investments, net of income	5,698	2,420
Others	(4,086)	740
Changes in non-cash operating items (note 22)	(8,126)	(87,719)
Net Cash Provided by (Used in) Operating Activities, Total	530,352	326,567
Financing Activities
Increase in long-term debt	2,015,533	1,386,743
Decrease in long-term debt	(1,699,592)	(2,366,105)
Issuance of convertible debentures, net of costs	0	571,944
Cash dividends on common shares	(166,384)	(127,530)
Dividends on preferred shares	(8,027)	(8,020)
Contributions from non-controlling interests, related party (note 17)	305,000	0
Contributions from non-controlling interests (note 17)	15,250	248,229
Production-based cash contributions from non-controlling interest	13,860	7,930
Distributions to non-controlling interests	(9,289)	(3,186)
Issuance of common shares, net of costs	473,911	438,810
Proceeds from settlement of derivative assets	0	36,676
Proceeds from exercise of share options	4,504	9,563
Shares surrendered to fund withholding taxes on exercised share options	(2,088)	(3,310)
Increase in other long-term liabilities	9,403	28,010
Decrease in other long-term liabilities	(20,144)	(6,709)
Net Cash Provided by (Used in) Financing Activities, Total	931,937	213,045
Investing Activities
Acquisitions of operating entities	0	(1,519,923)
Divestiture of operating entity	0	83,863
Additions to property, plant and equipment	(466,369)	(565,103)
Increase in other assets	(5,912)	(7,239)
Receipt of principal on notes receivable	17,950	0
Increase in long-term investments	(1,005,072)	(63,656)
Decrease in long-term investments	1,158
Proceeds from sale of long-lived assets	2,912	0
Net Cash Provided by (Used in) Investing Activities, Total	(1,455,333)	(2,072,058)
Effect of exchange rate differences on cash and restricted cash	(606)	598
Increase (decrease) in cash, cash equivalents and restricted cash	6,350	(1,531,848)
Cash, cash equivalents and restricted cash, beginning of year	59,423	1,591,271
Cash, cash equivalents and restricted cash, end of year	65,773	59,423
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	155,309	166,773
Cash paid during the year for income taxes	9,652	8,633
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	45,154	112,959
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	65,767	38,724
Acquisition of equity investments in exchange for loan receivable and property, plant and equipment	13,092	5,368
Convertible Debentures
Non-cash financing and investing activities:
Issuance of common shares upon conversion of convertible debentures	$ 468	$ 846,271

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2018
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 North American business units consisting of the Liberty Utilities Group and the Liberty Power Group . The Liberty Utilities Group (“Liberty Utilities Group”) owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations; the Liberty Power Group (“ Liberty Power Group ”) owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets. APUC also owns a 41.5% equity interest in Atlantica Yield plc (“Atlantica”) (NASDAQ: AY), a company that acquires, owns and manages a diversified international portfolio of contracted renewable energy, power generation, electric transmission and water assets.

Significant accounting policies

Significant accounting policies	12 Months Ended
	Dec. 31, 2018
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(r)). (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. The determination of whether the definition of a business has been met for a development stage project depends on the concentration of assets, the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. 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 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 regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility 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 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. (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(d)) 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, together 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 asset 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 capital leases are initially recorded at cost determined as the present value of minimum lease payments. 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, dividend, equity and other income on the consolidated statements of operations. 2018 2017 Interest capitalized on non-regulated property $ 1,434 $ 4,325 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,684 1,297 Allowance for equity funds 2,728 2,335 Total $ 5,846 $ 7,957 Improvements that increase or prolong the service life or capacity of an asset are capitalized. Cost 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. Investment tax credits and government 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. 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. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2018 2017 2018 2017 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 40 40 Equipment 5 - 43 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. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Liberty Utilities 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 Company 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 are 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 analysis 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 of 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 a VIE 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. 1. Significant accounting policies (continued) (m) Variable interest entities (continued) Total net book value of generating assets and long-term debt of these facilities amounts to $59,288 (2017 - $67,398 ) and $22,263 (2017 - $28,628 ), respectively. The portion of long-term debt which has recourse to the Company is $ nil (2017 - $3,109 ). The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,232 (2017 - $17,508 ), operating expenses and amortization of $4,634 (2017 - $4,289 ) and interest expense of $1,258 (2017 - $2,755 ). (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 interest, dividend, equity and other income 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. 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 acquired 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 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 pension and post-employment non-service costs in the consolidated statements of operations. 1. Significant accounting policies (continued) (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, or regulatory assets when the amount is recoverable through rates. 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, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation. (q) 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. (r) 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. 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 Class A membership equity investors (“Class A partnership units” or “Class A 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 percentages ownership interests. In those situations, simply applying the percentage ownership interest to 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 Class A 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 Class A 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 Class A Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments. 1. Significant accounting policies (continued) (r) Non-controlling interests (continued) 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. (s) 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 are not completed at the date of initial application. Results for 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with the Company’s historical accounting under Topic 605. 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 20, Segmented information for details of revenue disaggregation by business units. Liberty Utilities Group revenue Liberty Utilities 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 is 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. The majority of Liberty Utilities Group's contracts have 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. The Company’s performance obligation is satisfied over time as electricity, natural gas or water is delivered. 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. 1. Significant accounting policies (continued) (s) Recognition of revenue (continued) Liberty Utilities Group revenue (continued) 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 20, 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. Liberty Power Group revenue Liberty Power 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. Progress towards satisfaction of the single performance obligation is measured using an output method based on units produced and delivered within the production month. 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. Progress towards satisfaction of the single performance obligation is measured using an output method based on time elapsed. Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses. The majority of Liberty Power Group 's contracts with customers are bundled arrangements of multiple performance obligations: electricity, capacity, and RECs. The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Liberty Power 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. Revenue is recorded net of sales taxes. (t) Foreign currency translation APUC’s reporting currency is the U.S. dollar. Within these consolidated financial statements, we denote 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

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2018
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 ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans as part of the disclosure framework project. This update removed certain disclosure requirements regarding AOCI expected to be recognized in income, related party transactions, and certain sensitivity analyses with respect to health care cost trends. This update also added disclosure requirements around the weighted-average interest crediting rates for cash balance plans and explanations for significant gains or losses in the reporting period. The early adoption of this ASU did not have a significant impact on the Company's consolidated financial statements. The FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement as part of the disclosure framework project. This update removed certain disclosure requirements from Topic 820 including the amount of and reasons for transfers between Level 1 and Level 2 measurements, the policy for timing of transfers between levels, and the valuation processes for Level 3 measurements. This update also clarified disclosure requirements relating to measurement uncertainty, and added disclosure requirements for Level 3 measurements, specifically around the changes in unrealized gains and losses included in other comprehensive income and the range and weighted average of significant unobservable inputs. The early adoption of this ASU did not have a significant impact on the Company's consolidated financial statements. The FASB issued ASU 2018-09, Codification Improvements to clarify the Codification and correct unintended application of guidance that is not expected to have a significant impact on current accounting practice. The adoption of this ASU had no impact on the Company's consolidated financial statements. The FASB issued ASU 2018-03, Technical Corrections and Improvements to Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to clarify the Codification and to correct unintended application of the guidance. The Company adopted this pronouncement concurrently with the adoption of ASU 2016-01. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("AOCI") to allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company early adopted this pronouncement as of January 1, 2018, and as a result, a net amount of $10,625 was reclassified out of AOCI and recorded as an increase to accumulated deficit as at that date. The FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting , to provide clarity and reduce both diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation , to a change to the terms or conditions of a share-based payment award. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost , to improve the reporting of defined benefit pension cost and post-retirement benefit cost ("net benefit cost") in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update also only allows the service cost component to be eligible for capitalization when applicable. The Company adopted this guidance effective January 1, 2018. The Company's regulated operations only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences exist. The Company applied the practical expedient for retrospective application on the consolidated statements of operations (note 10). 2. Recently issued accounting pronouncements (continued) (a) Recently adopted accounting pronouncements (continued) The FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Non-financial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . The update clarifies the scope of the standard and provides additional guidance on partial sales of non-financial assets. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business . The update is intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company follows the pronouncements of this update as of January 1, 2018. The FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash to eliminate current diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. Prior to the adoption of this update, the Company presented changes in restricted cash as investing activities on the consolidated statement of cash flows. The FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory . The new standard requires the recognition of current and deferred income taxes for an intra-entity transfer of an asset other than inventory. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments in order to eliminate current diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The adoption of this update had no significant impact on the Company's consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2018-19: Codification Improvements to Topic 326, Financial Instruments — Credit Losses as part of its project to correct unintended application of accounting standards. The amendments clarify that receivables arising from operating leases are not within the scope of ASC 326-20. Instead, impairment of receivables arising from operating leases should be accounted for in accordance with Topic 842, Leases . The amendments in this Update are effective the same date as Update 2016-13, which is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company is currently assessing the impact of this Update. 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. Early adoption is permitted. The Company is currently assessing the impact 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. Early adoption is permitted. 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 2018-16, 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. The amendments in this Update are required to be adopted concurrently with the amendments in Update 2017-12, which is required for all fiscal years beginning after December 15, 2018. The amendments will be adopted prospectively for qualifying new or redesignated hedging relationships entered into after the date of adoption. The FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40 ): Customers 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. Therefore, an entity will follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. In addition, the capitalized implementation costs are required to be expensed over the term of the hosting arrangement. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted in any interim period. The amendments can either be applied retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently assessing the impacts of this update. 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 update is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. No impact on the consolidated financial statements is expected from the adoption of this update. 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 update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company does not expect a significant impact on the 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 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 GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. Early adoption for fiscal years and interim periods beginning after December 15, 2018 is permitted. The Company is currently in the process of evaluating 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. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) 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 issued an amendment to ASC Topic 842 that permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The FASB issued a further update to ASC Topic 842 in ASU 2018-11 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The FASB has also issued further codification and narrow-scope improvements to ASC Topic 842 to correct and clarify specific aspects of the guidance. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. The Company is in the process of finalizing its assessment of the financial, operational, and business processes impacts of the new lease accounting standard. At this point, the Company expects that the adoption of Topic 842 will not have a material impact on the consolidated financial statements. The Company intends to implement new processes and procedures for the identification, analysis, and measurement of new lease contracts on a prospective basis. A new software solution is being implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company intends to elect 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 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 will make 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). The Company intends to adopt the lease accounting standard retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment.

Business acquisitions and devel

Business acquisitions and development projects	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Business acquisitions and development projects	Business acquisitions and development projects (a) Agreement to acquire Enbridge Gas New Brunswick Limited Partnership On December 4, 2018, the Company entered into an agreement to acquire Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas”). New Brunswick Gas is a regulated utility that provides natural gas to approximately 12,000 customers and operates approximately 800 km of natural gas distribution pipeline. The total purchase price for the transaction is C $331,000 , subject to certain closing adjustments. Closing of the transaction remains subject to regulatory approval and is expected in 2019. (b) Agreement to acquire St. Lawrence Gas Company, Inc. On August 31, 2017, the Company entered into an agreement to acquire St. Lawrence Gas Company, Inc. (“SLG”). SLG is a rate regulated natural gas distribution utility serving customers in northern New York State. The total purchase price for the transaction is $70,000 , less total third-party debt of SLG outstanding at closing, subject to certain closing adjustments. Closing of the transaction remains subject to regulatory approval and is expected to occur in 2019. (c) Approval to acquire the Perris Water Distribution System On August 10, 2017, the Company’s Board of Directors approved the acquisition of 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 Liberty Utilities 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 2019. (d) Great Bay Solar Facility The Great Bay Solar Facility consists of a 75 MWac solar powered generating facility in Somerset County, Maryland. As of December 31, 2017, three sites had been fully synchronized with the power grid, while the last site was placed in service in March 2018. Commercial operations as defined by the power purchase agreement was reached for all sites by March 29, 2018. The Great Bay Solar 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. 3. Business acquisitions and development projects (continued) (e) Acquisition of Empire On January 1, 2017, the Company completed the acquisition of Empire, a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. The purchase price of approximately $2,414,000 for the acquisition of Empire consists of a cash payment to Empire shareholders of $34.00 per common share and the assumption of approximately $855,000 of debt. The cash payment was funded with the acquisition facility for an amount of $1,336,440 (note 9(b)), proceeds received from the initial instalment of convertible debentures and existing credit facility. The costs related to the acquisition have been expensed through the consolidated statements of operations. Working capital $ 41,292 Property, plant and equipment 2,058,867 Goodwill 752,418 Regulatory assets 236,933 Other assets 43,609 Long-term debt (907,547 ) Regulatory liabilities (145,594 ) Pension and other post-employment benefits (78,204 ) Deferred income taxes liability, net (418,855 ) Other liabilities (76,532 ) Total net assets acquired $ 1,506,387 Cash and cash equivalents 1,742 Total net assets acquired, net of cash and cash equivalents $ 1,504,645 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies and cost savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Liberty Utilities Group segment. 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 the Empire's assets is 39 years. (f) Luning Solar Facility Luning Utilities (Luning Holdings) LLC (the “Luning Holdings”) is owned by the Calpeco Electric System. The 50 MWac solar generating facility is located in Mineral County, Nevada. During 2016, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded $7,826 as of December 31, 2016 and $31,212 on February 17, 2017. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Luning Solar project. During a six-month period in year 2022, the tax investor has the right to withdraw from Luning Holdings and require the Company to redeem its remaining interests for cash. As a result, 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, 2018. On February 15, 2017, as the Luning Solar Facility achieved commercial operation, Luning Holdings obtained control for a total purchase price of $110,856 . 3. Business acquisitions and development projects (continued) (f) Luning Solar Facility (continued) The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 152 Property, plant and equipment 110,857 Asset retirement obligation (546 ) Non-controlling interest (tax equity) (38,633 ) Total net assets acquired $ 71,830 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. (g) Bakersfield II Solar Facility On December 14, 2016, the Company completed construction and placed in service a 10 MWac solar powered generating facility located adjacent to the Company’s 20 MWac Bakersfield I Solar Facility in Kern County, California (“Bakersfield II Solar Facility”). Commercial operations as defined by the power purchase agreement was reached on January 11, 2017. The Bakersfield II Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield II Partnership”). The Class A partnership units are owned by a third-party tax equity investor who funded $2,454 on November 29, 2016 and approximately $9,800 on February 28, 2017. With 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.

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivable Accounts receivable as of December 31, 2018 include unbilled revenue of $79,742 ( 2017 - $78,289 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2018 are presented net of allowance for doubtful accounts of $5,281 ( 2017 - $5,555 ).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2018 Cost Accumulated depreciation Net book value Generation $ 2,470,279 $ 450,230 $ 2,020,049 Distribution 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 212,579 — 212,579 $ 7,406,319 $ 1,012,761 $ 6,393,558 5. Property, plant and equipment (continued) 2017 Cost Accumulated Net book Generation $ 2,382,279 $ 394,509 $ 1,987,770 Distribution 4,205,823 388,859 3,816,964 Land 71,689 — 71,689 Equipment and other 91,233 37,104 54,129 Construction in progress Generation 209,979 — 209,979 Distribution 164,366 — 164,366 $ 7,125,369 $ 820,472 $ 6,304,897 Generation assets include cost of $104,107 ( 2017 - $113,822 ) and accumulated depreciation of $34,916 ( 2017 - $34,908 ) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $1,987 ( 2017 - $1,633 ). Distribution assets include cost of $ 1,383,960 (2017 - $1,341,716 ) and accumulated depreciation of $ 69,960 (2017 - $28,809 ) related to regulated generation and transmission assets. Distribution assets include cost of $546,332 (2017 - $493,570 ) and accumulated depreciation of $42,476 (2017 - $8,578 ) related to commonly owned facilities (note 1(k)). Total expenditures for the year ended December 31, 2018 were $75,427 (2017 - $79,657 ). Distribution assets include cost of $3,076 (2017 - $3,076 ) and accumulated depreciation of $669 (2017 - $336 ) related to assets under capital lease. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. For the year ended December 31, 2018, contributions received in aid of construction of $6,057 ( 2017 - $12,742 ) have been credited to the cost of the assets.

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2018 Cost Accumulated amortization Net book value 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 2017 Cost Accumulated Net book Power sales contracts $ 56,540 $ 36,878 $ 19,662 Customer relationships 26,799 8,836 17,963 Interconnection agreements 14,181 — 703 13,478 $ 97,520 $ 46,417 $ 51,103 Estimated amortization expense for intangible assets for the next year is $2,093 , $2,265 in year two, $2,430 in year three, $2,400 in year four and $1,820 in year five. 6. Intangible assets and goodwill (continued) All goodwill pertains to the Liberty Utilities Group . Changes in goodwill are as follows: Balance, January 1, 2017 $ 228,377 Business acquisitions 752,418 Divestiture of operating entity (note 21(a)) (26,513 ) Balance, December 31, 2018 and 2017 $ 954,282

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Regulatory matters	Regulatory matters The Company’s regulated utility operating companies are subject to regulation by the public utility commissions of the states 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 state 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. On January 1, 2017, the Company completed the acquisition of Empire, an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. Empire also provides regulated water utility distribution services to three towns in Missouri. The Empire District Gas Company, a wholly owned subsidiary, is engaged in the distribution of natural gas in Missouri. These businesses are subject to regulation by the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma, the Arkansas Public Service Commission and the Federal Energy Regulatory 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. 7. Regulatory matters (continued) At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed: Utility State Regulatory Proceeding Type Annual Revenue Increase $'000 Effective Date Empire Electric System Missouri Tax Reform docket $(17,837) Prospective decrease in annual revenue effective August 30, 2018 due to the reduction of the U.S. federal corporate income tax rate. EnergyNorth Gas System New Hampshire General Rate Review $10,711 Effective May 1, 2018. The regulator also approved a one-time recoupment of $1,326 for the difference between the final rates and temporary rates granted on July 1, 2017. In November 2018, EnergyNorth received an order for rehearing clarifying the implementation of the decoupling mechanism that was approved and resolving the impacts of tax reform through the rehearing. The net result was a one-time decrease to the recoupment of $280. Missouri Gas System Missouri General Rate Review $4,600 Effective July 1, 2018 Peach State Gas System Georgia GRAM $2,367 Effective February 1, 2019 New England Natural Gas System Massachusetts Gas System Enhancement Plan $3,676 Effective May 1, 2018 New England Gas System Massachusetts GRC $8,300 $7,800 effective March 1, 2016 $500 effective March 1, 2017 Calpeco Electric System California Post-Test Year Adjustment Mechanism $2,175 January 1, 2018 Midstates Gas System Illinois GRC $2,200 June 7, 2017 Various Various Various $3,048 Other rate reviews closed: Missouri Water ($1,015), and Litchfield Park Water & Sewer ($617), Park Water 2018 increase ($1,531), Georgia 2018 Gas Rate Adjustment Mechanism (-$115) 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2018 2017 Regulatory assets Environmental remediation (a) $ 82,295 $ 82,711 Pension and post-employment benefits (b) 125,959 105,712 Debt premium (c) 48,847 57,406 Fuel and commodity costs adjustments (d) 26,310 34,525 Rate adjustment mechanism (e) 36,484 35,813 Clean Energy and other customer programs (f) 22,269 20,582 Deferred construction costs (g) 13,986 14,344 Asset retirement (h) 21,048 16,080 Income taxes (i) 34,822 36,546 Rate review costs (j) 7,990 9,295 Other 30,464 28,512 Total regulatory assets $ 450,474 $ 441,526 Less: current regulatory assets (59,037 ) (66,567 ) Non-current regulatory assets $ 391,437 $ 374,959 Regulatory liabilities Income taxes (i) $ 323,384 $ 321,138 Cost of removal (k) 193,564 184,188 Rate base offset (l) 10,900 13,214 Fuel and commodity costs adjustments (d) 23,517 23,543 Deferred compensation received in relation to lost production (m) 6,897 9,398 Deferred construction costs - fuel related (g) 7,258 7,418 Pension and post-employment benefits (b) 877 10,082 Other 12,195 7,143 Total regulatory liabilities $ 578,592 $ 576,124 Less: current regulatory liabilities (39,005 ) (37,687 ) Non-current regulatory liabilities $ 539,587 $ 538,437 (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'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 differs from those adopted and recovery or refunds are expected to occur in future periods. 7. Regulatory matters (continued) (c) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (d) Fuel and commodity costs adjustments The revenue from the utilities includes a component which 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 not recorded on the consolidated statements of operations but rather 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 23(b)(i)) are recoverable through the commodity costs adjustment. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, and Granite State Electric System are subject to a revenue decoupling mechanism approved by their respective regulator which require 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. (f) 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. (g) Deferred construction costs Deferred construction costs reflect deferred construction costs and fuel related costs of specific generating facilities of Empire. These amounts are being recovered over the life of the plants. (h) Asset retirement The costs of retirement of assets are expected to be recovered through rates as well as the on-going liability accretion and asset depreciation expense. (i) 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 was recorded for excess deferred taxes probable of being refunded to customers of $15,586 . The Tax Cuts and Jobs Act (the “Tax Act”) was enacted on December 22, 2017. Among other provisions, the Act reduces the corporate income tax rate from 35% to 21%. A reduction of regulatory asset and an increase to regulatory liability was recorded in 2017 for excess deferred taxes probable of being refunded to customers of $327,947 . 7. Regulatory matters (continued) (i) Income taxes (continued) As a result of the Tax Act enacted in 2017, regulators in the states where Liberty Utilities Group operates are contemplating the ratemaking implications of the reduction of federal tax rates from the legacy 35% tax rate and the new 21% federal statutory income tax rate effective January 2018. The Company is working with the regulators to identify the most appropriate way in each jurisdiction to address the impact of the Tax Act on cost of service based rates. As at December 31, 2018, the impact on regulated liability on account of ordered or probable orders related to the Tax Act was immaterial. (j) 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. (k) Cost of removal The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant. (l) 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. (m) Deferred compensation received in relation to lost production The regulatory liability for deferred compensation received from lost production represents Empire's refund from Southwest Power Administration for lost revenues at one of its generating facilities. These costs are being amortized over the period approved by state regulators. 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, 2018
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: 2018 2017 Long-term investment in Atlantica carried at fair value (a) $ 814,530 $ — Notes receivable from equity investees (e) $ 101,416 $ 30,060 Other long-term investments Equity-method investees AAGES (b) 2,622 — Red Lily I Wind Facility (c) 15,705 18,174 Amherst Island Wind Project (d) 7,655 8,921 Other 4,510 5,172 $ 30,492 $ 32,267 Other investments 3,870 5,004 Other long-term investments 34,362 37,271 Less: current portion (1,407 ) — $ 32,955 $ 37,271 Dividend income of $41,079 (2017 - $1,167 ) and equity loss of $1,609 (2017 - income $2,742 ) are included in Interest, dividend, equity and other income on the consolidated statements of operations. 8. Long-term investments (continued) (a) Investment in Atlantica On March 9, 2018, APUC purchased from Abengoa S.A. (“Abengoa”) a 25% equity interest in Atlantica for a purchase price of $607,567 , based on a price of $24.25 per ordinary share of Atlantica plus a contingent payment of up to $0.60 per-share payable two years after closing, subject to certain conditions. On November 27, 2018, APUC purchased from Abengoa an additional 16.5% equity interest in Atlantica for a purchase price of $345,000 , based on a price of $20.90 per ordinary share of Atlantica comprised of a payment of approximately $305,000 drawn from the Company's credit facility for payment on closing and a holdback of $40,000 payable at a later date, subject to certain conditions. The Company transferred the Atlantica shares to AAGES (AY Holdings) B.V. (“AY Holdings”), a new entity controlled and consolidated by APUC. 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. The difference between the purchase price and the value of the Atlantica shares based on the NASDAQ share price on the acquisition dates resulted in a combined immediate fair value loss of $139,864 . A fair value gain of $1,907 was recorded for the period from acquisition to December 31, 2018 resulting in a net loss on fair value for the year of $137,957 . The Company also recorded dividend income of $ $39,263 from the Atlantica shares during the period from acquisition to December 31, 2018. On November 28, 2018, Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”) obtained a three year secured credit facility in the amount of $306,500 and subscribed to a 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 drawn under the credit facility. 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. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest (note 17). (b) Investment in AAGES APUC and Abengoa created AAGES B.V., AAGES Development Canada Inc. and AAGES Development Spain (collectively, the “AAGES entities”) to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Each partner initially contributed $5,000 to the AAGES entities. AAGES Development Canada Inc. and AAGES Development Spain are considered a VIE due to the level of equity at risk. The Company is not considered the primary beneficiary of AAGES Development Canada Inc. and AAGES Development Spain as the two partners have joint control and all decisions must be unanimous. As such, the Company is accounting for its investment in the joint ventures under the equity method. The AAGES entities contributed equity loss of $3,005 to the Company's consolidated financial results for the year ended December 31, 2018. As of December 31, 2018, the Company’s maximum exposure to loss of $7,509 related to AAGES Development Canada Inc. and AAGES Development Spain is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(e). (c) Red Lily I Wind Facility The Red Lily I Wind Facility (the “Partnership”) is a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company owns a 75% equity interest in the Partnership. Due to certain participating rights being held by the minority investor, the decisions which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, APUC is deemed, under U.S. GAAP, to not have control over the Partnership. As APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility, the Company accounts for the Partnership using the equity method. The Red Lily I Wind Facility contributed equity income of $1,637 (2017 - $2,139 ) to the Company's consolidated financial results for the year ended December 31, 2018. 8. Long-term investments (continued) (d) Amherst Island Wind Project APUC has a 50% interest in Windlectric Inc. (“Windlectric”) which owns a 74.1 MW wind generating facility (“Amherst Island Wind Facility”) in the Province of Ontario. Construction was completed during the second quarter of 2018 and sale of power under the power purchase agreement has started. Subsequent to year-end, the Company exercised its option to acquire the remaining common shares at a fixed price. The acquisition is subject to regulatory approval expected to be obtained in 2019. Windlectric is considered a VIE due to the level of equity at risk. The Company is not considered the primary beneficiary of Windlectric as the two shareholders have joint control and all decisions must be unanimous. As such, the Company accounts for its investment in the joint venture under the equity method. The interest capitalized during the year ended December 31, 2018 to the investment while the Amherst Island Wind Facility was under construction amounts to $739 (2017 - $1,115 ). As at December 31, 2018, the net book value of property, plant and equipment of the joint venture was $308,825 while the third-party construction debt was $190,910 (2017 - $106,628 ). Windlectric contributed equity loss of $1,714 (2017 - nil) to the Company's consolidated financial results for the year ended December 31, 2018. As of December 31, 2018, the Company’s maximum exposure to loss of $192,052 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(e). Subsequent to year-end, the joint venture borrowed from the Company to repay in full the third-party construction debt. (e) Development loans receivable from equity investees The Company entered into 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, or guarantees) in amounts necessary for the continued development and construction of the equity investees' wind projects. As at December 31, 2018 , the Company has a loan and credit support facility with Windlectric of $96,477 (2017 - $ 30,060 ). The loan to Windlectric bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2019. The letters of credit are charged an annual fee of 2% on their stated amount. As of December 31, 2018, the following credit support was outstanding on behalf of Windlectric: letters of credit and guarantees of obligations to the utilities under the power purchase agreement; a guarantee of the obligations under the wind turbine, transmission line, transformer, and other supply agreements; and, a guarantee of the obligations under the engineering, procurement, and construction management agreements. The value of the guarantee obligations is recognized under other long-term liabilities and as at December 31, 2018 is valued at $1,637 (2017 - $1,952 ) using a probability weighted discounted cash flow (level 3). The Company recognized interest income of $6,144 on the advances and credit support from the day Amherst Island Wind Facility achieved commercial operations to December 31, 2018 . As at December 31, 2018 , the Company has a balance receivable from the AAGES entities of $4,940 . As at December 31, 2018, the Company has issued $3,750 in letters of credit on behalf of AAGES. Subsequent to year-end, $1,750 was repaid under this credit support facility. Following acquisition of control of Deerfield SponsorCo (note 8(f)(ii)), amounts advanced to the wind facility are eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in OCI from the date of acquisition. 8. Long-term investments (continued) (f) Other transactions i. Wataynikaneyap Power Transmission Project Subsequent to year-end, APUC acquired a 9.8% ownership interest in the Wataynikaneyap Power Transmission Project, a transmission project that involves the development, construction and operation of a 1,800 km transmission line in Northwestern Ontario. ii. Deerfield Wind Facility The Company had a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 149 MW construction-stage wind development project (“Deerfield Wind Project”) in the State of Michigan. On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo and obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting which requires that the fair value of assets acquired and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(e)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of $nil was recorded on acquisition. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ (10,808 ) Property, plant and equipment 328,371 Construction loan (261,952 ) Asset retirement obligation (2,092 ) Deferred revenue (1,156 ) Deferred tax liability (1,470 ) Net assets acquired $ 50,893 Cash and cash equivalents $ 3,107 Net assets acquired, net of cash and cash equivalents $ 47,786 On May 10, 2017, tax equity funding of $166,595 was received.

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-term debt	Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2018 2017 Senior unsecured revolving credit facilities (a) — 2019-2023 N/A $ 97,000 $ 51,827 Senior unsecured bank credit facilities (b) — 2019 N/A 321,807 134,988 Commercial paper (a) — 2023 N/A 6,000 5,576 U.S. dollar borrowings Senior unsecured notes (c) 4.09 % 2020-2047 $ 1,225,000 1,218,680 1,217,797 Senior unsecured utility notes (d) 5.99 % 2020-2035 $ 222,000 240,161 246,560 Senior secured utility bonds (e) 4.75 % 2020-2044 $ 662,500 676,697 772,871 Subordinated unsecured notes (f) 6.88 % 2078 $ 287,500 278,771 — Canadian dollar borrowings Senior unsecured notes (g) 4.43 % 2020-2027 C$ 650,669 474,764 623,223 Senior secured project notes 10.25 % 2020-2027 C$ 31,310 22,915 26,709 $ 3,336,795 $ 3,079,551 Less: current portion (13,048 ) (12,364 ) $ 3,323,747 $ 3,067,187 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. Short-term obligations of $321,807 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. Recent financing activities: (a) Senior unsecured revolving credit facilities On September 20, 2017, the Company amended the terms of its C $65,000 senior unsecured revolving bank credit facility to increase the commitments to C $165,000 and, on November 16, 2018, the Company extended the maturity from November 19, 2018 to November 19, 2019. On February 23, 2018, the Liberty Utilities Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023. Concurrent with this amendment, the Liberty Utilities Group closed Empire's credit facility. Liberty Utilities' credit facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire. On October 6, 2017, the Liberty Power Group amended the terms of its C $350,000 senior unsecured revolving bank credit facility to increase the commitments to $500,000 and extended the maturity from July 31, 2019 to October 6, 2022. The Liberty Power 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 Liberty Power Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 2021. 9. Long-term debt (continued) (b) Senior unsecured bank credit facilities On December 21, 2017, the Company entered into a $600,000 term credit facility with two Canadian banks maturing on December 21, 2018. On March 7, 2018, the Company drew $600,000 under this facility. On December 19, 2018, the Company extended the maturity of this facility to June 21, 2019. The balance drawn as at December 31, 2018 is $186,807 . On December 30, 2016, in connection with the acquisition of Empire (note 3(e)), the Company drew $1,336,440 from its Acquisition Facility. Following receipt of the Final Instalment from the convertible debentures on February 7, 2017 (note 12(h)) and the senior notes financing on March 24, 2017 (note 9(d)), the Company fully repaid the Acquisition Facility. As at December 31, 2018, the Company had drawn $135,000 on its Corporate Term Credit Facility which matures on July 5, 2019. (c) Senior unsecured notes On March 24, 2017, the Liberty Utilities Group 's debt financing entity issued $750,000 senior unsecured notes in six tranches. The proceeds were applied to repay the Acquisition Facility (note 9(b)) and other existing indebtedness. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0% . In anticipation of this financing, the Liberty Utilities Group had entered into forward contracts to lock in the underlying U.S. Treasury interest rates. Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group will be approximately 3.6% . (d) Senior unsecured utility notes On January 1, 2017, in connection with the acquisition of Empire (note 3(e)), the Company assumed $102,000 in unsecured utility notes. The notes consist of two tranches, with maturities in 2033 and 2035 with coupons at 6.7% and 5.8% . (e) Senior secured utility bonds On January 1, 2017 in connection with the acquisition of Empire (note 3(e)), the Company assumed $733,000 in secured utility bonds. The bonds are secured by a first mortgage indenture and consist of ten tranches with maturities ranging between 2018 and 2044 with coupons ranging from 3.58% to 6.82% . On June 1, 2018, the Company repaid, upon its maturity, a $90,000 secured utility note. In June 2017, outstanding bonds payable for the Park Water Systems in the amount of $63,000 were repaid using proceeds from the Mountain Water condemnation discussed in note 21(a). (f) Subordinated unsecured notes 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. The subordinated notes are listed on the New York Stock Exchange ("NYSE") under the ticker symbol "AQNA". 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 rest 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. 9. Long-term debt (continued) (f) Canadian dollar senior unsecured notes Subsequent to year-end, the Liberty Power 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 Liberty Power Group unwound and settled the related forward-starting interest rate swap on a notional bond of C $135,000 (note 23(b)(ii)). On July 25, 2018, the Company repaid, upon its maturity, a C $135,000 unsecured note. On January 17, 2017, the Liberty Power Group issued C $300,000 senior unsecured notes bearing interest at 4.09% with a maturity date of February 17, 2027. The notes were sold at a price of C$99.929 per C$100.00 principal amount. As of December 31, 2018 , the Company had accrued $33,822 in interest expense ( 2017 - $33,064 ). Interest expense on the long-term debt in 2018 was $150,262 ( 2017 - $142,791 ). Principal payments due in the next five years and thereafter are as follows: 2019 2020 2021 2022 2023 Thereafter Total $ 334,855 $ 308,917 $ 111,880 $ 343,737 $ 481,859 $ 1,740,471 $ 3,321,719

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2018
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 2018 were $8,446 ( 2017 - $7,232 ). 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 2018 2017 2018 2017 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 523,743 $ 247,246 $ 176,975 $ 61,888 Projected benefit obligation assumed from business combination — 256,486 — 97,761 Service cost 15,481 14,747 5,791 4,838 Interest cost 18,717 20,191 6,727 6,642 Actuarial (gain) loss (29,845 ) 35,696 (14,800 ) 10,263 Contributions from retirees — — 1,920 1,821 Gain on curtailment (1,875 ) (849 ) — (4 ) Benefits paid (49,429 ) (49,774 ) (8,288 ) (6,234 ) Projected benefit obligation, end of year $ 476,792 $ 523,743 $ 168,325 $ 176,975 Change in plan assets Fair value of plan assets, beginning of year 403,945 176,040 130,487 21,701 Plan assets acquired in business combination — 184,510 — 91,532 Actual return on plan assets (36,987 ) 63,250 (10,603 ) 19,733 Employer contributions 21,570 29,919 2,068 2,068 Benefits paid (49,429 ) (49,774 ) (6,410 ) (4,547 ) Fair value of plan assets, end of year $ 339,099 $ 403,945 $ 115,542 $ 130,487 Unfunded status $ (137,693 ) $ (119,798 ) $ (52,783 ) $ (46,488 ) Amounts recognized in the consolidated balance sheets consists of: Non-current assets — — 3,161 3,936 Current liabilities (872 ) (861 ) (850 ) (1,172 ) Non-current liabilities (136,821 ) (118,937 ) (55,094 ) (49,252 ) Net amount recognized $ (137,693 ) $ (119,798 ) $ (52,783 ) $ (46,488 ) The accumulated benefit obligation for the pension plans was $439,458 and $490,108 as of December 31, 2018 and 2017 , 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 2018 2017 2018 2017 Accumulated benefit obligation 439,458 462,943 163,375 171,175 Fair value of plan assets 339,099 376,276 107,430 121,561 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2018 2017 2018 2017 Projected benefit obligation 476,791 523,743 163,375 171,175 Fair value of plan assets 339,099 403,945 107,430 121,561 On June 22, 2017, all Mountain Water employees were terminated as a result of the condemnation of the Mountain Water assets to the City of Missoula (note 21(a)). The pension and OPEB obligations of these employees remain with the Company. The assets and projected benefit obligations of the plans were revalued at June 30, 2017 and resulted in an actuarial gain of $2,354 recorded in OCI and a curtailment gain of $853 recorded against the loss on long-lived assets. In 2018, the Company permanently froze the accrual of benefits for participants in Park Water'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 an decrease to the projected benefit obligation of $1,875 which is recorded as a prior service credit in OCI. Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2017 $ 27,572 $ (5,617 ) $ (3,861 ) $ (732 ) Additions to AOCI (2,652 ) — (3,066 ) — Reclassification to regulatory accounts (note 7(b)) 1,136 — 3,515 — Amortization in current period (928 ) 622 230 262 Balance, December 31, 2017 $ 25,128 $ (4,995 ) $ (3,182 ) $ (470 ) Additions to AOCI 34,916 (1,875 ) 3,254 — Reclassification to regulatory accounts (note 7(b)) (22,166 ) — (14,232 ) — Amortization in current period (1,074 ) 649 272 262 Gain (loss) on plan settlements (2,547 ) — — — Balance, December 31, 2018 $ 34,257 $ (6,221 ) $ (13,888 ) $ (208 ) The movements in AOCI for Empire's pension and OPEB plans are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(b)). 10. Pension and other post-employment benefits (continued) (b) Assumptions Weighted average assumptions used to determine net benefit obligation for 2018 and 2017 were as follows: Pension benefits OPEB 2018 2017 2018 2017 Discount rate 4.19 % 3.43 % 4.26 % 3.60 % Interest crediting rate (for cash balance plans) 4.43 % 4.50 % N/A N/A 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 The mortality assumption for December 31, 2018 was updated to the projected generationally scale MP-2018, adjusted to reflect the ultimate improvement rates in the 2018 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 2018 and 2017 were as follows: Pension benefits OPEB 2018 2017 2018 2017 Discount rate 3.57 % 4.01 % 3.60 % 4.12 % Expected return on assets 7.13 % 7.01 % 6.52 % 3.88 % Rate of compensation increase 3.00 % 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 2024 2023 10. Pension and other post-employment benefits (continued) (c) Benefit costs The following table lists the components of net benefit cost for the pension plans and OPEB recorded as part of operating expenses 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 2018 2017 2018 2017 Service cost $ 15,481 $ 14,747 $ 5,791 $ 4,838 Non-service costs Interest cost 18,717 20,191 6,727 6,642 Expected return on plan assets (27,820 ) (24,842 ) (7,451 ) (6,404 ) Amortization of net actuarial loss (gain) 1,119 1,140 (272 ) (230 ) Amortization of prior service credits (649 ) (622 ) (262 ) (262 ) Amortization of regulatory assets/liability 9,823 13,031 3,982 391 Net benefit cost $ 16,671 $ 23,645 $ 8,515 $ 4,975 As a result of the adoption of ASU 2017-07 (note 2(a)), the service cost components of pension plans and OPEB are shown as part of operating expenses within operating income in the consolidated statements of operations. The remaining components of net benefit cost are considered non-service costs and have been included outside of operating income in pension and post-employment non-service costs in the consolidated statements of operations. The Company applied the practical expedient for retrospective application on the consolidated statements of operations and as such, the $9,035 of non-service costs for the twelve months ended December 31, 2017 has been reclassified from administrative expenses to pension and post-employment non-service costs. (d) 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 69 % 49% - 78% Debt securities 31 % 22% - 51% 100 % The fair values of investments as of December 31, 2018 , by asset category, are as follows: Asset Class Level 1 Percentage Equity securities $ 338,946 75 % Debt securities 115,695 25 % Other — — % $ 454,641 100 % As of December 31, 2018 , the funds do not hold any material investments in APUC. 10. Pension and other post-employment benefits (continued) (e) Cash flows The Company expects to contribute $20,137 to its pension plans and $5,562 to its post-employment benefit plans in 2019. The expected benefit payments over the next ten years are as follows: 2019 2020 2021 2022 2023 2024 — 2028 Pension plan $ 31,101 $ 29,366 $ 32,508 $ 33,415 $ 35,111 $ 183,338 OPEB 6,077 6,686 7,172 7,731 8,241 47,119

Other assets

Other assets	12 Months Ended
	Dec. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2018 2017 Income tax recoverable $ 1,961 $ 5,967 Deferred financing costs 4,449 3,546 Restricted cash 18,954 15,939 Other 9,335 10,811 34,699 36,263 Less: current portion (6,115 ) (7,110 ) $ 28,584 $ 29,153

Other long-term liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Other long-term liabilities	Other long-term liabilities Other long-term liabilities consist of the following: 2018 2017 Advances in aid of construction (a) $ 63,703 $ 62,683 Environmental remediation obligation (b) 55,621 54,322 Asset retirement obligations (c) 43,291 44,166 Customer deposits (d) 29,974 28,529 Unamortized investment tax credits (e) 17,491 17,839 Deferred credits (f) 42,711 21,168 Preferred shares, Series C (g) 13,418 14,718 Other (h) 39,710 45,434 305,919 288,859 Less: current portion (42,337 ) (46,754 ) $ 263,582 $ 242,105 (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 2018, $3,687 (2017 - $10,498 ) was transferred from advances in aid of construction to contributions in aid of construction. 12. Other long-term liabilities (continued) (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. The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $59,181 (2017 - $57,292 ) which at discount rates ranging from 2.5% to 2.8% represents the recorded accrual of $55,621 as of December 31, 2018 (2017 - $54,322 ). Approximately $36,611 is expected to be incurred over the next four years with the balance of cash flows to be incurred over the following 27 years. Changes in the environmental remediation obligation are as follows: 2018 2017 Opening balance $ 54,322 $ 47,202 Remediation activities (2,163 ) (1,561 ) Accretion 1,479 1,114 Changes in cash flow estimates 4,051 1,645 Revision in assumptions (2,068 ) 5,922 Closing balance $ 55,621 $ 54,322 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, 2018, the Company has reflected a regulatory asset of $82,295 (2017 - $82,711 ) 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) disposal 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: 2018 2017 Opening Balance $ 44,166 $ 18,486 Obligation assumed from business acquisition and constructed projects 225 28,267 Retirement activities (5,130 ) (2,811 ) Accretion 1,974 1,981 Change in cash flow estimates 2,056 (1,757 ) Closing Balance $ 43,291 $ 44,166 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(h)). (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. 12. Other long-term liabilities (continued) (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. (f) Deferred credits During the year, the Company settled $16,000 of contingent consideration related to prior acquisitions resulting in a gain of approximately $12,000 which was recorded as a reduction of acquisition costs on the consolidated statements of operations. (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 (fifty-three thousand and four hundred dollars 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: 2019 $ 940 2020 985 2021 1,000 2022 1,019 2023 1,183 Thereafter to 2031 10,370 Redemption amount 3,914 19,411 Less: amounts representing interest (5,993 ) 13,418 Less current portion (940 ) $ 12,478 (h) Other Convertible debentures As at December 31, 2018, the carrying value of the convertible debentures was $470 (2017 - $971 ). On March 1, 2016, the Company completed the sale of C$1,150,000 aggregate principal amount of 5.0% convertible debentures. The proceeds received from the initial instalment in 2016 and the final instalment in 2017, net of financing costs were $266,889 and $571,642 , respectively. The convertible debentures mature on March 31, 2026 and bore interest at an annual rate of 5% per C$1,000 principal amount of convertible debentures until and including the Final Instalment Date, after which the interest rate is 0% . The interest expense recorded for the year ended December 31, 2018 is $ nil ( 2017 - $ 7,193 ). 12. Other long-term liabilities (continued) (h) Other (continued) Convertible debentures (continued) The debentures are convertible into up to 108,490,566 common shares. During the year ended December 31, 2018 $447 (2017 - $855,691 ) of principal converted to 56,926 (2017 - 108,370,081 ) common shares of the Company (note 13), representing conversion into common shares of 99.9% of the convertible debentures as at December 31, 2018 .

Shareholders' capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares 2018 2017 Common shares, beginning of year 431,765,935 274,087,018 Public offering (a)(i) 50,041,624 43,470,000 Conversion of convertible debentures (note 12(h)) 56,926 108,370,081 Dividend reinvestment plan (a)(ii) 5,880,843 3,905,848 Exercise of share-based awards (c) 1,106,105 1,932,988 Common shares, end of year 488,851,433 431,765,935 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 2019. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan. (i) Public offering On 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 ). On November 10, 2017, APUC issued 43,470,000 common shares at $10.45 (C $13.25 ) per share pursuant to a public offering for proceeds of $454,158 (C $576,000 ) before issuance costs of $19,193 (C $24,342 ) or $14,109 (C $17,895 ) net of taxes. (ii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 1,606,001 common shares under the dividend reinvestment plan. 13. Shareholders’ capital (continued) (b) Preferred shares APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2018 and 2017 : Preferred shares Number of shares Price per share Carrying amount C$ 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 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 Series D dividend rate will reset on that date and every five years thereafter at a rate equal to the then five -year Government of Canada bond yield plus 3.28% . The Series D preferred shares are redeemable at C $25 per share at the option of the Company on March 31, 2019 and every fifth year thereafter. The holders of Series A and Series D preferred shares have 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. The Series A did not convert to Series B on December 31, 2018. The Series B and Series E preferred shares will be entitled to receive quarterly floating-rate cumulative dividends, as and when declared by the Board, at a rate equal to the then ninety-day Government of Canada treasury bill yield plus 2.94% and 3.28% , respectively. The holders of Series B and Series E preferred shares will have the right to convert their shares back into Series A and Series D preferred shares on December 31, 2023 and March 31, 2019, respectively and every fifth year thereafter. The Series A, Series B, Series D and Series E preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof. 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, 2018 , APUC recorded $9,458 (2017 - $8,361 ) in total share-based compensation expense detailed as follows: 2018 2017 Share options $ 2,054 $ 3,070 Director deferred share units 714 593 Employee share purchase 312 436 Performance and restricted share units 6,378 4,262 Total share-based compensation $ 9,458 $ 8,361 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, 2018 , total unrecognized compensation costs related to non-vested options and PSUs were $1,221 and $8,243 , respectively, and are expected to be recognized over a period of 1.64 and 1.60 years, respectively. (i) Share option plan The Company’s share option plan (the “Plan”) permits the grant of share options to key 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 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 which 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. In the case of qualified retirement, the Board may accelerate the vesting of the unvested options then held by the optionee at the Board’s discretion. All vested options may be exercised within ninety days after retirement. In the case of death, the options vest immediately and the period over which the options can be exercised is one year. In the case of disability, options continue to vest and be exercisable in accordance with the terms of the grant and the provisions of the plan. Employees have up to thirty days to exercise vested options upon resignation or termination. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Board (or the compensation committee of the Board (“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 adjusted 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: 2018 2017 Risk-free interest rate 2.1 % 1.4 % Expected volatility 21 % 25 % Expected dividend yield 4.8 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 1.41 C$ 1.45 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, 2017 6,045,014 C$ 9.64 6.27 C$ 10,595 Granted 2,328,343 12.82 8.00 — Exercised (1,634,501 ) 7.81 3.76 7,696 Balance, December 31, 2017 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 Exercisable, December 31, 2018 3,198,175 C$ 10.44 4.93 C$ 10,501 (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 (a) 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, for Canadian employees, and (b) 15% of the employee contribution amount for the first fifteen thousand dollars per employee contributed annually, for U.S. employees. 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 contribution 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 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, 2018 , a total of 252,698 common shares ( 2017 - 283,523 ) 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, 2018 , 380,656 ( 2017 - 293,906 ) 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 are granted annually for three -year overlapping performance cycles. 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 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. 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, 2017 578,988 C$ 9.82 1.74 C$ 6,595 Granted, including dividends 811,974 13.54 2.00 — Exercised (374,973 ) 8.33 — 4,394 Forfeited (60,961 ) 12.61 — — Balance, December 31, 2017 955,028 C$ 12.30 1.84 C$ 13,428 Granted, including dividends 791,524 12.41 2.00 — 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 Exercisable, December 31, 2018 173,533 C$ 11.66 — C$ 2,383 (v) Bonus deferral RSUs During the year, 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) (iv) 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$ — $ — Granted, including dividends 131,611 12.82 — Exercised (4,545 ) 12.82 61 Balance and exercisable, December 31, 2018 127,066 C$ 12.82 C$ 1,745

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2018
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 Net change on available-for-sale investments Pension and post-employment actuarial changes Total Balance, January 1, 2017 $ (25,921 ) $ 53,740 $ 65 $ (10,833 ) $ 17,051 OCI (loss) before reclassifications (21,780 ) 8,004 — 600 (13,176 ) Amounts reclassified — (6,378 ) (65 ) (224 ) (6,667 ) Net current period OCI (21,780 ) 1,626 (65 ) 376 (19,843 ) Balance, December 31, 2017 $ (47,701 ) $ 55,366 $ — $ (10,457 ) $ (2,792 ) Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a)) — 11,657 — (1,032 ) 10,625 OCI before reclassifications (26,488 ) 1,567 — 2,046 (22,875 ) Amounts reclassified — (4,257 ) — — (86 ) (4,343 ) Net current period OCI $ (26,488 ) $ (2,690 ) $ — $ 1,960 $ (27,218 ) Balance, December 31, 2018 $ (74,189 ) $ 64,333 $ — $ (9,529 ) $ (19,385 ) 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, 2018
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: 2018 2017 Dividend Dividend per share Dividend Dividend per share Common shares $ 235,440 $ 0.5011 $ 185,915 $ 0.4660 Series A preferred shares C$ 5,400 C$ 1.1250 C$ 5,400 C$ 1.1250 Series D preferred shares C$ 5,000 C$ 1.2500 C$ 5,000 C$ 1.2500

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related party transactions	Related party transactions Equity-method investments The Company entered in a number of transactions with equity-method investees in 2018 and 2017 (note 8). In addition, the Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $11,390 ( 2017 - $4,675 ) during the year. Subject to certain limitations, Atlantica has a right of first offer on any proposed sale, transfer or other disposition by the AAGES entities (other than to APUC) of its interest in infrastructure facilities that are developed or constructed in whole or in part by the AAGES entities under long-term revenue agreements. Similarly, Atlantica has rights, subject to certain limitations, with respect to any proposed sale, transfer or other disposition of APUC’s interest, not held through the AAGES entities, in infrastructure facilities that are developed or constructed in whole or in part by APUC outside of Canada or the United States under long-term revenue agreements. There were no such transactions in 2018. Redeemable non-controlling interests In 2018, contributions of $305,000 were received from AAGES B.V for a preference share of AY Holdings (note 8(a) and note 17). 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, 2018
Noncontrolling Interest [Abstract]
Non-controlling Interests and Redeemable non-controlling Interest	Non-controlling interests and redeemable non-controlling interests Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2018 2017 HLBV and other adjustments attributable to: Non-controlling interests - Class A partnership units $ 103,150 $ 39,850 Non-controlling interests - redeemable Class A partnership units 7,545 10,358 Other net earnings attributable to: Non-controlling interests (2,174 ) (2,438 ) $ 108,521 $ 47,770 Redeemable non-controlling interests, held by related party (2,622 ) — Net effect of non-controlling interests $ 105,899 $ 47,770 17. Non-controlling interests and redeemable non-controlling interests (continued) The non-controlling Class A membership equity investors (“Class A 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(r). 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, 2018, non-controlling interests of $519,896 ( 2017 - $602,636 ) includes Class A partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $519,100 ( 2017 - $601,780 ) and other non-controlling interests of $ $796 ( 2017 - $856 ). Contributions from Class A partnership investors of $15,250 and $42,750 was received for the Great Bay Solar Facility in 2018 and 2017, respectively (note 3(d)); $9,800 was received for the Bakersfield II Solar Facility on February 28, 2017 (note 3(g)); and, $166,595 was received for the Deerfield Wind Project on May 10, 2017 (note 8(f)(ii)). 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, 2018. Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2018 2017 2018 2017 Opening balance $ — $ — $ 41,553 $ 21,922 Net effect from operations 2,622 — (7,545 ) (10,356 ) Contributions 305,000 — — 31,105 Dividends and distributions declared — — (644 ) (1,118 ) Closing balance $ 307,622 $ — $ 33,364 $ 41,553 Contributions of $305,000 were received from Abengoa-Algonquin Global Energy Solutions B.V. for a preference share of AY Holdings (note 8(a)). Contributions from Class A partnership investors of $31,212 were received for the Luning Solar Facility on February 17, 2017 (note 3(f)).

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2018
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% ( 2017 - 26.5% ). The differences are as follows: 2018 2017 Expected income tax expense at Canadian statutory rate $ 35,102 $ 46,410 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (34,165 ) (20,987 ) Net loss from investment in Atlantica 25,870 — Base Erosion Anti-Abuse Tax 6,101 — Non-controlling interests share of income 29,637 18,979 Allowance for equity funds used during construction (719 ) (799 ) Capital gain rate differential 722 (687 ) Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation 58 5,489 Non-deductible acquisition costs 4,267 13,660 Change in valuation allowance 1,160 (974 ) Tax credits (1,419 ) (6,288 ) Adjustment relating to prior periods 3,673 (31 ) U.S. Tax reform and related deferred tax adjustments (18,363 ) 17,112 Other 1,448 1,543 Income tax expense $ 53,372 $ 73,427 On December 22, 2017, the Tax Act was signed into legislation. The Tax Act includes a broad range of legislative changes including a reduction of the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018, limitations on the deductibility of interest and 100% expensing of qualified property. The Tax Act provides an exemption to regulated utilities from the limitations on the deductibility of interest and also does not permit regulated utilities to immediately expense 100% of the cost of new investments in qualified property. As a result of the Tax Act being enacted during 2017, the Company was required to revalue its United States deferred income tax assets and liabilities based on the rates they are expected to reverse at in the future, which is generally 21% for U.S. federal tax purposes. The Company recognized a provisional charge to income tax expense of $17,112 in 2017 as a result of the revaluation of its U.S. non-regulated net deferred income tax assets. In 2018, the Company completed its remeasurement of deferred income tax assets and liabilities as permitted under the measurement period outlined under SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). The final adjustments 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. 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. The Company reduced its regulated net deferred income tax liabilities by $15,586 and recorded an equivalent increase to net regulatory liabilities since the benefit of lower Missouri state income taxes is probable of being returned to customers by order of the applicable regulator. For the years ended December 31, 2018 and 2017 , earnings before income taxes consist of the following: 2018 2017 Canada $ (109,537 ) $ (2,711 ) U.S. 241,998 177,843 $ 132,461 $ 175,132 18. Income taxes (continued) Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total 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 Year ended December 31, 2017 Canada $ 3,296 $ (14,168 ) $ (10,872 ) United States 4,221 80,078 84,299 $ 7,517 $ 65,910 $ 73,427 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, 2018 and 2017 are presented below: 2018 2017 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 329,099 $ 328,679 Pension and OPEB 48,586 43,638 Acquisition-related costs 1,420 1,601 Environmental obligation 14,790 14,803 Reserves and other non-deductible costs 20,517 30,652 Regulatory liabilities 161,560 154,597 Financial derivatives 12,831 7,607 Other 10,425 16,384 Total deferred income tax assets 599,228 597,961 Less valuation allowance (28,018 ) (19,951 ) Total deferred tax assets 571,210 578,010 Deferred tax liabilities: Property, plant and equipment (653,962 ) (668,083 ) Intangible assets (7,247 ) (7,157 ) Outside basis in partnership (167,659 ) (125,519 ) Regulatory accounts (113,758 ) (114,062 ) Financial derivatives — (980 ) Other (314 ) — Total deferred tax liabilities (942,940 ) (915,801 ) Net deferred tax liabilities $ (371,730 ) $ (337,791 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 72,415 $ 61,357 Deferred tax liabilities (444,145 ) (399,148 ) Net deferred tax liabilities $ (371,730 ) $ (337,791 ) 18. Income taxes (continued) The valuation allowance for deferred tax assets as at December 31, 2018 was $ 28,018 ( 2017 - $19,951 ). 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, 2018 , the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2020 and onwards $ 925,439 The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of its subsidiaries. Deferred income taxes have not been provided on approximately $280,643 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.

Basic and diluted net earnings

Basic and diluted net earnings per share	12 Months Ended
	Dec. 31, 2018
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. The convertible debentures (note 12(h)) are convertible into common shares at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The Final Instalment Date occurred on February 2, 2017, and as such, the shares issuable upon conversion of the convertible debentures are included in diluted earnings per share beginning on that date. 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: 2018 2017 Net earnings attributable to shareholders of APUC $ 184,988 $ 149,475 Series A Preferred shares dividend 4,169 4,164 Series D Preferred shares dividend 3,858 3,856 Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 176,961 $ 141,455 Weighted average number of shares Basic 461,818,023 382,323,434 Effect of dilutive securities 4,227,595 3,662,714 Diluted 466,045,618 385,986,148 The shares potentially issuable as a result of 3,380,184 share options ( 2017 - 2,328,343 ) are excluded from this calculation as they are anti-dilutive.

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segmented information	Segmented information The Company is managed under two primary North American business units consisting of the Liberty Power Group and the Liberty Utilities Group . The two business units are the two segments of the Company. The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets in North America and internationally; the Liberty Utilities 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. For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. Dividend income from Atlantica (note 8(a)) and equity income from the AAGES entities (note 8(b)) are included in the operations of the Liberty Power Group . The change in value of the investment in Atlantica carried at fair value (note 8(a)) 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. The results of operations and assets for these segments are reflected in the tables below. Year ended December 31, 2018 Liberty Utilities Group Liberty Power Group Corporate Total Revenue (1)(2) $ 1,400,164 $ 247,223 $ — $ 1,647,387 Fuel, power and water purchased 456,974 27,164 — 484,138 Net revenue 943,190 220,059 — 1,163,249 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 330,751 48,496 (1,888 ) 377,359 Interest expense 99,063 50,920 2,135 152,118 Interest, dividend, equity and other income (5,558 ) (45,741 ) (1,840 ) (53,139 ) Change in value of investment carried at fair value — — 137,957 137,957 Other expenses 5,699 1,576 687 7,962 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 959 29,273 260 30,492 Total assets 6,012,641 3,269,786 106,541 9,388,968 Capital expenditures 370,221 96,148 — 466,369 (1) Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the twelve months ended December 31, 2018 that do not represent revenue recognized from contracts with customers. (2) Liberty Utilities Group revenue includes $7,425 related to alternative revenue programs for the twelve months ended December 31, 2018 that do not represent revenue recognized from contracts with customers. 20. Segmented information (continued) Year ended December 31, 2017 Liberty Utilities Group Liberty Power Group Corporate Total Revenue $ 1,290,786 $ 231,152 $ — $ 1,521,938 Fuel and power purchased 373,635 19,590 — 393,225 Net revenue 917,151 211,562 — 1,128,713 Operating expenses 383,380 66,851 — 450,231 Administrative expenses 33,037 15,992 611 49,640 Depreciation and amortization 171,111 79,183 1,020 251,314 Gain on foreign exchange — — 323 323 Operating income (loss) 329,623 49,536 (1,954 ) 377,205 Interest expense 97,698 36,646 21,478 155,822 Interest, dividend and other income (4,208 ) (2,871 ) (2,159 ) (9,238 ) Other expense 6,087 1,713 47,689 55,489 Earnings (loss) before income taxes $ 230,046 $ 14,048 $ (68,962 ) $ 175,132 Property, plant and equipment $ 4,023,479 $ 2,246,869 $ 34,549 $ 6,304,897 Equity-method investees 2,220 29,710 337 32,267 Total assets 5,817,599 2,474,293 103,675 8,395,567 Capital expenditures 407,408 157,695 — 565,103 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. 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: 2018 2017 Revenue Canada $ 70,358 $ 73,406 United States 1,577,029 1,448,532 $ 1,647,387 $ 1,521,938 Property, plant and equipment Canada $ 415,979 $ 453,323 United States 5,977,579 5,851,574 $ 6,393,558 $ 6,304,897 Intangible assets Canada $ 23,994 $ 27,624 United States 31,000 23,479 $ 54,994 $ 51,103 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, 2018
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 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. APUC believes that the claims are without merit, and intends to vigorously defend the action. 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. Mountain Water was the subject of a condemnation lawsuit filed by the city of Missoula. On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision that the city of Missoula could proceed with condemnation of Mountain Water’s assets. The fair market value of the condemned property as of May 6, 2014 was assessed by the Commissioners to be $88,600 . Upon taking possession of Mountain Water’s assets on June 22, 2017, the city of Missoula paid $83,863 to Mountain Water, net of closing adjustments and amounts required to be paid by the City directly to various developers in satisfaction of obligations under Funded By Other contracts relating to the assets. The condemnation of the Mountain Water assets resulted in a gain on long-lived assets of $4,370 . 21. 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, 2018 . APUC has outstanding purchase commitments for power purchases, gas delivery, service and supply, service agreements, capital project commitments and operating leases. 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) $ 46,536 $ 10,896 $ 11,114 $ 11,338 $ 11,566 $ 191,208 $ 282,658 Gas supply and service agreements (ii) 77,658 51,349 27,672 24,422 22,424 48,313 251,838 Service agreements 43,732 39,093 38,451 37,463 40,737 312,559 512,035 Capital projects 67,575 1,663 196 7,330 — — 76,764 Operating leases 7,629 7,154 7,096 7,076 6,776 178,583 214,314 Total $ 243,130 $ 110,155 $ 84,529 $ 87,629 $ 81,503 $ 730,663 $ 1,337,609 (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, 2018 . 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, 2018
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: 2018 2017 Accounts receivable $ 3,005 $ (45,818 ) Fuel and natural gas in storage 1,351 (4,385 ) Supplies and consumables inventory (7,189 ) (1,864 ) Income taxes recoverable (763 ) (557 ) Prepaid expenses 2,907 (2,755 ) Accounts payable (22,915 ) 7,525 Accrued liabilities 28,687 14,041 Current income tax liability 2,974 (3,190 ) Asset retirements and environmental obligations (7,293 ) (4,372 ) Net regulatory assets and liabilities (8,890 ) (46,344 ) $ (8,126 ) $ (87,719 )

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Financial instruments	nancial instruments (a) Fair value of financial instruments 2018 Carrying amount Fair value Level 1 Level 2 Level 3 Notes receivable $ 103,696 $ 110,019 $ — $ 110,019 $ — Investment in Atlantica 814,530 814,530 814,530 — — 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 regulated 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 swap 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 23. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2017 Carrying amount Fair value Level 1 Level 2 Level 3 Notes receivable $ 33,378 $ 38,192 $ — $ 38,192 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 63,363 63,363 — — 63,363 Energy contracts not designated as a cash flow hedge 109 109 — 109 — Commodity contracts for regulatory operations 74 74 — 74 — Total derivative instruments 63,546 63,546 — 183 63,363 Total financial assets $ 96,924 $ 101,738 $ — $ 38,375 $ 63,363 Long-term debt $ 3,079,551 $ 3,262,711 $ 651,969 $ 2,610,742 $ — Convertible debentures 971 1,018 1,018 — — Preferred shares, Series C 14,718 15,124 — 15,124 — Derivative instruments: Energy contracts designated as a cash flow hedge 77 77 — — 77 Energy contracts not designated as a cash flow hedge 31 31 — 31 — Cross-currency swap designated as a net investment hedge 57,412 57,412 — 57,412 — Interest rate swaps designated as a hedge 8,460 8,460 — 8,460 — Currency forward contract not designated as hedge 344 344 — 344 — Commodity contracts for regulated operations 2,620 2,620 — 2,620 — Total derivative instruments 68,944 68,944 — 68,867 77 Total financial liabilities $ 3,164,184 $ 3,347,797 $ 652,987 $ 2,694,733 $ 77 (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, 2018 and 2017 due to the short-term maturity of these instruments. Notes receivable fair values (level 2) have been 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. 23. 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 stock exchange 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. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $14.55 to $172.97 with a weighted average of $24.72 as of December 31, 2018 . 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. Significant increases (decreases) in any of these inputs in isolation would have resulted in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 23(b)(ii) and 23(b)(iv). Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision. (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: 2018 Financial contracts: Swaps 2,366,386 Options 300,000 Forward contracts 6,560,000 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(d)). 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. 23. Financial instruments (continued) (b) Derivative instruments (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: 2018 2017 Regulatory assets: Swap contracts $ 66 $ — Forward contracts $ — $ 6,319 Regulatory liabilities: Swap contracts $ 218 $ 287 Option contracts $ 134 $ 138 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) 871,391 December 2028 36.33 PJM Western HUB 2,438,697 December 2023 29.06 PJM NI HUB 2,997,939 December 2027 36.46 ERCOT North HUB Subsequent to year-end, the Company entered into a long-term energy derivative contract for the Minonk Wind Facility with a notional quantity of 251,581 MW-hours and a price of $20.72 per MW-hr. The contract expires December 2024. 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 the year, the Company amended and extended the forward-starting date of the interest rate swap to begin on March 29, 2019. As a result of the amendment, $898 of hedge ineffectiveness was recognized in earnings upon hedge dedesignation. The change in fair value since the hedge redesignation date is recorded in OCI. Subsequent to year end, 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(g)). In 2017, the Company settled forward contracts to purchase $250,000 10 -year U.S. Treasury bills at an interest rate of 1.8395% and $250,000 30 -year U.S. Treasury bills at an interest rate of 2.5539% designated as hedges to the interest rate risk related to $479,000 of senior unsecured notes. The effective portion of the hedge was recorded in OCI at the time and is reclassified to interest expense as the underlying hedged transactions are incurred. 23. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2018 2017 Effective portion of cash flow hedge $ 1,567 $ 8,004 Amortization of cash flow hedge (33 ) (27 ) Amounts reclassified from AOCI (4,224 ) (6,351 ) OCI attributable to shareholders of APUC $ (2,690 ) $ 1,626 The Company expects $6,289 and $989 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 loss of $37,204 for the year ended December 31, 2018 ( 2017 - gain of $17,817 ) 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 Liberty Power Group ’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $41,244 ( 2017 - gain of $ 19,063 ) was recorded in OCI in 2018 . (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. 23. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives (continued) The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligation, 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 currently hedges some of that risk (note 23(b)(ii)). 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, 2018 , a loss on foreign exchange gain of $1,115 ( 2017 - loss of $297 ) 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 and for the ineffective portion of gains and losses on derivatives that are accounted for 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: 2018 2017 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ 77 $ (79 ) Currency forward contract (1,230 ) 297 Commodity contracts — (2,885 ) Total change in unrealized gain on derivative financial instruments $ (1,153 ) $ (2,667 ) Realized loss (gain) on derivative financial instruments: Interest rate swaps — (144 ) Energy derivative contracts (73 ) 553 Currency forward contract 115 12,261 Total realized loss on derivative financial instruments $ 42 $ 12,670 Loss (gain) on derivative financial instruments not accounted for as hedges (1,111 ) 10,003 Ineffective portion of derivative financial instruments accounted for as hedges 632 637 $ (479 ) $ 10,640 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments 636 (1,918 ) Loss (gain) on foreign exchange (1,115 ) 12,558 $ (479 ) $ 10,640 23. 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 Liberty Power Group accounts receivable to be significant as over 84% 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 Liberty Utilities Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to the Liberty Utilities Group accounts receivable balances of $207,740 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 state regulators of the Liberty Utilities Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers. As of December 31, 2018 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2018 Canadian $ US $ Cash and cash equivalents and restricted cash $ 27,720 $ 45,452 Accounts receivable 13,562 241,068 Allowance for doubtful accounts — (5,281 ) Notes receivable 138,353 2,279 $ 179,635 $ 283,518 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, 2018 , in addition to cash on hand of $46,819 the Company had $1,046,826 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants which may limit amounts available to be drawn. 23. 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 $ 334,855 $ 420,797 $ 825,596 $ 1,740,471 $ 3,321,719 Convertible debentures — — — — 470 470 Advances in aid of construction 1,205 — — 62,498 63,703 Interest on long-term debt 156,768 269,942 221,528 928,736 1,576,974 Purchase obligations 325,326 — — — 325,326 Environmental obligation 4,158 30,140 2,885 21,998 59,181 Derivative financial instruments: Cross-currency swap 5,277 46,026 34,436 7,459 93,198 Interest rate swaps 8,473 — — — 8,473 Currency forward — — — — — Energy derivative and commodity contracts 588 526 57 — 1,171 Other obligations 33,350 — — 122,408 155,758 Total obligations $ 870,000 $ 767,431 $ 1,084,502 $ 2,884,040 $ 5,605,973

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2018
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, 2018
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(r)).
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. The determination of whether the definition of a business has been met for a development stage project depends on the concentration of assets, the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. 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 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 regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility 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 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
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(d)) 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. Cost 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. Investment tax credits and government 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. 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. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below Range of useful lives Weighted average useful lives 2018 2017 2018 2017 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 40 40 Equipment 5 - 43 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. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Liberty Utilities 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. Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management, together 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 asset 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 capital leases are initially recorded at cost determined as the present value of minimum lease payments. 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, dividend, equity and other income on the consolidated statements of operations.
Commonly owned facilities	Commonly owned facilities The Company 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 are 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 analysis 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 of 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 a VIE 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 interest, dividend, equity and other income 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. 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 acquired 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 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 pension and post-employment non-service costs in the consolidated statements of operations.
Asset retirement obligations	Asset retirement obligations The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. 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, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation.
Share-based compensation	Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; 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.
Noncontrolling interests	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. 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 Class A membership equity investors (“Class A partnership units” or “Class A 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 percentages ownership interests. In those situations, simply applying the percentage ownership interest to 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 Class A 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 Class A 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 Class A Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments. 1. Significant accounting policies (continued) (r) Non-controlling interests (continued) 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.
Recognition of revenue	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 are not completed at the date of initial application. Results for 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with the Company’s historical accounting under Topic 605. 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 20, Segmented information for details of revenue disaggregation by business units. Liberty Utilities Group revenue Liberty Utilities 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 is 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. The majority of Liberty Utilities Group's contracts have 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. The Company’s performance obligation is satisfied over time as electricity, natural gas or water is delivered. 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. 1. Significant accounting policies (continued) (s) Recognition of revenue (continued) Liberty Utilities Group revenue (continued) 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 20, 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. Liberty Power Group revenue Liberty Power 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. Progress towards satisfaction of the single performance obligation is measured using an output method based on units produced and delivered within the production month. 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. Progress towards satisfaction of the single performance obligation is measured using an output method based on time elapsed. Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses. The majority of Liberty Power Group 's contracts with customers are bundled arrangements of multiple performance obligations: electricity, capacity, and RECs. The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Liberty Power 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. Revenue is recorded net of sales taxes.
Foreign currency translation	Foreign currency translation APUC’s reporting currency is the U.S. dollar. Within these consolidated financial statements, we denote 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	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 our rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Other income tax credits are treated as a reduction to income tax expense in the year the credit arises or future periods to the extent that realization of such benefit is more likely than not. 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% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
Financial instruments and derivatives	Financial instruments and derivatives Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts. Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument. The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. 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 effective portion of the change in fair value is recognized in OCI. The ineffective portion is immediately recognized in earnings. 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. To the extent that the hedge is ineffective, such differences are recognized in earnings. 1. Significant accounting policies (continued) (v) Financial instruments and derivatives (continued) The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
Fair value measurements	Fair value measurements The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels: • Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. • Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.
Commitments and contingencies	Commitments and contingencies Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.
Use of estimates	Use of estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the measurement of deferred taxes and the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and, the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Recently adopted accounting pronouncements	Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans as part of the disclosure framework project. This update removed certain disclosure requirements regarding AOCI expected to be recognized in income, related party transactions, and certain sensitivity analyses with respect to health care cost trends. This update also added disclosure requirements around the weighted-average interest crediting rates for cash balance plans and explanations for significant gains or losses in the reporting period. The early adoption of this ASU did not have a significant impact on the Company's consolidated financial statements. The FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement as part of the disclosure framework project. This update removed certain disclosure requirements from Topic 820 including the amount of and reasons for transfers between Level 1 and Level 2 measurements, the policy for timing of transfers between levels, and the valuation processes for Level 3 measurements. This update also clarified disclosure requirements relating to measurement uncertainty, and added disclosure requirements for Level 3 measurements, specifically around the changes in unrealized gains and losses included in other comprehensive income and the range and weighted average of significant unobservable inputs. The early adoption of this ASU did not have a significant impact on the Company's consolidated financial statements. The FASB issued ASU 2018-09, Codification Improvements to clarify the Codification and correct unintended application of guidance that is not expected to have a significant impact on current accounting practice. The adoption of this ASU had no impact on the Company's consolidated financial statements. The FASB issued ASU 2018-03, Technical Corrections and Improvements to Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to clarify the Codification and to correct unintended application of the guidance. The Company adopted this pronouncement concurrently with the adoption of ASU 2016-01. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("AOCI") to allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company early adopted this pronouncement as of January 1, 2018, and as a result, a net amount of $10,625 was reclassified out of AOCI and recorded as an increase to accumulated deficit as at that date. The FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting , to provide clarity and reduce both diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation , to a change to the terms or conditions of a share-based payment award. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost , to improve the reporting of defined benefit pension cost and post-retirement benefit cost ("net benefit cost") in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update also only allows the service cost component to be eligible for capitalization when applicable. The Company adopted this guidance effective January 1, 2018. The Company's regulated operations only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences exist. The Company applied the practical expedient for retrospective application on the consolidated statements of operations (note 10). 2. Recently issued accounting pronouncements (continued) (a) Recently adopted accounting pronouncements (continued) The FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Non-financial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . The update clarifies the scope of the standard and provides additional guidance on partial sales of non-financial assets. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business . The update is intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company follows the pronouncements of this update as of January 1, 2018. The FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash to eliminate current diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. Prior to the adoption of this update, the Company presented changes in restricted cash as investing activities on the consolidated statement of cash flows. The FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory . The new standard requires the recognition of current and deferred income taxes for an intra-entity transfer of an asset other than inventory. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments in order to eliminate current diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this update had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The adoption of this update had no significant impact on the Company's consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2018-19: Codification Improvements to Topic 326, Financial Instruments — Credit Losses as part of its project to correct unintended application of accounting standards. The amendments clarify that receivables arising from operating leases are not within the scope of ASC 326-20. Instead, impairment of receivables arising from operating leases should be accounted for in accordance with Topic 842, Leases . The amendments in this Update are effective the same date as Update 2016-13, which is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company is currently assessing the impact of this Update. 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. Early adoption is permitted. The Company is currently assessing the impact 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. Early adoption is permitted. 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 2018-16, 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. The amendments in this Update are required to be adopted concurrently with the amendments in Update 2017-12, which is required for all fiscal years beginning after December 15, 2018. The amendments will be adopted prospectively for qualifying new or redesignated hedging relationships entered into after the date of adoption. The FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40 ): Customers 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. Therefore, an entity will follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. In addition, the capitalized implementation costs are required to be expensed over the term of the hosting arrangement. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted in any interim period. The amendments can either be applied retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently assessing the impacts of this update. 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 update is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. No impact on the consolidated financial statements is expected from the adoption of this update. 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 update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company does not expect a significant impact on the 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 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 GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. Early adoption for fiscal years and interim periods beginning after December 15, 2018 is permitted. The Company is currently in the process of evaluating 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. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) 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 issued an amendment to ASC Topic 842 that permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The FASB issued a further update to ASC Topic 842 in ASU 2018-11 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The FASB has also issued further codification and narrow-scope improvements to ASC Topic 842 to correct and clarify specific aspects of the guidance. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. The Company is in the process of finalizing its assessment of the financial, operational, and business processes impacts of the new lease accounting standard. At this point, the Company expects that the adoption of Topic 842 will not have a material impact on the consolidated financial statements. The Company intends to implement new processes and procedures for the identification, analysis, and measurement of new lease contracts on a prospective basis. A new software solution is being implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company intends to elect 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 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 will make 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). The Company intends to adopt the lease accounting standard retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment.

Significant accounting polici_3

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Capitalization of Interest	The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 2018 2017 Interest capitalized on non-regulated property $ 1,434 $ 4,325 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,684 1,297 Allowance for equity funds 2,728 2,335 Total $ 5,846 $ 7,957
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 2018 2017 2018 2017 Generation 3 - 60 3 - 60 33 33 Distribution 5 - 100 5 - 100 40 40 Equipment 5 - 43 5 - 43 10 10

Business acquisitions and dev_2

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 152 Property, plant and equipment 110,857 Asset retirement obligation (546 ) Non-controlling interest (tax equity) (38,633 ) Total net assets acquired $ 71,830 Working capital $ 41,292 Property, plant and equipment 2,058,867 Goodwill 752,418 Regulatory assets 236,933 Other assets 43,609 Long-term debt (907,547 ) Regulatory liabilities (145,594 ) Pension and other post-employment benefits (78,204 ) Deferred income taxes liability, net (418,855 ) Other liabilities (76,532 ) Total net assets acquired $ 1,506,387 Cash and cash equivalents 1,742 Total net assets acquired, net of cash and cash equivalents $ 1,504,645 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ (10,808 ) Property, plant and equipment 328,371 Construction loan (261,952 ) Asset retirement obligation (2,092 ) Deferred revenue (1,156 ) Deferred tax liability (1,470 ) Net assets acquired $ 50,893 Cash and cash equivalents $ 3,107 Net assets acquired, net of cash and cash equivalents $ 47,786

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment consist of the following: 2018 Cost Accumulated depreciation Net book value Generation $ 2,470,279 $ 450,230 $ 2,020,049 Distribution 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 212,579 — 212,579 $ 7,406,319 $ 1,012,761 $ 6,393,558 5. Property, plant and equipment (continued) 2017 Cost Accumulated Net book Generation $ 2,382,279 $ 394,509 $ 1,987,770 Distribution 4,205,823 388,859 3,816,964 Land 71,689 — 71,689 Equipment and other 91,233 37,104 54,129 Construction in progress Generation 209,979 — 209,979 Distribution 164,366 — 164,366 $ 7,125,369 $ 820,472 $ 6,304,897

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible assets consist of the following: 2018 Cost Accumulated amortization Net book value 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 2017 Cost Accumulated Net book Power sales contracts $ 56,540 $ 36,878 $ 19,662 Customer relationships 26,799 8,836 17,963 Interconnection agreements 14,181 — 703 13,478 $ 97,520 $ 46,417 $ 51,103
Goodwill	Changes in goodwill are as follows: Balance, January 1, 2017 $ 228,377 Business acquisitions 752,418 Divestiture of operating entity (note 21(a)) (26,513 ) Balance, December 31, 2018 and 2017 $ 954,282

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2018
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 $'000 Effective Date Empire Electric System Missouri Tax Reform docket $(17,837) Prospective decrease in annual revenue effective August 30, 2018 due to the reduction of the U.S. federal corporate income tax rate. EnergyNorth Gas System New Hampshire General Rate Review $10,711 Effective May 1, 2018. The regulator also approved a one-time recoupment of $1,326 for the difference between the final rates and temporary rates granted on July 1, 2017. In November 2018, EnergyNorth received an order for rehearing clarifying the implementation of the decoupling mechanism that was approved and resolving the impacts of tax reform through the rehearing. The net result was a one-time decrease to the recoupment of $280. Missouri Gas System Missouri General Rate Review $4,600 Effective July 1, 2018 Peach State Gas System Georgia GRAM $2,367 Effective February 1, 2019 New England Natural Gas System Massachusetts Gas System Enhancement Plan $3,676 Effective May 1, 2018 New England Gas System Massachusetts GRC $8,300 $7,800 effective March 1, 2016 $500 effective March 1, 2017 Calpeco Electric System California Post-Test Year Adjustment Mechanism $2,175 January 1, 2018 Midstates Gas System Illinois GRC $2,200 June 7, 2017 Various Various Various $3,048 Other rate reviews closed: Missouri Water ($1,015), and Litchfield Park Water & Sewer ($617), Park Water 2018 increase ($1,531), Georgia 2018 Gas Rate Adjustment Mechanism (-$115) 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2018 2017 Regulatory assets Environmental remediation (a) $ 82,295 $ 82,711 Pension and post-employment benefits (b) 125,959 105,712 Debt premium (c) 48,847 57,406 Fuel and commodity costs adjustments (d) 26,310 34,525 Rate adjustment mechanism (e) 36,484 35,813 Clean Energy and other customer programs (f) 22,269 20,582 Deferred construction costs (g) 13,986 14,344 Asset retirement (h) 21,048 16,080 Income taxes (i) 34,822 36,546 Rate review costs (j) 7,990 9,295 Other 30,464 28,512 Total regulatory assets $ 450,474 $ 441,526 Less: current regulatory assets (59,037 ) (66,567 ) Non-current regulatory assets $ 391,437 $ 374,959 Regulatory liabilities Income taxes (i) $ 323,384 $ 321,138 Cost of removal (k) 193,564 184,188 Rate base offset (l) 10,900 13,214 Fuel and commodity costs adjustments (d) 23,517 23,543 Deferred compensation received in relation to lost production (m) 6,897 9,398 Deferred construction costs - fuel related (g) 7,258 7,418 Pension and post-employment benefits (b) 877 10,082 Other 12,195 7,143 Total regulatory liabilities $ 578,592 $ 576,124 Less: current regulatory liabilities (39,005 ) (37,687 ) Non-current regulatory liabilities $ 539,587 $ 538,437 (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'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 differs from those adopted and recovery or refunds are expected to occur in future periods. 7. Regulatory matters (continued) (c) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (d) Fuel and commodity costs adjustments The revenue from the utilities includes a component which 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 not recorded on the consolidated statements of operations but rather 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 23(b)(i)) are recoverable through the commodity costs adjustment. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, EnergyNorth Natural Gas System, and Granite State Electric System are subject to a revenue decoupling mechanism approved by their respective regulator which require 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. (f) 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. (g) Deferred construction costs Deferred construction costs reflect deferred construction costs and fuel related costs of specific generating facilities of Empire. These amounts are being recovered over the life of the plants. (h) Asset retirement The costs of retirement of assets are expected to be recovered through rates as well as the on-going liability accretion and asset depreciation expense. (i) 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 was recorded for excess deferred taxes probable of being refunded to customers of $15,586 . The Tax Cuts and Jobs Act (the “Tax Act”) was enacted on December 22, 2017. Among other provisions, the Act reduces the corporate income tax rate from 35% to 21%. A reduction of regulatory asset and an increase to regulatory liability was recorded in 2017 for excess deferred taxes probable of being refunded to customers of $327,947 . 7. Regulatory matters (continued) (i) Income taxes (continued) As a result of the Tax Act enacted in 2017, regulators in the states where Liberty Utilities Group operates are contemplating the ratemaking implications of the reduction of federal tax rates from the legacy 35% tax rate and the new 21% federal statutory income tax rate effective January 2018. The Company is working with the regulators to identify the most appropriate way in each jurisdiction to address the impact of the Tax Act on cost of service based rates. As at December 31, 2018, the impact on regulated liability on account of ordered or probable orders related to the Tax Act was immaterial. (j) 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. (k) Cost of removal The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant. (l) 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. (m) Deferred compensation received in relation to lost production The regulatory liability for deferred compensation received from lost production represents Empire's refund from Southwest Power Administration for lost revenues at one of its generating facilities. These costs are being amortized over the period approved by state regulators.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term Investments	Long-term investments consist of the following: 2018 2017 Long-term investment in Atlantica carried at fair value (a) $ 814,530 $ — Notes receivable from equity investees (e) $ 101,416 $ 30,060 Other long-term investments Equity-method investees AAGES (b) 2,622 — Red Lily I Wind Facility (c) 15,705 18,174 Amherst Island Wind Project (d) 7,655 8,921 Other 4,510 5,172 $ 30,492 $ 32,267 Other investments 3,870 5,004 Other long-term investments 34,362 37,271 Less: current portion (1,407 ) — $ 32,955 $ 37,271 Dividend income of $41,079 (2017 - $1,167 ) and equity loss of $1,609 (2017 - income $2,742 ) are included in Interest, dividend, equity and other income on the consolidated statements of operations. 8. Long-term investments (continued) (a) Investment in Atlantica On March 9, 2018, APUC purchased from Abengoa S.A. (“Abengoa”) a 25% equity interest in Atlantica for a purchase price of $607,567 , based on a price of $24.25 per ordinary share of Atlantica plus a contingent payment of up to $0.60 per-share payable two years after closing, subject to certain conditions. On November 27, 2018, APUC purchased from Abengoa an additional 16.5% equity interest in Atlantica for a purchase price of $345,000 , based on a price of $20.90 per ordinary share of Atlantica comprised of a payment of approximately $305,000 drawn from the Company's credit facility for payment on closing and a holdback of $40,000 payable at a later date, subject to certain conditions. The Company transferred the Atlantica shares to AAGES (AY Holdings) B.V. (“AY Holdings”), a new entity controlled and consolidated by APUC. 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. The difference between the purchase price and the value of the Atlantica shares based on the NASDAQ share price on the acquisition dates resulted in a combined immediate fair value loss of $139,864 . A fair value gain of $1,907 was recorded for the period from acquisition to December 31, 2018 resulting in a net loss on fair value for the year of $137,957 . The Company also recorded dividend income of $ $39,263 from the Atlantica shares during the period from acquisition to December 31, 2018. On November 28, 2018, Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”) obtained a three year secured credit facility in the amount of $306,500 and subscribed to a 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 drawn under the credit facility. 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. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest (note 17). (b) Investment in AAGES APUC and Abengoa created AAGES B.V., AAGES Development Canada Inc. and AAGES Development Spain (collectively, the “AAGES entities”) to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Each partner initially contributed $5,000 to the AAGES entities. AAGES Development Canada Inc. and AAGES Development Spain are considered a VIE due to the level of equity at risk. The Company is not considered the primary beneficiary of AAGES Development Canada Inc. and AAGES Development Spain as the two partners have joint control and all decisions must be unanimous. As such, the Company is accounting for its investment in the joint ventures under the equity method. The AAGES entities contributed equity loss of $3,005 to the Company's consolidated financial results for the year ended December 31, 2018. As of December 31, 2018, the Company’s maximum exposure to loss of $7,509 related to AAGES Development Canada Inc. and AAGES Development Spain is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(e). (c) Red Lily I Wind Facility The Red Lily I Wind Facility (the “Partnership”) is a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company owns a 75% equity interest in the Partnership. Due to certain participating rights being held by the minority investor, the decisions which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, APUC is deemed, under U.S. GAAP, to not have control over the Partnership. As APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility, the Company accounts for the Partnership using the equity method. The Red Lily I Wind Facility contributed equity income of $1,637 (2017 - $2,139 ) to the Company's consolidated financial results for the year ended December 31, 2018. 8. Long-term investments (continued) (d) Amherst Island Wind Project APUC has a 50% interest in Windlectric Inc. (“Windlectric”) which owns a 74.1 MW wind generating facility (“Amherst Island Wind Facility”) in the Province of Ontario. Construction was completed during the second quarter of 2018 and sale of power under the power purchase agreement has started. Subsequent to year-end, the Company exercised its option to acquire the remaining common shares at a fixed price. The acquisition is subject to regulatory approval expected to be obtained in 2019. Windlectric is considered a VIE due to the level of equity at risk. The Company is not considered the primary beneficiary of Windlectric as the two shareholders have joint control and all decisions must be unanimous. As such, the Company accounts for its investment in the joint venture under the equity method. The interest capitalized during the year ended December 31, 2018 to the investment while the Amherst Island Wind Facility was under construction amounts to $739 (2017 - $1,115 ). As at December 31, 2018, the net book value of property, plant and equipment of the joint venture was $308,825 while the third-party construction debt was $190,910 (2017 - $106,628 ). Windlectric contributed equity loss of $1,714 (2017 - nil) to the Company's consolidated financial results for the year ended December 31, 2018. As of December 31, 2018, the Company’s maximum exposure to loss of $192,052 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(e). Subsequent to year-end, the joint venture borrowed from the Company to repay in full the third-party construction debt. (e) Development loans receivable from equity investees The Company entered into 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, or guarantees) in amounts necessary for the continued development and construction of the equity investees' wind projects. As at December 31, 2018 , the Company has a loan and credit support facility with Windlectric of $96,477 (2017 - $ 30,060 ). The loan to Windlectric bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2019. The letters of credit are charged an annual fee of 2% on their stated amount. As of December 31, 2018, the following credit support was outstanding on behalf of Windlectric: letters of credit and guarantees of obligations to the utilities under the power purchase agreement; a guarantee of the obligations under the wind turbine, transmission line, transformer, and other supply agreements; and, a guarantee of the obligations under the engineering, procurement, and construction management agreements. The value of the guarantee obligations is recognized under other long-term liabilities and as at December 31, 2018 is valued at $1,637 (2017 - $1,952 ) using a probability weighted discounted cash flow (level 3). The Company recognized interest income of $6,144 on the advances and credit support from the day Amherst Island Wind Facility achieved commercial operations to December 31, 2018 . As at December 31, 2018 , the Company has a balance receivable from the AAGES entities of $4,940 . As at December 31, 2018, the Company has issued $3,750 in letters of credit on behalf of AAGES. Subsequent to year-end, $1,750 was repaid under this credit support facility. Following acquisition of control of Deerfield SponsorCo (note 8(f)(ii)), amounts advanced to the wind facility are eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in OCI from the date of acquisition. 8. Long-term investments (continued) (f) Other transactions i. Wataynikaneyap Power Transmission Project Subsequent to year-end, APUC acquired a 9.8% ownership interest in the Wataynikaneyap Power Transmission Project, a transmission project that involves the development, construction and operation of a 1,800 km transmission line in Northwestern Ontario. ii. Deerfield Wind Facility The Company had a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 149 MW construction-stage wind development project (“Deerfield Wind Project”) in the State of Michigan. On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo and obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting which requires that the fair value of assets acquired and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(e)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of $nil was recorded on acquisition. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ (10,808 ) Property, plant and equipment 328,371 Construction loan (261,952 ) Asset retirement obligation (2,092 ) Deferred revenue (1,156 ) Deferred tax liability (1,470 ) Net assets acquired $ 50,893 Cash and cash equivalents $ 3,107 Net assets acquired, net of cash and cash equivalents $ 47,786
Allocation of Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 152 Property, plant and equipment 110,857 Asset retirement obligation (546 ) Non-controlling interest (tax equity) (38,633 ) Total net assets acquired $ 71,830 Working capital $ 41,292 Property, plant and equipment 2,058,867 Goodwill 752,418 Regulatory assets 236,933 Other assets 43,609 Long-term debt (907,547 ) Regulatory liabilities (145,594 ) Pension and other post-employment benefits (78,204 ) Deferred income taxes liability, net (418,855 ) Other liabilities (76,532 ) Total net assets acquired $ 1,506,387 Cash and cash equivalents 1,742 Total net assets acquired, net of cash and cash equivalents $ 1,504,645 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ (10,808 ) Property, plant and equipment 328,371 Construction loan (261,952 ) Asset retirement obligation (2,092 ) Deferred revenue (1,156 ) Deferred tax liability (1,470 ) Net assets acquired $ 50,893 Cash and cash equivalents $ 3,107 Net assets acquired, net of cash and cash equivalents $ 47,786

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long Term Debt	. Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2018 2017 Senior unsecured revolving credit facilities (a) — 2019-2023 N/A $ 97,000 $ 51,827 Senior unsecured bank credit facilities (b) — 2019 N/A 321,807 134,988 Commercial paper (a) — 2023 N/A 6,000 5,576 U.S. dollar borrowings Senior unsecured notes (c) 4.09 % 2020-2047 $ 1,225,000 1,218,680 1,217,797 Senior unsecured utility notes (d) 5.99 % 2020-2035 $ 222,000 240,161 246,560 Senior secured utility bonds (e) 4.75 % 2020-2044 $ 662,500 676,697 772,871 Subordinated unsecured notes (f) 6.88 % 2078 $ 287,500 278,771 — Canadian dollar borrowings Senior unsecured notes (g) 4.43 % 2020-2027 C$ 650,669 474,764 623,223 Senior secured project notes 10.25 % 2020-2027 C$ 31,310 22,915 26,709 $ 3,336,795 $ 3,079,551 Less: current portion (13,048 ) (12,364 ) $ 3,323,747 $ 3,067,187 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. Short-term obligations of $321,807 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. Recent financing activities: (a) Senior unsecured revolving credit facilities On September 20, 2017, the Company amended the terms of its C $65,000 senior unsecured revolving bank credit facility to increase the commitments to C $165,000 and, on November 16, 2018, the Company extended the maturity from November 19, 2018 to November 19, 2019. On February 23, 2018, the Liberty Utilities Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023. Concurrent with this amendment, the Liberty Utilities Group closed Empire's credit facility. Liberty Utilities' credit facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire. On October 6, 2017, the Liberty Power Group amended the terms of its C $350,000 senior unsecured revolving bank credit facility to increase the commitments to $500,000 and extended the maturity from July 31, 2019 to October 6, 2022. The Liberty Power 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 Liberty Power Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 2021. 9. Long-term debt (continued) (b) Senior unsecured bank credit facilities On December 21, 2017, the Company entered into a $600,000 term credit facility with two Canadian banks maturing on December 21, 2018. On March 7, 2018, the Company drew $600,000 under this facility. On December 19, 2018, the Company extended the maturity of this facility to June 21, 2019. The balance drawn as at December 31, 2018 is $186,807 . On December 30, 2016, in connection with the acquisition of Empire (note 3(e)), the Company drew $1,336,440 from its Acquisition Facility. Following receipt of the Final Instalment from the convertible debentures on February 7, 2017 (note 12(h)) and the senior notes financing on March 24, 2017 (note 9(d)), the Company fully repaid the Acquisition Facility. As at December 31, 2018, the Company had drawn $135,000 on its Corporate Term Credit Facility which matures on July 5, 2019. (c) Senior unsecured notes On March 24, 2017, the Liberty Utilities Group 's debt financing entity issued $750,000 senior unsecured notes in six tranches. The proceeds were applied to repay the Acquisition Facility (note 9(b)) and other existing indebtedness. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0% . In anticipation of this financing, the Liberty Utilities Group had entered into forward contracts to lock in the underlying U.S. Treasury interest rates. Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group will be approximately 3.6% . (d) Senior unsecured utility notes On January 1, 2017, in connection with the acquisition of Empire (note 3(e)), the Company assumed $102,000 in unsecured utility notes. The notes consist of two tranches, with maturities in 2033 and 2035 with coupons at 6.7% and 5.8% . (e) Senior secured utility bonds On January 1, 2017 in connection with the acquisition of Empire (note 3(e)), the Company assumed $733,000 in secured utility bonds. The bonds are secured by a first mortgage indenture and consist of ten tranches with maturities ranging between 2018 and 2044 with coupons ranging from 3.58% to 6.82% . On June 1, 2018, the Company repaid, upon its maturity, a $90,000 secured utility note. In June 2017, outstanding bonds payable for the Park Water Systems in the amount of $63,000 were repaid using proceeds from the Mountain Water condemnation discussed in note 21(a). (f) Subordinated unsecured notes 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. The subordinated notes are listed on the New York Stock Exchange ("NYSE") under the ticker symbol "AQNA". 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 rest 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. 9. Long-term debt (continued) (f) Canadian dollar senior unsecured notes Subsequent to year-end, the Liberty Power 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 Liberty Power Group unwound and settled the related forward-starting interest rate swap on a notional bond of C $135,000 (note 23(b)(ii)). On July 25, 2018, the Company repaid, upon its maturity, a C $135,000 unsecured note. On January 17, 2017, the Liberty Power Group issued C $300,000 senior unsecured notes bearing interest at 4.09% with a maturity date of February 17, 2027. The notes were sold at a price of C$99.929 per C$100.00 principal amount.
Principal Payments	Principal payments due in the next five years and thereafter are as follows: 2019 2020 2021 2022 2023 Thereafter Total $ 334,855 $ 308,917 $ 111,880 $ 343,737 $ 481,859 $ 1,740,471 $ 3,321,719 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: 2019 $ 940 2020 985 2021 1,000 2022 1,019 2023 1,183 Thereafter to 2031 10,370 Redemption amount 3,914 19,411 Less: amounts representing interest (5,993 ) 13,418 Less current portion (940 ) $ 12,478

Pension and other post-retire_2

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2018 2017 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 523,743 $ 247,246 $ 176,975 $ 61,888 Projected benefit obligation assumed from business combination — 256,486 — 97,761 Service cost 15,481 14,747 5,791 4,838 Interest cost 18,717 20,191 6,727 6,642 Actuarial (gain) loss (29,845 ) 35,696 (14,800 ) 10,263 Contributions from retirees — — 1,920 1,821 Gain on curtailment (1,875 ) (849 ) — (4 ) Benefits paid (49,429 ) (49,774 ) (8,288 ) (6,234 ) Projected benefit obligation, end of year $ 476,792 $ 523,743 $ 168,325 $ 176,975 Change in plan assets Fair value of plan assets, beginning of year 403,945 176,040 130,487 21,701 Plan assets acquired in business combination — 184,510 — 91,532 Actual return on plan assets (36,987 ) 63,250 (10,603 ) 19,733 Employer contributions 21,570 29,919 2,068 2,068 Benefits paid (49,429 ) (49,774 ) (6,410 ) (4,547 ) Fair value of plan assets, end of year $ 339,099 $ 403,945 $ 115,542 $ 130,487 Unfunded status $ (137,693 ) $ (119,798 ) $ (52,783 ) $ (46,488 ) Amounts recognized in the consolidated balance sheets consists of: Non-current assets — — 3,161 3,936 Current liabilities (872 ) (861 ) (850 ) (1,172 ) Non-current liabilities (136,821 ) (118,937 ) (55,094 ) (49,252 ) Net amount recognized $ (137,693 ) $ (119,798 ) $ (52,783 ) $ (46,488 ) Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets: Pension OPEB 2018 2017 2018 2017 Accumulated benefit obligation 439,458 462,943 163,375 171,175 Fair value of plan assets 339,099 376,276 107,430 121,561 Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets: Pension OPEB 2018 2017 2018 2017 Projected benefit obligation 476,791 523,743 163,375 171,175 Fair value of plan assets 339,099 403,945 107,430 121,561
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, 2017 $ 27,572 $ (5,617 ) $ (3,861 ) $ (732 ) Additions to AOCI (2,652 ) — (3,066 ) — Reclassification to regulatory accounts (note 7(b)) 1,136 — 3,515 — Amortization in current period (928 ) 622 230 262 Balance, December 31, 2017 $ 25,128 $ (4,995 ) $ (3,182 ) $ (470 ) Additions to AOCI 34,916 (1,875 ) 3,254 — Reclassification to regulatory accounts (note 7(b)) (22,166 ) — (14,232 ) — Amortization in current period (1,074 ) 649 272 262 Gain (loss) on plan settlements (2,547 ) — — — Balance, December 31, 2018 $ 34,257 $ (6,221 ) $ (13,888 ) $ (208 )
Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2018 and 2017 were as follows: Pension benefits OPEB 2018 2017 2018 2017 Discount rate 4.19 % 3.43 % 4.26 % 3.60 % Interest crediting rate (for cash balance plans) 4.43 % 4.50 % N/A N/A 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
Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR)	Weighted average assumptions used to determine net benefit cost for 2018 and 2017 were as follows: Pension benefits OPEB 2018 2017 2018 2017 Discount rate 3.57 % 4.01 % 3.60 % 4.12 % Expected return on assets 7.13 % 7.01 % 6.52 % 3.88 % Rate of compensation increase 3.00 % 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 2024 2023
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses	Pension benefits OPEB 2018 2017 2018 2017 Service cost $ 15,481 $ 14,747 $ 5,791 $ 4,838 Non-service costs Interest cost 18,717 20,191 6,727 6,642 Expected return on plan assets (27,820 ) (24,842 ) (7,451 ) (6,404 ) Amortization of net actuarial loss (gain) 1,119 1,140 (272 ) (230 ) Amortization of prior service credits (649 ) (622 ) (262 ) (262 ) Amortization of regulatory assets/liability 9,823 13,031 3,982 391 Net benefit cost $ 16,671 $ 23,645 $ 8,515 $ 4,975
Target Asset Allocation	The Company’s target asset allocation is as follows: Asset Class Target (%) Range (%) Equity securities 69 % 49% - 78% Debt securities 31 % 22% - 51% 100 % The fair values of investments as of December 31, 2018 , by asset category, are as follows: Asset Class Level 1 Percentage Equity securities $ 338,946 75 % Debt securities 115,695 25 % Other — — % $ 454,641 100 %
Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2019 2020 2021 2022 2023 2024 — 2028 Pension plan $ 31,101 $ 29,366 $ 32,508 $ 33,415 $ 35,111 $ 183,338 OPEB 6,077 6,686 7,172 7,731 8,241 47,119

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other Assets	Other assets consist of the following: 2018 2017 Income tax recoverable $ 1,961 $ 5,967 Deferred financing costs 4,449 3,546 Restricted cash 18,954 15,939 Other 9,335 10,811 34,699 36,263 Less: current portion (6,115 ) (7,110 ) $ 28,584 $ 29,153

Other long-term liabilities and

Other long-term liabilities and deferred credits (Tables)	12 Months Ended
	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Other Long Term Liabilities	Other long-term liabilities consist of the following: 2018 2017 Advances in aid of construction (a) $ 63,703 $ 62,683 Environmental remediation obligation (b) 55,621 54,322 Asset retirement obligations (c) 43,291 44,166 Customer deposits (d) 29,974 28,529 Unamortized investment tax credits (e) 17,491 17,839 Deferred credits (f) 42,711 21,168 Preferred shares, Series C (g) 13,418 14,718 Other (h) 39,710 45,434 305,919 288,859 Less: current portion (42,337 ) (46,754 ) $ 263,582 $ 242,105 (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 2018, $3,687 (2017 - $10,498 ) was transferred from advances in aid of construction to contributions in aid of construction. 12. Other long-term liabilities (continued) (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. The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $59,181 (2017 - $57,292 ) which at discount rates ranging from 2.5% to 2.8% represents the recorded accrual of $55,621 as of December 31, 2018 (2017 - $54,322 ). Approximately $36,611 is expected to be incurred over the next four years with the balance of cash flows to be incurred over the following 27 years. Changes in the environmental remediation obligation are as follows: 2018 2017 Opening balance $ 54,322 $ 47,202 Remediation activities (2,163 ) (1,561 ) Accretion 1,479 1,114 Changes in cash flow estimates 4,051 1,645 Revision in assumptions (2,068 ) 5,922 Closing balance $ 55,621 $ 54,322 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, 2018, the Company has reflected a regulatory asset of $82,295 (2017 - $82,711 ) 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) disposal 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: 2018 2017 Opening Balance $ 44,166 $ 18,486 Obligation assumed from business acquisition and constructed projects 225 28,267 Retirement activities (5,130 ) (2,811 ) Accretion 1,974 1,981 Change in cash flow estimates 2,056 (1,757 ) Closing Balance $ 43,291 $ 44,166 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(h)). (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. 12. Other long-term liabilities (continued) (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. (f) Deferred credits During the year, the Company settled $16,000 of contingent consideration related to prior acquisitions resulting in a gain of approximately $12,000 which was recorded as a reduction of acquisition costs on the consolidated statements of operations. (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 (fifty-three thousand and four hundred dollars 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: 2019 $ 940 2020 985 2021 1,000 2022 1,019 2023 1,183 Thereafter to 2031 10,370 Redemption amount 3,914 19,411 Less: amounts representing interest (5,993 ) 13,418 Less current portion (940 ) $ 12,478 (h) Other Convertible debentures As at December 31, 2018, the carrying value of the convertible debentures was $470 (2017 - $971 ). On March 1, 2016, the Company completed the sale of C$1,150,000 aggregate principal amount of 5.0% convertible debentures. The proceeds received from the initial instalment in 2016 and the final instalment in 2017, net of financing costs were $266,889 and $571,642 , respectively. The convertible debentures mature on March 31, 2026 and bore interest at an annual rate of 5% per C$1,000 principal amount of convertible debentures until and including the Final Instalment Date, after which the interest rate is 0% . The interest expense recorded for the year ended December 31, 2018 is $ nil ( 2017 - $ 7,193 ). 12. Other long-term liabilities (continued) (h) Other (continued) Convertible debentures (continued) The debentures are convertible into up to 108,490,566 common shares. During the year ended December 31, 2018 $447 (2017 - $855,691 ) of principal converted to 56,926 (2017 - 108,370,081 ) common shares of the Company (note 13), representing conversion into common shares of 99.9% of the convertible debentures as at December 31, 2018 .
Changes in Environmental Remediation Obligation	Changes in the environmental remediation obligation are as follows: 2018 2017 Opening balance $ 54,322 $ 47,202 Remediation activities (2,163 ) (1,561 ) Accretion 1,479 1,114 Changes in cash flow estimates 4,051 1,645 Revision in assumptions (2,068 ) 5,922 Closing balance $ 55,621 $ 54,322
Schedule of Asset Retirement Obligations	Changes in the asset retirement obligations are as follows: 2018 2017 Opening Balance $ 44,166 $ 18,486 Obligation assumed from business acquisition and constructed projects 225 28,267 Retirement activities (5,130 ) (2,811 ) Accretion 1,974 1,981 Change in cash flow estimates 2,056 (1,757 ) Closing Balance $ 43,291 $ 44,166
Principal Payments	Principal payments due in the next five years and thereafter are as follows: 2019 2020 2021 2022 2023 Thereafter Total $ 334,855 $ 308,917 $ 111,880 $ 343,737 $ 481,859 $ 1,740,471 $ 3,321,719 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: 2019 $ 940 2020 985 2021 1,000 2022 1,019 2023 1,183 Thereafter to 2031 10,370 Redemption amount 3,914 19,411 Less: amounts representing interest (5,993 ) 13,418 Less current portion (940 ) $ 12,478

Shareholders' capital (Tables)

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Number of Common Shares	Number of common shares 2018 2017 Common shares, beginning of year 431,765,935 274,087,018 Public offering (a)(i) 50,041,624 43,470,000 Conversion of convertible debentures (note 12(h)) 56,926 108,370,081 Dividend reinvestment plan (a)(ii) 5,880,843 3,905,848 Exercise of share-based awards (c) 1,106,105 1,932,988 Common shares, end of year 488,851,433 431,765,935
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, 2018 and 2017 : 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, 2018 , APUC recorded $9,458 (2017 - $8,361 ) in total share-based compensation expense detailed as follows: 2018 2017 Share options $ 2,054 $ 3,070 Director deferred share units 714 593 Employee share purchase 312 436 Performance and restricted share units 6,378 4,262 Total share-based compensation $ 9,458 $ 8,361
Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2018 2017 Risk-free interest rate 2.1 % 1.4 % Expected volatility 21 % 25 % Expected dividend yield 4.8 % 4.3 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option C$ 1.41 C$ 1.45
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, 2017 6,045,014 C$ 9.64 6.27 C$ 10,595 Granted 2,328,343 12.82 8.00 — Exercised (1,634,501 ) 7.81 3.76 7,696 Balance, December 31, 2017 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 Exercisable, December 31, 2018 3,198,175 C$ 10.44 4.93 C$ 10,501
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, 2017 578,988 C$ 9.82 1.74 C$ 6,595 Granted, including dividends 811,974 13.54 2.00 — Exercised (374,973 ) 8.33 — 4,394 Forfeited (60,961 ) 12.61 — — Balance, December 31, 2017 955,028 C$ 12.30 1.84 C$ 13,428 Granted, including dividends 791,524 12.41 2.00 — 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 Exercisable, December 31, 2018 173,533 C$ 11.66 — C$ 2,383 (v) Bonus deferral RSUs During the year, 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) (iv) 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$ — $ — Granted, including dividends 131,611 12.82 — Exercised (4,545 ) 12.82 61 Balance and exercisable, December 31, 2018 127,066 C$ 12.82 C$ 1,745

Accumulated other comprehensi_2

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2018
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 Net change on available-for-sale investments Pension and post-employment actuarial changes Total Balance, January 1, 2017 $ (25,921 ) $ 53,740 $ 65 $ (10,833 ) $ 17,051 OCI (loss) before reclassifications (21,780 ) 8,004 — 600 (13,176 ) Amounts reclassified — (6,378 ) (65 ) (224 ) (6,667 ) Net current period OCI (21,780 ) 1,626 (65 ) 376 (19,843 ) Balance, December 31, 2017 $ (47,701 ) $ 55,366 $ — $ (10,457 ) $ (2,792 ) Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a)) — 11,657 — (1,032 ) 10,625 OCI before reclassifications (26,488 ) 1,567 — 2,046 (22,875 ) Amounts reclassified — (4,257 ) — — (86 ) (4,343 ) Net current period OCI $ (26,488 ) $ (2,690 ) $ — $ 1,960 $ (27,218 ) Balance, December 31, 2018 $ (74,189 ) $ 64,333 $ — $ (9,529 ) $ (19,385 )

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Cash Dividends [Abstract]
Dividends	Dividends declared during the year were as follows: 2018 2017 Dividend Dividend per share Dividend Dividend per share Common shares $ 235,440 $ 0.5011 $ 185,915 $ 0.4660 Series A preferred shares C$ 5,400 C$ 1.1250 C$ 5,400 C$ 1.1250 Series D preferred shares C$ 5,000 C$ 1.2500 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, 2018
Noncontrolling Interest [Abstract]
Net Loss Attributable to Non-controlling Interests	Net effect attributable to non-controlling interests for the years ended December 31 consists of the following: 2018 2017 HLBV and other adjustments attributable to: Non-controlling interests - Class A partnership units $ 103,150 $ 39,850 Non-controlling interests - redeemable Class A partnership units 7,545 10,358 Other net earnings attributable to: Non-controlling interests (2,174 ) (2,438 ) $ 108,521 $ 47,770 Redeemable non-controlling interests, held by related party (2,622 ) — Net effect of non-controlling interests $ 105,899 $ 47,770 17. Non-controlling interests and redeemable non-controlling interests (continued) The non-controlling Class A membership equity investors (“Class A 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(r).
Changes in Redeemable Non-Controlling Interest	Changes in redeemable non-controlling interests are as follows: Redeemable non-controlling interests held by related party Redeemable non-controlling interests 2018 2017 2018 2017 Opening balance $ — $ — $ 41,553 $ 21,922 Net effect from operations 2,622 — (7,545 ) (10,356 ) Contributions 305,000 — — 31,105 Dividends and distributions declared — — (644 ) (1,118 ) Closing balance $ 307,622 $ — $ 33,364 $ 41,553

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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% ( 2017 - 26.5% ). The differences are as follows: 2018 2017 Expected income tax expense at Canadian statutory rate $ 35,102 $ 46,410 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (34,165 ) (20,987 ) Net loss from investment in Atlantica 25,870 — Base Erosion Anti-Abuse Tax 6,101 — Non-controlling interests share of income 29,637 18,979 Allowance for equity funds used during construction (719 ) (799 ) Capital gain rate differential 722 (687 ) Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation 58 5,489 Non-deductible acquisition costs 4,267 13,660 Change in valuation allowance 1,160 (974 ) Tax credits (1,419 ) (6,288 ) Adjustment relating to prior periods 3,673 (31 ) U.S. Tax reform and related deferred tax adjustments (18,363 ) 17,112 Other 1,448 1,543 Income tax expense $ 53,372 $ 73,427
Income (Loss) Before Taxes	For the years ended December 31, 2018 and 2017 , earnings before income taxes consist of the following: 2018 2017 Canada $ (109,537 ) $ (2,711 ) U.S. 241,998 177,843 $ 132,461 $ 175,132
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, 2018 Canada $ 2,872 $ (14,197 ) $ (11,325 ) United States 8,475 56,222 64,697 $ 11,347 $ 42,025 $ 53,372 Year ended December 31, 2017 Canada $ 3,296 $ (14,168 ) $ (10,872 ) United States 4,221 80,078 84,299 $ 7,517 $ 65,910 $ 73,427
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, 2018 and 2017 are presented below: 2018 2017 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 329,099 $ 328,679 Pension and OPEB 48,586 43,638 Acquisition-related costs 1,420 1,601 Environmental obligation 14,790 14,803 Reserves and other non-deductible costs 20,517 30,652 Regulatory liabilities 161,560 154,597 Financial derivatives 12,831 7,607 Other 10,425 16,384 Total deferred income tax assets 599,228 597,961 Less valuation allowance (28,018 ) (19,951 ) Total deferred tax assets 571,210 578,010 Deferred tax liabilities: Property, plant and equipment (653,962 ) (668,083 ) Intangible assets (7,247 ) (7,157 ) Outside basis in partnership (167,659 ) (125,519 ) Regulatory accounts (113,758 ) (114,062 ) Financial derivatives — (980 ) Other (314 ) — Total deferred tax liabilities (942,940 ) (915,801 ) Net deferred tax liabilities $ (371,730 ) $ (337,791 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 72,415 $ 61,357 Deferred tax liabilities (444,145 ) (399,148 ) Net deferred tax liabilities $ (371,730 ) $ (337,791 )
Non Capital Losses Carry Forwards	As of December 31, 2018 , the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2020 and onwards $ 925,439

Basic and diluted net earning_2

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 Net earnings attributable to shareholders of APUC $ 184,988 $ 149,475 Series A Preferred shares dividend 4,169 4,164 Series D Preferred shares dividend 3,858 3,856 Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 176,961 $ 141,455 Weighted average number of shares Basic 461,818,023 382,323,434 Effect of dilutive securities 4,227,595 3,662,714 Diluted 466,045,618 385,986,148

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Results of Operations and Assets for Segments	Year ended December 31, 2018 Liberty Utilities Group Liberty Power Group Corporate Total Revenue (1)(2) $ 1,400,164 $ 247,223 $ — $ 1,647,387 Fuel, power and water purchased 456,974 27,164 — 484,138 Net revenue 943,190 220,059 — 1,163,249 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 330,751 48,496 (1,888 ) 377,359 Interest expense 99,063 50,920 2,135 152,118 Interest, dividend, equity and other income (5,558 ) (45,741 ) (1,840 ) (53,139 ) Change in value of investment carried at fair value — — 137,957 137,957 Other expenses 5,699 1,576 687 7,962 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 959 29,273 260 30,492 Total assets 6,012,641 3,269,786 106,541 9,388,968 Capital expenditures 370,221 96,148 — 466,369 (1) Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the twelve months ended December 31, 2018 that do not represent revenue recognized from contracts with customers. (2) Liberty Utilities Group revenue includes $7,425 related to alternative revenue programs for the twelve months ended December 31, 2018 that do not represent revenue recognized from contracts with customers. 20. Segmented information (continued) Year ended December 31, 2017 Liberty Utilities Group Liberty Power Group Corporate Total Revenue $ 1,290,786 $ 231,152 $ — $ 1,521,938 Fuel and power purchased 373,635 19,590 — 393,225 Net revenue 917,151 211,562 — 1,128,713 Operating expenses 383,380 66,851 — 450,231 Administrative expenses 33,037 15,992 611 49,640 Depreciation and amortization 171,111 79,183 1,020 251,314 Gain on foreign exchange — — 323 323 Operating income (loss) 329,623 49,536 (1,954 ) 377,205 Interest expense 97,698 36,646 21,478 155,822 Interest, dividend and other income (4,208 ) (2,871 ) (2,159 ) (9,238 ) Other expense 6,087 1,713 47,689 55,489 Earnings (loss) before income taxes $ 230,046 $ 14,048 $ (68,962 ) $ 175,132 Property, plant and equipment $ 4,023,479 $ 2,246,869 $ 34,549 $ 6,304,897 Equity-method investees 2,220 29,710 337 32,267 Total assets 5,817,599 2,474,293 103,675 8,395,567 Capital expenditures 407,408 157,695 — 565,103
Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2018 2017 Revenue Canada $ 70,358 $ 73,406 United States 1,577,029 1,448,532 $ 1,647,387 $ 1,521,938 Property, plant and equipment Canada $ 415,979 $ 453,323 United States 5,977,579 5,851,574 $ 6,393,558 $ 6,304,897 Intangible assets Canada $ 23,994 $ 27,624 United States 31,000 23,479 $ 54,994 $ 51,103

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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) $ 46,536 $ 10,896 $ 11,114 $ 11,338 $ 11,566 $ 191,208 $ 282,658 Gas supply and service agreements (ii) 77,658 51,349 27,672 24,422 22,424 48,313 251,838 Service agreements 43,732 39,093 38,451 37,463 40,737 312,559 512,035 Capital projects 67,575 1,663 196 7,330 — — 76,764 Operating leases 7,629 7,154 7,096 7,076 6,776 178,583 214,314 Total $ 243,130 $ 110,155 $ 84,529 $ 87,629 $ 81,503 $ 730,663 $ 1,337,609 (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, 2018 . 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, 2018
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: 2018 2017 Accounts receivable $ 3,005 $ (45,818 ) Fuel and natural gas in storage 1,351 (4,385 ) Supplies and consumables inventory (7,189 ) (1,864 ) Income taxes recoverable (763 ) (557 ) Prepaid expenses 2,907 (2,755 ) Accounts payable (22,915 ) 7,525 Accrued liabilities 28,687 14,041 Current income tax liability 2,974 (3,190 ) Asset retirements and environmental obligations (7,293 ) (4,372 ) Net regulatory assets and liabilities (8,890 ) (46,344 ) $ (8,126 ) $ (87,719 )

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair value of financial instruments 2018 Carrying amount Fair value Level 1 Level 2 Level 3 Notes receivable $ 103,696 $ 110,019 $ — $ 110,019 $ — Investment in Atlantica 814,530 814,530 814,530 — — 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 regulated 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 swap 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 23. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2017 Carrying amount Fair value Level 1 Level 2 Level 3 Notes receivable $ 33,378 $ 38,192 $ — $ 38,192 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 63,363 63,363 — — 63,363 Energy contracts not designated as a cash flow hedge 109 109 — 109 — Commodity contracts for regulatory operations 74 74 — 74 — Total derivative instruments 63,546 63,546 — 183 63,363 Total financial assets $ 96,924 $ 101,738 $ — $ 38,375 $ 63,363 Long-term debt $ 3,079,551 $ 3,262,711 $ 651,969 $ 2,610,742 $ — Convertible debentures 971 1,018 1,018 — — Preferred shares, Series C 14,718 15,124 — 15,124 — Derivative instruments: Energy contracts designated as a cash flow hedge 77 77 — — 77 Energy contracts not designated as a cash flow hedge 31 31 — 31 — Cross-currency swap designated as a net investment hedge 57,412 57,412 — 57,412 — Interest rate swaps designated as a hedge 8,460 8,460 — 8,460 — Currency forward contract not designated as hedge 344 344 — 344 — Commodity contracts for regulated operations 2,620 2,620 — 2,620 — Total derivative instruments 68,944 68,944 — 68,867 77 Total financial liabilities $ 3,164,184 $ 3,347,797 $ 652,987 $ 2,694,733 $ 77 (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: 2018 Financial contracts: Swaps 2,366,386 Options 300,000 Forward contracts 6,560,000
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: 2018 2017 Regulatory assets: Swap contracts $ 66 $ — Forward contracts $ — $ 6,319 Regulatory liabilities: Swap contracts $ 218 $ 287 Option contracts $ 134 $ 138 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) 871,391 December 2028 36.33 PJM Western HUB 2,438,697 December 2023 29.06 PJM NI HUB 2,997,939 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: 2018 2017 Effective portion of cash flow hedge $ 1,567 $ 8,004 Amortization of cash flow hedge (33 ) (27 ) Amounts reclassified from AOCI (4,224 ) (6,351 ) OCI attributable to shareholders of APUC $ (2,690 ) $ 1,626
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: 2018 2017 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ 77 $ (79 ) Currency forward contract (1,230 ) 297 Commodity contracts — (2,885 ) Total change in unrealized gain on derivative financial instruments $ (1,153 ) $ (2,667 ) Realized loss (gain) on derivative financial instruments: Interest rate swaps — (144 ) Energy derivative contracts (73 ) 553 Currency forward contract 115 12,261 Total realized loss on derivative financial instruments $ 42 $ 12,670 Loss (gain) on derivative financial instruments not accounted for as hedges (1,111 ) 10,003 Ineffective portion of derivative financial instruments accounted for as hedges 632 637 $ (479 ) $ 10,640 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments 636 (1,918 ) Loss (gain) on foreign exchange (1,115 ) 12,558 $ (479 ) $ 10,640
Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2018 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2018 Canadian $ US $ Cash and cash equivalents and restricted cash $ 27,720 $ 45,452 Accounts receivable 13,562 241,068 Allowance for doubtful accounts — (5,281 ) Notes receivable 138,353 2,279 $ 179,635 $ 283,518
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 $ 334,855 $ 420,797 $ 825,596 $ 1,740,471 $ 3,321,719 Convertible debentures — — — — 470 470 Advances in aid of construction 1,205 — — 62,498 63,703 Interest on long-term debt 156,768 269,942 221,528 928,736 1,576,974 Purchase obligations 325,326 — — — 325,326 Environmental obligation 4,158 30,140 2,885 21,998 59,181 Derivative financial instruments: Cross-currency swap 5,277 46,026 34,436 7,459 93,198 Interest rate swaps 8,473 — — — 8,473 Currency forward — — — — — Energy derivative and commodity contracts 588 526 57 — 1,171 Other obligations 33,350 — — 122,408 155,758 Total obligations $ 870,000 $ 767,431 $ 1,084,502 $ 2,884,040 $ 5,605,973

Notes to the Consolidated Fin_2

Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements - Narrative (Details) - business_unit	12 Months Ended
	Dec. 31, 2018	Nov. 27, 2018	Mar. 09, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business units	2
Atlantica Yield
Schedule of Equity Method Investments [Line Items]
Equity interest	41.50%	16.50%	25.00%

Significant accounting polici_4

Significant accounting policies - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)Facility	Dec. 31, 2017USD ($)MWh
Significant Accounting Policies [Line Items]
Number of electric generating facilities | Facility		3
Number of power generating facilities | Facility		2
Non-regulated energy sales		$ 1,647,387,000	$ 1,521,938,000
Interest expense on long-term debt and others		152,118,000	$ 155,822,000
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		59,288,000	$ 67,398,000
Long-term debt of Long Sault		22,263,000	28,628,000
Long-term debt of Long Sault, with recourse		0	3,109,000
Operating expenses and amortization		4,634,000	4,289,000
Interest expense on long-term debt and others		$ 1,258,000	2,755,000
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	$ 2,488,000
Adjustment to retained earnings, for previously deferred revenue, net of tax	$ 1,860,000
Non-regulated energy sales
Significant Accounting Policies [Line Items]
Non-regulated energy sales		$ 235,359,000	217,542,000
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		$ 17,232,000	$ 17,508,000

Significant accounting polici_5

Significant accounting policies - Capitalization of Interest (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Capitalization [Line Items]
Total	$ 5,846	$ 7,957
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	1,434	4,325
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	1,684	1,297
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	$ 2,728	$ 2,335

Significant accounting polici_6

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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	40 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	43 years	43 years
Equipment and other | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years	10 years

Recently issued accounting pr_2

Recently issued accounting pronouncements (Details) - Accounting Standards Update 2018-02 $ in Thousands	Jan. 01, 2018USD ($)
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	$ 10,625
Accumulated OCI
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	$ 10,625

Business acquisitions and dev_3

Business acquisitions and development projects - Additional Information (Details) $ / shares in Units, customer in Thousands, $ in Thousands

Dec. 04, 2018USD ($)customerkm

Aug. 31, 2017USD ($)

Aug. 10, 2017USD ($)

Feb. 28, 2017USD ($)

Feb. 15, 2017MWac

Jan. 01, 2017USD ($)$ / shares

Dec. 31, 2016USD ($)

Dec. 30, 2016USD ($)

Dec. 14, 2016MWac

Nov. 29, 2016USD ($)

Mar. 31, 2018MWac

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

New Brunswick Gas

Business Acquisition [Line Items]

Number of customers providing natural gas to | customer

12,000

Length of natural gas distribution pipeline | km

800

Business combination, purchase price

$ 331,000

Perris Water Distribution System

Business Acquisition [Line Items]

Business combination, purchase price

$ 11,500

St. Lawrence Gas Company, Inc.

Business Acquisition [Line Items]

Business combination, purchase price

$ 70,000

Empire

Business Acquisition [Line Items]

Business combination, purchase price

$ 2,414,000

Business acquisition, cash paid per common share (usd per share) | $ / shares

$ 34

Business combination, liabilities incurred

$ 855,000

Intangible asset, useful life

39 years

Great Bay Solar Project

Business Acquisition [Line Items]

Solar power capacity (megawatt ac) | MWac

75

Great Bay Solar Facility | Partnership

Business Acquisition [Line Items]

Partnership agreement, funded amount

$ 15,250

$ 42,750

Luning Solar Facility

Business Acquisition [Line Items]

Solar power capacity (megawatt ac) | MWac

50

Luning Solar Facility | Partnership | Tax Investor

Business Acquisition [Line Items]

Partnership agreement, funded amount

$ 7,826

Bakersfield Solar Project

Business Acquisition [Line Items]

Solar power capacity (megawatt ac) | MWac

20

Bakersfield Solar Project II

Business Acquisition [Line Items]

Solar power capacity (megawatt ac) | MWac

10

Bakersfield Solar Project II | Tax Investor

Business Acquisition [Line Items]

Partnership agreement, funded amount

$ 9,800

$ 2,454

Bridge Loan | Acquisition Facility | Line of Credit

Business Acquisition [Line Items]

Proceed from long-term lines of credit

$ 1,336,440

Bridge Loan | Acquisition Facility | Line of Credit | Empire

Business Acquisition [Line Items]

Proceed from long-term lines of credit

$ 1,336,440

Business acquisitions and dev_4

Business acquisitions and development projects - Acquisition of Empire (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Goodwill (note 6)	$ 954,282	$ 954,282		$ 228,377
Empire
Business Acquisition [Line Items]
Working capital			$ 41,292
Property, plant and equipment			2,058,867
Goodwill (note 6)			752,418
Regulatory assets			236,933
Other assets			43,609
Long-term debt			(907,547)
Regulatory liabilities			(145,594)
Pension and OPEB			(78,204)
Deferred income tax liability, net			(418,855)
Other liabilities			(76,532)
Total net assets acquired			1,506,387
Cash and cash equivalents			1,742
Net assets acquired, net of cash and cash equivalent			$ 1,504,645

Business acquisitions and dev_5

Business acquisitions and development projects - Acquisition of Luning Solar Facility (Details) $ in Thousands	Feb. 15, 2017USD ($)MWac	Dec. 31, 2016USD ($)
Luning Solar Facility
Business Acquisition [Line Items]
Business combination, purchase price	$ 110,856
Working capital	152
Property, plant and equipment	110,857
Asset retirement obligation	(546)
Non-controlling interest (tax equity)	(38,633)
Total net assets acquired	$ 71,830
Luning Solar Facility
Business Acquisition [Line Items]
Solar power capacity (megawatt ac) | MWac	50
Partnership | Tax Investor | Luning Solar Facility
Business Acquisition [Line Items]
Partnership agreement, funded amount		$ 7,826

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 5,281	$ 5,555
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 79,742	$ 78,289

Property, plant and equipment -

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Cost	$ 7,406,319	$ 7,125,369
Accumulated depreciation	1,012,761	820,472
Net book value	6,393,558	6,304,897
Land
Property, Plant and Equipment [Line Items]
Cost	73,773	71,689
Accumulated depreciation	0	0
Net book value	73,773	71,689
Equipment and other
Property, Plant and Equipment [Line Items]
Cost	88,757	91,233
Accumulated depreciation	41,295	37,104
Net book value	47,462	54,129
Generation
Property, Plant and Equipment [Line Items]
Cost	2,470,279	2,382,279
Accumulated depreciation	450,230	394,509
Net book value	2,020,049	1,987,770
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	104,996	209,979
Accumulated depreciation	0	0
Net book value	104,996	209,979
Liberty Utilities Group
Property, Plant and Equipment [Line Items]
Cost	4,455,935	4,205,823
Accumulated depreciation	521,236	388,859
Net book value	3,934,699	3,816,964
Liberty Utilities Group | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	212,579	164,366
Accumulated depreciation	0	0
Net book value	$ 212,579	$ 164,366

Property, plant and equipment_2

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 546,332	$ 493,570
Accumulated depreciation related to commonly owned facilities	42,476	8,578
Expenditures	75,427	79,657
Contribution received	6,057	12,742
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	104,107	113,822
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	34,916	34,908
Depreciation expense	1,987	1,633
Distribution
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	1,383,960	1,341,716
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	69,960	28,809
Liberty Utilities Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	669	$ 336
Liberty Utilities Group
Property, Plant, and Equipment Disclosure [Line Items]
Expansion costs	$ 1,000

Intangible assets and goodwil_2

Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Cost	$ 101,417	$ 97,520
Accumulated amortization	46,423	46,417
Net book value	54,994	51,103
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	60,775	56,540
Accumulated amortization	36,063	36,878
Net book value	24,712	19,662
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	26,795	26,799
Accumulated amortization	9,476	8,836
Net book value	17,319	17,963
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	13,847	14,181
Accumulated amortization	884	703
Net book value	$ 12,963	$ 13,478

Intangible assets and goodwil_3

Intangible assets and goodwill - Additional Information (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 2,093
Estimated amortization expense for intangibles in year 2	2,265
Estimated amortization expense for intangibles in year 3	2,430
Estimated amortization expense for intangibles in year 4	2,400
Estimated amortization expense for intangibles in year 5	$ 1,820

Intangible assets and goodwil_4

Intangible assets and goodwill - Schedule of Goodwill (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 954,282
Business acquisitions	752,418
Divestiture of operating entity	(26,513)
Goodwill end of the period	$ 954,282

Regulatory matters - Approved A

Regulatory matters - Approved Annual Revenue Increases (Details) - USD ($) $ in Thousands	Aug. 30, 2018	Jul. 01, 2018	May 01, 2018	Jan. 01, 2018	Jul. 01, 2017	Jun. 07, 2017	Mar. 01, 2016	Nov. 30, 2018	Mar. 31, 2017	Dec. 31, 2018
Missouri Department of Public Utilities
Regulatory Liabilities [Line Items]
Approved revenue increase	$ (17,837)	$ 4,600
New Hampshire Public Utilities Commission
Regulatory Liabilities [Line Items]
Approved revenue increase			$ 10,711
Recoupment of difference between final and temporary rates					$ 1,326			$ 280
Arizona Corporate Commission
Regulatory Liabilities [Line Items]
Approved revenue increase							$ 2,367
Massachusetts Department of Public Utilities
Regulatory Liabilities [Line Items]
Approved revenue increase			$ 3,676				$ 7,800		$ 500	$ 8,300
California Public Utilities Commission
Regulatory Liabilities [Line Items]
Approved revenue increase				$ 2,175
Illinois Commerce Commission
Regulatory Liabilities [Line Items]
Approved revenue increase						$ 2,200
Various
Regulatory Liabilities [Line Items]
Approved revenue increase										3,048
Missouri Water System
Regulatory Liabilities [Line Items]
Approved revenue increase										1,015
Litchfield Park Water And Sewer
Regulatory Liabilities [Line Items]
Approved revenue increase										617
Park Water Georgia
Regulatory Liabilities [Line Items]
Approved revenue increase										1,531
Gas Rate Adjustment Mechanism
Regulatory Liabilities [Line Items]
Approved revenue increase										$ 115

Regulatory matters - Regulatory

Regulatory matters - Regulatory Assets and Liabilities (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 450,474	$ 441,526
Less: current regulatory assets		(59,037)	(66,567)
Non-current regulatory assets		391,437	374,959
Total regulatory liabilities		578,592	576,124
Less: current regulatory liabilities		(39,005)	(37,687)
Non-current regulatory liabilities		539,587	538,437
Reduction of regulatory asset	$ 15,586		327,947
Increase of regulatory liability			327,947
Taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities		323,384	321,138
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities		193,564	184,188
Rate-base offset
Regulatory Liabilities [Line Items]
Total regulatory liabilities		10,900	13,214
Fuel and commodity costs adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities		23,517	23,543
Deferred compensation received in relation to lost production
Regulatory Liabilities [Line Items]
Total regulatory liabilities		6,897	9,398
Deferred construction costs - fuel related
Regulatory Liabilities [Line Items]
Total regulatory liabilities		7,258	7,418
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities		877	10,082
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 12,195	7,143
Rate adjustment
Regulatory Liabilities [Line Items]
Collection period for services rendered		24 months
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		$ 82,295	82,711
Regulatory assets recovery period		7 years
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 125,959	105,712
Regulatory asset approved not yet being recovered, average recovery term		10 years
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 48,847	57,406
Fuel and commodity costs adjustment
Regulatory Liabilities [Line Items]
Total regulatory assets		26,310	34,525
Rate adjustment
Regulatory Liabilities [Line Items]
Total regulatory assets		36,484	35,813
Clean Energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets		22,269	20,582
Deferred construction costs - fuel related
Regulatory Liabilities [Line Items]
Total regulatory assets		13,986	14,344
Asset retirement
Regulatory Liabilities [Line Items]
Total regulatory assets		21,048	16,080
Taxes
Regulatory Liabilities [Line Items]
Total regulatory assets		34,822	36,546
Rate case costs
Regulatory Liabilities [Line Items]
Total regulatory assets		7,990	9,295
Other
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 30,464	$ 28,512

Long-term investments - Schedul

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investment carried at fair value	$ 814,530	$ 0
Equity-method investees	30,492	32,267
Other investments	3,870	5,004
Other long-term investments	34,362	37,271
Less: current portion	(1,407)	0
Other long-term investments	32,955	37,271
Notes Receivable | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from equity investees (e)	101,416	30,060
Atlantica Yield
Accounts, Notes, Loans and Financing Receivable [Line Items]
Investment carried at fair value	814,530	0
Abengoa-Algonquin Global Energy Solutions
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	2,622	0
Red Lily I Wind Facility
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	15,705	18,174
Interest in Amherst Wind Project
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	7,655	8,921
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	4,510	$ 5,172
Variable Interest Entity, Not Primary Beneficiary | Windlectric | Notes Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from equity investees (e)	$ 96,477

Long-term investments - Additio

Long-term investments - Additional Information (Detail)	Nov. 28, 2018USD ($)	Nov. 27, 2018USD ($)$ / shares	Mar. 09, 2018USD ($)$ / shares	Dec. 31, 2018USD ($)shareholderMW	Dec. 31, 2017USD ($)	Jan. 01, 2019USD ($)km	Jun. 30, 2018USD ($)	May 10, 2017USD ($)	Mar. 14, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Dividend income				$ 41,079,000	$ 1,167,000
Income (loss) from equity method investments				(1,609,000)	(2,742,000)
Amount drawn under credit facility	$ 305,000,000	$ 305,000,000
Holdback amount on credit facility		$ 40,000,000
Change in value of investment carried at fair value (note 8(a))				(137,957,000)	0
Equity-method investees				$ 30,492,000	32,267,000
Red Lily I Project, wind energy facility, capacity (megawatt) | MW				26.4
Property, plant and equipment				$ 6,393,558,000	6,304,897,000
Development loans | Notes Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from equity investees (e)				101,416,000	30,060,000
Atlantica Yield
Accounts, Notes, Loans and Financing Receivable [Line Items]
Dividend income				$ 39,263,000
Equity interest		16.50%	25.00%	41.50%
Equity interest, share price (in usd per share) | $ / shares		$ 20.90	$ 24.25
Contingent payment (in usd per share) | $ / shares			$ 0.60
Contributions of capital		$ 345,000,000	$ 607,567,000
Fair value loss			$ 139,864,000	$ 137,957,000
Change in value of investment carried at fair value (note 8(a))				1,907,000
Abengoa-Algonquin Global Energy Solution B.V.
Accounts, Notes, Loans and Financing Receivable [Line Items]
Income (loss) from equity method investments				3,005,000
Equity-method investees							$ 5,000,000
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount				7,509,000
Letters of credit, issued				3,750,000
Abengoa-Algonquin Global Energy Solution B.V. | Notes Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from equity investees (e)				4,940,000
75% Interest in Red Lily I Partnership
Accounts, Notes, Loans and Financing Receivable [Line Items]
Income (loss) from equity method investments				$ (1,637,000)	(2,139,000)
75% Interest in Red Lily I Partnership | Maximum
Accounts, Notes, Loans and Financing Receivable [Line Items]
Option to subscribe equity interest in partnership, percentage				75.00%
50% interest in Odell and Deerfield Wind Projects | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Letter of credit fee percent				2.00%
50% Interest in Deerfield Wind Project
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest				50.00%
Project power capacity (megawatt) | MW				149
Interest in Amherst Wind Project
Accounts, Notes, Loans and Financing Receivable [Line Items]
Income (loss) from equity method investments				$ 1,714,000
Equity-method investees				7,655,000	8,921,000
Interest capitalized on non-regulated property				739,000	1,115,000
Property, plant and equipment				308,825,000
Long-term debt				190,910,000	106,628,000
Deerfield SponsorCo
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity interest									50.00%
Tax equity funding received								$ 166,595,000
Amherst and Deerfield Wind Projects
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accrued interest revenue				$ 6,144
Variable Interest Entity, Not Primary Beneficiary
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of shareholders with joint control | shareholder				2
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount				$ 192,052,000
Variable Interest Entity, Not Primary Beneficiary | Windlectric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Value of guarantee obligations recognized				1,637,000	$ 1,952,000
Variable Interest Entity, Not Primary Beneficiary | Windlectric | Notes Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from equity investees (e)				$ 96,477,000
Windlectric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Project power capacity (megawatt) | MW				74.1
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
Subsequent Event | Abengoa-Algonquin Global Energy Solution B.V.
Accounts, Notes, Loans and Financing Receivable [Line Items]
Amount repaid under credit support facility						$ 1,750,000
Subsequent Event | Wataynikaneyap Power Transmission
Accounts, Notes, Loans and Financing Receivable [Line Items]
Ownership percentage of noncontrolling interest						9.80%
Distance of transmission line | km						1,800

Long-term investments - Prelimi

Long-term investments - Preliminary Allocation of the Assets Acquired and Liabilities Assumed (Detail) - Deerfield SponsorCo $ in Thousands	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Working capital	$ (10,808)
Property, plant and equipment	328,371
Construction loan	(261,952)
Asset retirement obligation	(2,092)
Deferred revenue	(1,156)
Deferred tax liability	(1,470)
Net assets acquired	50,893
Cash and cash equivalent	3,107
Net assets acquired, net of cash and cash equivalent	$ 47,786

Long-term debt - Schedule of Lo

Long-term debt - Schedule of Long-term Debt (Detail) - USD ($)	Dec. 31, 2018	Oct. 17, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Less: current portion	$ (13,048,000)		$ (12,364,000)
Long-term debt, excluding current portion	3,323,747,000		3,067,187,000
Senior Unsecured Notes
Debt Instrument [Line Items]
Long-term debt	3,336,795,000		3,079,551,000
Less: current portion	(13,048,000)		(12,364,000)
Long-term debt, excluding current portion	$ 3,323,747,000		3,067,187,000
Senior Unsecured Notes | Canadian Dollar Senior Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	4.43%
Par value	$ 650,669,000
Long-term debt	$ 474,764,000		623,223,000
Senior Unsecured Notes | Canadian Dollar Senior Secured Project Notes
Debt Instrument [Line Items]
Weighted average coupon	10.25%
Par value	$ 31,310,000
Long-term debt	$ 22,915,000		26,709,000
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	$ 1,218,680,000		1,217,797,000
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Utility Notes
Debt Instrument [Line Items]
Weighted average coupon	5.99%
Par value	$ 222,000,000
Long-term debt	$ 240,161,000		246,560,000
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	$ 676,697,000		772,871,000
Senior Unsecured Notes | U.S. Dollar Subordinated Unsecured Notes
Debt Instrument [Line Items]
Weighted average coupon	6.88%	6.875%
Par value	$ 287,500,000	$ 287,500
Long-term debt	$ 278,771,000		0
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	$ 97,000,000		51,827,000
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Bank Credit Facilities
Debt Instrument [Line Items]
Long-term debt	321,807,000		134,988,000
Revolving Credit Facility | Senior Unsecured Notes | Commercial Paper
Debt Instrument [Line Items]
Long-term debt	$ 6,000,000		$ 5,576,000

Long-term debt - Narrative (Det

Long-term debt - Narrative (Detail)

Oct. 17, 2018USD ($)

Mar. 24, 2017USD ($)Tranche

Jan. 01, 2017USD ($)Tranche

Dec. 30, 2016USD ($)

Jun. 30, 2018USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Jan. 01, 2019CAD ($)

Jul. 25, 2018CAD ($)

Feb. 23, 2018USD ($)

Feb. 15, 2018USD ($)

Dec. 21, 2017USD ($)

Oct. 06, 2017USD ($)

Oct. 05, 2017CAD ($)

Sep. 20, 2017CAD ($)

Jun. 30, 2017USD ($)

Jan. 17, 2017CAD ($)

Dec. 31, 2016CAD ($)

Debt Instrument [Line Items]

Short-term debt

$ 321,807,000

Repayment of long-term debt

1,699,592,000

$ 2,366,105,000

Interest on long term debt

33,822,000

33,064,000

Interest expense during the year on long-term liabilities

150,262,000

142,791,000

Senior Unsecured Notes

Debt Instrument [Line Items]

Long-term debt

3,336,795,000

3,079,551,000

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

Debt Instrument [Line Items]

Par value

$ 287,500

$ 287,500,000

Weighted average coupon

6.875%

6.88%

Long-term debt

$ 278,771,000

0

Senior Unsecured Notes | Senior Unsecured Debenture Due February 2027

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 135,000,000

Par value

$ 300,000,000

Maturity date

4.09%

Debt instrument, sales price ratio

0.99929

Senior Debt

Debt Instrument [Line Items]

Debt instrument, number of tranches | Tranche

6

Debt instrument, weighted average life

15 years

Par value

$ 750,000,000

Weighted average coupon

4.00%

Effective weighted average interest rate

3.60%

Long-term debt

$ 479,000,000

Revolving Credit Facility | Senior Unsecured Notes

Debt Instrument [Line Items]

Weighted average coupon

0.00%

Revolving Credit Facility | Senior Unsecured Notes | APUC Senior Unsecured Revolving Facility Maturing November 2017

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 165,000,000

$ 65,000,000

Revolving Credit Facility | Senior Unsecured Notes | Empire Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

Revolving Credit Facility | Senior Unsecured Notes | Liberty Power Bilateral Revolving Credit Facility Maturing August 2018

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 500,000,000

$ 350,000,000

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

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 200,000,000

$ 600,000,000

Amount draw on credit facility

$ 186,807,000

Line of Credit | Bridge Loan | Acquisition Facility

Debt Instrument [Line Items]

Amount draw on credit facility

$ 135,000,000

Proceed from long-term lines of credit

$ 1,336,440,000

Subsequent Event | Senior Unsecured Notes | Senior Unsecured Notes Due January 2029

Debt Instrument [Line Items]

Par value

$ 300,000

Weighted average coupon

4.60%

Debt instrument, sales price ratio

0.99952

Subsequent Event | Bonds

Debt Instrument [Line Items]

Long-term debt

$ 135,000,000

Park Water Company | Bonds

Debt Instrument [Line Items]

Long-term debt

$ 63,000,000

Empire

Debt Instrument [Line Items]

Long-term debt

$ 907,547,000

Empire | U.S. Dollar Senior Unsecured Utility Notes

Debt Instrument [Line Items]

Debt instrument, number of tranches | Tranche

2

Long-term debt

$ 102,000,000

Empire | Secured Utility Notes

Debt Instrument [Line Items]

Debt instrument, number of tranches | Tranche

10

Long-term debt

$ 733,000,000

Repayment of debt

$ 90,000,000

Empire | Line of Credit | Bridge Loan | Acquisition Facility

Debt Instrument [Line Items]

Proceed from long-term lines of credit

$ 1,336,440,000

Minimum | Senior Debt

Debt Instrument [Line Items]

Debt instrument, term

3 years

Minimum | Empire | U.S. Dollar Senior Unsecured Utility Notes

Debt Instrument [Line Items]

Maturity date

6.70%

Minimum | Empire | Secured Utility Notes

Debt Instrument [Line Items]

Maturity date

3.58%

Maximum | Senior Debt

Debt Instrument [Line Items]

Debt instrument, term

30 years

Maximum | Empire | U.S. Dollar Senior Unsecured Utility Notes

Debt Instrument [Line Items]

Maturity date

5.80%

Maximum | Empire | Secured Utility Notes

Debt Instrument [Line Items]

Maturity date

6.82%

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

Debt Instrument [Line Items]

Basis spread on variable rate

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

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

4.677%

- Principal Payments (Detail)

- Principal Payments (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2,019	$ 334,855
2,020	308,917
2,021	111,880
2,022	343,737
2,023	481,859
Thereafter	1,740,471
Total, including adjustment	$ 3,321,719

Pension and other post-retire_3

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Dec. 31, 2017
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost		$ 8,446	$ 7,232
Accumulated benefit obligation for pension plan		439,458	490,108
Actuarial (gain) loss	$ (2,354)
Gain on curtailment	$ 853
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit)		1,875
Reclassification of non-service costs			9,035
Pension Plans
Employee Benefits Disclosure [Line Items]
Actuarial (gain) loss		(29,845)	35,696
Gain on curtailment		(1,875)	(849)
Expected employer contributions for next year		20,137
Other Postretirement Benefit Plans, Defined Benefit
Employee Benefits Disclosure [Line Items]
Actuarial (gain) loss		(14,800)	10,263
Gain on curtailment		0	$ (4)
Expected employer contributions for next year		$ 5,562

Pension and other post-retire_4

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Dec. 31, 2017
Change in projected benefit obligation
Actuarial (gain) loss	$ (2,354)
Gain on curtailment	853
Pension Plans
Change in projected benefit obligation
Projected benefit obligation, beginning of year	247,246	$ 523,743	$ 247,246
Projected benefit obligation assumed from business combination		0	256,486
Service cost		15,481	14,747
Interest cost		18,717	20,191
Actuarial (gain) loss		(29,845)	35,696
Contributions from retirees		0	0
Gain on curtailment		(1,875)	(849)
Benefits paid		(49,429)	(49,774)
Projected benefit obligation, end of year		476,792	523,743
Change in plan assets
Fair value of plan assets, beginning of year	176,040	403,945	176,040
Plan assets acquired in business combination		0	184,510
Actual return on plan assets		(36,987)	63,250
Employer contributions		21,570	29,919
Benefits paid		(49,429)	(49,774)
Fair value of plan assets, end of year		339,099	403,945
Unfunded status		(137,693)	(119,798)
Non-current assets		0	0
Current liabilities		(872)	(861)
Non-current liabilities		(136,821)	(118,937)
Net amount recognized		(137,693)	(119,798)
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation
Projected benefit obligation, beginning of year	61,888	176,975	61,888
Projected benefit obligation assumed from business combination		0	97,761
Service cost		5,791	4,838
Interest cost		6,727	6,642
Actuarial (gain) loss		(14,800)	10,263
Contributions from retirees		1,920	1,821
Gain on curtailment		0	(4)
Benefits paid		(8,288)	(6,234)
Projected benefit obligation, end of year		168,325	176,975
Change in plan assets
Fair value of plan assets, beginning of year	$ 21,701	130,487	21,701
Plan assets acquired in business combination		0	91,532
Actual return on plan assets		(10,603)	19,733
Employer contributions		2,068	2,068
Benefits paid		(6,410)	(4,547)
Fair value of plan assets, end of year		115,542	130,487
Unfunded status		(52,783)	(46,488)
Non-current assets		3,161	3,936
Current liabilities		(850)	(1,172)
Non-current liabilities		(55,094)	(49,252)
Net amount recognized		$ (52,783)	$ (46,488)

Pension and other post-retire_5

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	$ 25,128	$ 27,572
Additions to AOCI	34,916	(2,652)
Reclassification to regulatory accounts (note 7(b))	(22,166)	1,136
Amortization in current period	(1,074)	(928)
Gain (loss) on plan settlements	(2,547)
Ending balance, December 31	34,257	25,128
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	(4,995)	(5,617)
Additions to AOCI	(1,875)	0
Reclassification to regulatory accounts (note 7(b))	0	0
Amortization in current period	649	622
Gain (loss) on plan settlements	0
Ending balance, December 31	(6,221)	(4,995)
Other Postretirement Benefit Plans, Defined Benefit
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward]
Beginning balance, January 1	(3,182)	(3,861)
Additions to AOCI	3,254	(3,066)
Reclassification to regulatory accounts (note 7(b))	(14,232)	3,515
Amortization in current period	272	230
Gain (loss) on plan settlements	0
Ending balance, December 31	(13,888)	(3,182)
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward]
Beginning balance, January 1	(470)	(732)
Additions to AOCI	0	0
Reclassification to regulatory accounts (note 7(b))	0	0
Amortization in current period	262	262
Gain (loss) on plan settlements	0
Ending balance, December 31	$ (208)	$ (470)

Pension and other post-retire_6

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 439,458	$ 462,943
Fair value of plan assets	339,099	376,276
Projected benefit obligation	476,791	523,743
Fair value of plan assets	339,099	403,945
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	163,375	171,175
Fair value of plan assets	107,430	121,561
Projected benefit obligation	163,375	171,175
Fair value of plan assets	$ 107,430	$ 121,561

Pension and other post-retire_7

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.57%	4.01%
Expected return on assets	7.13%	7.01%
Rate of compensation increase	3.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.60%	4.12%
Expected return on assets	6.52%	3.88%
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	2,024	2,023

Pension and other post-retire_8

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.19%	3.43%
Interest crediting rate (for cash balance plans)	4.43%	4.50%
Rate of compensation increase	4.00%	3.00%
Rate of compensation increase	3.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.26%	3.60%
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	2,031	2,024

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, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 15,481	$ 14,747
Interest cost	18,717	20,191
Expected return on plan assets	(27,820)	(24,842)
Amortization of net actuarial loss (gain)	1,119	1,140
Amortization of prior service credits	(649)	(622)
Amortization of regulatory assets/liability	9,823	13,031
Net benefit cost	16,671	23,645
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	5,791	4,838
Interest cost	6,727	6,642
Expected return on plan assets	(7,451)	(6,404)
Amortization of net actuarial loss (gain)	(272)	(230)
Amortization of prior service credits	(262)	(262)
Amortization of regulatory assets/liability	3,982	391
Net benefit cost	$ 8,515	$ 4,975

Pension and other post-retir_10

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	69.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	31.00%
Minimum | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	49.00%
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	51.00%

Pension and other post-retir_11

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) $ in Thousands	Dec. 31, 2018USD ($)
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	100.00%
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 454,641
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	75.00%
Equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 338,946
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	$ 115,695
Other
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	0.00%
Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0

Pension and other post-retir_12

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2,019	$ 31,101
2,020	29,366
2,021	32,508
2,022	33,415
2,023	35,111
2024-2028	183,338
Post Retirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
2,019	6,077
2,020	6,686
2,021	7,172
2,022	7,731
2,023	8,241
2024-2028	$ 47,119

Other assets - Schedule of Othe

Other assets - Schedule of Other Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Income tax recoverable	$ 1,961	$ 5,967
Deferred financing costs	4,449	3,546
Restricted cash	18,954	15,939
Other	9,335	10,811
Total other assets	34,699	36,263
Less: current portion	(6,115)	(7,110)
Other assets, noncurrent	$ 28,584	$ 29,153

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Long-term Liabilities
Advances in aid of construction (a)	$ 63,703	$ 62,683
Environmental remediation obligation (b)	55,621	54,322	$ 47,202
Asset retirement obligations (c)	43,291	44,166	$ 18,486
Customer deposits (d)	29,974	28,529
Unamortized investment tax credits (e)	17,491	17,839
Deferred credits (f)	42,711	21,168
Preferred shares, Series C (g)	13,418	14,718
Other (h)	39,710	45,434
Other Liabilities	305,919	288,859
Less: current portion	(42,337)	(46,754)
Other long-term liabilities	263,582	242,105
Transfers from advances in aid of construction to contributions in aid of construction	3,687	10,498
Estimated environmental remediation costs	59,181	57,292
Accrual for environmental loss contingencies to be incurred over next three years	$ 36,611
Accrual for environmental loss contingencies, payment period	27 years
Amount of regulatory assets	$ 450,474	441,526
Minimum
Other Long-term Liabilities
Other liability repayment period	5 years
Accrual environmental cost	2.50%
Maximum
Other Long-term Liabilities
Other liability repayment period	40 years
Accrual environmental cost	2.80%
Environmental costs
Other Long-term Liabilities
Regulatory asset, expenditure recovery provided by regulator, time period	7 years
Amount of regulatory assets	$ 82,295	$ 82,711
Series C Preferred Stock
Other Long-term Liabilities
Preferred shares, Series C (g)	$ 13,418

Other long-term liabilities - C

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening balance	$ 54,322	$ 47,202
Remediation activities	(2,163)	(1,561)
Accretion	1,479	1,114
Changes in cash flow estimates	4,051	1,645
Revision in assumptions	(2,068)	5,922
Closing balance	$ 55,621	$ 54,322

Other long-term liabilities - A

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening Balance	$ 44,166	$ 18,486
Obligation assumed from business acquisition and constructed projects	225	28,267
Retirement activities	(5,130)	(2,811)
Accretion	1,974	1,981
Change in cash flow estimates	2,056	(1,757)
Closing Balance	$ 43,291	$ 44,166

Other long-term liabilities - P

Other long-term liabilities - Preferred Shares, Series C (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)shares	Dec. 31, 2018$ / shares	Dec. 31, 2017USD ($)
Class of Stock [Line Items]
Contingent consideration related to prior acquisition	$ 16,000
Gain on contingent consideration	12,000
Preferred stock redemption price per share (in USD per share) | $ / shares		$ 25
2,019	334,855
2,020	308,917
2,021	111,880
2,022	343,737
2,023	481,859
Thereafter to 2031	1,740,471
Total Preferred shares series C	$ 13,418		$ 14,718
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	$ (5,993)
Total Preferred shares series C	13,418
Less current portion	(940)
Preferred shares series C, noncurrent	12,478
Series C Preferred Stock | Dividends Payable
Class of Stock [Line Items]
2,019	940
2,020	985
2,021	1,000
2,022	1,019
2,023	1,183
Thereafter to 2031	10,370
Redemption amount	3,914
Estimated dividend and redemption payments	$ 19,411
Executives of company | Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares | shares	36

Other long-term liabilities -_2

Other long-term liabilities - Convertible Debentures (Details)	Mar. 01, 2016CAD ($)shares$ / instrument	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Debt conversion, shares issued (in shares) | shares		56,926	108,370,081
Convertible Subordinated Debt
Debt Instrument [Line Items]
Debt instrument, effective interest rate		0.00%
Convertible Unsecured Subordinated Debentures | Convertible Subordinated Debt
Debt Instrument [Line Items]
Long-term debt		$ 470,000	$ 971,000
Par value	$ 1,150,000,000
Maturity date	5.00%
Proceeds from issuance of debt			571,642,000	$ 266,889,000
Debt instrument, convertible, price per instrument (USD per debenture) | $ / instrument	1,000,000
interest expense		0	7,193,000
Debt instrument, convertible, number of equity instruments (in shares) | shares	108,490,566
Principle converted amount		$ 447,000	$ 855,691,000
Debt conversion, shares issued (in shares) | shares		56,926,000	108,370,081
Debt instrument, convertible debt, percentage of shares issued		0.999

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Common Shares Rollforward
Beginning balance (in shares)	431,765,935	274,087,018
Public offering and subscription receipts (in shares)	50,041,624	43,470,000
Conversion of convertible debentures (in shares)	56,926	108,370,081
Dividend reinvestment plan (in shares)	5,880,843	3,905,848
Exercise of share-based awards	1,106,105	1,932,988
Ending balance (in shares)	488,851,433	431,765,935

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	Dec. 20, 2018CAD ($)shares	Dec. 20, 2018USD ($)$ / sharesshares	Apr. 24, 2018CAD ($)shares	Apr. 24, 2018USD ($)$ / sharesshares	Nov. 10, 2017CAD ($)shares	Nov. 10, 2017USD ($)$ / sharesshares	Dec. 31, 2018USD ($)Rightvoteshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2023$ / shares	Dec. 31, 2018CAD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 20, 2018$ / shares	Apr. 24, 2018$ / shares	Nov. 10, 2017$ / 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%
Common shares issued (in shares)							50,041,624	43,470,000
Discount rate on share purchases under dividend reinvestment plan							5.00%
Dividend reinvestment plan shares issued (in shares)							1,606,001
Carrying amount C$								$ 184,299			$ 184,299
Preferred stock redemption price per share (in CAD per share) | $ / shares										$ 25
Total share-based compensation expense | $							$ 9,458	8,361
Death Benefits
Stockholders Equity Note [Line Items]
Stock options exercised period							1 year
Resignation or Termination
Stockholders Equity Note [Line Items]
Stock options exercised period							30 days
Maximum | Retirement
Stockholders Equity Note [Line Items]
Stock options exercised period							90 days
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 | $							$ 2,054	3,070
Unrecognized compensation costs, non-vested options | $											$ 1,221
Unrecognized compensation costs, non-vested options, period of recognition							1 year 7 months 21 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
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 | $							$ 312	$ 436
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
Common stock, shares issued (in shares)								283,523		252,698	252,698
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
Shares issued during period (in shares)							380,656	293,906.32
Performance and restricted share units
Stockholders Equity Note [Line Items]
Total share-based compensation expense | $							$ 6,378	$ 4,262
Unrecognized compensation costs, non-vested awards | $											$ 8,243
Unrecognized compensation costs, non-vested options, period of recognition							1 year 7 months 5 days
Series A Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares)								4,800,000		4,800,000	4,800,000
Shares issued, price per share (CAD per share) | (per share)								$ 25		$ 25
Carrying amount C$								$ 100,463		$ 116,546	$ 100,463
Fixed cumulative annual dividend per share (CAD per share) | $ / shares										$ 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
Series D Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock issued (in shares)								4,000,000		4,000,000	4,000,000
Shares issued, price per share (CAD per share) | (per share)								$ 25		$ 25
Carrying amount C$								$ 83,836		$ 97,259	$ 83,836
Fixed cumulative annual dividend per share (CAD per share) | $ / shares										$ 1.25
Subsequent yield period							5 years
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%
Government of Canada Bond Yield | Series D Preferred Stock
Stockholders Equity Note [Line Items]
Dividend variable interest rate							3.28%
Government of Canada Treasury Bill Yield | Series B Preferred Stock
Stockholders Equity Note [Line Items]
Dividend variable interest rate							2.94%
Government of Canada Treasury Bill Yield | Series E Preferred Stock
Stockholders Equity Note [Line Items]
Dividend variable interest rate							3.28%
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%
Range Three | Employee share purchase
Stockholders Equity Note [Line Items]
Employer matching contribution, percent							15.00%
Public Stock Offering
Stockholders Equity Note [Line Items]
Sale of stock, price per share (CAD per share) | (per share)		$ 10.09		$ 9.23		$ 10.45						$ 13.76	$ 11.85	$ 13.25
Payments of Stock Issuance Costs	$ 492	$ 366	$ 765	$ 590	$ 24,342	$ 19,193
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	43,470,000	43,470,000
Cash proceeds from issuance of shares	$ 172,500	$ 126,485	$ 444,437	$ 346,458	$ 576,000	$ 454,158
Payments Of Stock Issuance Costs, Net of Tax					$ 17,895	$ 14,109
Scenario, Forecast | Series A Preferred Stock
Stockholders Equity Note [Line Items]
Fixed cumulative annual dividend per share (CAD per share) | $ / shares									$ 1.2905

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 9,458	$ 8,361
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	2,054	3,070
Director deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	714	593
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	312	436
Performance and restricted share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	$ 6,378	$ 4,262

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Equity [Abstract]
Risk-free interest rate	2.10%	1.40%
Expected volatility	21.00%	25.00%
Expected dividend yield	4.80%	4.30%
Expected life	5 years 6 months	5 years 6 months
Weighted average grant date fair value per option (CAD per share)	$ 1.41	$ 1.45

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of awards
Beginning balance (in shares)	6,738,856	6,045,014
Granted (in shares)	1,166,717	2,328,343
Exercised (in shares)	(1,589,211)	(1,634,501)
Forfeited (in shares)	(23,720)
Ending balance (in shares)	6,292,642	6,738,856	6,045,014
Exercisable (in shares)	3,198,175
Weighted average exercise price
Beginning balance (CAD per share)	$ 11.18	$ 9.64
Granted (CAD per share)	12.80	12.82
Exercised (CAD per share)	10.66	7.81
Forfeited (CAD per share)	12.80
Ending balance (CAD per share)	11.61	$ 11.18	$ 9.64
Exercisable (CAD per share)	$ 10.44
Additional Disclosures
Outstanding shares, weighted average remaining contractual term	5 years 9 months	6 years 3 months 25 days	6 years 3 months 7 days
Granted, weighted average remaining contractual term	8 years	8 years
Exercised shares, weighted average remaining contractual term	5 years 7 days	3 years 9 months 4 days
Exercisable , weighted average remaining contractual term	4 years 11 months 5 days
Beginning balance, aggregate intrinsic value	$ 19,380	$ 10,595
Granted, aggregate intrinsic value	0	0
Exercised, aggregate intrinsic value	5,059	7,696
Ending balance, aggregate intrinsic value	13,342	$ 19,380	$ 10,595
Exercisable, aggregate intrinsic value	$ 10,501

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of awards
Beginning balance (in shares)	955,028	578,988
Granted, including dividends (in shares)	791,524	811,974
Exercised (in shares)	(285,551)	(374,973)
Forfeited (in shares)	(68,869)	(60,961)
Ending balance (in shares)	1,392,132	955,028	578,988
Exercisable (in shares)	173,533
Weighted average grant-date fair value
Beginning balance (CAD per share)	$ 12.30	$ 9.82
Granted, including dividends (CAD per share)	12.41	13.54
Exercised (CAD per share)	10.02	8.33
Forfeited (CAD per share)	13.02	12.61
Ending balance (CAD per share)	12.75	$ 12.30	$ 9.82
Exercisable (CAD per share)	$ 11.66
Additional Disclosures
Outstanding, Weighted average remaining contractual term	1 year 7 months 6 days	1 year 10 months 2 days	1 year 8 months 26 days
Granted, including dividends, Weighted average remaining contractual term	2 years	2 years
Outstanding, aggregate intrinsic value	$ 19,114	$ 13,428	$ 6,595
Granted, including dividends, aggregate intrinsic value	0	0
Exercised, aggregate intrinsic value	3,691	4,394
Forfeited, aggregate intrinsic value	0	$ 0
Exercisable, aggregate intrinsic value	$ 2,383

Shareholders' capital Sharehold

Shareholders' capital Shareholders' Capital - Bonus Deferral RSUs (Details) - Bonus Deferral Restricted Stock Units - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Beginning balance (in shares)	0
Granted, including dividends (in shares)		131,611.02
Exercised (in shares)		(4,544.67)
Ending balance (in shares)	127,066	0
Weighted average grant-date fair value
Beginning balance (CAD per share)	$ 0
Granted, including dividends (CAD per share)		$ 12.82
Exercised (CAD per share)		12.82
Ending balance (CAD per share)	$ 12.82	$ 0
Outstanding, aggregate intrinsic value	$ 1,745	$ 0
Granted, including dividends, aggregate intrinsic value		0
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, 2018	Dec. 31, 2017	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ 3,320,100	$ 1,851,316
OCI (loss) before reclassifications	(22,875)	(13,176)
Amounts reclassified	(4,343)	(6,667)
Other comprehensive loss, net of tax	(28,699)	(19,816)
Ending Balance	3,697,522	3,320,100
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(47,701)	(25,921)
OCI (loss) before reclassifications	(26,488)	(21,780)
Amounts reclassified	0	0
Other comprehensive loss, net of tax	(26,488)	(21,780)
Ending Balance	(74,189)	(47,701)
Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	55,366	53,740
OCI (loss) before reclassifications	1,567	8,004
Amounts reclassified	(4,257)	(6,378)
Other comprehensive loss, net of tax	(2,690)	1,626
Ending Balance	64,333	55,366
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	0	65
OCI (loss) before reclassifications	0	0
Amounts reclassified	0	(65)
Other comprehensive loss, net of tax	0	(65)
Ending Balance	0	0
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(10,457)	(10,833)
OCI (loss) before reclassifications	2,046	600
Amounts reclassified	(86)	(224)
Other comprehensive loss, net of tax	1,960	376
Ending Balance	(9,529)	(10,457)
Accumulated OCI
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(2,792)	17,051
Other comprehensive loss, net of tax	(27,218)	(19,843)
Ending Balance	$ (19,385)	$ (2,792)
Accounting Standards Update 2018-02
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			$ 10,625
Accounting Standards Update 2018-02 | Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			0
Accounting Standards Update 2018-02 | Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			11,657
Accounting Standards Update 2018-02 | Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			0
Accounting Standards Update 2018-02 | Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			(1,032)
Accounting Standards Update 2018-02 | Accumulated OCI
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Cumulative catch-up adjustment related to adoption of ASU 2018-02 on tax effects in AOCI (note 2(a))			$ 10,625

Dividends (Detail)

Dividends (Detail) $ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018CAD ($)$ / shares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017CAD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares
Dividends [Line Items]
Dividend declared for common share holders | $		$ 235,440		$ 185,915
Cash dividend declared per common share (USD per share) | $ / shares		$ 0.5011		$ 0.4660
Series A Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders | $	$ 5,400		$ 5,400
Dividend declared per preferred share (CAD per share) | $ / shares	$ 1.1250		$ 1.1250
Series D Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders | $	$ 5,000		$ 5,000
Dividend declared per preferred share (CAD per share) | $ / shares	$ 1.2500		$ 1.2500

Related party transactions (Det

Related party transactions (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Transactions with Third Party [Line Items]
Contributions from redeemable non-controlling interests	$ 0	$ 31,105
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses	11,390	$ 4,675
Related Party
Transactions with Third Party [Line Items]
Contributions from redeemable non-controlling interests	$ 305,000

Non-controlling Interests and_3

Non-controlling Interests and Redeemable non-controlling Interest - Net Loss Attributable to Non-Controlling Interest (Details) - USD ($) $ in Thousands	May 10, 2017	Feb. 28, 2017	Feb. 17, 2017	Dec. 31, 2016	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests						$ 108,521	$ 47,770
Non-controlling interests - redeemable Class A partnership units						7,545	10,356
Redeemable non-controlling interests, held by related party						(2,622)	0
Net effect of non-controlling interests						105,899	47,770
Change in tax attributes, accelerated income					$ 55,900
Non-controlling interests						519,896	602,636
Contributions from redeemable non-controlling interests						0	31,105
Other Noncontrolling Interests
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests						(2,174)	(2,438)
Non-controlling interests						796	856
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Net effect of non-controlling interests						103,150	39,850
Non-controlling interests - redeemable Class A partnership units						7,545	10,358
Non-controlling interests						519,100	601,780
Great Bay Solar Facility | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount						15,250	$ 42,750
Luning Solar Facility
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests			$ 31,212
Abengoa-Algonquin Global Energy Solution B.V.
Noncontrolling Interest [Line Items]
Contributions from redeemable non-controlling interests						$ 305,000
Tax Investor | Bakersfield II Solar Facility | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount		$ 9,800
Tax Investor | Deerfield Wind Project | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount	$ 166,595
Tax Investor | Luning Solar Facility | Partnership
Noncontrolling Interest [Line Items]
Partnership agreement, funded amount				$ 7,826

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, 2018	Dec. 31, 2017
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	$ 41,553	$ 21,922
Net effect from operations	(7,545)	(10,356)
Contributions from redeemable non-controlling interests	0	31,105
Dividends and distributions declared	(644)	(1,118)
Closing balance	33,364	41,553
Related Party
Increase (Decrease) in Temporary Equity [Roll Forward]
Opening balance	0	0
Net effect from operations	2,622	0
Contributions from redeemable non-controlling interests	305,000	0
Dividends and distributions declared	0	0
Closing balance	$ 307,622	$ 0

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - USD ($) $ in Thousands	Jun. 01, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Canadian enacted statutory rate		26.50%	26.50%
U.S. Tax reform and related deferred tax adjustments	$ (15,586)	$ 18,363	$ (17,112)
Valuation allowance for deferred tax assets		28,018	$ 19,951
Deferred income taxes, undistributed earnings of foreign subsidiaries		$ 280,643

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	Jun. 01, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Expected income tax expense at Canadian statutory rate		$ 35,102	$ 46,410
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates		(34,165)	(20,987)
Net loss from investment in Atlantica		25,870	0
Base Erosion Anti-Abuse Tax		6,101	0
Non-controlling interests share of income		29,637	18,979
Allowance for equity funds used during construction		(719)	(799)
Capital gain rate differential		722	(687)
Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation		58	5,489
Non-deductible acquisition costs		4,267	13,660
Change in valuation allowance		1,160	(974)
Tax credits		(1,419)	(6,288)
Adjustment relating to prior periods		3,673	(31)
U.S. Tax reform and related deferred tax adjustments	$ 15,586	(18,363)	17,112
Other		1,448	1,543
Income tax expense		$ 53,372	$ 73,427

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 132,461	$ 175,132
Canada
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	(109,537)	(2,711)
U.S.
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	$ 241,998	$ 177,843

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Expenses [Line Items]
Income tax expenses, current	$ 11,347	$ 7,517
Income tax expenses, deferred	42,025	65,910
Income tax expense	53,372	73,427
Canada
Income Tax Expenses [Line Items]
Income tax expenses, current	2,872	3,296
Income tax expenses, deferred	(14,197)	(14,168)
Income tax expense	(11,325)	(10,872)
United States
Income Tax Expenses [Line Items]
Income tax expenses, current	8,475	4,221
Income tax expenses, deferred	56,222	80,078
Income tax expense	$ 64,697	$ 84,299

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, 2018	Dec. 31, 2017
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$ 329,099	$ 328,679
Pension and OPEB	48,586	43,638
Acquisition-related costs	1,420	1,601
Environmental obligation	14,790	14,803
Reserves and other non-deductible costs	20,517	30,652
Regulatory liabilities	161,560	154,597
Financial derivatives	12,831
Other	10,425	16,384
Total deferred income tax assets	599,228	597,961
Less valuation allowance	(28,018)	(19,951)
Total deferred tax assets	571,210	578,010
Deferred tax liabilities:
Property, plant and equipment	(653,962)	(668,083)
Intangible assets	(7,247)	(7,157)
Outside basis in partnership	(167,659)	(125,519)
Regulatory accounts	(113,758)	(114,062)
Financial derivatives	0	(980)
Other	(314)	0
Total deferred tax liabilities	(942,940)	(915,801)
Net deferred tax liabilities	(371,730)	(337,791)
Deferred tax assets	72,415	61,357
Deferred tax liabilities	$ (444,145)	$ (399,148)

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) $ in Thousands	Dec. 31, 2018USD ($)
2020 and onwards
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	$ 925,439

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, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Net earnings attributable to shareholders of APUC	$ 184,988	$ 149,475
Series A and D Preferred shares dividend	8,027	8,020
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted	$ 176,961	$ 141,455
Weighted average number of shares
Basic (in shares)	461,818,023	382,323,434
Effect of dilutive securities (in shares)	4,227,595	3,662,714
Diluted (in shares)	466,045,618	385,986,148
Series A Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 4,169	$ 4,164
Series D Preferred Stock
Class of Stock [Line Items]
Series A and D Preferred shares dividend	$ 3,858	$ 3,856

Basic and diluted net earning_4

Basic and diluted net earnings per share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures (in shares)	3,380,184	2,328,343

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018business_unitcountry
Segment Reporting [Abstract]
Number of business units | business_unit	2
Number of countries in which entity operates | country	2

Segmented information - Results

Segmented information - Results of Operations and Assets for Segments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue
Revenue	$ 1,647,387	$ 1,521,938
Fuel, power and water purchased	484,138	393,225
Net revenue	1,163,249	1,128,713
Operating expenses	472,466	450,231
Administrative expenses	52,710	49,640
Depreciation and amortization	260,772	251,314
Gain on foreign exchange	(58)	323
Operating income	377,359	377,205
Interest expense	152,118	155,822
Interest, dividend, equity and other income	(53,139)	(9,238)
Change in value of investment carried at fair value	137,957	0
Other expenses	7,962	55,489
Earnings (loss) before income taxes	132,461	175,132
Property, plant and equipment	6,393,558	6,304,897
Investment carried at fair value	814,530	0
Equity-method investees	30,492	32,267
Total assets	9,388,968	8,395,567
Capital expenditures	466,369	565,103
Revenue related to net hedging gains, not recognized as revenue from contract with customers	14,953
Liberty Utilities Group
Revenue
Revenue	1,400,164	1,290,786
Fuel, power and water purchased	456,974	373,635
Net revenue	943,190	917,151
Operating expenses	401,486	383,380
Administrative expenses	33,234	33,037
Depreciation and amortization	177,719	171,111
Gain on foreign exchange	0	0
Operating income	330,751	329,623
Interest expense	99,063	97,698
Interest, dividend, equity and other income	(5,558)	(4,208)
Change in value of investment carried at fair value	0
Other expenses	5,699	6,087
Earnings (loss) before income taxes	231,547	230,046
Property, plant and equipment	4,210,115	4,023,479
Investment carried at fair value	0
Equity-method investees	959	2,220
Total assets	6,012,641	5,817,599
Capital expenditures	370,221	407,408
Revenue related to alternative revenue programs, not recognized as revenue from contract with customers	7,425
Liberty Power Group
Revenue
Revenue	247,223	231,152
Fuel, power and water purchased	27,164	19,590
Net revenue	220,059	211,562
Operating expenses	70,980	66,851
Administrative expenses	18,539	15,992
Depreciation and amortization	82,044	79,183
Gain on foreign exchange	0	0
Operating income	48,496	49,536
Interest expense	50,920	36,646
Interest, dividend, equity and other income	(45,741)	(2,871)
Change in value of investment carried at fair value	0
Other expenses	1,576	1,713
Earnings (loss) before income taxes	41,741	14,048
Property, plant and equipment	2,152,420	2,246,869
Investment carried at fair value	814,530
Equity-method investees	29,273	29,710
Total assets	3,269,786	2,474,293
Capital expenditures	96,148	157,695
Corporate
Revenue
Revenue	0	0
Fuel, power and water purchased	0	0
Net revenue	0	0
Operating expenses	0	0
Administrative expenses	937	611
Depreciation and amortization	1,009	1,020
Gain on foreign exchange	(58)	323
Operating income	(1,888)	(1,954)
Interest expense	2,135	21,478
Interest, dividend, equity and other income	(1,840)	(2,159)
Change in value of investment carried at fair value	137,957
Other expenses	687	47,689
Earnings (loss) before income taxes	(140,827)	(68,962)
Property, plant and equipment	31,023	34,549
Investment carried at fair value	0
Equity-method investees	260	337
Total assets	106,541	103,675
Capital expenditures	$ 0	$ 0

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenue	$ 1,647,387	$ 1,521,938
Property, plant and equipment	6,393,558	6,304,897
Intangible assets	54,994	51,103
Canada
Segment Reporting Information [Line Items]
Revenue	70,358	73,406
Property, plant and equipment	415,979	453,323
Intangible assets	23,994	27,624
United States
Segment Reporting Information [Line Items]
Revenue	1,577,029	1,448,532
Property, plant and equipment	5,977,579	5,851,574
Intangible assets	$ 31,000	$ 23,479

Commitments and contingencies -

Commitments and contingencies - Estimates of Future Commitments (Detail) - USD ($) $ in Thousands	Oct. 30, 2018	Jun. 22, 2017	May 06, 2014	Dec. 31, 2018
Commitments Disclosure [Line Items]
Year 1				$ 243,130
Year 2				110,155
Year 3				84,529
Year 4				87,629
Year 5				81,503
Thereafter				730,663
Total				1,337,609
Power purchase
Commitments Disclosure [Line Items]
Year 1				46,536
Year 2				10,896
Year 3				11,114
Year 4				11,338
Year 5				11,566
Thereafter				191,208
Total				282,658
Gas supply and service agreements
Commitments Disclosure [Line Items]
Year 1				77,658
Year 2				51,349
Year 3				27,672
Year 4				24,422
Year 5				22,424
Thereafter				48,313
Total				251,838
Service agreements
Commitments Disclosure [Line Items]
Year 1				43,732
Year 2				39,093
Year 3				38,451
Year 4				37,463
Year 5				40,737
Thereafter				312,559
Total				512,035
Capital projects
Commitments Disclosure [Line Items]
Year 1				67,575
Year 2				1,663
Year 3				196
Year 4				7,330
Year 5				0
Thereafter				0
Total				76,764
Operating leases
Commitments Disclosure [Line Items]
Year 1				7,629
Year 2				7,154
Year 3				7,096
Year 4				7,076
Year 5				6,776
Thereafter				178,583
Total				214,314
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
Lawsuit vs. Mountain Water Company and City of Missoula
Commitments Disclosure [Line Items]
Fair value of condemned property			$ 88,600
Litigation settlement, amount		$ 83,863
Gain on long-lived assets				$ 4,370

Non-cash operating items - Chan

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	$ 3,005	$ (45,818)
Fuel and natural gas in storage	1,351	(4,385)
Supplies and consumables inventory	(7,189)	(1,864)
Income taxes recoverable	(763)	(557)
Prepaid expenses	2,907	(2,755)
Accounts payable	(22,915)	7,525
Accrued liabilities	28,687	14,041
Current income tax liability	2,974	(3,190)
Asset retirements and environmental obligations	(7,293)	(4,372)
Net regulatory assets and liabilities	(8,890)	(46,344)
Changes in non-cash operating items	$ (8,126)	$ (87,719)

Financial instruments - Fair V

Financial instruments - Fair Value of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value of Financial Instruments [Line Items]
Other long-term investments	$ 34,362	$ 37,271
Cross currency swap | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	93,198
Foreign exchange forward | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	0
Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	1,171
Interest rate swaps
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	8,473
Level 1
Fair Value of Financial Instruments [Line Items]
Other long-term investments	814,530
Total financial assets	814,530
Long-term debt	768,400	651,969
Convertible debentures	639	1,018
Total financial liabilities	769,039	652,987
Level 2
Fair Value of Financial Instruments [Line Items]
Notes receivable	110,019	38,192
Derivative financial instruments, assets	970	183
Total financial assets	110,989	38,375
Long-term debt	2,588,373	2,610,742
Convertible debentures	0
Derivative financial instruments, liabilities	102,785	68,867
Total financial liabilities	2,704,861	2,694,733
Level 2 | Energy contracts | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		109
Level 2 | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		31
Level 2 | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	93,198	57,412
Level 2 | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	869
Level 2 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	101	74
Derivative financial instruments, liabilities	1,114	2,620
Level 2 | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	8,473	8,460
Level 2 | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		344
Level 2 | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures		15,124
Preferred shares, Series C	13,703
Level 3
Fair Value of Financial Instruments [Line Items]
Notes receivable	0	0
Derivative financial instruments, assets	61,838	63,363
Total financial assets	61,838	63,363
Derivative financial instruments, liabilities	57	77
Total financial liabilities	57	77
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	61,838	63,363
Derivative financial instruments, liabilities	57	77
Level 3 | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		0
Level 3 | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	0
Portion at Other than Fair Value Measurement [Member] | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		441
Carrying amount
Fair Value of Financial Instruments [Line Items]
Notes receivable	103,696	33,378
Other long-term investments	814,530
Derivative financial instruments, assets	62,808	63,546
Total financial assets	981,034	96,924
Long-term debt	3,336,795	3,079,551
Convertible debentures	470	971
Derivative financial instruments, liabilities	102,842	68,944
Total financial liabilities	3,453,525	3,164,184
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	61,838	63,363
Derivative financial instruments, liabilities	57	77
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		109
Derivative financial instruments, liabilities		31
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	93,198	57,412
Carrying amount | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	869
Carrying amount | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	101	74
Derivative financial instruments, liabilities	1,114	2,620
Carrying amount | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	8,473	8,460
Carrying amount | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		344
Carrying amount | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures		14,718
Preferred shares, Series C	13,418
Fair value
Fair Value of Financial Instruments [Line Items]
Notes receivable	110,019	38,192
Other long-term investments	814,530
Derivative financial instruments, assets	62,808	63,546
Total financial assets	987,357	101,738
Long-term debt	3,356,773	3,262,711
Convertible debentures	639	1,018
Derivative financial instruments, liabilities	102,842	68,944
Total financial liabilities	3,473,957	3,347,797
Fair value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	61,838	63,363
Derivative financial instruments, liabilities	57	77
Fair value | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		109
Derivative financial instruments, liabilities		31
Fair value | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	93,198	57,412
Fair value | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	869
Fair value | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	101	74
Derivative financial instruments, liabilities	1,114	2,620
Fair value | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	8,473	8,460
Fair value | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		344
Fair value | Series C Preferred Stock
Fair Value of Financial Instruments [Line Items]
Convertible debentures		$ 15,124
Preferred shares, Series C	$ 13,703

Financial instruments - Additi

Financial instruments - Additional Information (Detail)	Mar. 24, 2017USD ($)	Oct. 25, 2016USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)$ / MWh	Dec. 31, 2017USD ($)	Jan. 01, 2019CAD ($)$ / MWh	Jan. 31, 2017USD ($)	Jan. 31, 2014USD ($)	Dec. 31, 2012USD ($)
Derivative [Line Items]
Other comprehensive income, foreign currency loss				$ 37,204,000	$ (17,817,000)
Other comprehensive income, foreign currency translation adjustment gain (loss)				$ (27,969,000)	(21,753,000)
Revenue collection period				45 days
Cash on hand				$ 46,819,000
Available for drawn on senior debt facilities				1,046,826,000
Utility Services
Derivative [Line Items]
Accounts receivable balances				207,740,000
Liberty Power Group
Derivative [Line Items]
Other comprehensive income, foreign currency translation adjustment gain (loss)				41,244,000	19,063,000
Bonds | Plan
Derivative [Line Items]
Debt instrument, term			10 years
Long-term debt			$ 135,000,000
Senior Debt
Derivative [Line Items]
Long-term debt					479,000,000
Par value	$ 750,000,000
Senior Unsecured Notes
Derivative [Line Items]
Long-term debt				3,336,795,000	3,079,551,000
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
Ten Year Foreign Exchange Forward
Derivative [Line Items]
Term of forward-starting interest rate swap		10 years
Notional amount		$ 250,000,000
Derivative, forward interest rate		1.8395%
Thirty Year Foreign Exchange Forward
Derivative [Line Items]
Term of forward-starting interest rate swap		30 years
Notional amount		$ 250,000,000
Derivative, forward interest rate		2.5539%
Forward contracts
Derivative [Line Items]
Other comprehensive income, foreign currency loss				1,115,000	$ (297,000)
Cash flow hedge | Interest rate swaps
Derivative [Line Items]
Term of forward-starting interest rate swap			10 years
Hedge ineffectiveness recognized in earnings				$ 898,000
Minimum
Derivative [Line Items]
Forward price | $ / MWh				14.55
Minimum | Senior Debt
Derivative [Line Items]
Debt instrument, term	3 years
Maximum
Derivative [Line Items]
Forward price | $ / MWh				172.97
Maximum | Senior Debt
Derivative [Line Items]
Debt instrument, term	30 years
Weighted Average
Derivative [Line Items]
Forward price | $ / MWh				24.72
Non-regulated Energy Sales
Derivative [Line Items]
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months				$ 6,289,000
Interest expense
Derivative [Line Items]
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months				$ 989,000
Accounts Receivable [Member] | Credit Concentration Risk [Member] | Liberty Power Group
Derivative [Line Items]
Percentage of revenue contributed				83.98471%
Subsequent Event | Bonds
Derivative [Line Items]
Long-term debt						$ 135,000,000
Subsequent Event | Interest Rate Contract [Member]
Derivative [Line Items]
Notional amount						$ 300,000,000
Derivative, forward interest rate						4.60%
Minonk Wind Facility | Subsequent Event | Cash flow hedge
Derivative [Line Items]
Notional quantity (MW-hrs) | $ / MWh						251,581,000
Receive average prices (per MW-hr) | $ / MWh						20.72

Financial instruments - Summar

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2018MMBTU
Swap
Derivative [Line Items]
Commodity volumes, Gas	2,366,386
Options
Derivative [Line Items]
Commodity volumes, Gas	300,000
Forward contracts
Derivative [Line Items]
Commodity volumes, Gas	6,560,000

Financial instruments - Impact

Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	$ 450,474	$ 441,526
Regulatory liabilities, natural gas derivative contracts	578,592	576,124
Swap
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	66	0
Regulatory liabilities, natural gas derivative contracts	218	287
Options
Derivative [Line Items]
Regulatory liabilities, natural gas derivative contracts	134	138
Forward contracts
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts	0	6,319
Regulatory liabilities, natural gas derivative contracts	$ 1,259	$ 0

Financial instruments - Long-t

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2018MWh$ / MWh
PJM Western HUB
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	871,391
Receive average prices (per MW-hr) | $ / MWh	36.33
PJM NI HUB
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,438,697
Receive average prices (per MW-hr) | $ / MWh	29.06
ERCOT North HUB
Derivative [Line Items]
Notional quantity (MW-hrs) | MWh	2,997,939
Receive average prices (per MW-hr) | $ / MWh	36.46

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, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge, gain (loss)	$ 1,567	$ 8,004
Amortization of cash flow hedge	(33)	(27)
Amounts reclassified from AOCI	(4,224)	(6,351)
Change in fair value of cash flow hedges, net of tax recovery of $952 and expense of $599, respectively (note 23(b)(ii))	$ (2,690)	$ 1,626

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, 2018	Dec. 31, 2017
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain on derivative financial instruments	$ (1,781)	$ 1,466
Total realized loss on derivative financial instruments	(1,115)	12,558
Ineffective portion of derivative financial instruments accounted for as hedges	33	27
Loss (gain) on derivative financial instruments	636	(1,918)
Gain (loss) on derivative instruments	(479)	10,640
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain on derivative financial instruments	(1,153)	(2,667)
Total realized loss on derivative financial instruments	42	12,670
Loss (gain) on derivative financial instruments not accounted for as hedges	(1,111)	10,003
Not Designated as Hedging Instrument | Interest rate swaps
Fair Value of Financial Instruments [Line Items]
Total realized loss on derivative financial instruments	0	(144)
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain on derivative financial instruments	77	(79)
Total realized loss on derivative financial instruments	(73)	553
Not Designated as Hedging Instrument | Foreign exchange forward
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain on derivative financial instruments	(1,230)	297
Total realized loss on derivative financial instruments	115	12,261
Not Designated as Hedging Instrument | Commodity contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized gain on derivative financial instruments	0	(2,885)
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Ineffective portion of derivative financial instruments accounted for as hedges	$ 632	$ 637

Financial instruments - Maximu

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2018 $ in Thousands, $ in Thousands	CAD ($)	USD ($)
Fair Value Disclosures [Abstract]
Cash and cash equivalents and restricted cash	$ 27,720	$ 45,452
Accounts receivable	13,562	241,068
Allowance for doubtful accounts	0	(5,281)
Notes receivable	138,353	2,279
Maximum exposure to credit risk for financial instruments	$ 179,635	$ 283,518

Financial instruments - Liabil

Financial instruments - Liabilities Mature (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Long-term debt obligations	$ 3,321,719
Convertible debentures	470
Advances in aid of construction	63,703
Interest on long-term debt	1,576,974
Purchase obligations	325,326
Environmental obligation	59,181	$ 57,292
Other obligations	155,758
Total obligations	5,605,973
Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	93,198
Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	8,473
Foreign exchange forward | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	1,171
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	334,855
Convertible debentures	0
Advances in aid of construction	1,205
Interest on long-term debt	156,768
Purchase obligations	325,326
Environmental obligation	4,158
Other obligations	33,350
Total obligations	870,000
Due less than 1 year | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	5,277
Due less than 1 year | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	8,473
Due less than 1 year | Foreign exchange forward | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Due less than 1 year | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	588
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	420,797
Interest on long-term debt	269,942
Environmental obligation	30,140
Other obligations	0
Total obligations	767,431
Due 2 to 3 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	46,026
Due 2 to 3 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Due 2 to 3 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	526
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	825,596
Interest on long-term debt	221,528
Environmental obligation	2,885
Other obligations	0
Total obligations	1,084,502
Due 4 to 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	34,436
Due 4 to 5 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Due 4 to 5 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	57
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	1,740,471
Convertible debentures	470
Advances in aid of construction	62,498
Interest on long-term debt	928,736
Environmental obligation	21,998
Other obligations	122,408
Total obligations	2,884,040
Due after 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	7,459
Due after 5 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	$ 0

Uncategorized Items - aqunf-201

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 2018-02 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (10,625,000)