Algonquin Power & Utilities (AQN) 40-F 15 Mar 16 2015 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015shares
Document Documentand Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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	255,869,419

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	CAD 124,353	CAD 9,273
Accounts receivable, net (note 4)	186,681	188,573
Natural gas in storage (note 1(h))	28,502	31,550
Regulatory assets (note 7)	32,213	61,645
Prepaid expenses	18,409	10,431
Derivative instruments (note 24)	15,039	10,688
Other current assets	18,537	15,359
Assets, current, total	423,734	327,519
Property, plant and equipment, net (note 5)	3,873,684	3,278,422
Intangible assets, net (note 6)	77,963	54,011
Goodwill (note 6)	110,493	92,328
Regulatory assets (note 7)	213,102	185,627
Derivative instruments (note 24)	73,322	31,782
Total long-term investments	174,802	43,279
Deferred income taxes (note 19)	18,109	64,275
Other assets (note 12)	26,516	25,605
Assets	4,991,725	4,102,848
Current liabilities:
Accounts payable	50,428	68,540
Accrued liabilities	193,320	199,374
Dividends payable (note 16)	41,802	25,395
Regulatory liabilities (note 7)	44,167	20,590
Long-term debt (note 9)	8,945	9,130
Other long-term liabilities and deferred credits (note 13)	36,621	49,303
Other liabilities	16,593	10,234
Liabilities, current, total	391,876	382,566
Long-term debt (note 9)	1,477,850	1,262,589
Regulatory liabilities (note 7)	131,180	101,166
Deferred income taxes (note 19)	175,799	134,460
Derivative instruments (note 24)	106,628	40,088
Pension and other post-employment benefits (note 10)	150,094	138,602
Other long-term liabilities (note 13)	223,135	177,235
Preferred shares, Series C (note 11)	17,548	17,608
Liabilities, noncurrent, total	2,282,234	1,871,748
Redeemable non-controlling interest (note 3(e))	25,751	12,146
Equity:
Preferred shares (note 14(b))	213,805	213,805
Common shares (note 14(a))	1,808,894	1,633,262
Subscription receipts (note 14(a)(ii))	110,503	110,503
Additional paid-in capital	38,241	33,068
Deficit	(523,116)	(505,305)
Accumulated other comprehensive income (note 15)	286,737	34,213
Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.	1,935,064	1,519,546
Non-controlling interests	356,800	316,842
Total Equity	CAD 2,291,864	CAD 1,836,388
Commitments and contingencies (note 22)
Liabilities and equity, total	CAD 4,991,725	CAD 4,102,848

Consolidated Statements of Oper

Consolidated Statements of Operations - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenue
Regulated electricity distribution	CAD 224,110	CAD 204,721
Regulated gas distribution	464,767	446,025
Regulated water reclamation and distribution	78,467	66,419
Non-regulated energy sales	222,581	202,300
Other revenue	37,930	22,149
Total revenue	1,027,855	941,614
Expenses
Operating expenses	278,561	234,038
Regulated electricity purchased	131,647	120,506
Regulated gas purchased	217,236	261,116
Non-regulated energy purchased	27,990	39,264
Administrative expenses	40,675	34,692
Depreciation and amortization	149,806	114,047
Gain on foreign exchange	(2,631)	(1,112)
Costs and Expenses, Total	843,284	802,551
Operating income from continuing operations	184,571	139,063
Interest expense	65,993	62,418
Interest, dividend, equity and other income	(9,095)	(7,758)
Other gains	(5,110)	0
Acquisition-related costs	1,832	2,552
Write-down of long-lived assets and loss on disposal	2,890	8,027
Loss (gain) on derivative financial instruments	(2,188)	1,375
Nonoperating Income (Expense)	54,322	66,614
Earnings (loss) before income taxes	130,249	72,449
Income tax expense (note 19)
Current	7,310	3,674
Deferred	36,403	13,133
Income tax expense	43,713	16,807
Earnings from continuing operations	86,536	55,642
Loss from discontinued operations, net of tax	(1,032)	(2,127)
Net earnings	85,504	53,515
Net loss attributable to non-controlling interests (note 18)	(31,976)	(22,186)
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	117,480	75,701
Series A and D Preferred shares dividend (note 16)	10,400	9,503
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	CAD 107,080	CAD 66,198
Basic net earnings per share from continuing operations (cad per share)	CAD 0.43	CAD 0.32
Basic net earnings per share (cad per share)	0.42	0.31
Diluted net earnings per share from continuing operations (cad per share)	0.42	0.32
Diluted net earnings per share (cad per share)	CAD 0.42	CAD 0.31

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net earnings	CAD 85,504	CAD 53,515
Other comprehensive income:
Foreign currency translation adjustment, net of tax recovery of $nil and $1,049, respectively (notes 1(v), 24(b)(iii) and 24(c))	289,035	104,183
Change in fair value of cash flow hedges’, net of tax expense of $12,010 and $6,589, respectively (note 24(b)(ii))	16,165	2,799
Change in unrealized appreciation in value of available-for-sale investments	(73)	1
Change in pension and other post-employment benefits, net of tax expense of $4,923 and tax recovery of $22,446, respectively (note 10)	7,571	(35,669)
Other comprehensive income, net of tax	312,698	71,314
Comprehensive income	398,202	124,829
Comprehensive income attributable to the non-controlling interests	28,198	7,077
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	CAD 370,004	CAD 117,752

Consolidated Statements of Com5

Consolidated Statements of Comprehensive Income (Parenthetical) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustment, tax expense (recovery)	CAD 0	CAD (1,049)
Change in fair value of cash flow hedges', tax expense	12,010	6,589
Change in pension and other post-employment benefits, tax expense (recovery)	CAD 4,923	CAD (22,446)

Consolidated Statement of Equit

Consolidated Statement of Equity - CAD CAD in Thousands	Total	Common shares	Preferred shares	Subscription receipts	Additional paid-in capital	Accumulated deficit	Accumulated OCI	Non- controlling interests
Beginning Balance at Dec. 31, 2013	CAD 1,465,961	CAD 1,351,264	CAD 116,546	CAD 0	CAD 7,313	CAD (488,406)	CAD (31,410)	CAD 510,654
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	53,515					75,701		(22,186)
Redeemable non-controlling interests not included in equity	(289)							(289)
Other comprehensive income	71,314						42,051	29,263
Dividends declared and distributions to non-controlling interests	(79,943)					(75,205)		(4,738)
Dividends and issuance of shares under dividend reinvestment plan	0	17,395				(17,395)
Contributions received from non-controlling interests	9,934							9,934
Shares issued pursuant to public offering, net of costs	263,869	263,869
Issuance of common shares under employee share purchase plan	734	734
Share-based compensation	3,203				3,203
Issuance of subscription receipts	110,503			110,503
Preferred shares, Series D	97,259		97,259
Acquisition of non-controlling interest	(159,672)				22,552		23,572	(205,796)
Ending Balance at Dec. 31, 2014	1,836,388	1,633,262	213,805	110,503	33,068	(505,305)	34,213	316,842
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	85,504					117,480		(31,976)
Redeemable non-controlling interests not included in equity	3,571							3,571
Other comprehensive income	312,698						252,524	60,174
Dividends declared and distributions to non-controlling interests	(108,555)					(105,929)		(2,626)
Dividends and issuance of shares under dividend reinvestment plan	0	29,302				(29,302)
Contributions received from non-controlling interests	10,815							10,815
Shares issued pursuant to public offering, net of costs	144,987	144,987
Issuance of common shares under employee share purchase plan	1,001	1,343			(282)	(60)
Share-based compensation	5,455				5,455
Ending Balance at Dec. 31, 2015	CAD 2,291,864	CAD 1,808,894	CAD 213,805	CAD 110,503	CAD 38,241	CAD (523,116)	CAD 286,737	CAD 356,800

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Operating Activities
Net earnings from continuing operations	CAD 86,536	CAD 55,642
Adjustments and items not affecting cash:
Depreciation and amortization	151,627	115,399
Deferred taxes	36,403	13,133
Unrealized loss (gain) on derivative financial instruments	(1,990)	3,046
Share-based compensation expense	5,455	3,203
Cost of equity funds used for construction purposes	(2,424)	(1,910)
Pension and post-employment expense	(3,333)	(2,050)
Write-down of long-lived assets and loss on disposal	1,781	8,463
Write-down of long-lived assets	220	0
Increase in deferred income	550	0
Changes in non-cash operating items (note 23)	(11,149)	(1,790)
Changes in non-cash operating items from discontinued operations	0	1,262
Cash used in discontinued operations	(1,806)	(1,682)
Net Cash Provided by (Used in) Operating Activities, Total	261,870	192,716
Financing Activities
Cash dividends on common shares	(79,121)	(57,848)
Cash dividends on preferred shares	(10,400)	(9,503)
Cash contributions from non-controlling interests	15,222	11,845
Production-based cash contributions from non-controlling interest	10,815	8,976
Cash distributions to non-controlling interests	(2,936)	(4,738)
Issuance of common shares, net of costs	144,694	261,452
Proceeds from subscription receipts	0	110,503
Issuance of preferred shares, net of costs	0	96,271
Acquisition of non-controlling interest	0	(127,121)
Increase in long-term debt	248,811	236,528
Decrease in long-term debt	(196,149)	(286,552)
Increase in other long-term liabilities	31,544	18,618
Decrease in other long-term liabilities	(6,182)	(3,091)
Net Cash Provided by (Used in) Financing Activities, Total	156,298	255,340
Investing Activities
Increase (decrease) in other assets	281	(13,785)
Distributions received in excess of equity income	1,386	264
Receipt of principal on notes receivable	29,273	280
Additions to property, plant and equipment	(204,195)	(432,373)
Acquisitions of long-term investments	(138,560)	(25,432)
Acquisitions of operating entities	(3,717)	(8,757)
Proceeds from sale of long-lived assets	5,516	26,535
Net Cash Provided by (Used in) Investing Activities, Total	(310,016)	(453,268)
Effect of exchange rate differences on cash	6,928	646
Increase (decrease) in cash and cash equivalents	115,080	(4,566)
Cash and cash equivalents, beginning of year	9,273	13,839
Cash and cash equivalents, end of year	124,353	9,273
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	69,610	57,098
Cash paid during the year for income taxes	6,153	2,571
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	44,834	25,568
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	CAD 30,645	CAD 18,129

Notes to the Consolidated Finan

Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2015
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 is a diversified generation, transmission and distribution utility company. The distribution business group operates in the United States under the name of Liberty Utilities Co. (“ Distribution Group ”) and provides rate regulated water, electricity and natural gas utility services. The generation business group operates under the name Algonquin Power Co. (“ Generation Group ”) and owns or has interests in a portfolio of non-regulated North American based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission business group operates under the name Liberty Utilities (Pipeline & Transmission) (“ Transmission Group ”) and invests in rate regulated electric transmission and natural gas pipeline systems in the United States and Canada.

Significant accounting policies

Significant accounting policies	12 Months Ended
	Dec. 31, 2015
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(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)). (c) Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets which 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 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 acquisitions 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. During the fourth quarter of each year, the Company assesses qualitative 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. 1. Significant accounting policies (continued) (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”). 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 (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”) 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 and requirements of ISO New England, Inc. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash as part of other assets (note 12) 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) Natural gas in storage Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents 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(c)) 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 recoverable value of 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 replacement cost. Supplies and consumables inventory is included in other current assets. 1. Significant accounting policies (continued) (j) Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority authorized and has committed to the funding of the 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. 2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071 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 13(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 2015 2014 2015 2014 Generation Group 3 - 60 3 - 60 32 35 Distribution Group 5 - 100 5 - 100 42 40 Equipment 5 - 50 5 - 50 14 14 Effective January 1, 2015, the Company changed the depreciation method from the straight-line method to 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. This change in the depreciation method results from having better information on the consumption of the benefits of certain individual components that are directly related to production and separately identified in the records of the Company. The change is being recognized prospectively.The impact of the change on the operating results for 2015 was a reduction of depreciation expense of $3,418 . The impact on basic and diluted net earnings per share for 2015 was an increase of $0.01 . The change is not expected to materially affect net earnings or net earnings per share on an annual basis. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Distribution 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) 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. Assets held and used: 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. Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell. 1. Significant accounting policies (continued) (l) 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(a) and (b)). 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. Total net book value of generating assets and long-term debt of these facilities amounts to $104,243 (2014 - $112,344 ) and $62,138 (2014 - $59,449 ), respectively. The debt only has recourse over the generating assets. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $18,651 (2014 - $11,218 ), operating expenses and amortization of $5,645 (2014 - $3,418 ) and interest expense of $4,407 (2014 - $3,820 ). (m) Long-term investments and notes receivable Investments in which APUC has significant influence but not control are accounted using the equity method. 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 investees in interest, dividend, equity and other income in the consolidated statements of operations. 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. 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. (n) Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, and other post-employment benefit (“OPEB”) 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 and OPEB 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. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses in the consolidated statements of operations. 1. Significant accounting policies (continued) (o) 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. (p) Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a 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 expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus is credited to common shares. (q) 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 and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units”) which 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 Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV method uses a balance sheet approach, which measures the allocation of income or loss of the Class A partnership units in each period by calculating the change in the amount of distribution the partners would contractually be entitled to based on a hypothetical liquidation of the book value carrying amounts of the entity at the beginning of a reporting period compared to the end of that period (note 18). Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity 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. 1. Significant accounting policies (continued) (r) Recognition of revenue Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered. Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas 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. Revenue for the Company’s Calpeco Electric System, Peach State Gas System and New England Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge 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 (note 7(e)). Water reclamation and distribution revenues are recorded 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. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue is recorded net of sales taxes. During the year, the Company settled insurance claims for business interruption at some of its generation facilities under repairs and as a result recognized revenue of $581 (2014 - $1,227 ). (s) Foreign currency translation The Company’s reporting currency is the Canadian dollar. The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian 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. (t) 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. Income tax credits are treated as a reduction to current 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. 1. Significant accounting policies (continued) (t) Income taxes (continued) 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. (u) 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 in 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 exposure, interest risk and price risk exposure 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. 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. 1. Significant accounting policies (continued) (v) 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 liabiliti

Recently issued accounting pron

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2015
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 2015-17 Income Taxes (Topic 740) to simplify the presentation of deferred income taxes. This ASU requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this ASU. The Company retrospectively adopted this ASU in the fourth quarter of 2015. As a result, a deferred tax asset and a deferred tax liability of $7,210 and $ 3,702 , respectively, that were presented as current as of December 31, 2014 have been reclassified to non-current deferred tax asset and deferred tax liability on the consolidated balance sheets. The FASB issued ASU 2015-13 Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This ASU clarifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The adoption of this ASU in the third quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-10, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the second quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-04, Compensation: Retirement Benefits (Subtopic 715), to provide a practical expedient that permits an entity with a fiscal year-end that does not coincide with a month-end and an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations to measure defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end or significant event. The Company adopted this ASU prospectively in the second quarter of 2015 and as a result, remeasured amendments to its pension plans, made during the second quarter, using the month-end closest to the amendments. The FASB issued ASU 2015-03, Interest: Imputation of Interest (Subtopic 835-30), to simplify presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. Effective January 1, 2015, the Company applied this ASU retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt. In accordance with ASU 2015-15 Interest: Imputation of Interest (Subtopic 835-30), the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments as other assets. The FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This newly issued accounting standard raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Effective January 1, 2015, the Company adopted this ASU prospectively and as a result, its adoption had no impact on discontinued operations reported in prior periods. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted 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 standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its 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 standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations.

Business acquisitions and devel

Business acquisitions and development projects	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Business acquisitions and development projects	Business acquisitions and development projects (a) Acquisition of Empire Subsequent to year-end, on February 9, 2016, the Company entered into an agreement and plan of merger pursuant to which, a subsidiary of Liberty Utilities Co. will merge with and into The Empire District Electric Company and its subsidiaries (“Empire”), and Empire will survive the merger and become a wholly owned indirect subsidiary of the Company. Empire is a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. Empire shareholders will receive U.S. $34.00 per common share in cash, which represents an aggregate purchase price of approximately $3,400,000 (U.S. $2,400,000 ), which includes the assumption of approximately $1,300,000 (U.S. $900,000 ) of debt. The closing of the acquisition, which is expected to occur in early 2017, is subject to customary closing conditions, including the approval of Empire’s common shareholders, and the receipt of certain state and federal regulatory and government approvals. On February 9, 2016, the Company obtained a $2,200,000 (U.S. $1,600,000 ) bridge financing commitment for the acquisition from a syndicate of banks (note 9). On March 1, 2016, the Company issued $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures represented by instalment receipts (the “Debentures” or the “Debenture Offering”) and received the first instalment of $333,000 . On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures and received the first instalment of $49,950 . The Debentures are expected to convert to common shares of the Company upon the closing of the acquisition of Empire (note 25). (b) Acquisition of Park Water System Subsequent to year-end, on January 8, 2016, the Company completed the acquisition of Western Water Holdings, LLC which is the parent company of Park Water Company (“Park Water System”), a regulated water distribution utility. Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. The total purchase price for the Park Water System is U.S. $341,750 , including debt assumed of U.S. $91,750 and is subject to certain closing adjustments. All costs related to the acquisition have been expensed through the consolidated statements of operations. Due to the timing of the acquisition, the Company has not completed the fair value measurements of the assets acquired and liabilities assumed. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the City of Missoula will ultimately take possession of Mountain Water Company. The City’s right to take Mountain Water Company is currently on appeal before the Montana Supreme Court, which is set to hear the appeal on April 22, 2016. If the City of Missoula prevails on appeal and ultimately takes possession of Mountain Water Company, the compensation to be paid by the City of Missoula for such taking will be the value of the utility plus accrued interest and attorney’s fees as determined by the Montana court. (c) Commercial operation of Morse Wind Facility In 2015, the Company completed construction of a 23 MW wind generating facility located near Morse, Saskatchewan (“Morse Wind Facility”). Sale of power to the utility commenced in March 2015 at rates equivalent to those under the power purchase agreement. Commercial operation date as defined in the power purchase agreement occurred on April 22, 2015. The cost of the generating assets of $65,016 is recorded as property, plant and equipment on the consolidated balance sheets while $16,709 is recorded as intangible Assets, for a total investment of $81,725 . The weighted average useful life of the Morse Wind Facility is 35 years. 3. Business acquisitions and development projects (continued) (d) Acquisition of New Hampshire Gas On January 2, 2015, the Distribution Group completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System is U.S. $3,161 . (e) Commercial operation of Bakersfield Solar I Facility In 2014, the Company completed construction a 20 MWac solar powered generating facility located in Kern County, California (“Bakersfield I Solar Facility”) which was placed in service on December 31, 2014. The Bakersfield I Solar Facility started selling power at the power purchase agreement price on May 15, 2015. The cost of these generating assets amounts to U.S.$ 57,160 and is recorded as property, plant and equipment on the consolidated balance sheets. The cost of the original development project is subject to certain adjustments which are expected to be finalized in 2016. The weighted average useful life of the Bakersfield Solar I Facility is 34 years. The Bakersfield I Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield I Partnership”). The Class A partnership units are owned by a third-party (the “Tax Equity Investor”) who funded a total of U.S. $22,438 to the project. With its partnership interest, the Tax Equity Investor will receive the majority of the tax attributes associated with the project. During a six-month period in year 2020, the Tax Investor has the right to withdraw from the Bakersfield I Solar Facility 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. Redemption is not considered probable as of December 31, 2015. (f) Commercial operation of Saint-Damase Wind Facility In 2014, the Company completed construction of a 24 MW wind powered generating facility located near St. Damase, Quebec (“Saint-Damase Wind Facility”) which achieved commercial operation on December 2, 2014. The cost of these generating assets amounts to $64,155 and is recorded as property, plant and equipment on the consolidated balance sheets. The weighted average useful life of the Saint-Damase Wind Facility is 34 years. (g) Acquisition of White Hall Water System On May 30, 2014, the Distribution Group acquired the assets of the White Hall Water System, a regulated water distribution and wastewater treatment utility located in White Hall, Arkansas. The White Hall Water System serves approximately 1,900 water distribution and 2,400 wastewater treatment customers. Total purchase price for the White Hall Water System assets, adjusted for certain working capital and other closing adjustments, is approximately U.S. $4,499 . (h) Acquisition of non-controlling interest in U.S. wind farms On March 31, 2014 , the Company acquired the 40% interest in Wind Portfolio SponsorCo, LLC (“Wind Portfolio SponsorCo”) for approximately U.S. $115,000 . Wind Portfolio SponsorCo indirectly holds the interests in Sandy Ridge, Senate and Minonk Wind acquired in 2012. As a result of the transaction, the Generation Group now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units resulting in the elimination of the non-controlling interest in respect of the Class B partnership units of Wind Portfolio SponsorCo as follows: Elimination of non-controlling interest in Class B partnership units $ 205,796 Non-controlling interest portion of currency translation adjustment recorded to AOCI (21,029 ) Non-controlling interest portion of unrealized gain on cash flow hedges recorded to AOCI (2,543 ) Decrease in deferred income tax asset (32,551 ) Additional paid-in capital (22,552 ) Cash $ 127,121 3. Business acquisitions and development projects (continued) (i) Commercial operation of Cornwall Solar Facility In 2014, the Company completed the construction of a 10 MWac solar powered generating facility located near Cornwall, Ontario (“Cornwall Solar Facility”) which achieved commercial operation on March 27, 2014. The cost of these generating assets of $40,090 is recorded as property, plant and equipment while $7,243 is recorded as intangible assets, for a total investment of $47,333 . The weighted average useful life of the Cornwall Solar Facility is 33 years. (j) Acquisition of New England Gas System On December 20, 2013 , the Company acquired certain regulated natural gas distribution utility assets (the “New England Gas System”) located in the State of Massachusetts. Total purchase price for the New England Gas System, net of the debt assumed, is $67,010 (U.S.$ 62,745 ), including the purchase price adjustment of U.S. $3,108 finalized in 2014. In 2014, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed. The key retrospective adjustments to the assets and liabilities were an increase to the regulatory asset for pension of U.S. $2,701 , a decrease of property, plant and equipment of U.S. $1,190 , an increase of the environmental obligation of U.S. $2,467 and an increase of the pension obligation of U.S. $772 . (k) Acquisition of Shady Oaks Wind Facility Effective January 1, 2013 , the Company acquired the 109.5 MW Shady Oaks wind-powered generating facility (“Shady Oaks Wind Facility”). The purchase agreement provides for final purchase price adjustments based on working capital at the acquisition date, energy generated by the project and basis differences between the relevant node and hub prices which are expected to be finalized in 2016. Changes in measurement of the final purchase price adjustment subsequent to December 31, 2013, the end of the business combination measurement period, are recorded in current period operations. To that effect, no gain or loss was recognized in 2015 (2014 - U.S. $1,133 ).

Accounts receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivable Accounts receivable as of December 31, 2015 include unbilled revenue of $49,002 (2014 - $52,880 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2015 are presented net of allowance for doubtful accounts of $7,966 (2014 - $7,229 ).

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, plant and equipment	Property, plant and equipment Property, plant and equipment consist of the following: 2015 Cost Accumulated depreciation Net book value Generation $ 2,138,748 $ 358,200 $ 1,780,548 Distribution 2,075,059 265,741 1,809,318 Land 23,258 — 23,258 Equipment and other 129,555 37,443 92,112 Construction in progress Generation 64,779 — 64,779 Distribution 103,669 — 103,669 $ 4,535,068 $ 661,384 $ 3,873,684 5. Property, plant and equipment (continued) 2014 Cost Accumulated Net book Generation $ 1,827,247 $ 270,746 $ 1,556,501 Distribution 1,555,289 147,726 1,407,563 Land 19,347 — 19,347 Equipment and other 119,367 29,526 89,841 Construction in progress Generation 82,840 — 82,840 Distribution 122,330 — 122,330 $ 3,726,420 $ 447,998 $ 3,278,422 Generation assets include cost of $158,514 ( 2014 - $155,629 ) and accumulated depreciation of $38,507 ( 2014 - $34,013 ) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,117 ( 2014 - $2,274 ). Investments tax credits, government grants and contributions received in aid of construction of $9,623 ( 2014 - $362 ) have been credited to the cost of the assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return.

Intangible assets and goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and goodwill	Intangible assets and goodwill Intangible assets consist of the following: 2015 Cost Accumulated amortization Net book value Power sales contracts $ 78,725 $ 40,244 $ 38,481 Customer relationships 37,083 10,371 26,712 Interconnection agreements 13,000 230 12,770 $ 128,808 $ 50,845 $ 77,963 2014 Cost Accumulated Net book Power sales contracts $ 64,605 $ 33,704 $ 30,901 Customer relationships 31,094 7,984 23,110 Interconnection agreements — — — — $ 95,699 $ 41,688 $ 54,011 Estimated amortization expense for intangible assets for the next year is $5,420 , $3,620 in year two, $3,250 in year three, $3,200 in year four and $3,160 in year five. 6. Intangible assets and goodwill (continued) Changes in goodwill are as follows: Distribution Group Balance, January 1, 2014 $ 84,647 Foreign exchange 7,681 Balance, December 31, 2014 $ 92,328 Business acquisitions 290 Foreign exchange 17,875 Balance, December 31, 2015 $ 110,493

Regulatory matters

Regulatory matters	12 Months Ended
	Dec. 31, 2015
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. 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. On February 18, 2016, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S. $2,725 revenue increase effective March 1, 2016. On February 10, 2016, the New England Gas System received a Final Order from the Massachusetts Department of Public Utilities approving an annual revenue increase of U.S. $7,800 effective March 1, 2016. On June 26, 2015, the EnergyNorth Gas System received a Final Order from the New Hampshire Public Utility Commission approving a settlement agreement allowing for a U.S. $12,400 revenue increase effective July 1, 2015. On March 12, 2015, the Pine Bluff Water System received a Final Order from the Arkansas Public Service Commission approving a revenue increase of U.S. $1,087 effective March 15, 2015. On February 11, 2015, the Midstates Gas System received a Final Order from the Illinois Commerce Commission approving a rate increase of U.S. $4,625 effective February 20, 2015. On March 17, 2014, the Granite State Electric System received a Final Order from the New Hampshire Public Utilities Commission approving a rate increase of U.S. $10,875 consisting of U.S. $9,760 in base rates and an additional U.S. $1,115 for incremental capital expended after the test year. In addition, the Order allows for a one time recovery of rate case expenses of U.S. $390 . The new rates were effective as of April 1, 2014 for services rendered on and after July 1, 2013. On April 18, 2014, the LPSCo Water System received a Final Order from the Arizona Corporation Commission approving a rate increase of U.S. $1,767 in connection with its rate application filed on February 28, 2013. The new rates became effective on May 1, 2014. In May 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S. $3,235 in connection with its annual GRAM filing on October 1, 2013. The new rates were effective as of June 1, 2014 for services rendered on and after February 1, 2014. On December 3, 2014, the Midstates Gas System received a Final Order from the Missouri Public Service Commission approving a rate increase of U.S. $4,868 effective January 2, 2015. On December 4, 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S. $3,680 in connection with its annual GRAM filing on October 1, 2014. The new rates are effective as of February 1, 2015. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2015 2014 Regulatory assets Environmental remediation (a) $ 116,747 $ 102,735 Pension and post-employment benefits (b) 69,537 63,512 Commodity costs adjustment (c) 7,643 41,502 Rate case costs (d) 6,535 4,161 Rate adjustment mechanism (e) 14,804 6,207 Other 30,049 29,155 Total regulatory assets $ 245,315 $ 247,272 Less current regulatory assets (32,213 ) (61,645 ) Non-current regulatory assets $ 213,102 $ 185,627 Regulatory liabilities Cost of removal (f) $ 107,988 $ 78,013 Rate-base offset (g) 24,984 23,427 Commodity costs adjustment (c) 32,423 10,389 Other 9,952 9,927 Total regulatory liabilities $ 175,347 $ 121,756 Less current regulatory liabilities (44,167 ) (20,590 ) Non-current regulatory liabilities $ 131,180 $ 101,166 (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(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. An amount of $32,313 relates to a recent acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future services 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. (c) Commodity costs adjustment The revenue of the electric and natural gas utilities includes a component which is designed to recover the cost of electricity or natural gas through rates charged to customers. Under deferred energy accounting, to the extent actual natural gas and purchased power costs differ from natural gas and purchased power 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 natural gas or electricity in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. 7. Regulatory matters (continued) (d) Rate case costs The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Peach State Gas System and New England Gas Systems 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 collected over a period not exceeding 24 months is accrued upon approval of the Final Order. (f) 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. (g) Rate-base offset The regulators imposed a rate-base offset that would reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of ten years. As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company earns carrying charges on the regulatory balances related to commodity cost adjustment and rate case costs.

Long-term investments

Long-term investments	12 Months Ended
	Dec. 31, 2015
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term investments	Long-term investments Long-term investments consist of the following: 2015 2014 Equity-method investees 50% interest in Odell Wind Project Joint Venture (a) $ 42,287 $ 2,267 50% interest in Deerfield Wind Project Joint Venture (b) 2,240 — Interests in natural gas pipeline developments (c) 5,623 1,063 Other 2,323 3,268 $ 52,473 $ 6,598 Available-for-sale investment $ 2,946 $ 137 Notes receivable Development loans (d) $ 96,924 $ 17,582 Red Lily Senior loan Tranche 2, interest at 6.31% (e) 11,588 11,588 Red Lily Subordinated loan Tranche 1, interest at 12.5% (e) 6,565 6,565 Other 4,306 3,775 119,383 39,510 Total long-term investments 174,802 46,245 Less current portion — (2,966 ) Total long-term investments $ 174,802 $ 43,279 8. Long-term investments (continued) (a) Odell Wind Project Joint Venture On November 14, 2014, the Company acquired a 50% equity interest in Odell SponsorCo LLC (“Odell SponsorCo”), which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Project”) in the state of Minnesota. The total construction costs of the Odell Wind Project are estimated to be U.S. $322,766 . The two members each contributed U.S. $1,000 to the capital of Odell SponsorCo on acquisition and another U.S. $23,800 on October 6, 2015. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, within 30 days of commencement of operations, which is expected in 2016. The interest capitalized during the year to the investment while the Odell Wind Project is under construction amounts to $4,415 (2014 - nil ). As of December 31, 2015, Odell SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Odell SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $190,840 as of December 31, 2015. (b) Deerfield Wind Project Joint Venture On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan. The total construction costs of the Deerfield Wind Project are estimated to be U.S. $303,000 . Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in 2016, each party will contribute another U.S. $18,596 plus accrued interest at 7% to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations, which is expected in late 2016. The interest capitalized during the year to the investment while the Deerfield Wind Project is under construction amounts to $94 . As of December 31, 2015, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $321,472 as of December 31, 2015. (c) Natural gas pipeline developments In December 2015, APUC acquired a 4.0% interest in Northeast Supply Pipeline LLC with an option to increase its participation to 10% . Northeast Supply LLC is a new entity undertaking the development, construction and ownership of natural gas transmission pipeline to be constructed between the Bradford and Susquehanna counties in Pennsylvania and Wright, NY. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 4.0% in a limited liability corporation together with the option to increase its participation to 10% provide significant influence. As such, the interest is accounted as an equity method investment. 8. Long-term investments (continued) (c) Natural gas pipeline developments (continued) In November 2014, APUC acquired a 2.5% interest in Northeast Expansion LLC with an option to increase its participation to 10% . Northeast Expansion LLC is a new entity undertaking the development, construction and ownership of a natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 2.5% in a limited liability corporation together with the option to increase its participation to 10% and the commitment from its New Hampshire subsidiary to a firm gas transportation agreement for service on the pipeline facilities provide significant influence. As such, the interest is accounted as an equity method investment. The total capital investment assuming the Company exercises its right to subscribe for 10% of each pipeline is estimated to be U.S. $520,000 . As of December 31, 2015, APUC had invested U.S. $4,063 (2014 - U.S. $375 ) in the pipeline projects. (d) Development loans The Company entered into a committed loan and credit support facility with Odell SponsorCo and Deerfield SponsorCo (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with 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 Joint Ventures’ Wind Projects. The loan bears interest at an annual rate of 7% - 8% on outstanding principal amount until commercial operation date and 5% thereafter until maturity date, and the letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date. As of December 31, 2015, the Company had outstanding loans of U.S. $62,751 from Odell SponsorCo and U.S. $7,281 from Deerfield SponsorCo for development costs of the Joint Ventures’ Wind Projects. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. As of December 31, 2015, the following credit support was issued by the Company: a U.S. $15,000 letter of credit on behalf of the Odell Wind Project, to the utility under the PPA; a U.S. $1,119 letter of credit on behalf of the the Odell Wind Project pursuant to the generator interconnection agreement; guarantee of the obligations of the Joint Ventures under the wind turbine supply agreements; guarantee of the obligations of the Deerfield Wind Project under the power purchase agreement and decommissioning plan; and, a U.S. $43,238 letter of credit and guarantee of the obligations of Deerfield SponsorCo, to the vendor under the membership interest purchase and contribution agreement. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at U.S. $1,147 using a probability weighted discounted cash flow (level 3). (e) Red Lily I The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. APUC provides operation and supervision services to the Red Lily I project, a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in Red Lily I is in the form of participation in a portion of the senior and subordinated debt facilities to the Partnership. The senior debt facility consists of two tranches. A third-party lender advanced $27,000 of senior debt to the Partnership as Tranche 1. In 2011, APUC advanced $13,000 of senior debt as Tranche 2 to the Partnership and received a pre-payment of $1,412 in 2012. The third-party lender has also advanced $4,000 of senior debt Tranche 2 to the Partnership. The Company’s senior loan Tranche 2 to the Partnership earned interest at the rate of 6.31% and was replaced by subordinated debt Tranche 2 on February 23, 2016 as described below. Both tranches of senior debt are secured by substantially all the assets of the Partnership on a pari passu basis. The subordinated loan earns an interest rate of 12.5% , and the principal matures in 2036 but is repayable by the Partnership in whole or in part at any time after 2016 , without a pre-payment premium. The subordinated loan is secured by substantially all the assets of the Partnership but is subordinated to the senior debt. 8. Long-term investments (continued) (e) Red Lily I (continued) Subsequent to year-end, on February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced by the Company. The proceeds from this additional subordinated debt were used by Red Lily I to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion. In connection with the subordinated debt facility, the Company has an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans, exercisable for a period of 90 days commencing on February 24, 2016. The above notes are secured by the underlying assets of the respective facilities.

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-term debt	Long-term debt Long-term debt consists of the following: 2015 2014 Generation Group $350,000 revolving credit facility, interest rate is equal to bankers’ acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is BA or LIBOR plus 1.45%, maturing July 31, 2019. $ 27,300 $ 23,400 Algonquin Power Co.: 481,991 481,438 Shady Oaks Wind Facility: U.S.$76,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points. This facility was repaid in May 2015. — 88,168 Long Sault Hydro Facility: Senior Debt: $34,760 bonds bearing an interest rate of 10.21%, maturing December 31, 2027. The bonds have interest and principal payments, payable monthly in arrears. 34,760 35,997 Chuteford Hydro Facility: Senior Debt: $2,587 bonds bearing an interest rate of 11.55%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears. 2,587 3,022 Distribution Group U.S.$200,000 revolving credit facility, interest rate is equal to LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.25%, maturing September 30, 2018. — 23,898 Liberty Utilities Co.: U.S.$ 50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S.$ 25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S.$115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S.$ 15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S.$ 75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; U.S.$ 60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S.$ 25,000, bearing an interest rate of 4.26%, maturing July 31, 2028; U.S.$ 90,000, bearing an interest rate of 4.13%, maturing April 30, 2045; U.S.$ 70,000, bearing an interest rate of 4.13%, maturing July 15, 2045. The notes have interest only payments, payable semi-annually. 721,581 419,876 2015 2014 Calpeco Electric System: U.S.$45,000 bearing an interest rate of 5.19%, maturing December 29, 2020; U.S.$25,000 bearing an interest rate of 5.59%, maturing December 29, 2025. The notes have interest only payments, payable semi-annually in arrears. 96,015 80,368 Liberty Water Co: Senior Unsecured Notes: U.S.$50,000 bearing an interest rate of 5.60% $5,000 matures annually beginning June 20, 2016; $25,000 maturing December 22, 2020. The note bears interest payments semi-annually in arrears. 68,488 57,301 New England Gas System: U.S.$6,500, bearing an interest rate of 9.44%, maturing February 15, 2020; U.S.$7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; U.S.$6,000, bearing an interest rate of 7.24%, maturing December 15, 2027. The notes have interest only payments, payable semi-annually in arrears. 32,130 27,288 Granite State Electric System: Senior Unsecured Notes: U.S.$5,000, bearing an interest rate of 7.37%, maturing November 1, 2023; U.S.$5,000, bearing an interest rate of 7.94%, maturing July 1, 2025; U.S.$5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually. 20,730 17,373 LPSCo Water System: 1999 and 2001 IDA bonds bearing interest rates of 5.85% and 6.71%. This facility was repaid in October 2015. — 12,441 Bella Vista Water System: U.S.$877 Water Infrastructure Financing Authority of Arizona loans bearing interest rates of 6.26% and 6.10%, and maturing March 1, 2020 and December 1, 2017, respectively. The loans have principal and interest payments, payable monthly and quarterly in arrears. 1,213 1,149 $ 1,486,795 $ 1,271,719 Less: current portion (8,945 ) (9,130 ) $ 1,477,850 $ 1,262,589 9. Long-term debt (continued) Certain long-term debt issued at a subsidiary level relating to a specific operating facility is secured by the respective facility with no other recourse to the Company. The loans have 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. Effective January 1, 2015, the Company applied ASU 2015-03 (note 2(a)) retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt in the table above. Generation Group On October 30, 2015, the Generation Group entered into a new extendible one -year letter of credit facility agreement. The new facility expands the group’s available liquidity by providing for issuances of letters of credit up to a maximum of $50,000 and U.S. $30,000 . If the facility is not extended at maturity, cash collateral equal to letters of credit outstanding at that date would be posted by the Company. On May 12, 2015, the U.S. $76,000 senior debt for the Shady Oaks Wind Facility was repaid. On December 31, 2014, the U.S. $19,200 senior debt for the Sanger thermal facility was repaid. On July 31, 2014, the Company increased the credit available under the senior unsecured revolving credit facility to $350,000 from $200,000 . The larger revolving credit facility will be used to provide additional liquidity in support of the Generation Group ’s development portfolio to be completed over the next three years. The maturity of the revolving credit facility has been extended to July 31, 2018. On May 27, 2015, the Generation Group extended the maturity of its senior unsecured revolving credit facility one year to July 31, 2019 with all other terms remaining the same. On January 17, 2014, the Company issued $200,000 senior unsecured debentures bearing interest at 4.65% and with a maturity date of February 15, 2022. The debentures were sold at a price of $99.864 per $100.00 principal amount. Interest payments are payable on February 15 and August 15 each year, commencing on February 15, 2014. The Company incurred deferred financing costs of $1,568 , which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, the Company entered into a cross currency swap, coterminous with the debentures, to economically 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 Company’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, an economic hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment (note 24(b)(iii)). Distribution Group On October 1, 2015, the U.S. $9,800 LPSCo Water System IDA bonds were fully repaid. On April 30, 2015, the Distribution Group issued U.S. $160,000 of senior unsecured 30 -year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing will be used in connection with the acquisition of the Park Water System and for general corporate purposes. The funds were drawn in two tranches: U.S. $90,000 was drawn on closing and U.S. $70,000 was drawn on July 15, 2015. 9. Long-term debt (continued) Corporate APUC has a senior unsecured revolving credit of U.S. $65,000 . subsequent to year end the maturity date of the facility was extended by one year to November 19, 2017. As of December 31, 2015 and 2014, no amounts were outstanding under this revolving credit facility. Subsequent to year-end, on February 9, 2016, in connection with the acquisition of Empire (note 3 (a)), the Company obtained $2,200,000 (U.S. $1,600,000 ) in bridge financing commitments from a syndicate of banks. The non-revolving term credit facilities are comprised of a U.S. $1,065,000 debt bridge facility, repayable in full on the first anniversary following its advance, and a U.S. $535,000 equity bridge facility repayable in full on the first anniversary following its advance. On March 1, 2016, upon issuing the Debentures (including the overallotment) (note 25) and receiving the First Instalment, the Company reduced its bridge commitments by $359,950 . Subsequent to year-end, on January, 4, 2016, a subsidiary of APUC entered into a U.S. $235,000 term credit facility with two U.S. banks. The term credit facility is available for acquisitions and general corporate purposes and matures on July 5, 2017. As of December 31, 2015, the Company had accrued $25,161 in interest expense (2014 - $18,770 ). Interest expense on the long-term debt in 2015 was $72,213 (2014 - $64,218 ). Principal payments due in the next five years and thereafter are as follows: 2016 2017 2018 2019 2020 Thereafter Total Generation Group $ 1,816 $ 2,045 $ 137,272 $ 30,152 $ 2,641 $ 375,415 $ 549,341 Distribution Group 7,129 76,358 7,135 7,149 147,640 701,371 946,782 Total $ 8,945 $ 78,403 $ 144,407 $ 37,301 $ 150,281 $ 1,076,786 $ 1,496,123

Pension and other post-retireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [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 2015 were $ 4,132 (2014 - $ 3,287 ). In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension 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 2015 2014 2015 2014 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 241,963 $ 178,113 $ 68,257 $ 45,399 Projected benefit obligation assumed from business combination — 1,022 — — Modifications to pension plan (4,995 ) (560 ) — — Service cost 6,663 4,828 3,093 2,022 Interest cost 9,642 8,549 2,914 2,186 Actuarial loss (gain) (16,098 ) 39,704 (8,466 ) 14,893 Contributions from retirees — — 412 331 Benefits paid (13,024 ) (8,125 ) (2,447 ) (1,586 ) Loss on foreign exchange 45,231 18,432 12,802 5,012 Projected benefit obligation, end of year $ 269,382 $ 241,963 $ 76,565 $ 68,257 Change in plan assets Fair value of plan assets, beginning of year 156,990 139,280 14,295 13,395 Actual return (loss) on plan assets (5,657 ) 6,568 20 1,176 Employer contributions 7,975 5,676 3,028 (222 ) Benefits paid (12,589 ) (7,414 ) (2,036 ) (1,255 ) Gain on foreign exchange 29,453 12,880 2,842 1,201 Fair value of plan assets, end of year $ 176,172 $ 156,990 $ 18,149 $ 14,295 Unfunded status $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) Amounts recognized in the consolidated balance sheets consists of: Current liabilities (470 ) — (1,062 ) (333 ) Non-current liabilities (92,740 ) (84,973 ) (57,354 ) (53,629 ) Net amount recognized $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) The accumulated benefit obligation for the pension plans was $251,932 and $219,007 as of December 31, 2015 and 2014 , respectively. During 2015, the Company permanently froze the accrual of retirement benefits for union participants and most non-union participants under existing plans, effective December 31, 2015 and March 31, 2015, respectively. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of U.S. $3,941 which is recorded as a prior service credit in OCI. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation (continued) The amounts recognized in OCI before tax were as follows: AOCI Pension OPEB Balance, January 1, 2014 $ (14,385 ) $ (9,083 ) Current year net actuarial gain 43,350 14,338 Current year prior service loss (563 ) — Amortization of net actuarial loss 349 641 Balance at December 31, 2014 $ 28,751 $ 5,896 Current year net actuarial loss 1,505 (7,554 ) Current year prior service credits (4,864 ) — Amortization of net actuarial gain (1,358 ) (680 ) Amortization of prior service credits 457 — Balance at December 31, 2015 $ 24,491 $ (2,338 ) The net actuarial loss for the defined benefit pension plans and OPEB that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $632 and $88 , respectively. (b) Assumptions Weighted average assumptions used to determine net benefit cost for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 3.71 % 4.55 % 3.82 % 4.60 % Expected return on assets 6.44 % 7.00 % 5.50 % 5.53 % Rate of compensation increase 3.01 % 2.97 % N/A N/A Health care cost trend rate Before Age 65 7.00 % 7.63 % Age 65 and after 7.00 % 7.63 % Assumed Ultimate Medical Inflation Rate 5.00 % 5.00 % Year in which Ultimate Rate is reached 2019 2019 Weighted average assumptions used to determine net benefit obligation for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 4.16 % 3.71 % 4.23 % 3.80 % Rate of compensation increase 3.00 % 3.01 % N/A N/A Health care cost trend rate Before Age 65 6.50 % 7.00 % Age 65 and after 6.50 % 7.00 % Assumed Ultimate Medical Inflation Rate 4.75 % 5.00 % Year in which Ultimate Rate is reached 2023 2019 10. Pension and other post-employment benefits (continued) (b) Assumptions (continued) The mortality assumption for December 31, 2015 was updated to the projected generationally scale MP-2015, adjusted to reflect the ultimate improvement rates in the 2015 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. The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2015 is as follows: 2015 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 10,763 Total service and interest cost 1,111 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (8,687 ) Total service and interest cost (871 ) (c) Benefit costs The following table lists the components of net benefit costs 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 2015 2014 2015 2014 Service cost $ 6,663 $ 4,828 $ 3,093 $ 2,022 Interest cost 9,642 8,549 2,914 2,186 Expected return on plan assets (11,989 ) (10,018 ) (713 ) (628 ) Amortization of net actuarial loss (gain) 1,398 (346 ) 510 (641 ) Amortization of prior service credits (471 ) — — — Net benefit cost $ 5,243 $ 3,013 $ 5,804 $ 2,939 (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 74 % 49% - 78% Debt securities 26 % 22% - 51% Other — % 0% - 1% 10. Pension and other post-employment benefits (continued) (d) Plan assets (continued) The fair values of investments as of December 31, 2015, by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 138,993 72 % Debt securities 54,542 28 % Other 787 — % As of December 31, 2015, the funds do not hold any material investments in APUC. (e) Cash flows The Company expects to contribute $9,232 to its pension plans and $4,237 to its post-employment benefit plans in 2016. The expected benefit payments over the next ten years are as follows: 2016 2017 2018 2019 2020 2021-2025 Pension plan $ 15,037 $ 13,829 $ 14,474 $ 15,120 $ 15,692 $ 88,692 OPEB 3,113 3,375 3,584 3,804 4,396 25,720

Mandatorily redeemable Series C

Mandatorily redeemable Series C preferred shares	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Mandatorily redeemable Series C preferred shares	Mandatorily redeemable Series C preferred shares 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 $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 $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: 2016 $ 979 2017 908 2018 1,068 2019 1,282 2020 1,344 Thereafter to 2031 18,516 Redemption amount 5,340 29,437 Less amounts representing interest (10,910 ) 18,527 Less current portion (979 ) $ 17,548

Other assets

Other assets	12 Months Ended
	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other assets	Other assets Other assets consist of the following: 2015 2014 Restricted cash $ 18,999 $ 18,702 Deferred financing costs 3,211 2,428 Other 4,770 4,475 26,980 25,605 Less current portion (464 ) — $ 26,516 $ 25,605

Other long-term liabilities and

Other long-term liabilities and deferred credits	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits Other long-term liabilities consist of the following: 2015 2014 Advances in aid of construction (a) $ 92,285 $ 81,104 Environmental remediation obligation (b) 71,529 70,072 Asset retirement obligations (c) 17,799 13,884 Customer deposits (d) 15,074 11,713 Deferred income (e) 13,682 13,132 Deferred credits (f) 24,110 19,130 Other 25,277 17,503 259,756 226,538 Less current portion (36,621 ) (49,303 ) $ 223,135 $ 177,235 (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 10 to 20 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 2015, $4,637 (2014 - $4,608 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems 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 historic 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 $78,495 (2014 - $72,594 ) which at discount rates ranging from 2.5% to 4.2% represents the recorded accrual of $71,529 as of December 31, 2015 (2014 - $70,072 ). Approximately $46,929 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 29 years. 13. Other long-term liabilities and deferred credits (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072 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, 2015, the Company has reflected a regulatory asset of $116,747 (2014 - $102,735 ) 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 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; and (iv) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC recorded additional asset retirement obligations of $ 506 (2014 - $ 2,570 ) for renewable generation facilities being constructed and accretion expense of $854 (2014 - $527 ). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Deferred income Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized. (f) Deferred credits Deferred credits include deferred tax credits (note 19) of $3,350 (2014 - $19,130 ).

Shareholders' capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Shareholders' capital	Shareholders’ capital (a) Common shares Number of common shares: 2015 2014 Common shares, beginning of year 238,149,468 206,348,985 Public offering (i) 14,355,000 29,444,000 Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii)) 3,364,951 2,356,483 Common shares, end of year 255,869,419 238,149,468 14. Shareholders’ capital (continued) (a) Common shares (continued) 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 April 2016. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan. (i) Public offering In December 2015, APUC issued 14,355,000 common shares at $10.45 per share pursuant to a public offering for proceeds of $150,010 before issuance costs of $6,735 or $5,023 net of taxes. In December 2014, APUC issued 10,055,000 common shares at $9.95 per share pursuant to a public offering for proceeds of $100,047 , before issuance costs of $4,243 or $3,021 net of taxes. In September 2014, APUC issued 19,389,000 common shares at $8.90 per share pursuant to a public offering for proceeds of $172,562 , before issuance costs of $7,648 or $5,719 net of taxes. (ii) Subscription receipts On December 29, 2014, the Company received total proceeds of $77,503 from the issuance to Emera Inc. (“Emera”) of 8,708,170 subscription receipts at a price of $8.90 per share in connection with the Odell SponsorCo investment (note 8(a)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by November 14, 2016, they will automatically convert into common shares. On December 29, 2014, the Company received total proceeds of $33,000 from the issuance to Emera of 3,316,583 subscription receipts at a price of $9.95 per share in connection with the Park Water System acquisition (note 3(b)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by December 29, 2016, they will automatically convert into common shares. (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 292,337 common shares under the dividend reinvestment plan. 14. 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, 2015 and 2014: Preferred shares Number of shares Price per share Carrying amount Series A 4,800,000 $ 25 $ 116,546 Series D 4,000,000 $ 25 97,259 $ 213,805 The holders of Series A and Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of $1.125 and $1.25 per share, respectively, for each year up to, but excluding December 31, 2018 and March 31, 2019, respectively. The Series A and Series D dividend rate will reset on those dates and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94% and 3.28% , respectively. The Series A and Series D preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018 and March 31, 2019, respectively, 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 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, 2018 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 (note 11). (c) Share-based compensation For the year ended December 31, 2015 , APUC recorded $5,330 (2014 - $3,248 ) in total share-based compensation expense detailed as follows: 2015 2014 Share options $ 2,742 $ 1,931 Directors deferred share units 404 273 Employee share purchase 158 116 Performance share units 2,026 928 Total share-based compensation $ 5,330 $ 3,248 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, 2015 , total unrecognized compensation costs related to non-vested options and PSUs were $3,125 and $1,866 , respectively, and are expected to be recognized over a period of 1.74 and 1.63 years, respectively. 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (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 10% 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. 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 estimated to equal the contractual life of the options. 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: 2015 2014 Risk-free interest rate 1.3 % 2.0 % Expected volatility 38 % 38 % Expected dividend yield 4.0 % 3.8 % Expected life 8 years 8 years Weighted average grant date fair value per option $ 2.45 $ 2.00 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 at January 1, 2014 4,567,129 $ 5.70 5.45 $ 7,814 Granted 969,998 7.95 8.00 — Balance at December 31, 2014 5,537,127 $ 6.09 4.96 $ 19,648 Granted 1,627,525 9.75 8.00 — Balance at December 31, 2015 7,164,652 $ 6.92 4.74 $ 28,561 Exercisable at December 31, 2015 4,618,323 $ 5.74 3.55 $ 23,898 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (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 dollar 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, 2015, a total of 111,355 common shares (2014 - 93,598 ) were issued to employees under the ESPP. (iii) Directors 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, 2015, 157,471 (2014 - 110,241 ) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. (iv) Performance share units The Company offers a PSU 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 0% to 197.5% of the number of PSUs granted. Dividends accumulating during the vesting period are converted to PSUs 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 have voting rights. Any PSUs 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. Compensation expense associated with PSUs is recognized rateably over the performance period and assumes that performance goals will be achieved at 100% . If goals met differ, compensation cost recognized is adjusted to reflect the performance conditions achieved. 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (iv) Performance share units (continued) A summary of the PSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 66,195 $ 6.57 0.62 $ 486 Granted 407,962 8.22 3.00 3,333 Exercised (22,665 ) 6.13 — (185 ) Forfeited (11,406 ) 8.22 — (93 ) Balance at December 31, 2014 440,086 $ 6.57 1.81 $ 4,242 Granted, including dividends 212,250 9.72 2.62 — Exercised (41,131 ) 6.86 — 381 Forfeited (47,089 ) 8.30 — — Balance at December 31, 2015 564,116 $ 7.59 1.63 $ 6,155 Exercisable at December 31, 2015 157,972 $ 8.22 — $ 1,723

Accumulated other comprehensive

Accumulated other comprehensive income (loss)	12 Months Ended
	Dec. 31, 2015
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, 2014 $ (57,471 ) $ 11,840 $ — $ 14,221 $ (31,410 ) OCI (loss) before reclassifications 68,938 3,358 519 (35,396 ) 37,419 Amounts reclassified — 5,423 (518 ) (273 ) 4,632 Net current period OCI 68,938 8,781 1 (35,669 ) 42,051 Acquisition of non-controlling interest 21,029 2,543 — — 23,572 Balance, December 31, 2014 $ 32,496 $ 23,164 $ 1 $ (21,448 ) $ 34,213 OCI before reclassifications 228,861 21,896 (73 ) 6,487 257,171 Amounts reclassified — (5,731 ) — 1,084 (4,647 ) Net current period OCI $ 228,861 $ 16,165 $ (73 ) $ 7,571 $ 252,524 Balance, December 31, 2015 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737 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 administrative expenses.

Dividends

Dividends	12 Months Ended
	Dec. 31, 2015
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 dividend on its commons shares in U.S. dollars. Dividends declared in Canadian equivalent dollars during the year were as follows: 2015 2014 Dividend Dividend per share Dividend Dividend per share Common shares $ 124,831 $ 0.4867 $ 83,097 $ 0.3695 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 4,103 $ 1.0257

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related party transactions	Related party transactions Emera Inc. A member of the Board of APUC is an executive at Emera. During 2015, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), and Bangor Hydro (“BH”) subsidiaries of Emera, amounting to U.S.$ 6,658 (2014 - U.S.$ 9,821 ). During 2015, Liberty Utilities purchased natural gas amounting to U.S. $ 2,292 (2014 - U.S. $3,961 ) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process the results of which were approved by the regulator in the relevant jurisdiction. There was U.S. $491 included in accruals in 2015 (2014 - U.S.$ nil ) related to these transactions at the end of the years. Equity-method investments The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $2,021 (2014 - $189 ) during the year. Senior Executives As at December 31, 2015, $ nil (December 31, 2014 - $47 ) was due from Algonquin Power Systems Ltd., a corporation partially owned by Ian Robertson and Chris Jarratt (collectively “Senior Executives”). Chartered Aircraft As part of its normal business practice, APUC has utilized chartered aircraft when it is beneficial to do so and had previously entered into a block time agreement to charter aircraft in which Senior Executives have a partial ownership. The Company terminated the agreement effective June 28, 2015 and paid a usage shortfall fee of $13 . During the year ended December 31, 2015, APUC reimbursed direct costs in connection with the use of the aircraft prior to termination of the block time agreement of $507 (2014 - $721 ). Office Facilities Until the fourth quarter of 2014, APUC had leased its head office facilities from an entity partially owned by Senior Executives. During the fourth quarter of 2014, APUC terminated the related party lease and moved all head office employees into new premises owned by the Company. Base lease costs for the year ended December 31, 2015 were $ nil (2014 - $ 356 ). Other A spouse of one of the Senior Executives was employed to provide market research services to certain subsidiaries of the Company. During the year ended December 31, 2015, APUC paid $22 (2014 - $192 ) in relation to these services. The spouse is no longer employed by the Company. 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 18MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction is expected to be settled in 2016. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Non-controlling Interests

Non-controlling Interests	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
Non-controlling Interests	Non-controlling interests Net loss attributable to non-controlling interests consists of the following: 2015 2014 Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo (i) $ — $ 3,484 Net loss attributable to Class A partnership units (ii) (33,942 ) (27,199 ) Other net earnings attributable to non-controlling interests 1,966 1,529 Total net loss attributable to non-controlling interests $ (31,976 ) $ (22,186 ) (i) On March 31, 2014, the Company acquired the remaining Class B partnership units of Wind Portfolio SponsorCo from the non-controlling interest holder. As a result of the transaction, the Company now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units (note 3(h)). (ii) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Senate, Minonk and Sandy Ridge wind facilities and, beginning December 31, 2014, the Bakersfield Solar facility 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(q).

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2015
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% (2014 - 26.5% ). The differences are as follows: 2015 2014 Expected income tax expense at Canadian statutory rate $ 34,516 $ 19,199 Increase (decrease) resulting from: Recognition of deferred credit (2,448 ) (5,763 ) Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (3,855 ) (1,677 ) Non-taxable corporate dividend (3,311 ) (2,618 ) Non-controlling interests share of income 12,511 8,824 Production tax credit (254 ) (339 ) Allowance for equity funds used during construction (935 ) (746 ) State taxes 733 604 Adjustment relating to prior periods 2,431 — CRA Settlement 2,709 — Other 1,616 (677 ) Income tax expense $ 43,713 $ 16,807 For the years ended December 31, 2015 and 2014, earnings from continuing operations before income taxes consist of the following: 2015 2014 Canadian operations $ 28,481 $ 11,930 U.S. operations 101,768 60,519 $ 130,249 $ 72,449 19. Income taxes (continued) Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2015 Canada $ 5,272 $ 1,959 $ 7,231 United States 2,038 34,444 36,482 $ 7,310 $ 36,403 $ 43,713 Year ended December 31, 2014 Canada $ 5,660 $ (3,538 ) $ 2,122 United States (1,986 ) 16,671 14,685 $ 3,674 $ 13,133 $ 16,807 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, 2015 and 2014 are presented below: 2015 2014 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 396,727 $ 319,056 Pension and OPEB 57,969 54,458 Acquisition-related costs 6,035 5,168 Environmental obligation 28,230 28,555 Production tax credit 3,027 2,098 Reserves not currently deductible 2,503 2,315 Other 4,970 3,988 Total deferred income tax assets 499,461 415,638 Less valuation allowance (17,478 ) (15,534 ) Total deferred tax assets 481,983 400,104 Deferred tax liabilities: Property, plant and equipment (544,616 ) (387,931 ) Intangible assets (2,760 ) (2,752 ) Outside basis in partnership (32,221 ) (15,194 ) Regulatory accounts (28,270 ) (49,399 ) Financial derivatives (31,806 ) (15,013 ) Total deferred tax liabilities (639,673 ) (470,289 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 18,109 $ 64,275 Deferred tax liabilities (175,799 ) $ (134,460 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) 19. Income taxes (continued) The valuation allowance for deferred tax assets as at December 31, 2015 was $ 17,478 (2014 - $15,534 ). 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, 2015, 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 2016 $ — 2017 and onwards 967,499 $ 967,499 On June 26, 2015, the Company entered into an agreement with the Canada Revenue Agency (“CRA”) regarding a CRA’s proposal to reassess APUC’s 2009 through 2013 income tax filings in relation to a unit exchange transaction that occurred on October 27, 2009. The agreement resulted in a $16,042 reduction in the APUC’s deferred tax assets and a proportional reduction of $13,333 in its deferred credits (note 13(f)). Consequently, the Company’s results for 2015 reflect a $2,709 net non-cash charge to deferred income tax expense. 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 $64,678 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, 2015
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 subscription receipts outstanding (note 14 (a)(ii)). 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 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 reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2015 2014 Net earnings attributable to shareholders of APUC $ 117,480 $ 75,701 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 4,103 Net earnings attributable to common shareholders of APUC $ 107,080 $ 66,198 Discontinued operations (1,032 ) (2,127 ) Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 108,112 $ 68,325 Weighted average number of shares Basic 253,172,088 213,953,870 Effect of dilutive securities 3,344,632 2,387,722 Diluted 256,516,720 216,341,592 The shares potentially issuable as a result of 1,627,525 share options (2014 - 1,786,401 ) are excluded from this calculation as they are anti-dilutive.

Segmented information

Segmented information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segmented information	Segmented information The Company’s management’s reporting structure is aligned under three business units: Generation, Transmission and Distribution. During the fourth quarter, Management determined that each business unit represents a reporting segment. The comparative information for 2014 has been reclassified to conform with the composition of the reporting segments presented in the current year. Generation , owns or has interests in hydroelectric, solar, wind power facilities and co-generation. Distribution operates electric, natural gas and water distribution utilities. Finally, Transmission invests in rate regulated electric transmission and natural gas pipeline systems. The Transmission segment includes the equity method investment in the Natural Gas Pipeline Development (note 8(c)) which is not yet significant and as a result is not presented separately in the tables below but grouped within Corporate. For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. The unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The results of operations and assets for these segments are reflected in the tables below. Year ended December 31, 2015 Generation Distribution Corporate Total Revenue $ 244,751 $ 783,104 $ — $ 1,027,855 Fuel and power purchased 27,990 348,883 — 376,873 Net revenue 216,761 434,221 — 650,982 Operating expenses 63,601 213,750 1,210 278,561 Administrative expenses 10,822 21,570 8,283 40,675 Depreciation and amortization 67,293 82,513 — 149,806 Gain on foreign exchange — — (2,631 ) (2,631 ) Operating income (loss) from continuing operations 75,045 116,388 (6,862 ) 184,571 Interest expense 29,395 34,971 1,627 65,993 Interest, dividend, equity and other income (1,154 ) (3,974 ) (3,967 ) (9,095 ) Other expenses (gain) (5,623 ) 391 2,656 (2,576 ) Earnings (loss) before income taxes $ 52,427 $ 85,000 $ (7,178 ) $ 130,249 Property, plant and equipment $ 1,895,617 $ 1,914,980 $ 63,087 $ 3,873,684 Equity-method investees 44,638 769 7,066 52,473 Total assets 2,345,905 2,532,894 112,926 4,991,725 Capital expenditures 55,992 141,445 6,758 204,195 21. Segmented information (continued) Year ended December 31, 2014 Generation Distribution Corporate Total Revenue $ 218,765 $ 722,849 $ — $ 941,614 Fuel and power purchased 39,264 381,622 — 420,886 Net revenue 179,501 341,227 — 520,728 Operating expenses 55,482 178,248 308 234,038 Administrative expenses 13,457 19,947 1,288 34,692 Depreciation and amortization 58,248 53,671 2,128 114,047 Gain on foreign exchange — — (1,112 ) (1,112 ) 52,314 89,361 (2,612 ) 139,063 Interest expense 33,868 27,139 1,411 62,418 Interest, dividend and other income (1,187 ) (3,369 ) (3,202 ) (7,758 ) Other expense (gain) 48 300 11,606 11,954 Earnings (loss) before income taxes $ 19,585 $ 65,291 $ (12,427 ) $ 72,449 Property, plant and equipment $ 1,687,465 $ 1,531,166 $ 59,791 $ 3,278,422 Equity-method investees 3,520 500 2,578 6,598 Total assets 1,896,265 2,098,244 108,339 4,102,848 Capital expenditures 201,063 176,849 54,461 432,373 The majority of non-regulated energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2015 or 2014: Hydro Québec 13% (2014 - 11% ); Manitoba Hydro 13% (2014 - 13% ); PJM 14% (2014 - 10% ); and ComEd 11% (2014 - 10% ). The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations. 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: 2015 2014 Revenue Canada $ 86,977 $ 92,267 United States 940,878 849,347 $ 1,027,855 $ 941,614 Property, plant and equipment Canada $ 592,598 $ 590,580 United States 3,281,086 2,687,842 $ 3,873,684 $ 3,278,422 Intangible assets Canada $ 40,186 $ 25,601 United States 37,777 28,410 $ 77,963 $ 54,011 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, 2015
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, with the exception of those matters described below. 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. On October 21, 2011, the Quebec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (including interest) to the Government of Quebec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management in prior years. The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position. As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $ nil to $6,800 . In 2012, the Company paid an amount of $1,884 to the Government of Quebec in relation to the early years covered by the claim in order to mitigate the impact of accruing interests on any amount ultimately determined to be payable or recoverable. (b) Commitments In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3, 8 and 25, the following significant commitments exist as of December 31, 2015. As a result of the dam safety legislation passed in Quebec (Bill C-93), APUC has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. The assessments have identified a number of remedial measures required to meet the new safety standards. APUC currently estimates further capital expenditures of approximately $ 8,000 over a period of 4 years related to compliance with the legislation. 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) $ 82,403 $ 52,644 $ 55,599 $ 59,165 $ 59,791 $ — $ 309,602 Gas supply and service agreements (ii) 66,264 46,673 36,621 35,482 32,070 82,509 299,619 Service agreements 38,335 38,151 35,019 35,734 35,955 518,193 701,387 Capital projects 35,842 7,571 71 71 71 18 43,644 Operating leases 5,863 5,319 4,866 4,754 4,793 106,210 131,805 Total $ 228,707 $ 150,358 $ 132,176 $ 135,206 $ 132,680 $ 706,930 $ 1,486,057 (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, 2015. 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, 2015
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: 2015 2014 Accounts receivable $ 6,715 $ (23,640 ) Natural gas in storage 3,049 (5,942 ) Supplies and consumable inventory (2,968 ) (3,861 ) Income taxes receivable (2,529 ) (189 ) Prepaid expenses (7,833 ) 827 Accounts payable (18,261 ) 54,299 Accrued liabilities (28,495 ) 32,520 Current income tax liability 1,820 (1,527 ) Net regulatory assets and liabilities 37,353 (54,277 ) $ (11,149 ) $ (1,790 )

Financial instruments

Financial instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Financial instruments	Financial instruments (a) Fair value of financial instruments 2015 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 119,383 $ 126,468 $ — $ 126,468 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 88,357 88,357 — — 88,357 Commodity contracts for regulated operations 4 4 — 4 — Total derivative financial instruments 88,361 88,361 — 4 88,357 Total financial assets $ 207,744 $ 214,829 $ — $ 126,472 $ 88,357 Long-term debt $ 1,486,795 $ 1,547,346 $ 511,829 $ 1,035,517 $ — Preferred shares, Series C 18,527 17,303 — 17,303 — Derivative financial instruments: Energy contracts designated as a cash flow hedge 446 446 — — 446 Cross-currency swap designated as a net investment hedge 101,559 101,559 — 101,559 — Interest rate swap designated as a hedge 9,659 9,659 — 9,659 — Currency forward contract not designated as a hedge 1,918 1,918 — 1,918 — Commodity contracts for regulated operations 1,676 1,676 — 1,676 — Total derivative financial instruments 115,258 115,258 — 114,812 446 Total financial liabilities $ 1,620,580 $ 1,679,907 $ 511,829 $ 1,167,632 $ 446 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2014 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 39,510 $ 41,339 $ — $ 41,339 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 41,966 41,966 — — 41,966 Energy contracts not designated as a cash flow hedge 504 504 — — 504 Total derivative financial instruments 42,470 42,470 — — 42,470 Total financial assets $ 81,980 $ 83,809 $ — $ 41,339 $ 42,470 Long-term debt $ 1,271,719 $ 1,363,934 $ 520,142 $ 843,792 $ — Preferred shares, Series C 18,693 18,209 — 18,209 — Derivative financial instruments: Cross-currency swap designated as a net investment hedge 36,276 36,276 — 36,276 — Interest rate swaps designated as a hedge 4,684 4,684 — 4,684 — Interest rate swaps not designated as a hedge 1,383 1,383 — 1,383 — Commodity contracts for regulated operations 2,928 2,928 — 2,928 — Total derivative financial instruments 45,271 45,271 — 45,271 — Total financial liabilities $ 1,335,683 $ 1,427,414 $ 520,142 $ 907,272 $ — 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2015 and 2014 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 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 derivative instruments primarily consist of swaps, options and forward physical deals 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 $18.39 to $138.3 with a weighted average of $39.98 as of December 31, 2015. The processes and methods of measurement are developed using the market knowledge of the trading operations within the Company and are derived from observable energy curves adjusted to reflect the illiquid market of the hedges and, in some cases, the variability in deliverable energy. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(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. The Company’s accounting policy is to recognize transfers between levels of the fair value hierarchy on the date of the event or change in circumstances that caused the transfer. There was no transfer into or out of level 1, level 2 or level 3 during the years ended December 31, 2015 and 2014. (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 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: 2015 Financial contracts: Gas swaps 1,086,228 Gas options 412,369 1,498,597 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. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7(c)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact. 24. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 2015 2014 Regulatory assets: Gas swap contracts U.S. $ 1,058 U.S. $ 2,178 Gas option contracts U.S. $ 154 U.S. $ 346 Regulatory liabilities: Gas swap contracts U.S. $ 3 U.S. $ — Gas option contracts U.S. $ — U.S. $ — (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 and at one of its hydro facilities no longer subject to a power purchase agreement 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) 49,135 December 2016 $ 68.56 AESO 801,098 December 2022 U.S. $ 42.81 PJM Western HUB 3,419,634 December 2022 U.S. $ 30.25 NI HUB 3,997,509 December 2027 U.S. $ 36.46 ERCOT North HUB As of December 31, 2015, an amount receivable under the derivatives for Sandy Ridge, Senate and Minonk Wind Facilities of $4,882 (2014 - $156 ) was held as collateral by the counterparty. On November 14, 2014, the Company entered into 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 $135,000 bond. The change in fair value resulted in a loss of $4,974 for the year ended December 31, 2015 (2014 - loss of $4,684 ), which is recorded in OCI. The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2015 2014 Effective portion of cash flow hedge, loss (gain) $ 21,932 $ (2,592 ) Amortization of cash flow hedge (36 ) (32 ) Loss (gain) reclassified from AOCI (5,731 ) 5,423 $ 16,165 $ 2,799 Less non-controlling interest — 5,982 OCI attributable to shareholders of APUC $ 16,165 $ 8,781 The Company expects $14,975 of unrealized gains currently in AOCI to be reclassified into non-regulated energy sales within the next twelve months, as the underlying hedged transactions settle. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iii) Foreign exchange hedge of net investment in foreign operation The Company is exposed to currency fluctuations from its U.S. based operations. APUC manages this risk primarily through the use of natural hedges by using U.S. long-term debt to finance its U.S. operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts. The Company designates the amounts drawn on the Generation Group’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from Odell and Deerfield Wind SponsorCo as a hedge of the foreign currency exposure of its net investment in the Generation Group’s U.S. operations. 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 nil for the year ended December 31, 2015 (2014 - $2,727 ) was recorded in OCI. Concurrent with its $150,000 and $200,000 debenture offerings in December 2012 and January 2014, 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 Generation 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 $68,195 (2014 - loss of $ 28,537 ) was recorded in OCI in 2015. (iv) Other derivatives The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility are 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 though the use of short-term financial forward energy purchase contracts which are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur. The Company is exposed to interest rate fluctuations related to certain of its floating rate debt 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 24(b)(ii)). The Company was party to an interest rate swap whereby the Company paid a fixed interest rate of 4.47% on a notional amount of $58,791 and received floating interest at 90 day CDOR. The swap expired on September 2015. As of December 31, 2014, the estimated fair value of the interest rate swap was a liability of $1,383 . This interest rate swap was not accounted for as a hedge. The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 8(d)). This risk is mitigated through the use of a currency forward contract to sell U.S. $63,400 for $85,812 on April 30, 2016. As of December 31, 2015, the estimated fair value of the instrument was a liability of $1,918 . This currency forward contract was 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. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives (continued) The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2015 2014 Change in unrealized loss (gain) on derivative financial instruments: Interest rate swaps $ (1,383 ) $ (1,797 ) Energy derivative contracts 886 3,386 Currency forward contract 1,918 — Total change in unrealized loss (gain) on derivative financial instruments $ 1,421 $ 1,589 Realized loss (gain) on derivative financial instruments: Interest rate swaps 1,498 1,962 Energy derivative contracts (579 ) (3,627 ) Total realized loss (gain) on derivative financial instruments $ 919 $ (1,665 ) Loss (gain) on derivative financial instruments not accounted for as hedges 2,340 (76 ) Ineffective portion of derivative financial instruments accounted for as hedges (2,610 ) 1,451 $ (270 ) $ 1,375 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (2,188 ) $ 1,375 Loss on foreign exchange $ 1,918 $ — $ (270 ) $ 1,375 (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 Generation Group accounts receivable to be significant as over 80% of revenue from power generation is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days. The remaining revenue is primarily earned by the Distribution Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to Distribution Group accounts receivable balances of U.S. $91,308 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 Distribution Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers. 24. Financial instruments (continued) (c) Risk management (continued) Credit risk (continued) As of December 31, 2015, the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2015 Canadian $ US $ Cash and cash equivalents and restricted cash $ 39,972 $ 74,696 Accounts receivable 15,016 129,791 Allowance for doubtful accounts (5,756 ) Notes receivable 19,664 72,052 $ 74,652 $ 270,783 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, 2015, in addition to cash on hand of $124,353 the Company had $580,901 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. 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 $ 8,945 $ 222,810 $ 187,582 $ 1,076,786 $ 1,496,123 Advances in aid of construction 1,347 — — 90,938 92,285 Interest on long-term debt 74,324 138,841 117,328 333,606 664,099 Purchase obligations 243,748 — — — 243,748 Environmental obligation 5,435 41,494 1,753 29,813 78,495 Derivative financial instruments: Cross-currency swap 4,828 8,963 7,508 80,260 101,559 Interest rate swaps — 9,659 — — 9,659 Currency forward 1,918 — — — 1,918 Energy derivative and commodity contracts 1,885 237 — — 2,122 Other obligations 12,808 — — 40,694 53,502 Total obligations $ 355,238 $ 422,004 $ 314,171 $ 1,652,097 $ 2,743,510

Subsequent event - Convertible

Subsequent event - Convertible Unsecured Subordinated Debentures	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent event - Convertible Unsecured Subordinated Debentures	Subsequent event - Convertible Unsecured Subordinated Debentures Subsequent to year-end, on March 1, 2016, the Company completed the sale of $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures. The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire. On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures bringing the total amount of Debentures under the Debenture Offering to $1,150,000 . The Debentures will mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0% . Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 15% , and the effective annual yield thereafter is 0% . If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Prior to the closing of the acquisition, the Company will at all times have cash on hand or maintain readily available capacity under the revolving credit facilities of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option. At the option of the holders and provided that payment of the Final Instalment has been made, each Debenture will be convertible into common shares of the Company at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $10.60 per common share. Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of Empire will not be satisfied; (ii) termination of the acquisition agreement; and (iii) September 11, 2017 if notice of the Final Instalment Date has not been given to holders on or before September 8, 2017. Upon any such redemption, the Company will pay for each Debenture $333 plus accrued and unpaid interest to the holder of the instalment receipt. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Instalment Date. At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

Comparative figures

Comparative figures	12 Months Ended
	Dec. 31, 2015
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 polici35

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2015
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(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)).
Business combinations, intangible assets and goodwill	Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets which 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 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 acquisitions 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. During the fourth quarter of each year, the Company assesses qualitative 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”). 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 (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”) 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 and requirements of ISO New England, Inc. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash as part of other assets (note 12) 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.
Natural gas in storage	Natural gas in storage Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents 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(c)) 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 recoverable value of 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 replacement cost. Supplies and consumables inventory is included in other current assets.
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 13(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. Effective January 1, 2015, the Company changed the depreciation method from the straight-line method to 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. This change in the depreciation method results from having better information on the consumption of the benefits of certain individual components that are directly related to production and separately identified in the records of the Company. The change is being recognized prospectively.The impact of the change on the operating results for 2015 was a reduction of depreciation expense of $3,418 . The impact on basic and diluted net earnings per share for 2015 was an increase of $0.01 . The change is not expected to materially affect net earnings or net earnings per share on an annual basis. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Distribution 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 with the relevant authority authorized and has committed to the funding of the 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. 2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071
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. Assets held and used: 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. Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell.
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(a) and (b)). 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 accounted using the equity method. 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 investees in interest, dividend, equity and other income in the consolidated statements of operations. 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. 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, and other post-employment benefit (“OPEB”) 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 and OPEB 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. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses 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.
Stock based compensation	Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a 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 expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus 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 and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units”) which 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 Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV method uses a balance sheet approach, which measures the allocation of income or loss of the Class A partnership units in each period by calculating the change in the amount of distribution the partners would contractually be entitled to based on a hypothetical liquidation of the book value carrying amounts of the entity at the beginning of a reporting period compared to the end of that period (note 18). Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.
Recognition of revenue	Recognition of revenue Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered. Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas 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. Revenue for the Company’s Calpeco Electric System, Peach State Gas System and New England Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge 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 (note 7(e)). Water reclamation and distribution revenues are recorded 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. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue is recorded net of sales taxes.
Foreign currency translation	Foreign currency translation The Company’s reporting currency is the Canadian dollar. The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian 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. Income tax credits are treated as a reduction to current 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. 1. Significant accounting policies (continued) (t) Income taxes (continued) 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 in 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 exposure, interest risk and price risk exposure 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. 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, and 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 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 adopted accounting pronouncements The FASB issued ASU 2015-17 Income Taxes (Topic 740) to simplify the presentation of deferred income taxes. This ASU requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this ASU. The Company retrospectively adopted this ASU in the fourth quarter of 2015. As a result, a deferred tax asset and a deferred tax liability of $7,210 and $ 3,702 , respectively, that were presented as current as of December 31, 2014 have been reclassified to non-current deferred tax asset and deferred tax liability on the consolidated balance sheets. The FASB issued ASU 2015-13 Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This ASU clarifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The adoption of this ASU in the third quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-10, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the second quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-04, Compensation: Retirement Benefits (Subtopic 715), to provide a practical expedient that permits an entity with a fiscal year-end that does not coincide with a month-end and an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations to measure defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end or significant event. The Company adopted this ASU prospectively in the second quarter of 2015 and as a result, remeasured amendments to its pension plans, made during the second quarter, using the month-end closest to the amendments. The FASB issued ASU 2015-03, Interest: Imputation of Interest (Subtopic 835-30), to simplify presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. Effective January 1, 2015, the Company applied this ASU retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt. In accordance with ASU 2015-15 Interest: Imputation of Interest (Subtopic 835-30), the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments as other assets. The FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This newly issued accounting standard raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Effective January 1, 2015, the Company adopted this ASU prospectively and as a result, its adoption had no impact on discontinued operations reported in prior periods. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted 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 standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its 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 standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations.
Recent accounting guidance not yet adopted	Recently issued accounting guidance not yet adopted 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 standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its 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 standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations.

Significant accounting polici36

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Capitalization of Interest	2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071
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 2015 2014 2015 2014 Generation Group 3 - 60 3 - 60 32 35 Distribution Group 5 - 100 5 - 100 42 40 Equipment 5 - 50 5 - 50 14 14

Business acquisitions and dev37

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Acquisition of Noncontrolling Interest	As a result of the transaction, the Generation Group now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units resulting in the elimination of the non-controlling interest in respect of the Class B partnership units of Wind Portfolio SponsorCo as follows: Elimination of non-controlling interest in Class B partnership units $ 205,796 Non-controlling interest portion of currency translation adjustment recorded to AOCI (21,029 ) Non-controlling interest portion of unrealized gain on cash flow hedges recorded to AOCI (2,543 ) Decrease in deferred income tax asset (32,551 ) Additional paid-in capital (22,552 ) Cash $ 127,121

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment consist of the following: 2015 Cost Accumulated depreciation Net book value Generation $ 2,138,748 $ 358,200 $ 1,780,548 Distribution 2,075,059 265,741 1,809,318 Land 23,258 — 23,258 Equipment and other 129,555 37,443 92,112 Construction in progress Generation 64,779 — 64,779 Distribution 103,669 — 103,669 $ 4,535,068 $ 661,384 $ 3,873,684 5. Property, plant and equipment (continued) 2014 Cost Accumulated Net book Generation $ 1,827,247 $ 270,746 $ 1,556,501 Distribution 1,555,289 147,726 1,407,563 Land 19,347 — 19,347 Equipment and other 119,367 29,526 89,841 Construction in progress Generation 82,840 — 82,840 Distribution 122,330 — 122,330 $ 3,726,420 $ 447,998 $ 3,278,422

Intangible assets and goodwill

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible assets consist of the following: 2015 Cost Accumulated amortization Net book value Power sales contracts $ 78,725 $ 40,244 $ 38,481 Customer relationships 37,083 10,371 26,712 Interconnection agreements 13,000 230 12,770 $ 128,808 $ 50,845 $ 77,963 2014 Cost Accumulated Net book Power sales contracts $ 64,605 $ 33,704 $ 30,901 Customer relationships 31,094 7,984 23,110 Interconnection agreements — — — — $ 95,699 $ 41,688 $ 54,011
Goodwill	Changes in goodwill are as follows: Distribution Group Balance, January 1, 2014 $ 84,647 Foreign exchange 7,681 Balance, December 31, 2014 $ 92,328 Business acquisitions 290 Foreign exchange 17,875 Balance, December 31, 2015 $ 110,493

Regulatory matters (Tables)

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory assets and liabilities consist of the following: 2015 2014 Regulatory assets Environmental remediation (a) $ 116,747 $ 102,735 Pension and post-employment benefits (b) 69,537 63,512 Commodity costs adjustment (c) 7,643 41,502 Rate case costs (d) 6,535 4,161 Rate adjustment mechanism (e) 14,804 6,207 Other 30,049 29,155 Total regulatory assets $ 245,315 $ 247,272 Less current regulatory assets (32,213 ) (61,645 ) Non-current regulatory assets $ 213,102 $ 185,627 Regulatory liabilities Cost of removal (f) $ 107,988 $ 78,013 Rate-base offset (g) 24,984 23,427 Commodity costs adjustment (c) 32,423 10,389 Other 9,952 9,927 Total regulatory liabilities $ 175,347 $ 121,756 Less current regulatory liabilities (44,167 ) (20,590 ) Non-current regulatory liabilities $ 131,180 $ 101,166 (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(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. An amount of $32,313 relates to a recent acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future services 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. (c) Commodity costs adjustment The revenue of the electric and natural gas utilities includes a component which is designed to recover the cost of electricity or natural gas through rates charged to customers. Under deferred energy accounting, to the extent actual natural gas and purchased power costs differ from natural gas and purchased power 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 natural gas or electricity in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. 7. Regulatory matters (continued) (d) Rate case costs The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Peach State Gas System and New England Gas Systems 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 collected over a period not exceeding 24 months is accrued upon approval of the Final Order. (f) 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. (g) Rate-base offset The regulators imposed a rate-base offset that would reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of ten years.

Long-term investments (Tables)

Long-term investments (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Long Term Investments And Notes Receivable [Abstract]
Long-term Investments	Long-term investments consist of the following: 2015 2014 Equity-method investees 50% interest in Odell Wind Project Joint Venture (a) $ 42,287 $ 2,267 50% interest in Deerfield Wind Project Joint Venture (b) 2,240 — Interests in natural gas pipeline developments (c) 5,623 1,063 Other 2,323 3,268 $ 52,473 $ 6,598 Available-for-sale investment $ 2,946 $ 137 Notes receivable Development loans (d) $ 96,924 $ 17,582 Red Lily Senior loan Tranche 2, interest at 6.31% (e) 11,588 11,588 Red Lily Subordinated loan Tranche 1, interest at 12.5% (e) 6,565 6,565 Other 4,306 3,775 119,383 39,510 Total long-term investments 174,802 46,245 Less current portion — (2,966 ) Total long-term investments $ 174,802 $ 43,279 8. Long-term investments (continued) (a) Odell Wind Project Joint Venture On November 14, 2014, the Company acquired a 50% equity interest in Odell SponsorCo LLC (“Odell SponsorCo”), which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Project”) in the state of Minnesota. The total construction costs of the Odell Wind Project are estimated to be U.S. $322,766 . The two members each contributed U.S. $1,000 to the capital of Odell SponsorCo on acquisition and another U.S. $23,800 on October 6, 2015. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, within 30 days of commencement of operations, which is expected in 2016. The interest capitalized during the year to the investment while the Odell Wind Project is under construction amounts to $4,415 (2014 - nil ). As of December 31, 2015, Odell SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Odell SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $190,840 as of December 31, 2015. (b) Deerfield Wind Project Joint Venture On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan. The total construction costs of the Deerfield Wind Project are estimated to be U.S. $303,000 . Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in 2016, each party will contribute another U.S. $18,596 plus accrued interest at 7% to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations, which is expected in late 2016. The interest capitalized during the year to the investment while the Deerfield Wind Project is under construction amounts to $94 . As of December 31, 2015, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $321,472 as of December 31, 2015. (c) Natural gas pipeline developments In December 2015, APUC acquired a 4.0% interest in Northeast Supply Pipeline LLC with an option to increase its participation to 10% . Northeast Supply LLC is a new entity undertaking the development, construction and ownership of natural gas transmission pipeline to be constructed between the Bradford and Susquehanna counties in Pennsylvania and Wright, NY. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 4.0% in a limited liability corporation together with the option to increase its participation to 10% provide significant influence. As such, the interest is accounted as an equity method investment. 8. Long-term investments (continued) (c) Natural gas pipeline developments (continued) In November 2014, APUC acquired a 2.5% interest in Northeast Expansion LLC with an option to increase its participation to 10% . Northeast Expansion LLC is a new entity undertaking the development, construction and ownership of a natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 2.5% in a limited liability corporation together with the option to increase its participation to 10% and the commitment from its New Hampshire subsidiary to a firm gas transportation agreement for service on the pipeline facilities provide significant influence. As such, the interest is accounted as an equity method investment. The total capital investment assuming the Company exercises its right to subscribe for 10% of each pipeline is estimated to be U.S. $520,000 . As of December 31, 2015, APUC had invested U.S. $4,063 (2014 - U.S. $375 ) in the pipeline projects. (d) Development loans The Company entered into a committed loan and credit support facility with Odell SponsorCo and Deerfield SponsorCo (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with 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 Joint Ventures’ Wind Projects. The loan bears interest at an annual rate of 7% - 8% on outstanding principal amount until commercial operation date and 5% thereafter until maturity date, and the letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date. As of December 31, 2015, the Company had outstanding loans of U.S. $62,751 from Odell SponsorCo and U.S. $7,281 from Deerfield SponsorCo for development costs of the Joint Ventures’ Wind Projects. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. As of December 31, 2015, the following credit support was issued by the Company: a U.S. $15,000 letter of credit on behalf of the Odell Wind Project, to the utility under the PPA; a U.S. $1,119 letter of credit on behalf of the the Odell Wind Project pursuant to the generator interconnection agreement; guarantee of the obligations of the Joint Ventures under the wind turbine supply agreements; guarantee of the obligations of the Deerfield Wind Project under the power purchase agreement and decommissioning plan; and, a U.S. $43,238 letter of credit and guarantee of the obligations of Deerfield SponsorCo, to the vendor under the membership interest purchase and contribution agreement. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at U.S. $1,147 using a probability weighted discounted cash flow (level 3). (e) Red Lily I The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. APUC provides operation and supervision services to the Red Lily I project, a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in Red Lily I is in the form of participation in a portion of the senior and subordinated debt facilities to the Partnership. The senior debt facility consists of two tranches. A third-party lender advanced $27,000 of senior debt to the Partnership as Tranche 1. In 2011, APUC advanced $13,000 of senior debt as Tranche 2 to the Partnership and received a pre-payment of $1,412 in 2012. The third-party lender has also advanced $4,000 of senior debt Tranche 2 to the Partnership. The Company’s senior loan Tranche 2 to the Partnership earned interest at the rate of 6.31% and was replaced by subordinated debt Tranche 2 on February 23, 2016 as described below. Both tranches of senior debt are secured by substantially all the assets of the Partnership on a pari passu basis. The subordinated loan earns an interest rate of 12.5% , and the principal matures in 2036 but is repayable by the Partnership in whole or in part at any time after 2016 , without a pre-payment premium. The subordinated loan is secured by substantially all the assets of the Partnership but is subordinated to the senior debt. 8. Long-term investments (continued) (e) Red Lily I (continued) Subsequent to year-end, on February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced by the Company. The proceeds from this additional subordinated debt were used by Red Lily I to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion. In connection with the subordinated debt facility, the Company has an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans, exercisable for a period of 90 days commencing on February 24, 2016.

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long Term Liabilities	Long-term debt consists of the following: 2015 2014 Generation Group $350,000 revolving credit facility, interest rate is equal to bankers’ acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is BA or LIBOR plus 1.45%, maturing July 31, 2019. $ 27,300 $ 23,400 Algonquin Power Co.: 481,991 481,438 Shady Oaks Wind Facility: U.S.$76,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points. This facility was repaid in May 2015. — 88,168 Long Sault Hydro Facility: Senior Debt: $34,760 bonds bearing an interest rate of 10.21%, maturing December 31, 2027. The bonds have interest and principal payments, payable monthly in arrears. 34,760 35,997 Chuteford Hydro Facility: Senior Debt: $2,587 bonds bearing an interest rate of 11.55%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears. 2,587 3,022 Distribution Group U.S.$200,000 revolving credit facility, interest rate is equal to LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.25%, maturing September 30, 2018. — 23,898 Liberty Utilities Co.: U.S.$ 50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S.$ 25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S.$115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S.$ 15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S.$ 75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; U.S.$ 60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S.$ 25,000, bearing an interest rate of 4.26%, maturing July 31, 2028; U.S.$ 90,000, bearing an interest rate of 4.13%, maturing April 30, 2045; U.S.$ 70,000, bearing an interest rate of 4.13%, maturing July 15, 2045. The notes have interest only payments, payable semi-annually. 721,581 419,876 2015 2014 Calpeco Electric System: U.S.$45,000 bearing an interest rate of 5.19%, maturing December 29, 2020; U.S.$25,000 bearing an interest rate of 5.59%, maturing December 29, 2025. The notes have interest only payments, payable semi-annually in arrears. 96,015 80,368 Liberty Water Co: Senior Unsecured Notes: U.S.$50,000 bearing an interest rate of 5.60% $5,000 matures annually beginning June 20, 2016; $25,000 maturing December 22, 2020. The note bears interest payments semi-annually in arrears. 68,488 57,301 New England Gas System: U.S.$6,500, bearing an interest rate of 9.44%, maturing February 15, 2020; U.S.$7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; U.S.$6,000, bearing an interest rate of 7.24%, maturing December 15, 2027. The notes have interest only payments, payable semi-annually in arrears. 32,130 27,288 Granite State Electric System: Senior Unsecured Notes: U.S.$5,000, bearing an interest rate of 7.37%, maturing November 1, 2023; U.S.$5,000, bearing an interest rate of 7.94%, maturing July 1, 2025; U.S.$5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually. 20,730 17,373 LPSCo Water System: 1999 and 2001 IDA bonds bearing interest rates of 5.85% and 6.71%. This facility was repaid in October 2015. — 12,441 Bella Vista Water System: U.S.$877 Water Infrastructure Financing Authority of Arizona loans bearing interest rates of 6.26% and 6.10%, and maturing March 1, 2020 and December 1, 2017, respectively. The loans have principal and interest payments, payable monthly and quarterly in arrears. 1,213 1,149 $ 1,486,795 $ 1,271,719 Less: current portion (8,945 ) (9,130 ) $ 1,477,850 $ 1,262,589
Principal Payments	Principal payments due in the next five years and thereafter are as follows: 2016 2017 2018 2019 2020 Thereafter Total Generation Group $ 1,816 $ 2,045 $ 137,272 $ 30,152 $ 2,641 $ 375,415 $ 549,341 Distribution Group 7,129 76,358 7,135 7,149 147,640 701,371 946,782 Total $ 8,945 $ 78,403 $ 144,407 $ 37,301 $ 150,281 $ 1,076,786 $ 1,496,123

Pension and other post-retire43

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [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 2015 2014 2015 2014 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 241,963 $ 178,113 $ 68,257 $ 45,399 Projected benefit obligation assumed from business combination — 1,022 — — Modifications to pension plan (4,995 ) (560 ) — — Service cost 6,663 4,828 3,093 2,022 Interest cost 9,642 8,549 2,914 2,186 Actuarial loss (gain) (16,098 ) 39,704 (8,466 ) 14,893 Contributions from retirees — — 412 331 Benefits paid (13,024 ) (8,125 ) (2,447 ) (1,586 ) Loss on foreign exchange 45,231 18,432 12,802 5,012 Projected benefit obligation, end of year $ 269,382 $ 241,963 $ 76,565 $ 68,257 Change in plan assets Fair value of plan assets, beginning of year 156,990 139,280 14,295 13,395 Actual return (loss) on plan assets (5,657 ) 6,568 20 1,176 Employer contributions 7,975 5,676 3,028 (222 ) Benefits paid (12,589 ) (7,414 ) (2,036 ) (1,255 ) Gain on foreign exchange 29,453 12,880 2,842 1,201 Fair value of plan assets, end of year $ 176,172 $ 156,990 $ 18,149 $ 14,295 Unfunded status $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) Amounts recognized in the consolidated balance sheets consists of: Current liabilities (470 ) — (1,062 ) (333 ) Non-current liabilities (92,740 ) (84,973 ) (57,354 ) (53,629 ) Net amount recognized $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 )
Amounts Recognized in Accumulated Other Comprehensive loss	The amounts recognized in OCI before tax were as follows: AOCI Pension OPEB Balance, January 1, 2014 $ (14,385 ) $ (9,083 ) Current year net actuarial gain 43,350 14,338 Current year prior service loss (563 ) — Amortization of net actuarial loss 349 641 Balance at December 31, 2014 $ 28,751 $ 5,896 Current year net actuarial loss 1,505 (7,554 ) Current year prior service credits (4,864 ) — Amortization of net actuarial gain (1,358 ) (680 ) Amortization of prior service credits 457 — Balance at December 31, 2015 $ 24,491 $ (2,338 )
Weighted Average Assumptions Used to Determine Net Benefit Obligation	Weighted average assumptions used to determine net benefit obligation for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 4.16 % 3.71 % 4.23 % 3.80 % Rate of compensation increase 3.00 % 3.01 % N/A N/A Health care cost trend rate Before Age 65 6.50 % 7.00 % Age 65 and after 6.50 % 7.00 % Assumed Ultimate Medical Inflation Rate 4.75 % 5.00 % Year in which Ultimate Rate is reached 2023 2019 Weighted average assumptions used to determine net benefit cost for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 3.71 % 4.55 % 3.82 % 4.60 % Expected return on assets 6.44 % 7.00 % 5.50 % 5.53 % Rate of compensation increase 3.01 % 2.97 % N/A N/A Health care cost trend rate Before Age 65 7.00 % 7.63 % Age 65 and after 7.00 % 7.63 % Assumed Ultimate Medical Inflation Rate 5.00 % 5.00 % Year in which Ultimate Rate is reached 2019 2019
Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR)	The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2015 is as follows: 2015 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 10,763 Total service and interest cost 1,111 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (8,687 ) Total service and interest cost (871 )
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses	The following table lists the components of net benefit costs 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 2015 2014 2015 2014 Service cost $ 6,663 $ 4,828 $ 3,093 $ 2,022 Interest cost 9,642 8,549 2,914 2,186 Expected return on plan assets (11,989 ) (10,018 ) (713 ) (628 ) Amortization of net actuarial loss (gain) 1,398 (346 ) 510 (641 ) Amortization of prior service credits (471 ) — — — Net benefit cost $ 5,243 $ 3,013 $ 5,804 $ 2,939
Target Asset Allocation	The Company’s target asset allocation is as follows: Asset Class Target (%) Range (%) Equity securities 74 % 49% - 78% Debt securities 26 % 22% - 51% Other — % 0% - 1% 10. Pension and other post-employment benefits (continued) (d) Plan assets (continued) The fair values of investments as of December 31, 2015, by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 138,993 72 % Debt securities 54,542 28 % Other 787 — %
Expected Benefit Payments	The expected benefit payments over the next ten years are as follows: 2016 2017 2018 2019 2020 2021-2025 Pension plan $ 15,037 $ 13,829 $ 14,474 $ 15,120 $ 15,692 $ 88,692 OPEB 3,113 3,375 3,584 3,804 4,396 25,720

Mandatorily redeemable Series44

Mandatorily redeemable Series C preferred shares (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Dividend and Redemption Payments	Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are: 2016 $ 979 2017 908 2018 1,068 2019 1,282 2020 1,344 Thereafter to 2031 18,516 Redemption amount 5,340 29,437 Less amounts representing interest (10,910 ) 18,527 Less current portion (979 ) $ 17,548

Other assets (Tables)

Other assets (Tables)	12 Months Ended
	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other Assets	Other assets consist of the following: 2015 2014 Restricted cash $ 18,999 $ 18,702 Deferred financing costs 3,211 2,428 Other 4,770 4,475 26,980 25,605 Less current portion (464 ) — $ 26,516 $ 25,605

Other long-term liabilities a46

Other long-term liabilities and deferred credits (Tables)	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other Long Term Liabilities	Other long-term liabilities consist of the following: 2015 2014 Advances in aid of construction (a) $ 92,285 $ 81,104 Environmental remediation obligation (b) 71,529 70,072 Asset retirement obligations (c) 17,799 13,884 Customer deposits (d) 15,074 11,713 Deferred income (e) 13,682 13,132 Deferred credits (f) 24,110 19,130 Other 25,277 17,503 259,756 226,538 Less current portion (36,621 ) (49,303 ) $ 223,135 $ 177,235 (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 10 to 20 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 2015, $4,637 (2014 - $4,608 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems 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 historic 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 $78,495 (2014 - $72,594 ) which at discount rates ranging from 2.5% to 4.2% represents the recorded accrual of $71,529 as of December 31, 2015 (2014 - $70,072 ). Approximately $46,929 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 29 years. 13. Other long-term liabilities and deferred credits (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072 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, 2015, the Company has reflected a regulatory asset of $116,747 (2014 - $102,735 ) 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 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; and (iv) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC recorded additional asset retirement obligations of $ 506 (2014 - $ 2,570 ) for renewable generation facilities being constructed and accretion expense of $854 (2014 - $527 ). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Deferred income Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized.
Changes in Environmental Remediation Obligation	Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072

Shareholders' capital (Tables)

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
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, 2015 and 2014: Preferred shares Number of shares Price per share Carrying amount Series A 4,800,000 $ 25 $ 116,546 Series D 4,000,000 $ 25 97,259 $ 213,805
Number of Common Shares	Number of common shares: 2015 2014 Common shares, beginning of year 238,149,468 206,348,985 Public offering (i) 14,355,000 29,444,000 Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii)) 3,364,951 2,356,483 Common shares, end of year 255,869,419 238,149,468
Share-Based Compensation Expense	For the year ended December 31, 2015 , APUC recorded $5,330 (2014 - $3,248 ) in total share-based compensation expense detailed as follows: 2015 2014 Share options $ 2,742 $ 1,931 Directors deferred share units 404 273 Employee share purchase 158 116 Performance share units 2,026 928 Total share-based compensation $ 5,330 $ 3,248
Fair Value of Share Options Granted	The following assumptions were used in determining the fair value of share options granted: 2015 2014 Risk-free interest rate 1.3 % 2.0 % Expected volatility 38 % 38 % Expected dividend yield 4.0 % 3.8 % Expected life 8 years 8 years Weighted average grant date fair value per option $ 2.45 $ 2.00
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 at January 1, 2014 4,567,129 $ 5.70 5.45 $ 7,814 Granted 969,998 7.95 8.00 — Balance at December 31, 2014 5,537,127 $ 6.09 4.96 $ 19,648 Granted 1,627,525 9.75 8.00 — Balance at December 31, 2015 7,164,652 $ 6.92 4.74 $ 28,561 Exercisable at December 31, 2015 4,618,323 $ 5.74 3.55 $ 23,898
Performance Stock Units	A summary of the PSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 66,195 $ 6.57 0.62 $ 486 Granted 407,962 8.22 3.00 3,333 Exercised (22,665 ) 6.13 — (185 ) Forfeited (11,406 ) 8.22 — (93 ) Balance at December 31, 2014 440,086 $ 6.57 1.81 $ 4,242 Granted, including dividends 212,250 9.72 2.62 — Exercised (41,131 ) 6.86 — 381 Forfeited (47,089 ) 8.30 — — Balance at December 31, 2015 564,116 $ 7.59 1.63 $ 6,155 Exercisable at December 31, 2015 157,972 $ 8.22 — $ 1,723

Accumulated other comprehensi48

Accumulated other comprehensive income (loss) (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2014 $ (57,471 ) $ 11,840 $ — $ 14,221 $ (31,410 ) OCI (loss) before reclassifications 68,938 3,358 519 (35,396 ) 37,419 Amounts reclassified — 5,423 (518 ) (273 ) 4,632 Net current period OCI 68,938 8,781 1 (35,669 ) 42,051 Acquisition of non-controlling interest 21,029 2,543 — — 23,572 Balance, December 31, 2014 $ 32,496 $ 23,164 $ 1 $ (21,448 ) $ 34,213 OCI before reclassifications 228,861 21,896 (73 ) 6,487 257,171 Amounts reclassified — (5,731 ) — 1,084 (4,647 ) Net current period OCI $ 228,861 $ 16,165 $ (73 ) $ 7,571 $ 252,524 Balance, December 31, 2015 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737

Dividends (Tables)

Dividends (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Cash Dividends [Abstract]
Dividends	Dividends declared in Canadian equivalent dollars during the year were as follows: 2015 2014 Dividend Dividend per share Dividend Dividend per share Common shares $ 124,831 $ 0.4867 $ 83,097 $ 0.3695 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 4,103 $ 1.0257

Non-controlling Interests (Tabl

Non-controlling Interests (Tables)	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
Net Earnings (Loss) Attributable to Noncontrolling Interests	Net loss attributable to non-controlling interests consists of the following: 2015 2014 Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo (i) $ — $ 3,484 Net loss attributable to Class A partnership units (ii) (33,942 ) (27,199 ) Other net earnings attributable to non-controlling interests 1,966 1,529 Total net loss attributable to non-controlling interests $ (31,976 ) $ (22,186 ) (i) On March 31, 2014, the Company acquired the remaining Class B partnership units of Wind Portfolio SponsorCo from the non-controlling interest holder. As a result of the transaction, the Company now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units (note 3(h)). (ii) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Senate, Minonk and Sandy Ridge wind facilities and, beginning December 31, 2014, the Bakersfield Solar facility 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(q).

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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% (2014 - 26.5% ). The differences are as follows: 2015 2014 Expected income tax expense at Canadian statutory rate $ 34,516 $ 19,199 Increase (decrease) resulting from: Recognition of deferred credit (2,448 ) (5,763 ) Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (3,855 ) (1,677 ) Non-taxable corporate dividend (3,311 ) (2,618 ) Non-controlling interests share of income 12,511 8,824 Production tax credit (254 ) (339 ) Allowance for equity funds used during construction (935 ) (746 ) State taxes 733 604 Adjustment relating to prior periods 2,431 — CRA Settlement 2,709 — Other 1,616 (677 ) Income tax expense $ 43,713 $ 16,807
Income (Loss) Before Taxes	For the years ended December 31, 2015 and 2014, earnings from continuing operations before income taxes consist of the following: 2015 2014 Canadian operations $ 28,481 $ 11,930 U.S. operations 101,768 60,519 $ 130,249 $ 72,449
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, 2015 Canada $ 5,272 $ 1,959 $ 7,231 United States 2,038 34,444 36,482 $ 7,310 $ 36,403 $ 43,713 Year ended December 31, 2014 Canada $ 5,660 $ (3,538 ) $ 2,122 United States (1,986 ) 16,671 14,685 $ 3,674 $ 13,133 $ 16,807
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, 2015 and 2014 are presented below: 2015 2014 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 396,727 $ 319,056 Pension and OPEB 57,969 54,458 Acquisition-related costs 6,035 5,168 Environmental obligation 28,230 28,555 Production tax credit 3,027 2,098 Reserves not currently deductible 2,503 2,315 Other 4,970 3,988 Total deferred income tax assets 499,461 415,638 Less valuation allowance (17,478 ) (15,534 ) Total deferred tax assets 481,983 400,104 Deferred tax liabilities: Property, plant and equipment (544,616 ) (387,931 ) Intangible assets (2,760 ) (2,752 ) Outside basis in partnership (32,221 ) (15,194 ) Regulatory accounts (28,270 ) (49,399 ) Financial derivatives (31,806 ) (15,013 ) Total deferred tax liabilities (639,673 ) (470,289 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 18,109 $ 64,275 Deferred tax liabilities (175,799 ) $ (134,460 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 )
Non Capital Losses Carry Forwards	As of December 31, 2015, 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 2016 $ — 2017 and onwards 967,499 $ 967,499

Basic and diluted net earning52

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 Net earnings attributable to shareholders of APUC $ 117,480 $ 75,701 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 4,103 Net earnings attributable to common shareholders of APUC $ 107,080 $ 66,198 Discontinued operations (1,032 ) (2,127 ) Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 108,112 $ 68,325 Weighted average number of shares Basic 253,172,088 213,953,870 Effect of dilutive securities 3,344,632 2,387,722 Diluted 256,516,720 216,341,592

Segmented information (Tables)

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Results of Operations and Assets for Segments	The results of operations and assets for these segments are reflected in the tables below. Year ended December 31, 2015 Generation Distribution Corporate Total Revenue $ 244,751 $ 783,104 $ — $ 1,027,855 Fuel and power purchased 27,990 348,883 — 376,873 Net revenue 216,761 434,221 — 650,982 Operating expenses 63,601 213,750 1,210 278,561 Administrative expenses 10,822 21,570 8,283 40,675 Depreciation and amortization 67,293 82,513 — 149,806 Gain on foreign exchange — — (2,631 ) (2,631 ) Operating income (loss) from continuing operations 75,045 116,388 (6,862 ) 184,571 Interest expense 29,395 34,971 1,627 65,993 Interest, dividend, equity and other income (1,154 ) (3,974 ) (3,967 ) (9,095 ) Other expenses (gain) (5,623 ) 391 2,656 (2,576 ) Earnings (loss) before income taxes $ 52,427 $ 85,000 $ (7,178 ) $ 130,249 Property, plant and equipment $ 1,895,617 $ 1,914,980 $ 63,087 $ 3,873,684 Equity-method investees 44,638 769 7,066 52,473 Total assets 2,345,905 2,532,894 112,926 4,991,725 Capital expenditures 55,992 141,445 6,758 204,195 21. Segmented information (continued) Year ended December 31, 2014 Generation Distribution Corporate Total Revenue $ 218,765 $ 722,849 $ — $ 941,614 Fuel and power purchased 39,264 381,622 — 420,886 Net revenue 179,501 341,227 — 520,728 Operating expenses 55,482 178,248 308 234,038 Administrative expenses 13,457 19,947 1,288 34,692 Depreciation and amortization 58,248 53,671 2,128 114,047 Gain on foreign exchange — — (1,112 ) (1,112 ) 52,314 89,361 (2,612 ) 139,063 Interest expense 33,868 27,139 1,411 62,418 Interest, dividend and other income (1,187 ) (3,369 ) (3,202 ) (7,758 ) Other expense (gain) 48 300 11,606 11,954 Earnings (loss) before income taxes $ 19,585 $ 65,291 $ (12,427 ) $ 72,449 Property, plant and equipment $ 1,687,465 $ 1,531,166 $ 59,791 $ 3,278,422 Equity-method investees 3,520 500 2,578 6,598 Total assets 1,896,265 2,098,244 108,339 4,102,848 Capital expenditures 201,063 176,849 54,461 432,373
Information on Operations by Geographic Area	Information on operations by geographic area is as follows: 2015 2014 Revenue Canada $ 86,977 $ 92,267 United States 940,878 849,347 $ 1,027,855 $ 941,614 Property, plant and equipment Canada $ 592,598 $ 590,580 United States 3,281,086 2,687,842 $ 3,873,684 $ 3,278,422 Intangible assets Canada $ 40,186 $ 25,601 United States 37,777 28,410 $ 77,963 $ 54,011

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
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) $ 82,403 $ 52,644 $ 55,599 $ 59,165 $ 59,791 $ — $ 309,602 Gas supply and service agreements (ii) 66,264 46,673 36,621 35,482 32,070 82,509 299,619 Service agreements 38,335 38,151 35,019 35,734 35,955 518,193 701,387 Capital projects 35,842 7,571 71 71 71 18 43,644 Operating leases 5,863 5,319 4,866 4,754 4,793 106,210 131,805 Total $ 228,707 $ 150,358 $ 132,176 $ 135,206 $ 132,680 $ 706,930 $ 1,486,057 (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, 2015. 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, 2015
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: 2015 2014 Accounts receivable $ 6,715 $ (23,640 ) Natural gas in storage 3,049 (5,942 ) Supplies and consumable inventory (2,968 ) (3,861 ) Income taxes receivable (2,529 ) (189 ) Prepaid expenses (7,833 ) 827 Accounts payable (18,261 ) 54,299 Accrued liabilities (28,495 ) 32,520 Current income tax liability 1,820 (1,527 ) Net regulatory assets and liabilities 37,353 (54,277 ) $ (11,149 ) $ (1,790 )

Financial instruments (Tables)

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair value of financial instruments 2015 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 119,383 $ 126,468 $ — $ 126,468 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 88,357 88,357 — — 88,357 Commodity contracts for regulated operations 4 4 — 4 — Total derivative financial instruments 88,361 88,361 — 4 88,357 Total financial assets $ 207,744 $ 214,829 $ — $ 126,472 $ 88,357 Long-term debt $ 1,486,795 $ 1,547,346 $ 511,829 $ 1,035,517 $ — Preferred shares, Series C 18,527 17,303 — 17,303 — Derivative financial instruments: Energy contracts designated as a cash flow hedge 446 446 — — 446 Cross-currency swap designated as a net investment hedge 101,559 101,559 — 101,559 — Interest rate swap designated as a hedge 9,659 9,659 — 9,659 — Currency forward contract not designated as a hedge 1,918 1,918 — 1,918 — Commodity contracts for regulated operations 1,676 1,676 — 1,676 — Total derivative financial instruments 115,258 115,258 — 114,812 446 Total financial liabilities $ 1,620,580 $ 1,679,907 $ 511,829 $ 1,167,632 $ 446 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2014 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 39,510 $ 41,339 $ — $ 41,339 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 41,966 41,966 — — 41,966 Energy contracts not designated as a cash flow hedge 504 504 — — 504 Total derivative financial instruments 42,470 42,470 — — 42,470 Total financial assets $ 81,980 $ 83,809 $ — $ 41,339 $ 42,470 Long-term debt $ 1,271,719 $ 1,363,934 $ 520,142 $ 843,792 $ — Preferred shares, Series C 18,693 18,209 — 18,209 — Derivative financial instruments: Cross-currency swap designated as a net investment hedge 36,276 36,276 — 36,276 — Interest rate swaps designated as a hedge 4,684 4,684 — 4,684 — Interest rate swaps not designated as a hedge 1,383 1,383 — 1,383 — Commodity contracts for regulated operations 2,928 2,928 — 2,928 — Total derivative financial instruments 45,271 45,271 — 45,271 — Total financial liabilities $ 1,335,683 $ 1,427,414 $ 520,142 $ 907,272 $ —
Summary of Commodity Volumes Associated with Derivative Contracts	The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2015 Financial contracts: Gas swaps 1,086,228 Gas options 412,369 1,498,597
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: 2015 2014 Regulatory assets: Gas swap contracts U.S. $ 1,058 U.S. $ 2,178 Gas option contracts U.S. $ 154 U.S. $ 346 Regulatory liabilities: Gas swap contracts U.S. $ 3 U.S. $ — Gas option contracts U.S. $ — U.S. $ —
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 and at one of its hydro facilities no longer subject to a power purchase agreement 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) 49,135 December 2016 $ 68.56 AESO 801,098 December 2022 U.S. $ 42.81 PJM Western HUB 3,419,634 December 2022 U.S. $ 30.25 NI HUB 3,997,509 December 2027 U.S. $ 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: 2015 2014 Effective portion of cash flow hedge, loss (gain) $ 21,932 $ (2,592 ) Amortization of cash flow hedge (36 ) (32 ) Loss (gain) reclassified from AOCI (5,731 ) 5,423 $ 16,165 $ 2,799 Less non-controlling interest — 5,982 OCI attributable to shareholders of APUC $ 16,165 $ 8,781
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: 2015 2014 Change in unrealized loss (gain) on derivative financial instruments: Interest rate swaps $ (1,383 ) $ (1,797 ) Energy derivative contracts 886 3,386 Currency forward contract 1,918 — Total change in unrealized loss (gain) on derivative financial instruments $ 1,421 $ 1,589 Realized loss (gain) on derivative financial instruments: Interest rate swaps 1,498 1,962 Energy derivative contracts (579 ) (3,627 ) Total realized loss (gain) on derivative financial instruments $ 919 $ (1,665 ) Loss (gain) on derivative financial instruments not accounted for as hedges 2,340 (76 ) Ineffective portion of derivative financial instruments accounted for as hedges (2,610 ) 1,451 $ (270 ) $ 1,375 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (2,188 ) $ 1,375 Loss on foreign exchange $ 1,918 $ — $ (270 ) $ 1,375
Maximum Credit Risk Exposure for Financial Instruments	As of December 31, 2015, the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2015 Canadian $ US $ Cash and cash equivalents and restricted cash $ 39,972 $ 74,696 Accounts receivable 15,016 129,791 Allowance for doubtful accounts (5,756 ) Notes receivable 19,664 72,052 $ 74,652 $ 270,783
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 $ 8,945 $ 222,810 $ 187,582 $ 1,076,786 $ 1,496,123 Advances in aid of construction 1,347 — — 90,938 92,285 Interest on long-term debt 74,324 138,841 117,328 333,606 664,099 Purchase obligations 243,748 — — — 243,748 Environmental obligation 5,435 41,494 1,753 29,813 78,495 Derivative financial instruments: Cross-currency swap 4,828 8,963 7,508 80,260 101,559 Interest rate swaps — 9,659 — — 9,659 Currency forward 1,918 — — — 1,918 Energy derivative and commodity contracts 1,885 237 — — 2,122 Other obligations 12,808 — — 40,694 53,502 Total obligations $ 355,238 $ 422,004 $ 314,171 $ 1,652,097 $ 2,743,510

Significant accounting polici57

Significant accounting policies - Additional Information (Detail) CAD in Thousands	12 Months Ended
	Dec. 31, 2015CADFacility	Dec. 31, 2015CAD$ / shares	Dec. 31, 2014CAD
Significant Accounting Policies [Line Items]
Deprecation expense, reduction	CAD 3,418
Earnings per share, basic and diluted, increase due to change in depreciation method (cad per share) | $ / shares		$ 0.01
Number of power generating facilities | Facility	2
Non-regulated energy sales	CAD 222,581		CAD 202,300
Interest expense	65,993		62,418
Revenue from insurance claims for business interruption	581		1,227
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	104,243	$ 104,243	112,344
Long-term debt of Long Sault	62,138	$ 62,138	59,449
Non-regulated energy sales	18,651		11,218
Operating expenses and amortization	5,645		3,418
Interest expense	CAD 4,407		CAD 3,820
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

Significant accounting polici58

Significant accounting policies - Capitalization of Interest (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization [Line Items]
Total	CAD 5,271	CAD 7,071
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	1,189	3,584
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	1,657	1,577
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property	CAD 2,425	CAD 1,910

Significant accounting polici59

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	32 years	35 years
Distribution | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Distribution | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	100 years	100 years
Distribution | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	42 years	40 years
Equipment and other | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Equipment and other | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years	50 years
Equipment and other | Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	14 years	14 years

Recently issued accounting pr60

Recently issued accounting pronouncements Recently issued accounting pronouncements (Details) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred finance costs	CAD 3,211	CAD 2,428
New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred tax assets, net, current	(7,210)
Deferred tax liabilities, net, current	CAD (3,702)
Other Assets | New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred finance costs		(8,304)
Long-term Debt | New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred finance costs		CAD 8,304

Business acquisitions and dev61

Business acquisitions and development projects - Additional Information (Details)

Mar. 09, 2016CAD

Mar. 01, 2016CAD

Feb. 09, 2016CAD

Feb. 09, 2016USD ($)

Jan. 08, 2016USD ($)water_utility

Apr. 22, 2015CADMWh

Jan. 02, 2015USD ($)

Dec. 02, 2014CADMWh

May. 30, 2014USD ($)customer

Mar. 31, 2014CAD

Mar. 31, 2014USD ($)

Dec. 20, 2013CAD

Dec. 20, 2013USD ($)

Jan. 01, 2013MW

Mar. 31, 2015USD ($)

Mar. 31, 2014USD ($)

Dec. 31, 2015CAD

Dec. 31, 2014CADMWac

Dec. 31, 2014USD ($)MWac

Feb. 09, 2016USD ($)$ / shares

May. 15, 2015USD ($)

Business Acquisition [Line Items]

Property, plant and equipment

CAD 3,873,684,000

CAD 3,278,422,000

Intangible assets

77,963,000

54,011,000

Acquisition of non-controlling interest

0

127,121,000

Additions to property, plant and equipment

CAD 204,195,000

432,373,000

New Hampshire Gas

Business Acquisition [Line Items]

Business combination, purchase price | $

$ 3,161,000

Wind Portfolio SponsorCo, LLC

Business Acquisition [Line Items]

Noncontrolling interest acquired

40.00%

40.00%

40.00%

Acquisition of non-controlling interest

CAD 127,121,000

$ 115,000,000

New England Gas System

Business Acquisition [Line Items]

Business combination, purchase price

CAD 67,010,000

$ 62,745,000

Weighted average useful life of assets acquired

34 years

Adjustment to total consideration transferred | $

$ 3,108,000

$ 2,701,000

Adjustments to property, plant, and equipment | $

(1,190,000)

Adjustments to environmental obligation | $

2,467,000

Adjustments to pension obligation | $

772,000

Shady Oaks

Business Acquisition [Line Items]

Adjustment to total consideration transferred | $

$ 0

$ 1,133,000

Project power capacity | MW

109.5

White Hall Water System

Business Acquisition [Line Items]

Business combination, purchase price | $

$ 4,499,000

Number of water distribution customers | customer

1,900

Number of wastewater treatment customers | customer

2,400

Subsequent Event | Empire

Business Acquisition [Line Items]

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

$ 34

Business combination, purchase price

CAD 3,400,000,000

$ 2,400,000,000

Business combination, liabilities incurred

1,300,000,000

$ 900,000,000

Subsequent Event | Park Water Company

Business Acquisition [Line Items]

Business combination, purchase price | $

$ 341,750,000

Business combination, liabilities incurred | $

$ 91,750,000

Number of regulated water utilities | water_utility

3

Morse Wind Facility

Business Acquisition [Line Items]

Wind power capacity | MWh

23

Property, plant and equipment

CAD 65,016,000

Intangible assets

16,709,000

Wind generating asset investment

CAD 81,725,000

Weighted average useful life of assets acquired

35 years

Cornwall Solar Facility

Business Acquisition [Line Items]

Business combination, purchase price

CAD 47,333,000

Weighted average useful life of assets acquired

33 years

33 years

Solar power capacity | MWac

10

10

Additions to property, plant and equipment

CAD 40,090,000

Payments to acquire intangible assets

CAD 7,243,000

Bakersfield Solar Project

Business Acquisition [Line Items]

Property, plant and equipment | $

$ 57,160,000

Solar power capacity | MWac

20

20

Bakersfield Solar Project | Partnership | Tax Investor

Business Acquisition [Line Items]

Partnership agreement, funded amount | $

$ 22,438,000

Saint-Damase

Business Acquisition [Line Items]

Wind power capacity | MWh

24

Property, plant and equipment

CAD 64,155,000

Weighted average useful life of assets acquired

34 years

Class B Units | Wind Portfolio SponsorCo, LLC

Business Acquisition [Line Items]

Ownership percentage

100.00%

100.00%

Bridge Loan | Subsequent Event

Business Acquisition [Line Items]

Line of credit facility, maximum borrowing capacity

CAD 2,200,000,000

$ 1,600,000,000

Convertible Subordinated Debt | Subsequent Event

Business Acquisition [Line Items]

Debt instrument, face value

CAD 1,150,000,000

CAD 1,000,000,000

Debt instrument, interest rate

5.00%

Debt instrument, convertible, price per instrument paid at closing (CAD per debenture)

CAD 333,000,000

Proceeds from issuance of debt

150,000,000

Proceeds from issuance of debt, first installment

CAD 49,950,000

Business acquisitions and dev62

Business acquisitions and development projects - Acquisition of Noncontrolling Interest (Details) CAD in Thousands, $ in Thousands	Mar. 31, 2014CAD	Mar. 31, 2014USD ($)	Dec. 31, 2015CAD	Dec. 31, 2014CAD
Business Acquisition [Line Items]
Acquisition of non-controlling interest				CAD 159,672
Acquisition of non-controlling interest			CAD 0	127,121
Wind Portfolio SponsorCo, LLC
Business Acquisition [Line Items]
Acquisition of non-controlling interest, decrease in deferred tax asset	CAD (32,551)
Acquisition of non-controlling interest	127,121	$ 115,000
Non- controlling interests
Business Acquisition [Line Items]
Acquisition of non-controlling interest				205,796
Non- controlling interests | Wind Portfolio SponsorCo, LLC
Business Acquisition [Line Items]
Acquisition of non-controlling interest	205,796
Foreign currency cumulative translation
Business Acquisition [Line Items]
Acquisition of non-controlling interest				(21,029)
Foreign currency cumulative translation | Wind Portfolio SponsorCo, LLC
Business Acquisition [Line Items]
Acquisition of non-controlling interest	(21,029)
Unrealized gain on cash flow hedges
Business Acquisition [Line Items]
Acquisition of non-controlling interest				(2,543)
Unrealized gain on cash flow hedges | Wind Portfolio SponsorCo, LLC
Business Acquisition [Line Items]
Acquisition of non-controlling interest	(2,543)
Additional paid-in capital
Business Acquisition [Line Items]
Acquisition of non-controlling interest				CAD (22,552)
Additional paid-in capital | Wind Portfolio SponsorCo, LLC
Business Acquisition [Line Items]
Acquisition of non-controlling interest	CAD (22,552)

Accounts receivable - Additiona

Accounts receivable - Additional Information (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	CAD 7,966	CAD 7,229
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	CAD 49,002	CAD 52,880

Property, plant and equipment64

Property, plant and equipment (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Cost	CAD 4,535,068	CAD 3,726,420
Accumulated depreciation	661,384	447,998
Net book value	3,873,684	3,278,422
Land
Property, Plant and Equipment [Line Items]
Cost	23,258	19,347
Accumulated depreciation	0	0
Net book value	23,258	19,347
Equipment and other
Property, Plant and Equipment [Line Items]
Cost	129,555	119,367
Accumulated depreciation	37,443	29,526
Net book value	92,112	89,841
Generation
Property, Plant and Equipment [Line Items]
Cost	2,138,748	1,827,247
Accumulated depreciation	358,200	270,746
Net book value	1,780,548	1,556,501
Generation | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	64,779	82,840
Accumulated depreciation	0	0
Net book value	64,779	82,840
Distribution
Property, Plant and Equipment [Line Items]
Cost	2,075,059	1,555,289
Accumulated depreciation	265,741	147,726
Net book value	1,809,318	1,407,563
Distribution | Construction in progress
Property, Plant and Equipment [Line Items]
Cost	103,669	122,330
Accumulated depreciation	0	0
Net book value	CAD 103,669	CAD 122,330

Property, plant and equipment -

Property, plant and equipment - Additional Information (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant, and Equipment Disclosure [Line Items]
Contribution received	CAD 9,623	CAD 362
Water & wastewater
Property, Plant, and Equipment Disclosure [Line Items]
Expansion cost, distribution cost	1,000
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	158,514	155,629
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	38,507	34,013
Depreciation expense	CAD 2,117	CAD 2,274

Intangible assets and goodwil66

Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Cost	CAD 128,808	CAD 95,699
Accumulated amortization	50,845	41,688
Net book value	77,963	54,011
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	78,725	64,605
Accumulated amortization	40,244	33,704
Net book value	38,481	30,901
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	37,083	31,094
Accumulated amortization	10,371	7,984
Net book value	26,712	23,110
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	13,000	0
Accumulated amortization	230	0
Net book value	CAD 12,770	CAD 0

Intangible assets and goodwil67

Intangible assets and goodwill - Additional Information (Detail) CAD in Thousands	Dec. 31, 2015CAD
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	CAD 5,420
Estimated amortization expense for intangibles in year 2	3,620
Estimated amortization expense for intangibles in year 3	3,250
Estimated amortization expense for intangibles in year 4	3,200
Estimated amortization expense for intangibles in year 5	CAD 3,160

Intangible assets and goodwil68

Intangible assets and goodwill - Schedule of Goodwill (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill beginning of the period	CAD 92,328	CAD 84,647
Business acquisitions	290
Foreign exchange	17,875	7,681
Goodwill end of the period	CAD 110,493	CAD 92,328

Regulatory matters - Regulatory

Regulatory matters - Regulatory Assets and Liabilities (Additional Information) (Detail) CAD in Thousands, $ in Thousands	Feb. 18, 2016USD ($)	Feb. 10, 2016USD ($)	Jun. 26, 2015USD ($)	Mar. 12, 2015USD ($)	Feb. 11, 2015USD ($)	Dec. 04, 2014USD ($)	Dec. 03, 2014USD ($)	Apr. 18, 2014USD ($)	Mar. 17, 2014USD ($)	May. 31, 2014USD ($)	Dec. 31, 2015CAD
Rate-base offset
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period											10 years
Rate adjustment mechanism
Regulatory Assets And Liabilities [Line Items]
Collection period for services rendered											24 months
Environmental costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets recovery period											7 years
Pension and post-employment benefits
Regulatory Assets And Liabilities [Line Items]
Portion related to current acquisition | CAD											CAD 32,313
Regulatory asset approved not yet being recovered, average recovery term											10 years
Georgia Public Service
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase						$ 3,680				$ 3,235
Georgia Public Service | Subsequent Event
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase	$ 2,725
Massachusetts Department of Public Utilities | Subsequent Event
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase		$ 7,800
New Hampshire Public Utilities Commission
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase			$ 12,400
Approved rate increase									$ 10,875
Approved base rate increase									9,760
Approved incremental capital expended									1,115
Approved recovery of rate case expenses									$ 390
Arkansas Public Service Commission
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase				$ 1,087
Illinois Commerce Commission
Regulatory Assets And Liabilities [Line Items]
Approved revenue increase					$ 4,625
Arizona Corporate Commission
Regulatory Assets And Liabilities [Line Items]
Approved rate increase								$ 1,767
Missouri Public Service Commission
Regulatory Assets And Liabilities [Line Items]
Approved rate increase							$ 4,868

Regulatory matters - Regulato70

Regulatory matters - Regulatory Assets and Liabilities (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	CAD 245,315	CAD 247,272
Less current regulatory assets	(32,213)	(61,645)
Non-current regulatory assets	213,102	185,627
Total regulatory liabilities	175,347	121,756
Less current regulatory liabilities	(44,167)	(20,590)
Non-current regulatory liabilities	131,180	101,166
Cost of removal
Regulatory Assets And Liabilities [Line Items]
Total regulatory liabilities	107,988	78,013
Rate-base offset
Regulatory Assets And Liabilities [Line Items]
Total regulatory liabilities	24,984	23,427
Commodity costs adjustment
Regulatory Assets And Liabilities [Line Items]
Total regulatory liabilities	32,423	10,389
Other
Regulatory Assets And Liabilities [Line Items]
Total regulatory liabilities	9,952	9,927
Environmental remediation
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	116,747	102,735
Pension and post-employment benefits
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	69,537	63,512
Commodity costs adjustment
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	7,643	41,502
Rate case costs
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	6,535	4,161
Rate adjustment mechanism
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	14,804	6,207
Other
Regulatory Assets And Liabilities [Line Items]
Total regulatory assets	CAD 30,049	CAD 29,155

Long-term investments (Detail)

Long-term investments (Detail) CAD in Thousands, $ in Thousands	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Oct. 19, 2015	Dec. 31, 2014CAD	Nov. 30, 2014	Nov. 14, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	CAD 52,473			CAD 6,598
Available-for-sale investment	2,946			137
Notes receivable	119,383			39,510
Total long-term investments	174,802			46,245
Less current portion	0			(2,966)
Total long-term investments	174,802			43,279
Notes Receivable | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable	96,924			17,582
Notes Receivable | Red Lily Senior loan, interest at 6.31%
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable	CAD 11,588			11,588
Note receivable interest rate	6.31%	6.31%
Notes Receivable | Red Lily Subordinated loan, interest at 12.5%
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable	CAD 6,565			6,565
Note receivable interest rate	12.50%	12.50%
Notes Receivable | Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable	CAD 4,306			3,775
50% interest in Odell Wind Project
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	CAD 42,287			2,267
Equity interest	50.00%	50.00%				50.00%
50% interest in Odell Wind Project | Notes Receivable | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable | $		$ 62,751
50% Interest in Deerfield Wind Project
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	CAD 2,240			0
Equity interest	50.00%	50.00%	50.00%
50% Interest in Deerfield Wind Project | Notes Receivable | Development loans
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable | $		$ 7,281
Interest in Natural Gas Pipeline Development
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	CAD 5,623			1,063
Equity interest					2.50%
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Equity-method investees	CAD 2,323			CAD 3,268

Long-term investments (Addition

Long-term investments (Additional Information) (Detail)

Feb. 23, 2016CAD

Oct. 19, 2015USD ($)memberMW

Oct. 06, 2015USD ($)member

Nov. 14, 2014USD ($)MW

Dec. 31, 2015CADmemberTranche

Nov. 30, 2014

Dec. 31, 2016USD ($)

Dec. 31, 2015CADmemberTrancheMW

Dec. 31, 2015USD ($)MW

Dec. 31, 2014CAD

Dec. 31, 2011CAD

Dec. 31, 2015USD ($)memberTranche

Dec. 31, 2014USD ($)

Dec. 31, 2012CAD

Accounts, Notes, Loans and Financing Receivable [Line Items]

Notes receivable | CAD

CAD 119,383,000

CAD 119,383,000

CAD 39,510,000

Red Lily I Project, wind energy facility, capacity (in megawatt) | MW

26.4

26.4

Development loans | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Notes receivable | CAD

CAD 96,924,000

CAD 96,924,000

17,582,000

Red Lily Senior loan, interest at 6.31% | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Note receivable interest rate

6.31%

6.31%

6.31%

Notes receivable | CAD

CAD 11,588,000

CAD 11,588,000

11,588,000

Number of tranches | Tranche

2

2

2

Prepayment received | CAD

CAD 1,412,000

Red Lily Subordinated loan, interest at 12.5% | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Note receivable interest rate

12.50%

12.50%

12.50%

Notes receivable | CAD

CAD 6,565,000

CAD 6,565,000

6,565,000

Red Lily Senior Loan Tranche 1 | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Third party payments to acquire note receivable | CAD

CAD 27,000,000

Red Lily Senior Loan Tranche 2 | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Note receivable interest rate

6.31%

6.31%

6.31%

Third party payments to acquire note receivable | CAD

CAD 4,000,000

Payments to acquire notes receivable | CAD

CAD 13,000,000

50% interest in Odell and Deerfield Wind Projects

Accounts, Notes, Loans and Financing Receivable [Line Items]

Guarantee obligations | $

$ 1,147,000

50% interest in Odell and Deerfield Wind Projects | Development loans

Accounts, Notes, Loans and Financing Receivable [Line Items]

Stated interest rate after commercial operation

5.00%

5.00%

5.00%

Letter of credit fee percent

2.00%

2.00%

Note receivable termination period

30 days

30 days

Note receivable, term

5 years

5 years

50% interest in Odell and Deerfield Wind Projects | Development loans | Maximum

Accounts, Notes, Loans and Financing Receivable [Line Items]

Note receivable interest rate

8.00%

8.00%

8.00%

50% interest in Odell and Deerfield Wind Projects | Development loans | Minimum

Accounts, Notes, Loans and Financing Receivable [Line Items]

Note receivable interest rate

7.00%

7.00%

7.00%

50% Interest in Deerfield Wind Project

Accounts, Notes, Loans and Financing Receivable [Line Items]

Equity interest

50.00%

50.00%

50.00%

50.00%

Project power capacity | MW

150

Number of members | member

2

2

2

2

Contributions of capital | $

$ 1,000,000

Option to acquire percentage of ownership

50.00%

50.00%

Equity method investment, option to purchase, adjustment period

90 days

90 days

Interest capitalized on non-regulated property | CAD

CAD 94,000

Maximum exposure to loss | CAD

CAD 321,472,000

CAD 321,472,000

50% Interest in Deerfield Wind Project | Deerfield SponsorCo | Letter of Credit

Accounts, Notes, Loans and Financing Receivable [Line Items]

Letter of credit issued | $

$ 43,238,000

50% Interest in Deerfield Wind Project | Development loans | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Notes receivable | $

$ 7,281,000

50% interest in Odell Wind Project

Accounts, Notes, Loans and Financing Receivable [Line Items]

Equity interest

50.00%

50.00%

50.00%

50.00%

Project power capacity | MW

200

Number of members | member

2

2

2

2

Contributions of capital | $

$ 23,800,000

$ 1,000,000

Option to acquire percentage of ownership

50.00%

50.00%

Equity method investment, option to purchase, adjustment period

30 days

30 days

Interest capitalized on non-regulated property | CAD

CAD 4,415,000

CAD 0

Maximum exposure to loss | CAD

CAD 190,840,000

CAD 190,840,000

50% interest in Odell Wind Project | Development loans | Notes Receivable

Accounts, Notes, Loans and Financing Receivable [Line Items]

Notes receivable | $

$ 62,751,000

Interest in Odell Wind Project to Utility under the PPA | Odell SponsorCo | Letter of Credit

Accounts, Notes, Loans and Financing Receivable [Line Items]

Letter of credit issued | $

15,000,000

Interest in Odell Wind Project Pursuant to the Generator Interconnection Agreement | Odell SponsorCo | Letter of Credit

Accounts, Notes, Loans and Financing Receivable [Line Items]

Letter of credit issued | $

$ 1,119,000

4.0% interest in natural gas transmission pipeline

Accounts, Notes, Loans and Financing Receivable [Line Items]

Equity interest

4.00%

4.00%

4.00%

4.0% interest in natural gas transmission pipeline | Maximum

Accounts, Notes, Loans and Financing Receivable [Line Items]

Option to subscribe equity interest in partnership, percentage

10.00%

2.5% interest in natural gas pipeline development

Accounts, Notes, Loans and Financing Receivable [Line Items]

Equity interest

2.50%

Total invested | $

$ 4,063,000

$ 375,000

2.5% interest in natural gas pipeline development | Maximum

Accounts, Notes, Loans and Financing Receivable [Line Items]

Option to subscribe equity interest in partnership, percentage

10.00%

10.00%

10.00%

Investment commitment if option is exercised | $

$ 520,000,000

Subsequent Event | Red Lily

Accounts, Notes, Loans and Financing Receivable [Line Items]

Option to subscribe equity interest in partnership, exercisable period

90 days

Subsequent Event | Maximum

Accounts, Notes, Loans and Financing Receivable [Line Items]

Subordinated loan to be advanced | CAD

CAD 15,588,000

Subsequent Event | Maximum | Red Lily

Accounts, Notes, Loans and Financing Receivable [Line Items]

Option to subscribe equity interest in partnership, percentage

75.00%

Plan | 50% Interest in Deerfield Wind Project

Accounts, Notes, Loans and Financing Receivable [Line Items]

Estimated construction costs | $

$ 303,000,000

Plan | 50% interest in Odell Wind Project

Accounts, Notes, Loans and Financing Receivable [Line Items]

Estimated construction costs | $

$ 322,766,000

Forecast | 50% Interest in Deerfield Wind Project

Accounts, Notes, Loans and Financing Receivable [Line Items]

Contributions of capital | $

$ 18,596,000

Equity method investment, contribution, percent of accrued interest

7.00%

Long-term debt (Detail)

Long-term debt (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total	CAD 1,486,795	CAD 1,271,719
Less: current portion	(8,945)	(9,130)
Long-term debt, excluding current portion	1,477,850	1,262,589
Generation | Revolving Credit Facility
Debt Instrument [Line Items]
Total	27,300	23,400
Generation | Senior Unsecured Notes | Algonquin Power Co. Senior Unsecured Notes
Debt Instrument [Line Items]
Total	481,991	481,438
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt
Debt Instrument [Line Items]
Total	0	88,168
Generation | Senior Debt | Long Sault Hydro Facility Senior Debt
Debt Instrument [Line Items]
Total	34,760	35,997
Generation | Senior Debt | Chuteford Hydro Facility Senior Debt
Debt Instrument [Line Items]
Total	2,587	3,022
Distribution
Debt Instrument [Line Items]
Total	946,782
Distribution | Revolving Credit Facility
Debt Instrument [Line Items]
Total	0	23,898
Distribution | Senior Unsecured Notes | Liberty Utilities Co. Senior Unsecured Notes
Debt Instrument [Line Items]
Total	721,581	419,876
Distribution | Senior Unsecured Notes | Calpeco Electric System Senior Unsecured Notes
Debt Instrument [Line Items]
Total	96,015	80,368
Distribution | Senior Unsecured Notes | Liberty Water Co, Senior Unsecured Notes
Debt Instrument [Line Items]
Total	68,488	57,301
Distribution | Senior Unsecured Notes | Granite State, Senior Unsecured Long-term Notes
Debt Instrument [Line Items]
Total	20,730	17,373
Distribution | Bonds | New England Gas System, First Mortgage Bonds
Debt Instrument [Line Items]
Total	32,130	27,288
Distribution | Bonds | LPSCo Water Bonds
Debt Instrument [Line Items]
Total	0	12,441
Distribution | Loans | Bella Vista Water Loans
Debt Instrument [Line Items]
Total	CAD 1,213	CAD 1,149

Long-term debt - Additional Inf

Long-term debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015CAD	Dec. 31, 2014CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 31, 2014CAD	Jul. 30, 2014CAD	Jan. 31, 2014CAD	Dec. 31, 2013CAD	Nov. 19, 2013USD ($)
Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity									$ 65,000,000
Generation | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity | CAD					CAD 350,000,000	CAD 200,000,000
Generation | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity | CAD	CAD 350,000,000	CAD 350,000,000
Debt instrument, basis spread on variable rate	1.45%	1.45%
Revolving credit facility, maturity date	Jul. 31, 2019	Jul. 31, 2019
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt
Debt Instrument [Line Items]
Debt instrument, face value				$ 76,000,000
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt | LIBOR
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.80%
Generation | Senior Debt | Long Sault Hydro Facility Senior Debt
Debt Instrument [Line Items]
Debt instrument, face value | CAD	CAD 34,760,000	CAD 34,760,000
Debt instrument, interest rate	10.21%	10.21%	10.21%	10.21%
Debt instrument, maturity date	Dec. 31, 2027	Dec. 31, 2027
Generation | Senior Debt | Chuteford Hydro Facility Senior Debt
Debt Instrument [Line Items]
Debt instrument, face value | CAD	CAD 2,587,000	CAD 2,587,000
Debt instrument, interest rate	11.55%	11.55%	11.55%	11.55%
Debt instrument, maturity date	Apr. 1, 2020	Apr. 1, 2020
Generation | Senior Unsecured Notes | 4.65% Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face value | CAD	CAD 200,000,000	CAD 200,000,000					CAD 200,000,000
Debt instrument, interest rate	4.65%	4.65%	4.65%	4.65%
Debt instrument, maturity date	Feb. 15, 2022	Feb. 15, 2022
Debt instrument, repayment terms	The notes are interest only, payable semi-annually in arrears.	The notes are interest only, payable semi-annually in arrears.
Generation | Senior Unsecured Notes | 4.82% Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face value | CAD	CAD 150,000,000	CAD 150,000,000						CAD 150,000,000
Debt instrument, interest rate	4.82%	4.82%	4.82%	4.82%
Debt instrument, maturity date	Feb. 15, 2021	Feb. 15, 2021
Debt instrument, repayment terms	The notes are interest only, payable semi-annually in arrears.	The notes are interest only, payable semi-annually in arrears.
Generation | Senior Unsecured Notes | 5.5% Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face value | CAD	CAD 135,000,000	CAD 135,000,000
Debt instrument, interest rate	5.50%	5.50%	5.50%	5.50%
Debt instrument, maturity date	Jul. 25, 2018	Jul. 25, 2018
Debt instrument, repayment terms	The notes are interest only, payable semi-annually in arrears.	The notes are interest only, payable semi-annually in arrears.
Distribution | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity			$ 200,000,000	$ 200,000,000
Debt instrument, basis spread on variable rate	1.25%	1.25%
Revolving credit facility, maturity date	Sep. 30, 2018	Sep. 30, 2018
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 9.44%
Debt Instrument [Line Items]
Debt instrument, face value			$ 6,500,000	$ 6,500,000
Debt instrument, interest rate	9.44%	9.44%	9.44%	9.44%
Debt instrument, maturity date	Feb. 15, 2020	Feb. 15, 2020
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually in arrears.	The notes have interest only payments, payable semi-annually in arrears.
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 7.99%
Debt Instrument [Line Items]
Debt instrument, face value			$ 7,000,000	$ 7,000,000
Debt instrument, interest rate	7.99%	7.99%	7.99%	7.99%
Debt instrument, maturity date	Sep. 15, 2026	Sep. 15, 2026
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually in arrears.	The notes have interest only payments, payable semi-annually in arrears.
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 7.24%
Debt Instrument [Line Items]
Debt instrument, face value			$ 6,000,000	$ 6,000,000
Debt instrument, interest rate	7.24%	7.24%	7.24%	7.24%
Debt instrument, maturity date	Dec. 15, 2027	Dec. 15, 2027
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually in arrears.	The notes have interest only payments, payable semi-annually in arrears.
Distribution | Bonds | Litchfield Park Service Company Bonds, 5.85%
Debt Instrument [Line Items]
Debt instrument, interest rate	5.85%	5.85%	5.85%	5.85%
Distribution | Bonds | Litchfield Park Service Company Bonds, 6.71%
Debt Instrument [Line Items]
Debt instrument, interest rate	6.71%	6.71%	6.71%	6.71%
Distribution | Loans | Bella Vista Water Loans, 6.26%
Debt Instrument [Line Items]
Debt instrument, face value			$ 877,000	$ 877,000
Debt instrument, interest rate	6.26%	6.26%	6.26%	6.26%
Debt instrument, maturity date	Mar. 1, 2020	Mar. 1, 2020
Debt instrument, repayment terms	The loans have principal and interest payments, payable monthly and quarterly in arrears.	The loans have principal and interest payments, payable monthly and quarterly in arrears.
Distribution | Loans | Bella Vista Water Loans, 6.10%
Debt Instrument [Line Items]
Debt instrument, face value			$ 877,000	$ 877,000
Debt instrument, interest rate	6.10%	6.10%	6.10%	6.10%
Debt instrument, maturity date	Dec. 1, 2017	Dec. 1, 2017
Debt instrument, repayment terms	The loans have principal and interest payments, payable monthly and quarterly in arrears.	The loans have principal and interest payments, payable monthly and quarterly in arrears.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.51%
Debt Instrument [Line Items]
Debt instrument, face value			$ 50,000,000	$ 50,000,000
Debt instrument, interest rate	3.51%	3.51%	3.51%	3.51%
Debt instrument, maturity date	Jul. 31, 2017	Jul. 31, 2017
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.23%
Debt Instrument [Line Items]
Debt instrument, face value			$ 25,000,000	$ 25,000,000
Debt instrument, interest rate	3.23%	3.23%	3.23%	3.23%
Debt instrument, maturity date	Jul. 31, 2020	Jul. 31, 2020
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.49%
Debt Instrument [Line Items]
Debt instrument, face value			$ 115,000,000	$ 115,000,000
Debt instrument, interest rate	4.49%	4.49%	4.49%	4.49%
Debt instrument, maturity date	Aug. 1, 2022	Aug. 1, 2022
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.14%
Debt Instrument [Line Items]
Debt instrument, face value			$ 15,000,000	$ 15,000,000
Debt instrument, interest rate	4.14%	4.14%	4.14%	4.14%
Debt instrument, maturity date	Mar. 13, 2023	Mar. 13, 2023
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.86%
Debt Instrument [Line Items]
Debt instrument, face value			$ 75,000,000	$ 75,000,000
Debt instrument, interest rate	3.86%	3.86%	3.86%	3.86%
Debt instrument, maturity date	Jul. 31, 2023	Jul. 31, 2023
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.89%
Debt Instrument [Line Items]
Debt instrument, face value			$ 60,000,000	$ 60,000,000
Debt instrument, interest rate	4.89%	4.89%	4.89%	4.89%
Debt instrument, maturity date	Jul. 30, 2027	Jul. 30, 2027
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.26%
Debt Instrument [Line Items]
Debt instrument, face value			$ 25,000,000	$ 25,000,000
Debt instrument, interest rate	4.26%	4.26%	4.26%	4.26%
Debt instrument, maturity date	Jul. 31, 2028	Jul. 31, 2028
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.13%, Due April 30, 2045
Debt Instrument [Line Items]
Debt instrument, face value			$ 90,000,000	$ 90,000,000
Debt instrument, interest rate	4.13%	4.13%	4.13%	4.13%
Debt instrument, maturity date	Apr. 30, 2045	Apr. 30, 2045
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.13%, Due July 15, 2045
Debt Instrument [Line Items]
Debt instrument, face value			$ 70,000,000	$ 70,000,000
Debt instrument, interest rate	4.13%	4.13%	4.13%	4.13%
Debt instrument, maturity date	Jul. 15, 2045	Jul. 15, 2045
Debt instrument, repayment terms	The notes are interest only, payable semi-annually.	The notes are interest only, payable semi-annually.
Distribution | Senior Unsecured Notes | Calpeco Electric System Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually in arrears.	The notes have interest only payments, payable semi-annually in arrears.
Distribution | Senior Unsecured Notes | California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.19%
Debt Instrument [Line Items]
Debt instrument, face value			$ 45,000,000	$ 45,000,000
Debt instrument, interest rate	5.19%	5.19%	5.19%	5.19%
Debt instrument, maturity date	Dec. 29, 2020	Dec. 29, 2020
Distribution | Senior Unsecured Notes | California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.59%
Debt Instrument [Line Items]
Debt instrument, face value			$ 25,000,000	$ 25,000,000
Debt instrument, interest rate	5.59%	5.59%	5.59%	5.59%
Debt instrument, maturity date	Dec. 29, 2025	Dec. 29, 2025
Distribution | Senior Unsecured Notes | Liberty Water Co, Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, face value			$ 50,000,000	$ 50,000,000
Debt instrument, interest rate	5.60%	5.60%	5.60%	5.60%
Annual principal payment			$ 5,000,000	$ 5,000,000
Balloon payment paid at maturity			25,000,000	25,000,000
Debt instrument, maturity date	Dec. 22, 2020	Dec. 22, 2020
Debt instrument, repayment terms	The note bears interest payments semi-annually in arrears.	The note bears interest payments semi-annually in arrears.
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.37%
Debt Instrument [Line Items]
Debt instrument, face value			$ 5,000,000	$ 5,000,000
Debt instrument, interest rate	7.37%	7.37%	7.37%	7.37%
Debt instrument, maturity date	Nov. 1, 2023	Nov. 1, 2023
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually.	The notes have interest only payments, payable semi-annually.
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.94%
Debt Instrument [Line Items]
Debt instrument, face value			$ 5,000,000	$ 5,000,000
Debt instrument, interest rate	7.94%	7.94%	7.94%	7.94%
Debt instrument, maturity date	Jul. 1, 2025	Jul. 1, 2025
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually.	The notes have interest only payments, payable semi-annually.
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.30%
Debt Instrument [Line Items]
Debt instrument, face value			$ 5,000,000	$ 5,000,000
Debt instrument, interest rate	7.30%	7.30%	7.30%	7.30%
Debt instrument, maturity date	Jun. 15, 2028	Jun. 15, 2028
Debt instrument, repayment terms	The notes have interest only payments, payable semi-annually.	The notes have interest only payments, payable semi-annually.

Long-term debt Long-term debt -

Long-term debt Long-term debt - Narrative (Detail)

Mar. 01, 2016CAD

Feb. 09, 2016CAD

Oct. 30, 2015CAD

Oct. 01, 2015USD ($)

Jul. 15, 2015USD ($)

May. 12, 2015USD ($)

Apr. 30, 2015USD ($)Tranche

Dec. 31, 2014USD ($)

Mar. 10, 2016

Dec. 31, 2015CAD

Dec. 31, 2014CAD

Feb. 09, 2016USD ($)

Jan. 04, 2016USD ($)bank

Dec. 31, 2015USD ($)

Oct. 30, 2015USD ($)

Dec. 31, 2014USD ($)

Jul. 31, 2014CAD

Jul. 30, 2014CAD

Jan. 17, 2014CAD

Nov. 19, 2013USD ($)

Debt Instrument [Line Items]

Deferred finance costs | CAD

CAD 3,211,000

CAD 2,428,000

Repayment of debt | CAD

196,149,000

286,552,000

Interest on long term debt | CAD

25,161,000

18,770,000

Interest expense during the year on long-term liabilities | CAD

CAD 72,213,000

64,218,000

Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 65,000,000

long-term line of credit outstanding

$ 0

$ 0

Generation | Senior Unsecured Notes | 4.65% Senior Unsecured Debentures Due 2022

Debt Instrument [Line Items]

Deferred finance costs | CAD

CAD 1,568,000

Debt instrument, face value | CAD

CAD 200,000,000

Debt instrument, interest rate

4.65%

Debt instrument sold, price per principal amount

0.99864

Generation | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity | CAD

CAD 350,000,000

CAD 200,000,000

Period of development

3 years

Generation | Senior Debt | Sanger Terminal Facility Bonds

Debt Instrument [Line Items]

Repayment of debt

$ 19,200,000

Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt

Debt Instrument [Line Items]

Repayment of debt

$ 76,000,000

Debt instrument, face value

$ 76,000,000

Distribution | Senior Unsecured Thirty Year Note via Private Placement

Debt Instrument [Line Items]

Proceeds from issuance of senior long-term debt

$ 70,000,000

$ 90,000,000

Distribution | Bonds | LPSCo Water Bonds

Debt Instrument [Line Items]

Repayment of debt

$ 9,800,000

Distribution | Senior Debt | Senior Unsecured Thirty Year Note via Private Placement

Debt Instrument [Line Items]

Debt instrument, term

30 years

Debt instrument, face value

$ 160,000,000

Debt instrument, interest rate

4.13%

Debt instrument, number of tranches | Tranche

2

Long-term Debt | New Accounting Pronouncement, Early Adoption, Effect

Debt Instrument [Line Items]

Deferred finance costs | CAD

8,304,000

Other Assets | New Accounting Pronouncement, Early Adoption, Effect

Debt Instrument [Line Items]

Deferred finance costs | CAD

CAD (8,304,000)

Letter of Credit | Generation

Debt Instrument [Line Items]

Debt instrument, term

1 year

Line of credit facility, maximum borrowing capacity

CAD 50,000,000

$ 30,000,000

Subsequent Event | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, term extension

1 year

Subsequent Event | Bridge Financing Commitments

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

CAD 2,200,000,000

$ 1,600,000,000

Subsequent Event | Bridge Financing Commitments | Debt Bridge Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

1,065,000,000

Line of credit facility, advance repayable, maximum time period

1 year

Subsequent Event | Bridge Financing Commitments | Equity Bridge Facility

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 535,000,000

Line of credit facility, increase (decrease) of borrowing capacity | CAD

CAD (359,950,000)

Line of credit facility, advance repayable, maximum time period

1 year

Subsequent Event | Line of Credit

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

$ 235,000,000

Line of credit facility, number of banks | bank

2

Long-term debt Long-term debt76

Long-term debt Long-term debt - Principal Payments (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt, Fiscal Year Maturity [Abstract]
2,016	CAD 8,945
2,017	78,403
2,018	144,407
2,019	37,301
2,020	150,281
Thereafter	1,076,786
Long-term debt	1,486,795	CAD 1,271,719
Total, including adjustment	1,496,123
Generation
Long-term Debt, Fiscal Year Maturity [Abstract]
2,016	1,816
2,017	2,045
2,018	137,272
2,019	30,152
2,020	2,641
Thereafter	375,415
Total, including adjustment	549,341
Distribution
Long-term Debt, Fiscal Year Maturity [Abstract]
2,016	7,129
2,017	76,358
2,018	7,135
2,019	7,149
2,020	147,640
Thereafter	701,371
Long-term debt	CAD 946,782

Pension and other post-retire77

Pension and other post-retirement benefits - Additional Information (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Employee Benefits Disclosure [Line Items]
Defined contribution pension plan cost	CAD 4,132	CAD 3,287
Accumulated benefit obligation for pension plan	251,932	CAD 219,007
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit)	3,941
Pension Plans
Employee Benefits Disclosure [Line Items]
Net actuarial loss for defined benefit pension plan that will be amortized from accumulated other comprehensive income over next fiscal year	632
Expected employer contributions for next year	9,232
Other Postretirement Benefit Plans, Defined Benefit
Employee Benefits Disclosure [Line Items]
Net actuarial loss for defined benefit pension plan that will be amortized from accumulated other comprehensive income over next fiscal year	88
Expected employer contributions for next year	CAD 4,237

Pension and other post-retire78

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Change in projected benefit obligation
Projected benefit obligation, beginning of year	CAD 241,963	CAD 178,113
Projected benefit obligation assumed from business combination	0	1,022
Modifications to pension plan	(4,995)	(560)
Service cost	6,663	4,828
Interest cost	9,642	8,549
Actuarial loss (gain)	(16,098)	39,704
Contributions from retirees	0	0
Benefits paid	(13,024)	(8,125)
Loss on foreign exchange	45,231	18,432
Projected benefit obligation, at end of year	269,382	241,963
Change in plan assets
Fair value of plan assets, beginning of year	156,990	139,280
Actual return (loss) on plan assets	(5,657)	6,568
Employer contributions	7,975	5,676
Benefits paid	(12,589)	(7,414)
Gain on foreign exchange	29,453	12,880
Fair value of plan assets, end of year	176,172	156,990
Unfunded status	(93,210)	(84,973)
Current liabilities	(470)	0
Non-current liabilities	(92,740)	(84,973)
Net amount recognized	(93,210)	(84,973)
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation
Projected benefit obligation, beginning of year	68,257	45,399
Projected benefit obligation assumed from business combination	0	0
Modifications to pension plan	0	0
Service cost	3,093	2,022
Interest cost	2,914	2,186
Actuarial loss (gain)	(8,466)	14,893
Contributions from retirees	412	331
Benefits paid	(2,447)	(1,586)
Loss on foreign exchange	12,802	5,012
Projected benefit obligation, at end of year	76,565	68,257
Change in plan assets
Fair value of plan assets, beginning of year	14,295	13,395
Actual return (loss) on plan assets	20	1,176
Employer contributions	3,028	(222)
Benefits paid	(2,036)	(1,255)
Gain on foreign exchange	2,842	1,201
Fair value of plan assets, end of year	18,149	14,295
Unfunded status	(58,416)	(53,962)
Current liabilities	(1,062)	(333)
Non-current liabilities	(57,354)	(53,629)
Net amount recognized	CAD (58,416)	CAD (53,962)

Pension and other post-retire79

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits
Beginning balance	CAD 28,751	CAD (14,385)
Current year net actuarial gain (loss)	1,505	43,350
Current year prior service credits	(4,864)	(563)
Amortization of net actuarial loss (gains)	1,358	349
Amortization of prior service credits	457
Ending balance	24,491	28,751
Other Postretirement Benefit Plans, Defined Benefit
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits
Beginning balance	5,896	(9,083)
Current year net actuarial gain (loss)	(7,554)	14,338
Current year prior service credits	0	0
Amortization of net actuarial loss (gains)	680	641
Amortization of prior service credits	0
Ending balance	CAD (2,338)	CAD 5,896

Pension and other post-retire80

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.71%	4.55%
Expected return on assets	6.44%	7.00%
Rate of compensation increase	3.01%	2.97%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.82%	4.60%
Expected return on assets	5.50%	5.53%
Health care cost trend rate
Before Age 65	7.00%	7.63%
Age 65 and after	7.00%	7.63%
Assumed Ultimate Medical Inflation Rate	5.00%	5.00%
Year in which Ultimate Rate is reached	2,019	2,019

Pension and other post-retire81

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.16%	3.71%
Rate of compensation increase	3.00%	3.01%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.23%	3.80%
Health care cost trend rate
Before Age 65	6.50%	7.00%
Age 65 and after	6.50%	7.00%
Assumed Ultimate Medical Inflation Rate	4.75%	5.00%
Year in which Ultimate Rate is reached	2,023	2,019

Pension and other post-retire82

Pension and other post-retirement benefits - Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR) (Detail) CAD in Thousands	12 Months Ended
	Dec. 31, 2015CAD
Compensation and Retirement Disclosure [Abstract]
Effect of a 1 percentage point increase in the HCCTR on year-end benefit obligation	CAD 10,763
Effect of a 1 percentage point increase in the HCCTR on total service and interest cost	1,111
Effect of a 1 percentage point decrease in the HCCTR on, year-end benefit obligation	(8,687)
Effect of a 1 percentage point decrease in the HCCTR on, total service and interest cost	CAD (871)

Pension and other post-retire83

Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	CAD 6,663	CAD 4,828
Interest cost	9,642	8,549
Expected return on plan assets	(11,989)	(10,018)
Amortization of net actuarial loss (gain)	1,398	(346)
Amortization of prior service credits	(471)	0
Net benefit cost	5,243	3,013
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	3,093	2,022
Interest cost	2,914	2,186
Expected return on plan assets	(713)	(628)
Amortization of net actuarial loss (gain)	510	(641)
Amortization of prior service credits	0	0
Net benefit cost	CAD 5,804	CAD 2,939

Pension and other post-retire84

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	12 Months Ended
	Dec. 31, 2015
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	73.85%
Target allocation percentage range, minimum	49.00%
Target allocation percentage range, maximum	78.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	25.71%
Target allocation percentage range, minimum	22.00%
Target allocation percentage range, maximum	51.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage	0.45%
Target allocation percentage range, minimum	0.00%
Target allocation percentage range, maximum	1.00%

Pension and other post-retire85

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) CAD in Thousands	Dec. 31, 2015CAD
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	72.00%
Equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	CAD 138,993
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Allocation percentage	28.00%
Debt securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	CAD 54,542
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	CAD 787

Pension and other post-retire86

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) CAD in Thousands	Dec. 31, 2015CAD
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2,016	CAD 15,037
2,017	13,829
2,018	14,474
2,019	15,120
2,020	15,692
2021-2025	88,692
Post Retirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
2,016	3,113
2,017	3,375
2,018	3,584
2,019	3,804
2,020	4,396
2021-2025	CAD 25,720

Mandatorily redeemable Series87

Mandatorily redeemable Series C preferred shares (Details) - CAD CAD / shares in Units, CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014	Jan. 01, 2013
Disclosure Estimated Dividend And Redemption Payments [Abstract]
2,016	CAD 8,945
2,017	78,403
2,018	144,407
2,019	37,301
2,020	150,281
Thereafter to 2031	1,076,786
Preferred Shares Series C, noncurrent	CAD 17,548	CAD 17,608
Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares	100		100,000
Preferred stock redemption price per share (in dollars per share)	CAD 53,400
Disclosure Estimated Dividend And Redemption Payments [Abstract]
Less amounts representing interest	CAD (10,910)
Total Preferred shares series C	18,527
Less current portion	(979)
Preferred Shares Series C, noncurrent	CAD 17,548
Executives of company | Series C Preferred Stock
Class of Stock [Line Items]
Redeemable preferred stock issued, shares	36
Dividends Payable | Series C Preferred Stock
Disclosure Estimated Dividend And Redemption Payments [Abstract]
2,016	CAD 979
2,017	908
2,018	1,068
2,019	1,282
2,020	1,344
Thereafter to 2031	18,516
Redemption amount	5,340
Estimated dividend and redemption payments	CAD 29,437

Other assets (Detail)

Other assets (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Restricted cash	CAD 18,999	CAD 18,702
Deferred financing costs	3,211	2,428
Other	4,770	4,475
Total other assets	26,980	25,605
Less current portion	(464)	0
Other assets	CAD 26,516	CAD 25,605

Other long-term liabilities a89

Other long-term liabilities and deferred credits (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Long-term Liabilities
Advances in aid of construction (a)	CAD 92,285	CAD 81,104
Asset retirement obligations (c)	17,799	13,884
Customer deposits (d)	15,074	11,713
Deferred income (e)	13,682	13,132
Deferred credits (f)	24,110	19,130
Other	25,277	17,503
Other Liabilities	259,756	226,538
Less current portion	36,621	49,303
Other long-term liabilities	223,135	177,235
Transfers from advances in aid of construction to contributions in aid of construction	4,637	4,608
Estimated environmental remediation costs	78,495	72,594
Estimated environmental remediation costs, net	71,529	70,072	CAD 69,555
Accrual for environmental loss contingencies to be incurred over next three years	CAD 46,929
Accrual for environmental loss contingencies, payment period	29 years
Amount of regulatory assets	CAD 245,315	247,272
Additional asset retirement obligation recorded	506	2,570
Accretion expense	854	527
Deferred tax credit	CAD 3,350	19,130
Minimum
Other Long-term Liabilities
Other liability repayment period	10 years
Accrual environmental cost	2.50%
Maximum
Other Long-term Liabilities
Other liability repayment period	20 years
Accrual environmental cost	4.20%
Environmental costs
Other Long-term Liabilities
Regulatory asset, expenditure recovery provided by regulator, time period	7 years
Amount of regulatory assets	CAD 116,747	CAD 102,735

Other long-term liabilities a90

Other long-term liabilities and deferred credits - Changes in Environmental Remediation Obligation (Details) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accrual for Environmental Loss Contingencies [Roll Forward]
Opening Balance	CAD 70,072	CAD 69,555
Remediation activities	(10,621)	(12,739)
Accretion	2,147	2,273
Changes in cash flow estimates	3,171	268
Revision in assumptions	(5,843)	1,954
Purchase price adjustment	0	2,726
Foreign exchange rate adjustment	12,603	6,035
Closing Balance	CAD 71,529	CAD 70,072

Shareholders' capital - Common

Shareholders' capital - Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Common Shares Rollforward
Beginning balance (in shares)	238,149,468	206,348,985
Public offering (in shares)	14,355,000	29,444,000
Issuance of shares under the dividend reinvestment and employee share purchase plans (in shares)	3,364,951	2,356,483
Ending balance (in shares)	255,869,419	238,149,468

Shareholders' capital - Additio

Shareholders' capital - Additional Information (Detail) CAD / shares in Units, CAD in Thousands	Dec. 29, 2014CADCAD / sharesshares	Dec. 31, 2015CADCAD / sharesshares	Dec. 31, 2014CADCAD / sharesshares	Sep. 30, 2014CADCAD / sharesshares	Mar. 10, 2016shares	Dec. 31, 2015CADRightCAD / sharesshares	Dec. 31, 2014CADCAD / sharesshares	Jan. 01, 2013shares
Stockholders Equity Note [Line Items]
Number of voting rights per share | Right						1
Discount rate on share purchases						50.00%
Common shares issued | shares						14,355,000	29,444,000
Proceeds from subscription receipts						CAD 0	CAD 110,503
Discount rate on share purchases under dividend reinvestment plan						5.00%
Carrying amount		CAD 213,805	CAD 213,805			CAD 213,805	213,805
Total share-based compensation expense						CAD 5,330	3,248
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%
Subsequent Event
Stockholders Equity Note [Line Items]
Additional shares issued under dividend reinvestment plan | shares					292,337
Employee Stock Option
Stockholders Equity Note [Line Items]
Total share-based compensation expense						CAD 2,742	1,931
Unrecognized compensation costs, non-vested options		CAD 3,125				CAD 3,125
Unrecognized compensation costs, non-vested options, period of recognition						1 year 8 months 27 days
Stock Option Plans | Maximum
Stockholders Equity Note [Line Items]
Percentage of shares reserves under plan (must not exceed)						10.00%
Performance Share Units
Stockholders Equity Note [Line Items]
Performance share units granting period						3 years
Percentage of shares issued on number of PSU grants, minimum						0.00%
Percentage of shares issued on number of PSU grants, maximum						197.50%
Employee share purchase
Stockholders Equity Note [Line Items]
Total share-based compensation expense						CAD 158	CAD 116
Vesting period of matching contribution shares						1 year
Maximum aggregate number of shares reserved for issuance from treasury | shares		2,000,000				2,000,000
Common stock, shares issued | shares		111,355	93,598			111,355	93,598
Deferred Share Units
Stockholders Equity Note [Line Items]
Shares issued during period | shares						157,471	110,241
Performance share units
Stockholders Equity Note [Line Items]
Total share-based compensation expense						CAD 2,026	CAD 928
Unrecognized compensation costs, non-vested awards		CAD 1,866				CAD 1,866
Unrecognized compensation costs, non-vested options, period of recognition						1 year 7 months 17 days
Percent of performance goals achieved						100.00%
Series A Preferred Stock
Stockholders Equity Note [Line Items]
Shares issued, price per share (CAD per share) | CAD / shares		CAD 25	CAD 25			CAD 25	CAD 25
Preferred stock issued, shares | shares		4,800,000	4,800,000			4,800,000	4,800,000
Carrying amount		CAD 116,546	CAD 116,546			CAD 116,546	CAD 116,546
Fixed cumulative annual dividend per share | CAD / shares		CAD 1.125				CAD 1.125
Subsequent yield period						5 years
Preferred stock redemption price per share (in dollars per share) | CAD / shares		25				CAD 25
Series C Preferred Stock
Stockholders Equity Note [Line Items]
Preferred stock redemption price per share (in dollars per share) | CAD / shares		CAD 53,400				CAD 53,400
Redeemable preferred stock issued, shares | shares		100				100		100,000
Series D Preferred Stock
Stockholders Equity Note [Line Items]
Shares issued, price per share (CAD per share) | CAD / shares		CAD 25	CAD 25			CAD 25	CAD 25
Preferred stock issued, shares | shares		4,000,000	4,000,000			4,000,000	4,000,000
Carrying amount		CAD 97,259	CAD 97,259			CAD 97,259	CAD 97,259
Fixed cumulative annual dividend per share | CAD / shares		CAD 1.25				CAD 1.25
Common shares
Stockholders Equity Note [Line Items]
Common shares issued | shares		14,355,000	10,055,000	19,389,000
Shares issued, price per share (CAD per share) | CAD / shares		CAD 10.45	CAD 9.95	CAD 8.90		CAD 10.45	CAD 9.95
Cash proceeds from issuance of shares		CAD 150,010	CAD 100,047	CAD 172,562
Stock issuance cost			4,243	7,648		CAD 6,735
Stock issuance costs, net of tax		CAD 5,023	CAD 3,021	CAD 5,719
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%
Emera | Subscription receipts | Park Water Company
Stockholders Equity Note [Line Items]
Common shares issued | shares	3,316,583
Shares issued, price per share (CAD per share) | CAD / shares	CAD 9.95
Proceeds from subscription receipts	CAD 33,000
Emera | Interest in Odell Wind Project | Subscription receipts
Stockholders Equity Note [Line Items]
Common shares issued | shares	8,708,170
Shares issued, price per share (CAD per share) | CAD / shares	CAD 8.90
Proceeds from subscription receipts	CAD 77,503
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%

Shareholder's capital - Share-B

Shareholder's capital - Share-Based Compensation Expense (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	CAD 5,330	CAD 3,248
Share options
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	2,742	1,931
Directors deferred share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	404	273
Employee share purchase
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	158	116
Performance share units
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]
Share-based compensation expense	CAD 2,026	CAD 928

Shareholders' capital - Fair Va

Shareholders' capital - Fair Value of Share Options Granted (Detail) - CAD / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Risk-free interest rate	1.30%	2.00%
Expected volatility	38.00%	38.00%
Expected dividend yield	4.00%	3.80%
Expected life	8 years	8 years
Weighted average grant date fair value per option (CAD per share)	CAD 2.45	CAD 2

Shareholders' capital - Stock O

Shareholders' capital - Stock Option Activity (Detail) - CAD CAD / shares in Units, CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of awards
Beginning balance, Shares	5,537,127	4,567,129
Granted, Shares	1,627,525	969,998
Ending balance, Shares	7,164,652	5,537,127	4,567,129
Exercisable, Shares	4,618,323
Weighted average exercise price
Beginning balance (CAD per share)	CAD 6.09	CAD 5.70
Granted (CAD per share)	9.75	7.95
Ending balance (CAD per share)	6.92	CAD 6.09	CAD 5.70
Exercisable (CAD per share)	CAD 5.74
Additional Disclosures
Outstanding shares, weighted average remaining contractual term	4 years 8 months 27 days	4 years 11 months 16 days	5 years 5 months 12 days
Granted, Weighted average remaining contractual term	8 years	8 years
Exercisable , Weighted average remaining contractual term	3 years 6 months 18 days
Beginning balance, aggregate intrinsic value	CAD 19,648	CAD 7,814
Granted, aggregate intrinsic value	0	0
Ending balance, aggregate intrinsic value	28,561	CAD 19,648	CAD 7,814
Exercisable , aggregate intrinsic value	CAD 23,898

Shareholder's capital - Perform

Shareholder's capital - Performance Stock Units (Detail) - Performance share units - CAD CAD / shares in Units, CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of awards
Beginning balance, Shares	440,086	66,195
Granted, Shares	212,250	407,962
Exercised, Shares	(41,131)	(22,665)
Forfeited, Shares	(47,089)	(11,406)
Ending balance, Shares	564,116	440,086	66,195
Exercisable, Shares	157,972
Weighted average grant-date fair value
Beginning balance (CAD per share)	CAD 6.57	CAD 6.57
Granted (CAD per share)	9.72	8.22
Exercised (CAD per share)	6.86	6.13
Forfeited (CAD per share)	8.30	8.22
Ending balance (CAD per share)	7.59	CAD 6.57	CAD 6.57
Exercisable (CAD per share)	CAD 8.22
Additional Disclosures
Outstanding, Weighted average remaining contractual term	1 year 7 months 17 days	1 year 9 months 22 days	7 months 13 days
Granted, Weighted average remaining contractual term	2 years 7 months 13 days	3 years
Outstanding, aggregate intrinsic value	CAD 6,155	CAD 4,242	CAD 486
Granted, aggregate intrinsic value	0	3,333
Exercised, aggregate intrinsic value	381	(185)
Forfeited, aggregate intrinsic value	0	CAD (93)
Exercisable, aggregate intrinsic value	CAD 1,723

Accumulated other comprehensi97

Accumulated other comprehensive income (loss) (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	CAD 34,213
Other comprehensive income, net of tax	312,698	CAD 71,314
Acquisition of non-controlling interest		(159,672)
Ending balance	286,737	34,213
Foreign currency cumulative translation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	32,496	(57,471)
OCI (loss) before reclassifications	228,861	68,938
Amounts reclassified	0	0
Other comprehensive income, net of tax	228,861	68,938
Acquisition of non-controlling interest		21,029
Ending balance	261,357	32,496
Unrealized gain on cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	23,164	11,840
OCI (loss) before reclassifications	21,896	3,358
Amounts reclassified	(5,731)	5,423
Other comprehensive income, net of tax	16,165	8,781
Acquisition of non-controlling interest		2,543
Ending balance	39,329	23,164
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	1	0
OCI (loss) before reclassifications	(73)	519
Amounts reclassified	0	(518)
Other comprehensive income, net of tax	(73)	1
Acquisition of non-controlling interest		0
Ending balance	(72)	1
Pension and post-employment actuarial changes
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(21,448)	14,221
OCI (loss) before reclassifications	6,487	(35,396)
Amounts reclassified	1,084	(273)
Other comprehensive income, net of tax	7,571	(35,669)
Acquisition of non-controlling interest		0
Ending balance	(13,877)	(21,448)
Accumulated OCI
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	34,213	(31,410)
OCI (loss) before reclassifications	257,171	37,419
Amounts reclassified	(4,647)	4,632
Other comprehensive income, net of tax	252,524	42,051
Acquisition of non-controlling interest		23,572
Ending balance	CAD 286,737	CAD 34,213

Dividends (Detail)

Dividends (Detail) - CAD	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Dividends [Line Items]
Dividend declared for common share holders	CAD 124,831,000	CAD 83,097,000
Cash dividend declared per common share (CAD per share)	CAD 0.4867	CAD 0.3695
Series A Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders	CAD 5,400,000	CAD 5,400,000
Dividend declared per preferred share (CAD per share)	CAD 1.1250	CAD 1.1250
Series D Preferred Stock
Dividends [Line Items]
Dividends declared for preferred share holders	CAD 5,000,000	CAD 4,103,000
Dividend declared per preferred share (CAD per share)	CAD 1.2500	CAD 1.0257

Related party transactions (Det

Related party transactions (Detail)	Jun. 28, 2015CAD	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Emera
Transactions with Third Party [Line Items]
Amounts due from related party | $						$ 491,000	$ 0
Emera | Energy Service
Transactions with Third Party [Line Items]
Inter-company sales | $			$ 6,658,000		$ 9,821,000
Emera | Natural Gas
Transactions with Third Party [Line Items]
Purchases from related party | $			$ 2,292,000		$ 3,961,000
Algonquin Power Systems Ltd.
Transactions with Third Party [Line Items]
Amounts due from related party		CAD 0		CAD 47,000
Equity Method Investee
Transactions with Third Party [Line Items]
Reimbursement of expenses		2,021,000		189,000
Algonquin Power Management Inc.
Transactions with Third Party [Line Items]
Aircraft usage shortfall fee	CAD 13,000
Cost in connection with aircraft		507,000		721,000
Base lease costs		0		356,000
Spouse of Senior Executive
Transactions with Third Party [Line Items]
Related party transactions, expenses paid		CAD 22,000		CAD 192,000

Non-controlling Interests (Deta

Non-controlling Interests (Details) - CAD CAD in Thousands	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Total net earnings/(loss) attributable to noncontrolling interests		CAD (31,976)	CAD (22,186)
Other Noncontrolling Interests
Noncontrolling Interest [Line Items]
Total net earnings/(loss) attributable to noncontrolling interests		1,966	1,529
Class B Units | Noncontrolling Interest, Class B Partnership Units of SponsorCo
Noncontrolling Interest [Line Items]
Total net earnings/(loss) attributable to noncontrolling interests		0	3,484
Class A Units | Class A Partnership Units
Noncontrolling Interest [Line Items]
Total net earnings/(loss) attributable to noncontrolling interests		CAD (33,942)	CAD (27,199)
Wind Portfolio SponsorCo, LLC | Class B Units
Noncontrolling Interest [Line Items]
Ownership percentage	100.00%

Income taxes - Additional Infor

Income taxes - Additional Information (Detail) - CAD CAD in Thousands	Jun. 26, 2015	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Canadian enacted statutory rate		26.50%	26.50%
Valuation allowance for deferred tax assets		CAD 17,478	CAD 15,534
Deferred taxes		36,403	CAD 13,133
Deferred income taxes, undistributed earnings of foreign subsidiaries		CAD 64,678
Tax years 2009 to 2013 | Canada Revenue Agency
Income Tax Examination [Line Items]
Reduction in deferred tax assets	CAD 16,042
Reduction in deferred tax credits	13,333
Deferred taxes	CAD 2,709

Income taxes - Provision for In

Income taxes - Provision for Income Taxes (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Expected income tax expense at Canadian statutory rate	CAD 34,516	CAD 19,199
Increase (decrease) resulting from:
Recognition of deferred credit	(2,448)	(5,763)
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(3,855)	(1,677)
Non-taxable corporate dividend	(3,311)	(2,618)
Non-controlling interests share of income	12,511	8,824
Production tax credit	(254)	(339)
Allowance for equity funds used during construction	(935)	(746)
State taxes	733	604
Adjustment relating to prior periods	2,431	0
CRA Settlement	2,709	0
Other	1,616	(677)
Income tax expense	CAD 43,713	CAD 16,807

Income taxes - Income (Loss) Be

Income taxes - Income (Loss) Before Taxes (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	CAD 130,249	CAD 72,449
Canadian operations
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	28,481	11,930
U.S. operations
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]
Income/(loss) before taxes	CAD 101,768	CAD 60,519

Income taxes - Income Tax Expen

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Expenses [Line Items]
Income tax expenses, current	CAD 7,310	CAD 3,674
Income tax expenses, deferred	36,403	13,133
Income tax expense	43,713	16,807
Canada
Income Tax Expenses [Line Items]
Income tax expenses, current	5,272	5,660
Income tax expenses, deferred	1,959	(3,538)
Income tax expense	7,231	2,122
United States
Income Tax Expenses [Line Items]
Income tax expenses, current	2,038	(1,986)
Income tax expenses, deferred	34,444	16,671
Income tax expense	CAD 36,482	CAD 14,685

Income taxes - Tax Effect on Si

Income taxes - Tax Effect on Significant Portions of Deferred Tax Assets and Deferred Tax Liabilities (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	CAD 396,727	CAD 319,056
Pension and OPEB	57,969	54,458
Acquisition-related costs	6,035	5,168
Environmental obligation	28,230	28,555
Production tax credit	3,027	2,098
Reserves not currently deductible	2,503	2,315
Other	4,970	3,988
Total deferred income tax assets	499,461	415,638
Less valuation allowance	(17,478)	(15,534)
Total deferred tax assets	481,983	400,104
Deferred tax liabilities:
Property, plant and equipment	(544,616)	(387,931)
Intangible assets	(2,760)	(2,752)
Outside basis in partnership	(32,221)	(15,194)
Regulatory accounts	(28,270)	(49,399)
Financial derivatives	(31,806)	(15,013)
Total deferred tax liabilities	(639,673)	(470,289)
Net deferred tax liabilities	(157,690)	(70,185)
Deferred tax assets	18,109	64,275
Deferred tax liabilities	CAD (175,799)	CAD (134,460)

Income taxes - Non Capital Loss

Income taxes - Non Capital Losses Carry Forwards (Detail) CAD in Thousands	Dec. 31, 2015CAD
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	CAD 967,499
Expires 2,016
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	0
2017 and onwards
Capital Loss Carryforwards [Line Items]
Non-capital loss carryforwards	CAD 967,499

Basic and diluted net earnin107

Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Net earnings attributable to shareholders of APUC	CAD 117,480	CAD 75,701
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	107,080	66,198
Discontinued operations	(1,032)	(2,127)
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted	CAD 108,112	CAD 68,325
Weighted average number of shares
Basic (in shares)	253,172,088	213,953,870
Effect of dilutive securities (in shares)	3,344,632	2,387,722
Diluted (in shares)	256,516,720	216,341,592
Series A Preferred Stock
Class of Stock [Line Items]
Series A Preferred shares dividend	CAD 5,400	CAD 5,400
Series D Preferred Stock
Class of Stock [Line Items]
Series A Preferred shares dividend	CAD 5,000	CAD 4,103

Basic and diluted net earnin108

Basic and diluted net earnings per share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Options and Convertible Debentures
Class of Stock [Line Items]
Anti-dilutive convertible debentures	1,627,525	1,786,401

Segmented information - Results

Segmented information - Results of Operations and Assets for Segments (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenue
Revenue	CAD 1,027,855	CAD 941,614
Fuel and power purchased	376,873	420,886
Net revenue	650,982	520,728
Operating expenses	278,561	234,038
Administrative expenses	40,675	34,692
Depreciation and amortization	149,806	114,047
Gain on foreign exchange	(2,631)	(1,112)
Operating income from continuing operations	184,571	139,063
Interest expense	65,993	62,418
Interest, dividend, equity and other income	(9,095)	(7,758)
Other expenses (gain)	(2,576)	11,954
Earnings (loss) before income taxes	130,249	72,449
Property, plant and equipment	3,873,684	3,278,422
Equity-method investees	52,473	6,598
Total assets	4,991,725	4,102,848
Capital expenditures	204,195	432,373
Generation
Revenue
Revenue	244,751	218,765
Fuel and power purchased	27,990	39,264
Net revenue	216,761	179,501
Operating expenses	63,601	55,482
Administrative expenses	10,822	13,457
Depreciation and amortization	67,293	58,248
Gain on foreign exchange	0	0
Operating income from continuing operations	75,045	52,314
Interest expense	29,395	33,868
Interest, dividend, equity and other income	(1,154)	(1,187)
Other expenses (gain)	(5,623)	48
Earnings (loss) before income taxes	52,427	19,585
Property, plant and equipment	1,895,617	1,687,465
Equity-method investees	44,638	3,520
Total assets	2,345,905	1,896,265
Capital expenditures	55,992	201,063
Distribution
Revenue
Revenue	783,104	722,849
Fuel and power purchased	348,883	381,622
Net revenue	434,221	341,227
Operating expenses	213,750	178,248
Administrative expenses	21,570	19,947
Depreciation and amortization	82,513	53,671
Gain on foreign exchange	0	0
Operating income from continuing operations	116,388	89,361
Interest expense	34,971	27,139
Interest, dividend, equity and other income	(3,974)	(3,369)
Other expenses (gain)	391	300
Earnings (loss) before income taxes	85,000	65,291
Property, plant and equipment	1,914,980	1,531,166
Equity-method investees	769	500
Total assets	2,532,894	2,098,244
Capital expenditures	141,445	176,849
Corporate
Revenue
Revenue	0	0
Fuel and power purchased	0	0
Net revenue	0	0
Operating expenses	1,210	308
Administrative expenses	8,283	1,288
Depreciation and amortization	0	2,128
Gain on foreign exchange	(2,631)	(1,112)
Operating income from continuing operations	(6,862)	(2,612)
Interest expense	1,627	1,411
Interest, dividend, equity and other income	(3,967)	(3,202)
Other expenses (gain)	2,656	11,606
Earnings (loss) before income taxes	(7,178)	(12,427)
Property, plant and equipment	63,087	59,791
Equity-method investees	7,066	2,578
Total assets	112,926	108,339
Capital expenditures	CAD 6,758	CAD 54,461

Segmented information - Additio

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015segmentcountry	Dec. 31, 2014
Segment Reporting Information [Line Items]
Number of business units | segment	3
Percentage of revenue contributed	80.00%
Number of countries in which entity operates | country	2
Sales Revenue, Net | Hydro Quebec
Segment Reporting Information [Line Items]
Percentage of revenue contributed	13.00%	11.00%
Sales Revenue, Net | Manitoba Hydro
Segment Reporting Information [Line Items]
Percentage of revenue contributed	13.00%	13.00%
Sales Revenue, Net | PJM
Segment Reporting Information [Line Items]
Percentage of revenue contributed	14.00%	10.00%
Sales Revenue, Net | ComEd
Segment Reporting Information [Line Items]
Percentage of revenue contributed	11.00%	10.00%

Segmented information - Informa

Segmented information - Information on Operations by Geographic Area (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenue	CAD 1,027,855	CAD 941,614
Property, plant and equipment	3,873,684	3,278,422
Intangible assets	77,963	54,011
Canada
Segment Reporting Information [Line Items]
Revenue	86,977	92,267
Property, plant and equipment	592,598	590,580
Intangible assets	40,186	25,601
United States
Segment Reporting Information [Line Items]
Revenue	940,878	849,347
Property, plant and equipment	3,281,086	2,687,842
Intangible assets	CAD 37,777	CAD 28,410

Commitments and contingencies -

Commitments and contingencies - Additional Information (Detail) - CAD	Oct. 21, 2011	Dec. 31, 2015	Dec. 31, 2012
Commitment And Contingencies [Line Items]
Estimated capital repair expenditure		CAD 8,000,000
Period estimated capital repair expenditures for energy project will be incurred		4 years
Water Rights
Commitment And Contingencies [Line Items]
Water lease claim payment	CAD 5,400,000
Minimum potential unrecoverable loss		CAD 0
Maximum potential unrecoverable loss		CAD 6,800,000
Leases
Commitment And Contingencies [Line Items]
Claims paid to government of Quebec			CAD 1,884,000

Commitments and contingencie113

Commitments and contingencies - Estimates of Future Commitments (Detail) CAD in Thousands	Dec. 31, 2015CAD
Commitments Disclosure [Line Items]
Year 1	CAD 228,707
Year 2	150,358
Year 3	132,176
Year 4	135,206
Year 5	132,680
Thereafter	706,930
Total	1,486,057
Power purchase (i)
Commitments Disclosure [Line Items]
Year 1	82,403
Year 2	52,644
Year 3	55,599
Year 4	59,165
Year 5	59,791
Thereafter	0
Total	309,602
Gas supply and service agreements (ii)
Commitments Disclosure [Line Items]
Year 1	66,264
Year 2	46,673
Year 3	36,621
Year 4	35,482
Year 5	32,070
Thereafter	82,509
Total	299,619
Service agreements
Commitments Disclosure [Line Items]
Year 1	38,335
Year 2	38,151
Year 3	35,019
Year 4	35,734
Year 5	35,955
Thereafter	518,193
Total	701,387
Capital projects
Commitments Disclosure [Line Items]
Year 1	35,842
Year 2	7,571
Year 3	71
Year 4	71
Year 5	71
Thereafter	18
Total	43,644
Operating leases
Commitments Disclosure [Line Items]
Year 1	5,863
Year 2	5,319
Year 3	4,866
Year 4	4,754
Year 5	4,793
Thereafter	106,210
Total	CAD 131,805

Changes in Non-Cash Operating I

Changes in Non-Cash Operating Items (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Disclosure Changes In Non Cash Operating Items [Abstract]
Accounts receivable	CAD 6,715	CAD (23,640)
Natural gas in storage	3,049	(5,942)
Supplies and consumable inventory	(2,968)	(3,861)
Income taxes receivable	(2,529)	(189)
Prepaid expenses	(7,833)	827
Accounts payable	(18,261)	54,299
Accrued liabilities	(28,495)	32,520
Current income tax liability	1,820	(1,527)
Net regulatory assets and liabilities	37,353	(54,277)
Changes in non-cash operating items	CAD (11,149)	CAD (1,790)

Financial instruments - Fair V

Financial instruments - Fair Value of Financial Instruments (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Level 1
Fair Value of Financial Instruments [Line Items]
Long-term debt	CAD 511,829	CAD 520,142
Total financial liabilities	511,829	520,142
Level 2
Fair Value of Financial Instruments [Line Items]
Notes receivable	126,468	41,339
Derivative financial instruments, assets	4	0
Total financial assets	126,472	41,339
Long-term debt	1,035,517	843,792
Preferred shares, Series C	17,303	18,209
Derivative financial instruments, liabilities	114,812	45,271
Total financial liabilities	1,167,632	907,272
Level 3
Fair Value of Financial Instruments [Line Items]
Notes receivable	0	0
Derivative financial instruments, assets	88,357	42,470
Total financial assets	88,357	42,470
Derivative financial instruments, liabilities	446	0
Total financial liabilities	446	0
Energy contracts | Designated as a hedge | Cash flow hedge | Level 3
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	88,357	41,966
Derivative financial instruments, liabilities	446
Energy contracts | Not designated as a hedge | Cash flow hedge | Level 3
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		504
Cross currency swap | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	101,559
Cross currency swap | Designated as a hedge | Net Investment Hedging | Level 2
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	101,559	36,276
Interest rate swaps
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	9,659
Interest rate swaps | Designated as a hedge | Level 2
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	9,659	4,684
Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		1,383
Interest rate swaps | Not designated as a hedge | Level 2
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		1,383
Foreign exchange forward | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	1,918
Foreign exchange forward | Not designated as a hedge | Level 2
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	1,918
Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	2,122
Commodity contracts for regulatory operations | Level 2
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	4
Derivative financial instruments, liabilities	1,676	2,928
Carrying amount
Fair Value of Financial Instruments [Line Items]
Notes receivable	119,383	39,510
Derivative financial instruments, assets	88,361	42,470
Total financial assets	207,744	81,980
Long-term debt	1,486,795	1,271,719
Preferred shares, Series C	18,527	18,693
Derivative financial instruments, liabilities	115,258	45,271
Total financial liabilities	1,620,580	1,335,683
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	88,357	41,966
Derivative financial instruments, liabilities	446
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		504
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	101,559	36,276
Carrying amount | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	9,659	4,684
Carrying amount | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		1,383
Carrying amount | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	1,918
Carrying amount | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	4
Derivative financial instruments, liabilities	1,676	2,928
Fair Value
Fair Value of Financial Instruments [Line Items]
Notes receivable	126,468	41,339
Derivative financial instruments, assets	88,361	42,470
Total financial assets	214,829	83,809
Long-term debt	1,547,346	1,363,934
Preferred shares, Series C	17,303	18,209
Derivative financial instruments, liabilities	115,258	45,271
Total financial liabilities	1,679,907	1,427,414
Fair Value | Energy contracts | Designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	88,357	41,966
Derivative financial instruments, liabilities	446
Fair Value | Energy contracts | Not designated as a hedge | Cash flow hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets		504
Fair Value | Cross currency swap | Designated as a hedge | Net Investment Hedging
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	101,559	36,276
Fair Value | Interest rate swaps | Designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	9,659	4,684
Fair Value | Interest rate swaps | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities		1,383
Fair Value | Foreign exchange forward | Not designated as a hedge
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, liabilities	1,918
Fair Value | Commodity contracts for regulatory operations
Fair Value of Financial Instruments [Line Items]
Derivative financial instruments, assets	4
Derivative financial instruments, liabilities	CAD 1,676	CAD 2,928

Financial instruments - Additi

Financial instruments - Additional Information (Detail) $ in Thousands	Nov. 14, 2014CAD	Dec. 31, 2015CADCAD / MWh	Dec. 31, 2014CAD	Dec. 31, 2015USD ($)CAD / MWh	Jan. 31, 2014CAD	Dec. 31, 2013CAD
Derivative [Line Items]
Long-term debt		CAD 1,486,795,000	CAD 1,271,719,000
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months		14,975,000
Other comprehensive income, foreign currency loss		0	(2,727,000)
Other comprehensive income, foreign currency translation adjustment loss		CAD (289,035,000)	(104,183,000)
Major customer revenue percentage		80.00%
Revenue collection period		45 days
Cash on hand		CAD 124,353,000
Available for drawn on senior debt facilities		580,901,000
Utility Services
Derivative [Line Items]
Accounts receivable balances | $				$ 91,308
Generation
Derivative [Line Items]
Other comprehensive income, foreign currency translation adjustment loss		68,195,000	28,537,000
Bonds | Plan
Derivative [Line Items]
Debt instrument, term	10 years
Long-term debt	CAD 135,000,000
Senior Unsecured Notes | Generation | 4.82% Senior Unsecured Notes
Derivative [Line Items]
Debt instrument, face value		150,000,000	150,000,000			CAD 150,000,000
Senior Unsecured Notes | Generation | 4.65% Senior Unsecured Notes
Derivative [Line Items]
Debt instrument, face value		200,000,000	200,000,000		CAD 200,000,000
Interest rate swaps
Derivative [Line Items]
Derivative liability		CAD 9,659,000
Interest rate swaps | Not designated as a hedge
Derivative [Line Items]
Fixed interest rate		4.47%		4.47%
Notional amount		CAD 58,791,000
Derivative liability			1,383,000
Energy contracts
Derivative [Line Items]
Derivative, collateral held by third parties		4,882,000	156,000
Foreign exchange forward | Not designated as a hedge
Derivative [Line Items]
Notional amount		85,812,000		$ 63,400
Cash flow hedge | Interest rate swaps
Derivative [Line Items]
Term of forward-starting interest rate swap	10 years
Change in fair value recorded in OCI		CAD 4,974,000	CAD 4,684,000
Minimum
Derivative [Line Items]
Forward price | CAD / MWh		18.39		18.39
Maximum
Derivative [Line Items]
Forward price | CAD / MWh		138.3		138.3
Weighted Average
Derivative [Line Items]
Forward price | CAD / MWh		39.98		39.98
Red Lily
Derivative [Line Items]
Estimated discount rate used to measure fair value of conversion option			9.00%
Derivative assets, fair value
Fair Value
Derivative [Line Items]
Derivative liability		CAD 115,258,000	CAD 45,271,000
Fair Value | Interest rate swaps | Not designated as a hedge
Derivative [Line Items]
Derivative liability			CAD 1,383,000
Fair Value | Foreign exchange forward | Not designated as a hedge
Derivative [Line Items]
Derivative liability		CAD 1,918,000

Financial instruments - Summar

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2015MMBTU
Derivative [Line Items]
Commodity volumes, Gas	1,498,597
Financial contracts Gas swaps
Derivative [Line Items]
Commodity volumes, Gas	1,086,228
Gas options
Derivative [Line Items]
Commodity volumes, Gas	412,369

Financial instruments - Impact

Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) CAD in Thousands, $ in Thousands	Dec. 31, 2015CAD	Dec. 31, 2015USD ($)	Dec. 31, 2014CAD	Dec. 31, 2014USD ($)
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts | CAD	CAD 245,315		CAD 247,272
Regulatory liabilities, natural gas derivative contracts | CAD	CAD 175,347		CAD 121,756
Gas swap contracts
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts		$ 1,058		$ 2,178
Regulatory liabilities, natural gas derivative contracts		3		0
Gas options
Derivative [Line Items]
Regulatory assets, natural gas derivative contracts		154		346
Regulatory liabilities, natural gas derivative contracts		$ 0		$ 0

Financial instruments - Long-t

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge	Dec. 31, 2015MWhCAD / MWh$ / MWh
AESO
Derivative [Line Items]
Notional quantity (MW-hrs)	49,135
Receive average prices (per MW-hr) | CAD / MWh	68.56
PJM Western HUB
Derivative [Line Items]
Notional quantity (MW-hrs)	801,098
Receive average prices (per MW-hr) | $ / MWh	42.81
NI HUB
Derivative [Line Items]
Notional quantity (MW-hrs)	3,419,634
Receive average prices (per MW-hr) | $ / MWh	30.25
ERCOT North HUB
Derivative [Line Items]
Notional quantity (MW-hrs)	3,997,509
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) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Effective portion of cash flow hedge, loss (gain)	CAD 21,932	CAD (2,592)
Amortization of cash flow hedge	(36)	(32)
Loss (gain) reclassified from AOCI	(5,731)	5,423
Loss (gain) reclassified from AOCI	16,165	2,799
Less noncontrolling interest	0	5,982
OCI attributable to shareholders of APUC	CAD 16,165	CAD 8,781

Financial instruments - Effect

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) - CAD CAD in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	CAD (1,990)	CAD 3,046
Total realized loss (gain) on derivative financial instruments	1,918	0
Ineffective portion of derivative financial instruments accounted for as hedges	36	32
Loss (gain) on derivative financial instruments	2,188	(1,375)
Gain (loss) on derivative instruments	(270)	1,375
Not Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	1,421	1,589
Total realized loss (gain) on derivative financial instruments	919	(1,665)
Loss (gain) on derivative financial instruments not accounted for as hedges	2,340	(76)
Not Designated as Hedging Instrument | Interest rate swaps
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	(1,383)	(1,797)
Total realized loss (gain) on derivative financial instruments	1,498	1,962
Not Designated as Hedging Instrument | Energy derivative contracts
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	886	3,386
Total realized loss (gain) on derivative financial instruments	(579)	(3,627)
Not Designated as Hedging Instrument | Foreign exchange forward
Fair Value of Financial Instruments [Line Items]
Total change in unrealized loss (gain) on derivative financial instruments	1,918	0
Designated as Hedging Instrument
Fair Value of Financial Instruments [Line Items]
Ineffective portion of derivative financial instruments accounted for as hedges	CAD (2,610)	CAD 1,451

Financial instruments - Maximu

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2015 CAD in Thousands, $ in Thousands	CAD	USD ($)
Fair Value Disclosures [Abstract]
Cash and cash equivalents and restricted cash	CAD 39,972	$ 74,696
Accounts receivable	CAD 15,016	129,791
Allowance for doubtful accounts		(5,756)
Notes receivable	CAD 19,664	72,052
Maximum exposure to credit risk for financial instruments	CAD 74,652	$ 270,783

Financial instruments - Liabil

Financial instruments - Liabilities Mature (Detail) - CAD CAD in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Long-term debt obligations	CAD 1,496,123
Advances in aid of construction	92,285
Interest on long-term debt	664,099
Purchase obligations	243,748
Environmental obligation	78,495	CAD 72,594
Other obligations	53,502
Total obligations	2,743,510
Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	101,559
Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	9,659
Foreign exchange forward | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	1,918
Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	2,122
Due less than 1 year
Derivative [Line Items]
Long-term debt obligations	8,945
Advances in aid of construction	1,347
Interest on long-term debt	74,324
Purchase obligations	243,748
Environmental obligation	5,435
Other obligations	12,808
Total obligations	355,238
Due less than 1 year | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	4,828
Due less than 1 year | Foreign exchange forward | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	1,918
Due less than 1 year | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	1,885
Due 2 to 3 years
Derivative [Line Items]
Long-term debt obligations	222,810
Interest on long-term debt	138,841
Environmental obligation	41,494
Other obligations	0
Total obligations	422,004
Due 2 to 3 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	8,963
Due 2 to 3 years | Commodity contracts for regulatory operations
Derivative [Line Items]
Derivative financial instruments, liabilities	237
Due 4 to 5 years
Derivative [Line Items]
Long-term debt obligations	187,582
Interest on long-term debt	117,328
Environmental obligation	1,753
Other obligations	0
Total obligations	314,171
Due 4 to 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	7,508
Due 4 to 5 years | Interest rate swaps
Derivative [Line Items]
Derivative financial instruments, liabilities	0
Due after 5 years
Derivative [Line Items]
Long-term debt obligations	1,076,786
Advances in aid of construction	90,938
Interest on long-term debt	333,606
Environmental obligation	29,813
Other obligations	40,694
Total obligations	1,652,097
Due after 5 years | Cross currency swap | Net Investment Hedging
Derivative [Line Items]
Derivative financial instruments, liabilities	CAD 80,260

Subsequent event - Convertib124

Subsequent event - Convertible Unsecured Subordinated Debentures (Details) - Convertible Subordinated Debt - Subsequent Event	Mar. 09, 2016CAD	Mar. 01, 2016CADCAD / sharesCAD / instrument	Feb. 28, 2017
Subsequent Event [Line Items]
Debt instrument, face value | CAD	CAD 1,150,000,000	CAD 1,000,000,000
Debt instrument, interest rate		5.00%
Debt instrument, convertible, price per instrument (CAD per debenture)		1,000
Debt instrument, convertible, price per instrument paid at closing (CAD per debenture)		333
Debt instrument, convertible, price per instrument outstanding (CAD per debenture)		667
Proceeds from issuance of debt | CAD	CAD 150,000,000
Debt instrument, effective interest rate		15.00%	0.00%
Debt Instrument, convertible, conversion price (CAD per share) | CAD / shares		CAD 10.60
Threshold consecutive trading days		20 days
Percentage of weighted average trading price		95.00%