Algonquin Power & Utilities (AQN) 40-F 28 Mar 14 2013 FY Annual report (Canada) Financial data

Document_and_Entity_Informatio

Document and Entity Information	12 Months Ended
	Dec. 31, 2013
Document Documentand Entity Information [Abstract]	'
Document Type	'40-F
Amendment Flag	'false
Document Period End Date	31-Dec-13
Document Fiscal Year Focus	'2013
Document Fiscal Period Focus	'FY
Trading Symbol	'AQUNF
Entity Registrant Name	'ALGONQUIN POWER & UTILITIES CORP.
Entity Central Index Key	'0001174169
Current Fiscal Year End Date	'--12-31
Entity Current Reporting Status	'Yes
Entity Common Stock, Shares Outstanding	206,348,985

Consolidated_Balance_Sheets

Consolidated Balance Sheets (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	13,839	53,122
Accounts receivable, net (note 4)	156,712	88,359
Natural gas in storage (note 1(g))	25,609	19,279
Supplies and consumables inventory	7,924	4,233
Regulatory assets (note 7)	34,643	10,644
Due from related parties (note 21)	0	816
Prepaid expenses	11,341	10,861
Notes receivable (note 8)	598	537
Deferred tax asset (note 19)	19,652	10,567
Income tax receivable (note 19)	379	556
Derivative instruments (note 26)	9,176	7,020
Assets held for sale (note 20)	23,927	26,900
Assets, Current, Total	303,800	232,894
Property, plant and equipment (note 5)	2,708,704	2,086,278
Intangible assets (note 6)	54,416	56,781
Assets held for sale (note 20)	0	76,437
Goodwill (note 6)	84,647	61,459
Regulatory assets (note 7)	155,705	123,748
Derivative instruments (note 26)	27,123	6,230
Long-term investments and notes receivable (note 8)	32,746	37,646
Deferred non-current income tax asset (note 19)	86,632	77,497
Other assets (note 13)	18,784	20,020
Assets	3,472,557	2,778,990
Current liabilities:	'	'
Accounts payable	14,489	34,271
Accrued liabilities	142,414	95,708
Due to related parties (note 21)	0	1,811
Dividends payable (note 18)	17,535	15,498
Regulatory liabilities (note 7)	21,632	8,626
Long term liabilities (note 9)	8,339	1,768
Pension and other post-employment benefits (note 11)	305	0
Other long term liabilities (note 14)	7,451	4,352
Advances in aid of construction (note 1(o))	1,239	591
Derivative instruments (note 26)	2,492	2,211
Environmental obligations (note 23(a)(ii))	10,111	2,523
Preferred shares series C (note 12)	1,038	0
Liabilities held for sale (note 20)	1,471	1,211
Income tax liability (note 19)	5,159	539
Deferred credits (note 19)	7,778	5,754
Deferred income tax liability (note 19)	2,308	1,133
Liabilities, Current, Total	243,761	175,996
Long-term liabilities (note 9)	1,247,249	769,058
Convertible debentures (note 10)	0	960
Advances in aid of construction (note 1(o))	77,697	71,626
Regulatory liabilities (note 7)	101,657	82,050
Deferred income tax liability (note 19)	137,153	100,798
Derivative instruments (note 26)	13,729	15,605
Deferred credits (note 19)	17,115	25,816
Pension and other post-employment benefits (note 11)	70,532	59,246
Environmental obligation (note 23(a)(ii))	59,444	54,817
Other long-term liabilities (note 14)	20,492	20,889
Preferred shares series C (note 12)	17,767	0
Liabilities, Noncurrent, Total	1,762,835	1,200,865
Equity:	'	'
Preferred shares (note 15(b))	116,546	116,546
Common shares (note 15(a))	1,351,264	1,245,326
Subscription receipts (note 15(a)(ii))	0	61,160
Additional paid-in capital	7,313	5,224
Deficit	-488,406	-406,143
Accumulated other comprehensive loss (note 16)	-31,410	-104,867
Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.	955,307	917,246
Noncontrolling interests	510,654	484,883
Total Equity	1,465,961	1,402,129
Commitments and contingencies (note 23)	'	'
Liabilities and Equity, Total	3,472,557	2,778,990

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (CAD)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenue:	'	'
Regulated electricity sales and distribution	166,156	108,457
Regulated gas sales and distributions	261,672	75,718
Regulated water reclamation and distribution	57,350	46,423
Non-regulated energy sales	180,191	114,351
Other revenue	9,922	3,857
Total revenue	675,291	348,806
Expenses	'	'
Operating	188,952	117,826
Regulated electricity purchased	97,376	68,209
Regulated gas purchased	148,784	37,461
Non-regulated fuel for generation	17,151	14,589
Depreciation of property, plant and equipment	91,978	45,187
Amortization of intangible assets	4,200	4,151
Administrative expenses	23,518	19,572
Gain on foreign exchange	-567	-561
Costs and Expenses, Total	571,392	306,434
Operating income from continuing operations	103,899	42,372
Interest expense	53,345	35,620
Interest, dividend income and other income	-7,785	-7,239
Loss on sale of assets	750	0
Acquisition-related costs	2,140	7,688
Gain on derivative financial instruments (note 26(b)(iv))	-5,200	-233
Nonoperating Income (Expense)	43,250	35,836
Earnings from continuing operations before income taxes	60,649	6,536
Income tax expense (recovery) (note 19)	'	'
Current	2,526	738
Deferred	6,629	-15,105
Income tax recovery	9,155	-14,367
Earnings from continuing operations	51,494	20,903
Income/(loss) from discontinued operations net of tax (note 20)	-42,011	1,043
Net earnings	9,483	21,946
Net earnings/(loss) attributable to noncontrolling interests	-10,813	7,414
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	20,296	14,532
Basic net earnings per share from continuing operations (note 22)	0.28	0.08
Basic net earnings/(loss) per share from discontinued operations (note 22)	-0.21	0.01
Basic net earnings per share (note 22)	0.07	0.09
Diluted net earnings per share from continuing operations (note 22)	0.28	0.08
Diluted net earnings/(loss) per share from discontinued operations (note 22)	-0.2	0.01
Diluted net earnings per share (note 22)	0.07	0.09

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Net earnings	9,483	21,946
Other comprehensive income (loss):	'	'
Foreign currency translation adjustment, net of tax of $149 and tax recovery of $388, respectively (notes 1(v), 26(b)(iii) and 26(c))	81,597	-9,399
Change in fair value of cash flow hedge, net of tax expense of $5,103 and $1,715, respectively (note 26(b)(ii))	17,308	5,168
Change in unrealized pension and other post-retirement expense, net of tax expense of $10,896 and tax recovery of $1,653, respectively (note 11)	16,727	-2,458
Other comprehensive income (loss), net of tax	115,632	-6,689
Comprehensive income	125,115	15,257
Comprehensive income attributable to the noncontrolling interests	31,362	9,082
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	93,753	6,175

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Foreign currency translation adjustment tax	149	-388
Change in fair value of cash flow hedge, tax	5,103	1,715
Change in unrealized pension and other post-retirement expense, tax	10,896	-1,653

Consolidated_Statement_of_Equi

Consolidated Statement of Equity (CAD)

Total

Calpeco

U.S. wind farms

Common Shares

Preferred Shares

Subscription Receipts

Additional Paid-in Capital

Additional Paid-in Capital

Accumulated Deficit

Accumulated Deficit

Accumulated OCI

Noncontrolling Interests

Noncontrolling Interests

Noncontrolling Interests

In Thousands, unless otherwise specified

U.S. wind farms

Calpeco

Calpeco

U.S. wind farms

Beginning Balance at Dec. 31, 2011

552,695

'

'

975,263

0

0

1,525

'

-366,080

'

-96,510

38,497

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings

21,946

'

'

'

'

'

'

'

14,532

'

'

7,414

'

'

Other comprehensive income

-6,689

'

'

'

'

'

'

'

'

'

-8,357

1,668

'

'

Dividends declared and distributions to non-controlling interests

-46,259

'

'

'

'

'

'

'

-43,619

'

'

-2,640

'

'

Dividends and issuance of shares under dividend reinvestment plan

0

'

'

7,343

'

'

'

'

-7,343

'

'

'

'

'

Exercise and conversion of subscription receipts

142,609

'

'

142,609

'

'

'

'

'

'

'

'

'

'

Exercise of subscription receipts

61,160

'

'

'

'

61,160

'

'

'

'

'

'

'

'

Conversion and redemption of convertible debentures

118,090

'

'

118,779

'

'

-689

'

'

'

'

'

'

'

Issuance of common shares under employee share purchase plan

432

'

'

432

'

'

'

'

'

'

'

'

'

'

Stock compensation expense

1,956

'

'

'

'

'

1,956

'

'

'

'

'

'

'

Public offering related taxes

900

'

'

900

'

'

'

'

'

'

'

'

'

'

Issuance of preferred shares

116,546

'

'

'

116,546

'

'

'

'

'

'

'

'

'

Acquisition on non-controlling interest

'

-38,656

'

'

'

'

'

'

'

-3,633

'

'

-35,023

'

Acquisitions

'

'

477,399

'

'

'

'

2,432

'

'

'

'

'

474,967

Ending Balance at Dec. 31, 2012

1,402,129

'

'

1,245,326

116,546

61,160

5,224

'

-406,143

'

-104,867

484,883

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings

9,483

'

'

'

'

'

'

'

20,296

'

'

-10,813

'

'

Other comprehensive income

115,632

'

'

'

'

'

'

'

'

'

73,457

42,175

'

'

Dividends declared and distributions to non-controlling interests

-65,364

'

'

'

'

'

'

'

-59,773

'

'

-5,591

'

'

Dividends and issuance of shares under dividend reinvestment plan

0

'

'

13,970

'

'

'

'

-13,970

'

'

'

'

'

Exercise and conversion of subscription receipts

0

'

'

90,464

'

-90,464

'

'

'

'

'

'

'

'

Exercise of subscription receipts

29,304

'

'

'

'

29,304

'

'

'

'

'

'

'

'

Conversion and redemption of convertible debentures

960

'

'

960

'

'

'

'

'

'

'

'

'

'

Issuance of common shares under employee share purchase plan

527

'

'

544

'

'

'

'

-17

'

'

'

'

'

Stock compensation expense

2,089

'

'

'

'

'

2,089

'

'

'

'

'

'

'

Preferred Series C shares

-18,497

'

'

'

'

'

'

'

-18,497

'

'

'

'

'

Acquisition on non-controlling interest

'

-10,302

'

'

'

'

'

'

'

-10,302

'

'

'

'

Ending Balance at Dec. 31, 2013

1,465,961

'

'

1,351,264

116,546

0

7,313

'

-488,406

'

-31,410

510,654

'

'

Consolidated_Statement_of_Equi1

Consolidated Statement of Equity (Parenthetical) (Calpeco)	Dec. 31, 2012
Calpeco	'
Percent of acquisition	49.99%

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Operating Activities:	'	'
Net earnings from continuing operations	51,494	20,903
Adjustments and items not affecting cash:	'	'
Depreciation of property, plant and equipment	91,978	45,187
Amortization of intangible assets	4,200	4,151
Other amortization	2,891	2,175
Deferred taxes	6,629	-15,105
Unrealized gain on derivative financial instruments	-6,758	-3,127
Share-based compensation	2,000	1,956
Cost of equity funds used for construction purposes	-1,786	0
Pension and post retirement expense	-302	2,852
Loss on sale of long lived assets	750	0
Changes in non-cash operating items (note 24)	-47,819	-3,476
Changes in non-cash operating items from discontinued operations (note 24)	36	-408
Cash provided/(used) in discontinued operations (note 20)	-4,388	7,846
Net Cash Provided by (Used in) Operating Activities, Total	98,925	62,954
Financing Activities:	'	'
Cash dividends on common shares	-52,335	-36,917
Cash dividends on preferred shares	-5,400	-769
Cash distributions to noncontrolling interests	-5,591	-2,640
Issuance of common shares	29,983	143,041
Proceeds from subscription receipts	0	61,160
Issuance of preferred shares	0	115,300
Deferred financing costs	-2,240	-5,435
Increase in long-term liabilities	950,346	505,542
Decrease in long-term liabilities	-685,472	-75,432
Increase in advances in aid of construction	2,299	1,051
Decrease in other long-term liabilities	-1,574	-860
Net Cash Provided by (Used in) Financing Activities, Total	230,016	704,041
Investing Activities:	'	'
Decrease in restricted cash	1,430	805
Increase in other assets	-3,004	-2,481
Distributions received in excess of equity income	727	343
Proceeds from sale of discontinued operations	24,968	0
Receipt of principal on notes receivable	109	1,894
Additions to property, plant and equipment	-158,377	-75,692
Additions to intangibles	0	-2,237
Acquisitions of operating entities	-239,014	-669,905
Acquisition of noncontrolling interest	0	-38,756
Proceeds from sale of long lived assets	3,408	204
Net Cash Provided by (Used in) Investing Activities, Total	-369,753	-785,825
Effect of exchange rate differences on cash	1,529	-935
Decrease in cash and cash equivalents	-39,283	-19,765
Cash and cash equivalents, beginning of the period	53,122	72,887
Cash and cash equivalents, end of the period	13,839	53,122
Supplemental disclosure of cash flow information:	'	'
Cash paid during the period for interest expense	44,185	28,635
Cash paid during the period for income taxes	1,107	252
Non-cash transactions	'	'
Property, plant and equipment acquisitions in accruals	10,829	10,495

Notes_to_the_Consolidated_Fina

Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Notes to the Consolidated Financial Statements	'
	Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC’s principal activity is the ownership of power generation facilities and water, gas and electric utilities, through investments in securities of subsidiaries including corporations, limited partnerships and trusts which carry on these businesses.
	APUC’s power generation business unit conducts business under the name Algonquin Power Co. (“APCo”). APCo owns or has interests in renewable energy facilities and thermal energy facilities. APUC’s Utility Services business unit conducts business under the name of Liberty Utilities Co. (“Liberty Utilities”). Liberty Utilities operates a portfolio of utilities in the United States of America providing electric, natural gas, water distribution or wastewater services.

Significant_accounting_policie

Significant accounting policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Significant accounting policies	'
	Significant accounting policies
	(a)	Basis of preparation
	The accompanying consolidated financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosures required under Regulation S-X provided by the Securities and Exchange Commission (“SEC”).
	(b)	Basis of consolidation
	The accompanying consolidated financial statements of APUC include the accounts of APUC and its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary. Intercompany transactions and balances have been eliminated.
	(c)	Accounting for rate regulated operations
	The regulated utility operating companies owned by Liberty Utilities are subject to rate regulation generally overseen by the public utility commissions 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 ASC Topic 980 Regulated Operations (“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 revenues 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 Assets & Liabilities 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 (credit) against income for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations.
	The electric and gas utilities’ and the 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, respectively.
	(d)	Cash and cash equivalents
	Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
	(e)	Restricted cash
	Restricted cash represent 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 13) in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.
	1	Significant accounting policies (continued)
	(f)	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.
	(g)	Gas in storage
	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. Existing rate orders allow the Company to pass through the cost of gas purchased directly to the rate payers 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 (note 7).
	(h)	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.
	(i)	Property, plant and equipment:
	Property, plant and equipment, consisting of renewable and thermal generation assets, electrical, gas, water and wastewater distribution assets, equipment and land, are recorded at cost. 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 equity funds used during construction (“AFUDC”) for regulated property. 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 (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). 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. 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 and other income on the consolidated statements of operations.
		2013			2012
	Interest capitalized on non-regulated property	$	669		$	1,036
	AFUDC capitalized on regulated property:
	Allowance for borrowed funds	1,055			628
	Allowance for equity funds	1,786			1,108
	Total	$	3,510		$	2,772
	Improvements that increase or prolong the service life or capacity of an asset are capitalized. Maintenance and repair costs are expensed as incurred.
	1	Significant accounting policies (continued)
	(i)	Property, plant and equipment (continued)
	Investment tax credits and government grants 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. Contributions in aid of construction represent amounts contributed by customers and governments and developers for the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 1(o)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.
	The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method. The range of estimated useful lives and the weighted average useful lives are summarized below:
		Range of useful lives			Weighted average
					useful lives
		2013		2012	2013		2012
	Generation
	Renewable	3 – 60		3 – 60	35		32
	Thermal	3 – 40		3 – 40	24		23
	Distribution
	Gas	5 – 80		5 – 80	38		38
	Electrical	8 – 75		8 – 75	41		42
	Water & wastewater	5 – 50		5 – 50	39		25
	Equipment	5 – 50		5 – 50	24		21
	In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of Liberty Utilities 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 operation 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.
	(j)	Intangibles
	The fair value of power sales contracts acquired in business combinations are amortized on a straight-line basis over the remaining term of the contract. These periods range from 6 to 25 years from date of acquisition.
	Customer relationships acquired in business combinations are amortized on a straight-line basis over their estimated life of 40 years.
	(k)	Goodwill
	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.
	The Company annually assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit 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, 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)
	(l)	Impairment of long-lived assets
	APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
	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 the 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.
	(m)	Variable interest entities
	The Company performs analyses to assess whether its operations and investments represent variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated.
	Long Sault is a hydroelectric generating facility in which APUC acquired an interest by way of subscribing to two notes from the original developers. The notes receivable effectively provide APUC the right to 65% after tax cash flows of the facility from 2014 to 2027 and 58% thereafter. The Company also has the right to acquire 58% of the equity in the facility at the end of the term of the notes in 2038.  Effective December 31, 2013, APUC acquired an equity interest in Long Sault (note 21). APUC has determined that the facility is a VIE since the Company is the primary beneficiary and therefore the Long Sault entity is subject to consolidation by the Company. Total net book value of generating assets and long-term debt of Long Sault amounts to $44,319 (2012 - $42,566) and to $37,143 (2012 - $38,136), respectively. The Long Sault debt only has recourse over the Long Sault generating assets. The financial performance of Long Sault reflected on the statement of operations includes non-regulated energy sales of $10,155 (2012 - $8,747), operating expenses and amortization of $2,391 (2012 - $2,728) and interest expense of $3,632 (2012 - $3,929).
	(n)	Long-term investments and notes receivable
	Investments in which APUC has significant influence but are not controlled are accounted using the equity method. APUC records its share in the income or loss of its investees in interest, dividend 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 that exceed one year and bear interest at a market rate based on the customer’s credit quality are initially recorded at cost, which is generally face value. Subsequent to acquisition, they 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.
If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.
(o)	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. These amounts are recorded as Advances in Aid of Construction in other long-term liabilities.
1	Significant accounting policies (continued)
(o)	Advances in aid of construction (continued)
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 2013, $627 (2012 - $3,555) was transferred from advances in aid of construction to contributions in aid of construction.
(p)	Deferred water rights and customer deposits
Deferred water rights are related to a hydroelectric generating facility which has a fifty year water lease with the first ten years of the water lease requiring no payment, which is a form of lease inducement. An annual average rate for water rights was estimated for the entire life of the lease and that average rate is being expensed over the lease term. The result of this policy is that the deferred water rights inducement amount recorded in the first ten years is being drawn down in the last forty years.
Customer deposits result from the Liberty Utilities’ 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. The deposits bear monthly interest and are applied to the customer account after 12 months if the customer is found to be credit worthy.
(q)	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. The Company recognizes the funded status of its defined benefit pension plans and other post employment benefit plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually at 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 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.
(r)	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, construction, development 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 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 accumulated obligation.
(s)	Stock based compensation
The Company has several share-based compensation plans: a share option plan; an employee common share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company recognizes all employee stock-based compensation as a cost in the financial statements. 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.
1	Significant accounting policies (continued)
(t)	Noncontrolling interests
Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent Company. Noncontrolling interests are initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of earnings and other comprehensive income attributable to the noncontrolling interests and any dividends or distributions paid to the noncontrolling interests.
Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent Company. Noncontrolling interests are initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of earnings and other comprehensive income attributable to the noncontrolling interests and any dividends or distributions paid to the noncontrolling interests.
If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net earnings or comprehensive income as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.
Certain of the Company’s U.S. based wind businesses are organized as limited liability corporations and partnerships and have noncontrolling 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 noncontrolling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. HLBV uses a balance sheet approach, which measures the allocation of income or loss of the Class A’s membership 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 17).
(u)	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.
Revenues related to utility electricity and natural gas sales and distribution are recorded based on metered consumptions by customers, which occur on a systematic basis throughout a month, rather than 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 revenues are calculated. These estimates of unbilled sales and revenues 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.
Beginning in 2013, in accordance with the revenue decoupling mechanism approved by its regulator, Liberty Utilities (CalPeco Electric) LLC (“Calpeco Electric System ”) is required to charge approved annual delivery revenues evenly over its 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).
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 waste water collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled revenues 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.
Revenue is recorded net of sale taxes.
Interest from long-term investments is recorded as earned.
1	Significant accounting policies (continued)
(v)	Foreign currency translation
The Company’s reporting currency is the Canadian dollar.
The Company’s US 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 while revenues and expenses are converted 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 other comprehensive income (“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.
(w)	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 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. Investment tax credits are recorded as an offset to the related long-lived asset. They are amortized over the estimated life of the asset as credits to income tax expense.
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 follows ASC 740-10 and 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.
(x)	Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized cost and there is no liquid market for these investments. Long-term liabilities, convertible debentures, and other long-term liabilities 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 respective asset’s carrying value at inception. Transaction costs for items classified as held-for-trading are expensed immediately. Transaction costs that are directly attributable to the issuance of financial liabilities, costs of arranging the Company’s credit facility and costs considered as commitment fees paid to financial institutions are recorded in deferred financing costs. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to revolving credit facilities are amortized on a straight-line basis over the term of the facility.
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 sheet. The amounts that could net settle are not significant. The Company applies hedge accounting to financial instruments used to manage its foreign currency risk exposure and price risk exposure associated with sales of generated electricity.
1	Significant accounting policies (continued)
(x)	Financial instruments and derivatives (continued)
For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized as other comprehensive income. The ineffective portion is immediately recognized in earnings. The amount recognized in accumulated other comprehensive income is removed and included in earnings in the same period as the hedged cash flows affect earnings under the same line item in the statement of income 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 recognized in accumulated other comprehensive income is transferred to the income statement in the same period that the hedged item affects profit or loss. If the forecast transaction is no longer expected to occur, then the balance in accumulated other comprehensive income 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 other comprehensive income) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings.
Calpeco Electric System and Liberty Utilities (Granite State Electric) Corp. (“Granite State Electric System”) enter into Power Purchase Agreements (“PPA”) for load serving 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 on-going basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
(y)	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 measurement date.
(z)	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.
1	Significant accounting policies (continued)
(aa)	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 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 and intangible assets, the annual impairment testing of reporting units containing 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, and the fair value of financial instruments, derivatives and share-based compensation. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Recently_issued_accounting_pro

Recently issued accounting pronouncements	12 Months Ended
	Dec. 31, 2013
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 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. These newly issued accounting standards require an entity to disclose both gross and net information about financial instruments and transactions eligible for offset in the balance sheet including financial instruments and transactions executed under a master netting or similar arrangement. The standards were issued to enable users of the financial statements to understand the effects or potential effects of such arrangements on an entity’s financial position. The adoption of these standards as at January 1, 2013 did not have a material impact on the Company’s consolidated financial statements.
	The FASB issued ASU 2013-02, Comprehensive Income (Topic 220): This newly issued accounting standard requires an entity to provide certain information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes to the financial statements, the effect of, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. Other than the additional disclosure (note 16), the adoption of this standard did not have a material impact on the Company’s consolidated financial statements.
	2.     Recently issued accounting pronouncements (continued)
	(b)	Recent accounting guidance not yet adopted
	The FASB issued ASU 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This newly issued accounting standard requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in some specific situations. This ASU is required to be applied prospectively for fiscal years, and interim periods beginning after December 15, 2013. The adoption of this standard is not expected to have an impact the Company’s financial position or results of operations.
	The FASB issued ASU 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. This newly issued accounting standard permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to interest rates on direct Treasury obligations of the U.S. government and the London Interbank Offered Rate. The amendments also remove the restriction on using different benchmark rates for similar hedges. This ASU is required to be applied prospectively for qualifying new or re-designated hedging relationships entered into on or after July 17, 2013. 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 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date. This newly issued accounting standard provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. This ASU is required to be applied retrospectively for fiscal years, and interim periods within those years beginning after December 15, 2013. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

Business_acquisitions_and_deve

Business acquisitions and development projects	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Business acquisitions and development projects	'
	Business acquisitions and development projects
	(a)	Agreement to acquire the noncontrolling interest in U.S. Wind farms
	On November 28, 2013, APCo entered into an agreement to acquire the 40% interest in Wind Portfolio SponsorCo, LLC ("SponsorCo") from Gamesa Corporación Tecnológica, S.A. for approximately U.S. $117,000. SponsorCo indirectly holds the interests in Sandy Ridge, Senate and Minonk Wind acquired in 2012. The transaction will result in the elimination of the noncontrolling interest in respect of the Class B partnership units of SponsorCo including its portion of Accumulated other comprehensive income and resulting tax effect. Any difference with the consideration paid will be recorded as Additional paid-in capital.
	3	Business acquisitions and development projects (continued)
	(b)	Acquisition of New England Gas System
	On December 20, 2013, Liberty Utilities 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 approximately U.S. $59,100, subject to certain working capital and other closing adjustments.
	The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:
	Cash	$	76
	Working capital	8,175
	Property, plant and equipment	84,636
	Regulatory assets	47,644
	Other assets	1,197
	Long term debt (including current portion)	(25,836		)
	Regulatory liabilities	(15,969		)
	Pension and OPEB	(25,360		)
	Environmental obligation	(10,225		)
	Deferred income tax liability, net	(1,217		)
	Total net assets acquired	$	63,121
	Due to the timing of the acquisition, the Company has not completed the fair value measurements of the assets acquired and liabilities assumed. The determination of the fair value has been based upon management’s preliminary estimates of final closing adjustments, certain estimates and assumptions with respect to the fair values 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. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts above.
	Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight line method. The weighted average useful life of New England Gas System assets is 55 years.
	All costs related to the acquisition have been expensed through the consolidated statements of operations.
	New England Gas System contributed revenue of $3,582 and net earnings of $1,153 to the Company’s consolidated financial results for 2013. Pro forma financial information is disclosed in note 3(f).
	3	Business acquisitions and development projects (continued)
	(c)	Acquisition of Peach State Gas System
	On April 1, 2013 Liberty Utilities acquired certain regulated natural gas distribution utility assets (the “Peach State Gas System”) located in the State of Georgia. The total purchase price for the Peach State Gas System adjusted for certain working capital and other closing adjustments, is approximately $155,578 (U.S. $153,000).
	The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:
	Working capital	$	9,605
	Property, plant and equipment	141,983
	Goodwill	12,226
	Deferred income tax asset, net	1,992
	Derivative asset	231
	Regulatory liabilities	(3,807		)
	Other liabilities	(1,853		)
	Pension and OPEB	(4,615		)
	Derivative liabilities	(184		)
	Total net assets acquired	$	155,578
	The Company has not completed the fair value measurement of the assets acquired and liabilities assumed, particularly that of certain executory contracts. The determination of the fair value has been based upon management’s preliminary estimates and assumptions with respect to the fair values 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. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts above.
	Goodwill represents the excess of the fair value of the consideration paid over the fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to the Peach State Gas System has been reported under the Liberty Utilities (East) segment.
	Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight line method. The weighted average useful life of the Peach State Gas System assets is 55 years.
	All costs related to the acquisition have been expensed through the consolidated statements of operations.
	Peach State Gas System contributed revenue of $37,889 and net earnings of $5,692 to the Company’s consolidated financial results for 2013. Pro forma financial information is disclosed in note 3(f).
	3	Business acquisitions and development projects (continued)
	(d)	Acquisition of Pine Bluff Water System
	On February 1, 2013, Liberty Utilities acquired United Water Arkansas Inc. a regulated water distribution utility (the “Pine Bluff Water System”) located in Pine Bluff, Arkansas. Total purchase price for the Pine Bluff Water System, adjusted for certain working capital and other closing adjustments, is approximately $27,858 (U.S. $27,934).
	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed.
	Cash	$	8
	Working capital	766
	Property, plant and equipment	28,371
	Regulatory assets	957
	Goodwill	5,034
	Other liabilities	(169		)
	Regulatory liabilities	(135		)
	Pension and OPEB	(4,277		)
	Deferred income tax liability, net	(2,697		)
	Total net assets acquired	$	27,858
	Goodwill represents the excess of the fair value of the consideration paid over the fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to the Pine Bluff Water System has been reported under the Liberty Utilities (Central) segment.
	Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight line method. The weighted average useful life of the Pine Bluff Water System assets is 40 years.
	All costs related to the acquisition have been expensed through the consolidated statements of operations.
	Pine Bluff Water System contributed revenue of $8,708 and net earnings of $1,894 to the Company’s consolidated financial results for 2013. The disclosure of pro forma revenue and earnings has been deemed immaterial.
	3	Business acquisitions and development projects (continued)
	(e)	Acquisition of Shady Oaks Wind Facility
	Effective January 1, 2013, APCo acquired the 109.5 megawatt (“MW”) Shady Oaks wind powered generating facility (“Shady Oaks Wind Facility”) by assuming the existing long-term debt of approximately U.S. $150,000 for no additional cash. 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.
	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date. The determination of the fair value is based upon management’s estimates and assumptions with respect to the fair value of the assets acquired and liabilities assumed.
Cash		$	4,682
Working capital		(846		)
Property, plant and equipment		144,243
Deferred tax asset		2,519
Long term debt (including current portion)		(149,235		)
Asset retirement obligation		(1,363		)
Total net assets acquired		$	—
Property, plant and equipment are amortized on a straight line basis over the lives of the assets, which have a weighted average useful life of 37 years.
Shady Oaks Wind Facility earns revenue from the sale of electricity and renewable energy credits and from capacity payments. Shady Oaks Wind Facility recognizes revenue from the sale of electricity and renewable energy credits (“RECs”) based upon the output delivered at rates specified under a long-term power purchase agreement with Commonwealth Edison Company (“ComEd”). Shady Oaks Wind Facility has contracted to sell approximately 310,000 MW hours of electricity (and associated RECs) to ComEd each year, commencing June 1, 2012, under this long-term power purchase agreement. On March 29, 2013, ComEd issued curtailment notice reducing the annual contract quantity for the delivery year from June 1, 2013 to May 31, 2014 to 252,617 MW hours. Electricity and associated renewable energy credits not sold to ComEd will be sold into wholesale electric markets.
Shady Oaks Wind Facility contributed revenue of $17,472 and net earnings of $3,297 to APUC’s consolidated financial results for 2013. The disclosure of pro forma revenue and earnings has been deemed impracticable as Shady Oaks Wind Facility being a newly constructed wind power generation facility only achieved commercial operations in the second half of 2012 and therefore had little operations prior to the acquisition by APCo.
All costs related to the acquisition have been expensed in the consolidated statements of operations.
3	Business acquisitions and development projects (continued)
(f)	Pro forma information
The supplemental pro forma financial information below was prepared using the acquisition method of accounting and is based on the historical financial information of APUC, New England Gas System and Peach State Gas System reflecting results of operations for 2013 and 2012 on a comparative basis as though the aforementioned companies were combined as of January 1, 2012. The acquiree’s pre-acquisition results have been added to APUC’s historical results, and the totals have been adjusted for the pro forma effects of acquisition-related costs, interest expense related to the financing of the business combinations, and related income taxes.
Pro forma	2013				2012
Total revenue from continuing operations	$	760,394			$	464,182
Net earnings from continuing operations	59,698				28,103
Basic net earnings from continuing operations per share	0.32				0.13
Diluted net earnings from continuing operations per share	0.32				0.13
The above unaudited pro forma financial information is presented for informational purposes only and does not purport to represent what the results would have been had the acquisition closed on the date assumed, nor is it necessarily indicative of the results that may be expected in future periods.
(g)	Acquisition of New Hampshire Electric and Gas Systems
In 2013, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed on July 3, 2012 for the New Hampshire electric and gas utilities. The carrying value of those assets and liabilities were retrospectively adjusted to the amounts detailed in the table below. As a result, the total consideration was reduced by $9,216, working capital acquired was reduced by $9,869 and goodwill was increased by $957.
	Granite State				EnergyNorth			Total
Cash	$	395			$	—		$	395
Restricted cash	3,252				—			3,252
Working capital	1,916				15,420			17,336
Property, plant and equipment	86,935				256,305			343,240
Regulatory assets	31,683				87,126			118,809
Deferred financing	31				—			31
Other assets	—				83			83
Goodwill	—				28,537			28,537
Customer deposits	(661		)		(962		)	(1,623		)
Long-term debt	(15,188		)		—			(15,188		)
Other long-term liabilities	(1,468		)		(3,287		)	(4,755		)
Advances in aid of construction	—				(86		)	(86		)
Derivative liabilities	—				(2,598		)	(2,598		)
Regulatory liabilities	(5,533		)		(27,456		)	(32,989		)
Pension and OPEB	(19,108		)		(29,197		)	(48,305		)
Environmental obligation	—				(54,431		)	(54,431		)
Deferred income tax liabilities, net	—				(61,484		)	(61,484		)
Total net assets acquired	$	82,254			$	207,970		$	290,224
3	Business acquisitions and development projects (continued)
(h)	Acquisition of solar energy project
On January 4, 2012, APCo acquired rights to develop a 10 MWac solar project located near Cornwall, Ontario which has been granted a Feed-in-Tariff contract by the Ontario Power Authority for a 20 year term at a rate of $443/MWh. The consideration for the development rights is $4,500 plus additional contingent consideration of $3,500 based on achieving certain construction milestones. As at December 31, 2013, the Company has paid a total of $3,000 based on achieved milestones. The transaction has been recorded as a purchase of intangible assets. In addition, as at December 31, 2013, the Company has invested $33,259 in the development and construction of the solar energy project which is recorded as property, plant and equipment.
(i)	Acquisition of noncontrolling interest in Calpeco Electric System
On December 21, 2012, APUC acquired the 49.999% interest in Calpeco Electric System from Emera Inc.(“Emera”) that it did not previously hold for $38,756 which was funded by the proceeds of common share subscription receipts (note 15(a)(ii)). The impact on the Company’s consolidated balance sheet was as follows:
	2012
Elimination of noncontrolling interest (net of intercompany balance of $1,297 with Emera)	$	33,726
Noncontrolling interest portion of currency translation adjustment transferred to AOCI	1,397
Accumulated deficit	3,633
Exercise of subscription receipts	$	38,756
During the third quarter of 2013, the Company completed the tax filings in connection with the acquisition of Emera’s noncontrolling interest in Calpeco Electric System and identified an adjustment to the deferred tax balance.   The $3,649 deferred tax adjustment identified has been recorded in the current period as an adjustment to accumulated deficit consistent with the accounting for the acquisition of the noncontrolling interest.

Accounts_receivable

Accounts receivable	12 Months Ended
	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]	'
Accounts receivable	'
	Accounts receivable
	Accounts receivable as of December 31, 2013 includes unbilled revenue of $45,274 (December 31, 2012 - $22,658) from the Company's regulated utilities. Accounts receivable as at December 31, 2013 is presented net of allowance for doubtful accounts of $8,461 (December 31, 2012 - $4,360).

Property_plant_and_equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, plant and equipment	'
	Property, plant and equipment
	Property, plant and equipment consist of the following:
	2013
		Cost		Accumulated		Net book
				depreciation		value
	Generation
	Renewable	$	1,438,229	$	166,175	$	1,272,054
	Thermal	116,975		43,596		73,379
	Distribution
	Water & wastewater	303,410		63,807		239,603
	Electricity	277,679		16,782		260,897
	Gas	690,034		19,758		670,276
	Land	8,266		—		8,266
	Equipment	71,292		25,111		46,181
	Construction in progress	138,048		—		138,048
		$	3,043,933	$	335,229	$	2,708,704
	2012
		Cost		Accumulated		Net book
				depreciation		value
	Generation
	Renewable	$	1,132,631	$	78,772	$	1,053,859
	Thermal	208,183		78,336		129,847
	Distribution
	Water & wastewater	240,376		52,162		188,214
	Electricity	259,461		7,765		251,696
	Gas	352,491		5,940		346,551
	Land	7,318		—		7,318
	Equipment	67,740		22,712		45,028
	Construction in progress	63,765		—		63,765
		$	2,331,965	$	245,687	$	2,086,278
	Renewable generation assets include cost of $86,774 (2012 - $88,198) and accumulated depreciation of $31,739 (2012 - $29,584) related to facilities under capital lease or owned by consolidated variable interest entities. Depreciation expense of facilities under capital lease was $2,155 (2012 - $2,244).
	Investments tax credits, government grants and contributions received in aid of construction of $3,098 (2012 - $6,341) have been credited to the cost of the distribution assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return.
	Subsequent to year-end, on January 3, 2014, APUC, through wholly owned subsidiaries, acquired a new office facility in Oakville, Ontario. The purchase price for the building was $46,800 and was financed through APUC's credit facility.

Intangible_assets_and_goodwill

Intangible assets and goodwill	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Intangible assets and goodwill	'
	Intangible assets and goodwill
	Intangible assets consist of the following:
	2013
		Cost				Accumulated				Net book
						amortization				value
	Power sales contracts	$	61,430			$	28,987			$	32,443
	Customer relationships	28,512				6,539				21,973
		$	89,942			$	35,526			$	54,416
	2012
		Cost				Accumulated				Net book
						amortization				value
	Power sales contracts	$	60,435			$	24,881			$	35,554
	Customer relationships	26,674				5,447				21,227
		$	87,109			$	30,328			$	56,781
	Estimated amortization expense for intangibles for the next three years is $4,560 each year, $2,810 in year four and $2,470 in year five.
	Changes in goodwill per operating segment are as follows:
		Liberty Utilities
		Central			West			East			Total
	Balance, January 1, 2012	$	192		$	9,517		$	—		$	9,709
	Business acquisitions	25,257			—			26,527			51,784
	Foreign exchange	(357		)	(251		)	574			(34		)
	Balance, December 31, 2012	$	25,092		$	9,266		$	27,101		$	61,459
	Business acquisitions	5,034			—			12,226			17,260
	Adjustments	(209		)	—			957			748
	Foreign exchange	2,056			640			2,484			5,180
	Balance, December 31, 2013	$	31,973		$	9,906		$	42,768		$	84,647

Regulatory_matters

Regulatory matters	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory matters	'
	7	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 U.S. Financial Accounting Standards Board ASC Topic 980 Regulated Operations (“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 revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.
	On November 29, 2012, the Company’s Calpeco Electric System regulator approved an All Parties General Rate Case Settlement. As an element of the decision, a revenue decoupling mechanism and a vegetation management memorandum account were agreed upon. The revenue decoupling mechanism will isolate base revenues from fluctuations caused by weather and economic factors. The vegetation management memorandum account allows for the tracking and pass through of vegetation management expenses to customers, one of the largest expenses of the utility.
	7	Regulatory matters (continued)
	At any given time, Liberty Utilities can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period.
	Regulatory assets and liabilities consist of the following:
		2013			2012
	Regulatory assets
	Environmental costs (a)	$	80,438		$	59,789
	Pension and post-employment benefits (b)	64,997			47,838
	Storm costs (c)	5,437			6,726
	Energy costs adjustment (d)	20,495			7,962
	Rate case costs (e)	3,119			2,398
	Vegetation management	2,297			2,082
	Debt premium (f)	4,504			—
	Asset retirement obligation (g)	1,468			1,095
	Tax related	2,995			1,160
	Other	4,598			5,342
	Total regulatory assets	$	190,348		$	134,392
	Less current regulatory assets	(34,643		)	(10,644		)
	Non-current regulatory assets	$	155,705		$	123,748
	Regulatory liabilities
	Cost of removal (h)	$	68,698		$	58,852
	Rate-base offset (i)	25,082			15,541
	Energy costs adjustment (d)	17,394			13,891
	Pension and post-employment benefits (b)	6,770			1,127
	Rate adjustment mechanism	1,681			—
	Tax related	133			—
	Other	3,531			1,265
	Total regulatory liabilities	$	123,289		$	90,676
	Less current regulatory liabilities	(21,632		)	(8,626		)
	Non-current regulatory liabilities	$	101,657		$	82,050
	(a)	Environmental remediation costs recovery: Actual expenditures incurred for the cleanup of certain former gas manufacturing facilities (see note 23 (a) (ii)) are recovered through rates over a period of 7 years.
	(b)	Pension and post-employment benefits: As part of a business acquisition, the Regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-retirement benefits that have not yet been recognized in net periodic cost and were presented as accumulated comprehensive income prior to the acquisition. A net portion of $12,213 is currently recovered through rates over the future services years of the employees. The balance of $46,014 relates to recent acquisitions and was authorized for recognition as an asset by the Regulator. Recovery of $23,013 through rates is expected to start in the second quarter of 2014. The remaining $23,001 is anticipated to be approved in a final rate order in 2015.
	(c)	Storm costs: Incurred repair costs resulting from certain storms, which are expected to be recovered through rates.
	7	Regulatory matters (continued)
	(d)	Energy cost adjustment: The revenue of the electric and natural gas utilities include 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 balance sheet. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future time 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 are recoverable through the energy cost adjustment (note 26(b)(i)).
	(e)	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.
	(f)	Debt premium: The value of debt assumed in the acquisition of New England Gas System has been recorded at fair value in accordance with ASC 805 Business Combinations. The Massachusetts regulator allows for recovery of interest at the coupon rate of the debt and a regulatory asset has been recorded for the difference between the fair value and face value of the debt.
	(g)	Asset retirement obligation: Asset retirement obligations incurred by the utilities are expected to be recovered through rates.
	(h)	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.
	(i)	Rate-base offset: The Regulator 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.
	The Company records carrying charges on the regulatory balances related to energy costs adjustment and storm costs. 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 income in the period of such determination.

Longterm_investments_and_notes

Long-term investments and notes receivable	12 Months Ended
	Dec. 31, 2013
Disclosure Long Term Investments And Notes Receivable [Abstract]	'
Long-term investments and notes receivable	'
	Long-term investments and notes receivable
	Long-term investments and notes receivable consist of the following:
		2013			2012
	Long-term investments
	32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	$	4,851		$	4,926
	25% of Class B non-voting shares of Cochrane Power Corporation	3,772			4,669
	45% interest in the Algonquin Power (Rattle Brook) Partnership (b)	—			3,884
	50% interest in the Valley Power Partnership	1,718			1,767
	Other	325			180
	Total long-term investments	$	10,666		$	15,426
	Notes Receivable
	Red Lily Senior loan, interest at 6.31% (a)	$	11,588		$	11,588
	Red Lily Subordinated loan, interest at 12.5% (a)	6,565			6,565
	Chapais Énergie, Société en Commandite interest at 10.789% and 4.91%, respectively	1,928			2,448
	Silverleaf resorts loan, interest at 15.48% maturing July 2020	2,149			2,010
	Other	448			146
		22,678			22,757
	Less: current portion	(598		)	(537		)
	Total long-term notes receivable	$	22,080		$	22,220
	Total long-term investments and notes receivable	$	32,746		$	37,646
	8	Long-term investments and notes receivable (continued)
	The above notes are secured by the underlying assets of the respective facilities.
	(a)	Red Lily I
	The Red Lily I Partnership (“Partnership”) is owned by an independent investor. The Company provides operation and supervision services to the Red Lily I project, a 26.4 megawatt wind energy facility located in south-eastern Saskatchewan.
	The Company’s investment in Red Lily I is in the form of participation in a portion of the senior debt facility, and a subordinated debt facility to the Partnership. In 2011, APUC advanced $13,000 under a senior debt facility to the Partnership and received a pre-payment of $1,412 in 2012. Another third party lender has also advanced $31,000 of senior debt to the Partnership. The Company’s senior loan to the Partnership earns interest at the rate of 6.31% and will mature in 2016. 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%, 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.
	A second tranche of subordinated loan for an amount equal to the amounts outstanding on Tranche 2 of the senior debt but no greater than $17,000 will be advanced in 2016 by the Company. The proceeds from this additional subordinated debt are required to be used to repay Tranche 2 of the Partnership’s senior debt, including APUC’s portion.
	In connection with the subordinated debt facility, the Company has been granted an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loan of up to $19,500, exercisable for a period of 90 days commencing in 2016. The fair value of the conversion option as at December 31, 2013 and 2012 was determined to be negligible.
	(b)	Algonquin Power (Rattle Brook) Partnership
	The Algonquin Power (Rattle Brook) Partnership was sold to related parties effective December 31, 2013 (see note 21).

Longterm_liabilities

Long-term liabilities	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-term liabilities	'
	9	Long-term liabilities
	Long term liabilities consist of the following:
		2013			2012
	APCo
	Revolving $200,000 credit facility, revolving line of credit 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 1.75%, maturing November 16, 2015.	$	124,570		$	27,074
	Senior Unsecured Notes:	149,920			149,910
	$150,000 senior unsecured notes, bearing an interest rate of 4.82% maturing February 15, 2021. The notes are interest only, payable semi-annually in arrears.
	Senior Unsecured Notes:	134,837			134,807
	$135,000 senior unsecured notes, bearing an interest rate of 5.50% maturing July 25, 2018. The notes are interest only, payable semi-annually in arrears.
	Senior Debt - Shady Oaks Wind Facility:	129,759			—
	U.S. $122,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points, maturing June 30, 2026.  The facility has principal and interest payments, payable semi-annually in arrears.
	Senior Debt - Long Sault Hydro Facility:	37,143			38,136
	Bonds bearing an interest rate of 10.21% maturing December 31,2027. The bonds have interest and principal payments, monthly in arrears.
		2013			2012
	Senior Debt - Sanger Thermal Facility:	20,421			19,102
	U.S. $19,200 California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bond Series 1990A, bearing an effective interest rate determined by the remarketing agent, maturing September 15, 2020. The bond has interest only payments, payable monthly in arrears. The effective interest rate in 2013 was 1.72% (2012 – 2.29%).
	Senior Debt - Chuteford Hydro Facility:	3,417			3,763
	Bonds bearing an interest rate of 11.6%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears.
	Liberty Utilities
	Revolving U.S. $200,000 credit facility, revolving line of credit 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.	85,620			27,360
	Senior Unsecured Notes:
	Liberty Utilities Co.:	388,214			223,852
	U.S. $50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S. $115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S. $60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S. $15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S. $25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S. $75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; and U.S. $25,000, bearing an interest rate of 4.26%, maturing July 31, 2028. The notes interest only payments, payable semi-annually.
	Calpeco Electric System:	74,452			69,643
	U.S. $45,000 senior unsecured notes bearing an interest rate of 5.19%, maturing December 29, 2020 and U.S. $25,000 senior unsecured notes bearing an interest rate of 5.59%, maturing December 29, 2025. The notes are interest only payments, payable semi-annually in arrears.
	Liberty Water Co:	53,180			49,745
	U.S. $50,000 senior unsecured notes bearing an interest rate of 5.60% maturing December 22, 2020. The note has interest only payments, payable semi-annually in arrears, until June 20, 2016 after which the note will bear semi-annual interest payments thereafter.
	New England Gas System:	25,244			—
	First mortgage bonds, 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 bonds have interest only payments.
	Granite State Electric System:	15,954			14,924
	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; and, U.S. $5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually.
	LPSCo Water System:	11,668			11,269
	1999 and 2001 IDA Bonds bearing interest rates of 5.95% and 6.75% and maturing October 1, 2023 and October 1, 2031 respectively. The bonds have principal and interest payments, payable monthly in arrears.
	Bella Vista Water System:	1,189			1,241
	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.
		$	1,255,588		$	770,826
	Less: current portion	(8,339		)	(1,768		)
		$	1,247,249		$	769,058
	9	Long-term liabilities (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 APUC, APCo or Liberty Utilities. The loans have certain financial covenants, which must be maintained on a quarterly basis. Noncompliance with the covenants could restrict cash distributions/dividends to APUC, APCo and Liberty Utilities from the specific facilities.
	APCo
	Subsequent to year-end on January 17, 2014, APCo 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 will be payable on February 15 and August 15 each year, commencing on February 15, 2014. APCo incurred deferred financing costs of $940, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, APCo entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars. APCo designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term USD payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in APCo’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 USD accruals that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation will be reported in the same manner as the translation adjustment (in other comprehensive income) related to the net investment.
	Effective January 1, 2013, concurrent with the acquisition of Shady Oaks Wind Facility (note 3(e)), APCo assumed existing long-term debt of approximately U.S. $150,000. Principal of U.S. $28,000 was repaid during the year and another portion of U.S. $40,000 was paid subsequent to year-end on February 10, 2014 leaving a balance of U.S. $82,000 outstanding at that date. The semi-annual principal repayment schedule for the following 12.5 years ranges from U.S., $3,000 to U.S. $6,000 with a final repayment in 2026. This debt may be repaid in whole or in part at any time without penalty.
	On December 3, 2012, APCo issued $150,000 senior unsecured debentures bearing interest at 4.82% and with a maturity date of February 15, 2021. The debentures were sold at a price of $99.94 per $100.00 principal amount. Interest payments are payable on February 15 and August 15 each year. APCo incurred deferred financing costs of $1,057, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, APCo entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars (note 26(b)(iii)).
	In 2012, APCo increased the maximum availability under its senior credit facility from $120,000 to $200,000 to meet future working capital needs. In addition, the bank syndicate agreed to release its security previously held over certain APCo entities, such that the facility is now fully unsecured. The facility has a maturity date of November 16, 2015.
	Liberty Utilities
	On December 20, 2013, in connection with the acquisition of New England Gas System, Liberty Utilities assumed first mortgage bonds of U.S. $6,000, bearing an interest rate of 7.24%, maturing December 15, 2027; U.S. $7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; and, U.S. $6,500, bearing an interest rate of 9.44%, maturing Feb 15, 2020.
	On September 30, 2013, Liberty Utilities increased the maximum availability under its revolving credit facility from U.S. $100,000 to $200,000 to meet future working capital requirements and allow for greater financial flexibility. The facility has a maturity date of September 30, 2018.
	On July 31, 2013, Liberty Utilities issued U.S. $125,000 of senior unsecured notes through a private placement in three tranches: U.S. $25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S. $75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; and, U.S. $25,000, bearing an interest rate of 4.26%, maturing July 31, 2028.  The proceeds from the private placement financing were used to fund a portion of the acquisition of the Peach State Gas System (note 3(c)).
	On March 14, 2013 Liberty Utilities issued U.S. $15,000 of senior unsecured notes through a private placement in connection with the acquisition of the Pine Bluff Water System (note 3(d)). The notes bear interest at 4.14% and mature March 13, 2023.
	9	Long-term liabilities (continued)
	Liberty Utilities (continued)
	In July 2012, Liberty Utilities issued U.S. $225,000 of senior unsecured notes through a private placement in three tranches: U.S. $50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S. $115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; and, U.S. $60,000, bearing an interest rate of 4.89%, maturing July 30, 2027. The notes are interest only, payable semi-annually. Liberty Utilities incurred deferred financing costs of $2,663, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Liberty Utilities used the proceeds of the private placement financing to fund a portion of the acquisition of the New Hampshire Electric and Gas Systems and Midwest Gas System.
	On July 3, 2012, in connection with the acquisition of Granite State Electric System, Liberty Utilities assumed senior unsecured long-term notes of 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; and, U.S. $5,000, bearing an interest rate of 7.30%, maturing June 15, 2028.
	APUC
	On November 19, 2013, APUC increased the maximum availability under its revolving credit facility from U.S. $30,000 to $65,000. The credit facility will be used for general corporate purposes and has a maturity date of November 19, 2016. As at December 31, 2013 and 2012, no amounts were outstanding under this facility.
	As of December 31, 2013, the Company had accrued $14,057 in interest expense (2012 - $4,482). Interest paid on the long-term liabilities in 2013 was $49,746 (2012 - $20,671).
	Principal payments due in the next five years and thereafter are:
		2014			2015			2016		2017		2018		Thereafter		Total
	APCo	$	7,864		$	132,508		$	8,212	$	10,540	$	10,767	$	430,176	$	600,067
	Liberty Utilities	475			504			5,852		59,075		91,524		498,091		655,521
	Total	$	8,339		$	133,012		$	14,064	$	69,615	$	102,291	$	928,267	$	1,255,588

Convertible_debentures

Convertible debentures	12 Months Ended
	Dec. 31, 2013
Disclosure Convertible Debentures [Abstract]	'
Convertible debentures	'
	Convertible debentures
		Series 2A			Series 3			Total
	Maturity date	2016			2017
		November 30			September 30
	Interest rate	6.35		%	7		%
	Conversion price per share	$	6		$	4.2
	Carrying value at January 1, 2012	$	59,726		$	62,571		$	122,297
	Conversion to common shares (note 15(a)(i)), net of costs	(59,950		)	(61,611		)	(121,561		)
	Amortization and accretion	224			—			224
	Carrying amount at December 31, 2012	$	—		$	960		$	960
	Conversion to common shares (note 15(a)(i)), net of costs	—			(960		)	(960		)
	Amortization and accretion	—			—			—
	Carrying and fair value amount at December 31, 2013	$	—		$	—		$	—

Pension_and_other_postretireme

Pension and other post-retirement benefits	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Pension and other post-retirement benefits	'
	Pension and other post-employment benefits
	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. Benefits are based on each employee’s years of service and compensation. Liberty Utilities initiated 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 Company’s policy is to make pension contributions within the range determined by generally accepted actuarial principles. 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.
	The Company acquired the Pine Bluff Water System, the Peach State Gas System and New England Gas System in 2013; therefore, the pension and OPEB implications for those current acquisitions are not included in the December 31, 2012 comparative information.
	(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 at December 31:
		Pension benefits								OPEB
		2013				2012				2013			2012
	Change in projected benefit obligation
	Projected benefit obligation, at beginning of year	$	104,291			$	239			$	31,674		$	—
	Projected benefit obligation assumed from business combination	73,601				101,840				17,943			30,637
	Modifications to pension plan	81											—
	Service cost	3,273				1,288				1,602			803
	Interest cost	4,350				1,906				1,508			606
	Actuarial (gain)/loss	(11,395		)		2,736				(8,499		)	857
	Benefits paid	(3,597		)		(1,507		)		(1,158		)	(601		)
	Loss/(gain) on foreign exchange	7,509				(2,211		)		2,329			(628		)
	Projected benefit obligation at end of year	$	178,113			$	104,291			$	45,399		$	31,674
	Change in plan asset
	Fair value of plan assets at beginning of year	66,524				203				10,195			—
	Plan assets acquired in business combination	57,285				68,045				658			10,786
	Actual return on plan assets	10,733				1,223				1,730			—
	Employer contributions	3,013				—				1,208			231
	Benefits paid	(3,597		)		(1,507		)		(1,158		)	(601		)
	Loss/(gain) on foreign exchange	5,322				(1,440		)		762			(221		)
	Fair value of plan assets at end of year	$	139,280			$	66,524			$	13,395		$	10,195
	Unfunded status	$	(38,833	)		$	(37,767	)		$	(32,004	)	$	(21,479	)
	Amounts recognized in the consolidated balance sheets consists of:
	Current liabilities	(305		)		—				—			—
	Non-current liabilities	(38,528		)		(37,767		)		(32,004		)	(21,479		)
	Net amount recognized	$	(38,833	)		$	(37,767	)		$	(32,004	)	$	(21,479	)
	11	Pension and other post-employment benefits (continued)
	(b)	Net pension and OPEB obligation (continued)
	The accumulated benefit obligation for the pension plans was $162,179 and $97,687 at December 31, 2013 and 2012, respectively.
	The amounts recognized in accumulated other comprehensive loss before tax were as follows:
		Accumulated other comprehensive income
		Pension				OPEB
	Balance, January 1, 2012	$	53			$	—
	Current year net actuarial gain	3,298				857
	Amortization of net actuarial loss	(2		)		(32		)
	Foreign exchange	(16		)		(4		)
	Balance at December 31, 2012	$	3,333			$	821
	Current year net actuarial loss	(18,011		)		(9,644		)
	Current year prior service loss	82				—
	Amortization of net actuarial loss	(23		)		(26		)
	Foreign exchange	234				(234		)
	Balance at December 31, 2013	$	(14,385	)		$	(9,083	)
	(c)	Assumptions
	Weighted average assumptions used to determine net benefit cost for 2013 and 2012 were as follows:
		Pension benefits						OPEB
		2013			2012			2013			2012
	Discount rate	3.68	%		3.89	%		3.69	%		3.97	%
	Expected return on assets	5.51	%		5.5	%		5.18	%		4.66	%
	Rate of compensation increase	3.13	%		3.31	%		2.97	%		N/A
	Healthcare cost trend rate
	Before Age 65							7.68	%		8.48	%
	Age 65 and after							7.68	%		7.5	%
	Assumed Ultimate Medical Inflation Rate							4.8	%		5	%
	Year in which Ultimate Rate is reached							2019			2017
	Weighted average assumptions used to determine net benefit obligation for 2013 and 2012 were as
	follows:
		Pension benefits						OPEB
		2013			2012			2013			2012
	Discount rate	4.55	%		3.62	%		4.6	%		3.75	%
Expected return on assets	7	%		5.5	%		5.53	%		4.66	%
Rate of compensation increase	2.97	%		3.09	%		2.97	%		N/A
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
11	Pension and other post-employment benefits (continued)
(c)	Assumptions (continued)
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 2013 is as follows:
	2013
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	5,829
Total service and interest cost	580
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(4,427	)
Total service and interest cost	(456		)
(d)	Benefit costs
The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of administrative expenses in the consolidated statements of operations. The employee benefit costs related to business acquired are recorded in the consolidated statements of operations from the date of acquisition.
	Pension benefits								OPEB
	2013				2012				2013			2012
Service cost	$	3,273			$	1,288			$	1,602		$	803
Interest cost	4,350				1,906				1,508			606
Expected return on plan assets	(4,160		)		(1,785		)		(602		)	—
Amortization of net actuarial loss	23				2				26			32
Net benefit cost	$	3,486			$	1,411			$	2,534		$	1,441
The net actuarial gain for the defined benefit pension plans and OPEB that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $283 and $608, respectively.
(e)	Plan assets
The Company’s investment strategy for its pension and post-retirement 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		79	%		48.9%-88.5%
Debt Securities		17	%		21.1%-51.1%
Other		4	%		0%-11.5%
The fair values of investments as at December 31, 2013, by asset category, are as follows:
Asset Class		Level 1			Percentage
Equity Securities		110,073			79	%
Debt Securities		23,173			17	%
Other		6,035			4	%
As at December 31, 2013, the funds do not hold any material investments in APUC.
11	Pension and other post-employment benefits (continued)
(f)	Cash flows
The Company expects to contribute $7,539 to its pension plans and $1,339 to its post retirement benefit plans in 2014.
The expected benefit payments over the next ten years are as follows:
	2014				2015				2016			2017			2018		2019-2023
Pension plan	$	8,320			$	8,238			$	8,812		$	9,374		$	9,839	$	55,838
OPEB	1,339				1,247				1,400			1,547			1,727		11,176
(g)	Defined contribution pension plans
The Company also provides defined contribution pension plans to its employees. The Company's contributions for 2013 were $2,437 (2012 - $1,108).

Mandatorily_redeemable_Series_

Mandatorily redeemable Series C preferred shares	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Mandatorily redeemable Series C preferred shares	'
	Mandatorily redeemable Series C preferred shares
	Effective January 1, 2013, the Company issued 100 redeemable Series C preferred shares in exchange for Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), a subsidiary of APCo and the legal owner of the St. Leon Wind Facility (note 21). 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 detailed below. As these shares are mandatorily redeemable for cash they are accounted for as liabilities in the financial statements. The cumulative dividends are indexed in proportion to the increase in CPI over the term of the shares. The dividend is intended to approximate the distributions that otherwise would have accrued to holders of Class B limited partnership units. The Series C 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.
	The Series C preferred shares were initially measured at their estimated fair value of $18,497 based on the present value of the expected contractual cash flows including dividends and redemption amount, discounted at a rate of 5.0%. The recognition of the initial fair value of $18,497 resulted in an adjustment to equity of the shareholders of the Company as the Class B shares had a nominal carrying amount prior to the exchange. The 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:
	2014	$	1,109
	2015	1,077
	2016	946
	2017	895
	2018	1,125
	Thereafter to 2031	20,859
	Redemption amount	5,340
		31,351
	Less amounts representing interest	(12,546		)
		18,805
	Less current portion	(1,038		)
		$	17,767

Other_assets

Other assets	12 Months Ended
	Dec. 31, 2013
Disclosure Other Assets [Abstract]	'
Other assets	'
	Other assets
	Other assets consist of the following:
		2013		2012
	Restricted cash	$	6,021	$	7,063
	Deferred financing costs	9,011		8,706
	Other	3,752		4,251
		$	18,784	$	20,020

Other_longterm_liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2013
Other Liabilities Disclosure [Abstract]	'
Other long-term liabilities	'
	Other long-term liabilities
	Other long-term liabilities consist of the following:
		2013			2012
	Asset retirement obligations	$	9,508		$	7,088
	Customer deposits	8,774			5,620
	Provision for injury and damages	1,215			3,480
	Deferred water rights inducement	2,764			2,845
	Contingent consideration	1,102			1,031
	Other	4,580			5,177
		27,943			25,241
	Less: current portion	(7,451		)	(4,352		)
		$	20,492		$	20,889
	The 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 (clean of natural gas and PCB contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of gas main when 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.

Shareholders_capital

Shareholders' capital	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Shareholders' capital	'
	Shareholders’ capital
	(a)	Common shares
	Number of common shares:
			2013			2012
	Common shares, beginning of period		188,763,486			136,122,780
	Conversion and redemption of convertible debentures (i)		150,816			24,991,784
	Conversion of subscription receipts (ii)		15,223,016			26,380,750
	Issuance of shares under the dividend reinvestment (iii) and employee share purchase plans (c(ii))		2,211,667			1,268,172
	Common shares, end of period		206,348,985			188,763,486
	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, of which none are authorized or outstanding.
	15	Shareholders’ capital (continued)
	(a)	Common shares (continued)
	Authorized (continued)
	On April 23, 2013, the Company’s shareholders renewed its shareholders’ rights plan (the “Rights Plan”). The Rights Plan has a term of three years. 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.
	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 of Directors of APUC.
	(i)Conversion and redemption of convertible debentures
	In 2013, $960 (2012 - $61,611) of Series 3 Debentures were redeemed for 150,816 (2012 - 14,669,266) shares of APUC.
	In 2012, the remaining principal amount of $59,957 of Series 2A Debentures were redeemed for 10,322,518 common shares of APUC.
	(ii)	Subscription receipts
	On March 26, 2013, in connection with the acquisition of the Peach State Gas system the Company issued 3,960,000 common shares at a price of $7.40 per share for total proceeds of $29,304 pursuant to a subscription receipt agreement with Emera.
	On May 14, 2012, in connection with the acquisition of Granite State Electric System and EnergyNorth Gas System, the Company issued 12,000,000 common shares at a price of $5.00 per share to Emera pursuant to a subscription receipt agreement. The $60,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisitions.
	On June 29, 2012, in connection with the acquisition of Sandy Ridge Wind Facility the Company received $15,000 from Emera relating to 2,614,006 subscription receipts representing a price of $5.74 per share and issued common shares relating to these subscription receipts in July 2012.
	On July 31, 2012, in connection with the acquisition of the Midwest Gas System the Company issued 6,976,744 common shares at a price of $6.45 per share to Emera pursuant to a subscription receipt agreement. The $45,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition.
	On December 10, 2012, in connection with the acquisition of Senate and Minonk Wind Facilities, the Company received $45,000 from Emera relating to the exercise of 7,842,016 subscription receipts at a price of $5.74 per subscription receipt pursuant to a subscription receipt agreement. The subscription receipts were converted to 7,842,016 common shares on February 14, 2013.
	On December 21, 2012, in connection with the acquisition of Emera’s noncontrolling interest in Calpeco Electric System, the Company received $38,756 from Emera related to the exercise of 8,211,000 subscription receipts at a price of $4.72 per subscription receipt pursuant to a subscription receipt agreement. On December 27, 2012, Emera exercised 4,790,000 of these subscription receipts and the Company issued 4,790,000 common shares in exchange. On February 14, 2013, the balance of 3,421,000 subscription receipts were exercised by Emera and the Company issued 3,421,000 common shares in exchange.
	Following the above noted subscription receipts transactions, as of December 31, 2013 all subscriptions receipts had been exercised for cash and converted to common shares.
	15	Shareholders’ capital (continued)
	(a)	Common shares (continued)
	(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 will be purchased in the open market or will be 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 501,818 shares under the dividend reinvestment plan.
	(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 of Directors of APUC. On November 9, 2012, APUC issued 4,800,000 Series A Preferred shares, at a price of $25 per share, for aggregate proceeds of $120,000 before issuance cost of $4,700 or $3,454 net of tax.
	The holders of preferred shares are entitled to receive fixed cumulative preferential dividends at an annual rate of $1.125 per share, payable quarterly, as and when declared by the Board of Directors of APUC (the “Board”). The Series A Preferred shares yield 4.5% annually for the initial six-year period up to, but excluding December 31, 2018, with the first dividend payment occurring December 31, 2012. The dividend rate will reset on December 31, 2018, and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018, and on December 31 of every fifth year thereafter. The holders of Series A Preferred shares have the right to convert their shares into Cumulative Floating Rate Preferred shares, Series B (“the Series B Preferred shares”), subject to certain conditions, on December 31, 2018, and on December 31 of every fifth year thereafter. The Series B Preferred shares carry the same features as the Series A Preferred shares, except that holders 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%. The holders of Series B Preferred shares will have the right to convert their Shares back into Series A Preferred shares on December 31, 2018, and on December 31 of every fifth year thereafter. The Series A Preferred shares and the Series B Preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.
	On January 1, 2013, the Company issued 100 redeemable Series C preferred shares in exchange for Class B limited partnership units issued by the St Leon LP. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets (note 12).
	Subsequent to year-end, on March 5, 2014, APUC issued 4,000,000 Series D Preferred shares, at a price of $25 per share, for aggregate proceeds of $100,000 before issuance costs of $3,900.
	The holders of the Series D preferred shares are entitled to receive fixed cumulative preferential dividends at an annual rate of $1.25 per share, payable quarterly, as and when declared by the Board of Directors of APUC (the “Board”). The Series D Preferred shares yield 5.0% annually for the initial five-year period up to, but excluding March 31, 2019, with the first dividend payment occurring June 30, 2014. The dividend rate will reset on March 31, 2019, and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 3.28%. The Series D preferred shares are redeemable at $25 per share at the option of the Company on March 31, 2019, and on March 31 of every fifth year thereafter. The holders of Series D Preferred shares have the right to convert their shares into Cumulative Floating Rate Preferred shares, Series E (“the Series E Preferred shares”), subject to certain conditions, on March 31, 2019, and on March 31 of every fifth year thereafter. The Series E Preferred shares carry the same features as the Series D Preferred shares, except that holders 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 3.28%. The holders of Series E Preferred shares will have the right to convert their Shares back into Series D Preferred shares on March 31, 2019, and on March 31 of every fifth year thereafter. The Series D Preferred shares and the Series E Preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.
	15	Shareholders’ capital (continued)
	(c)	Share-based compensation
	For the year ended December 31, 2013, APUC recorded $2,046 (2012 - $1,833) in total share-based compensation expense detailed as follows:
		2013				2012
	Stock options	$	1,687			$	1,376
	Directors deferred share units	155				155
	Employee share purchase	75				42
	Performance share units	129				260
	Total share-based compensation	$	2,046			$	1,833
	The compensation expense is recorded as part of administrative expenses in the consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
	As at December 31, 2013, total unrecognized compensation costs related to non-vested options and share unit awards were $1,762 and $86 respectively, and are expected to be recognized over a period of 1.57 years and 1.0 respectively.
	(i)	Stock option plan
	The Company’s stock 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 historic 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.
	15	Shareholders’ capital (continued)
	(c)	Share-based compensation (continued)
	(i)	Stock option plan (continued)
	The following assumptions were used in determining the fair value of share options granted:
		2013				2012
	Risk-free interest rate	1.61		%		1.7		%
	Expected volatility	37		%		38		%
	Expected dividend yield	3.83		%		4.4		%
	Expected life	8 years				8 years
	Weighted average grant date fair value per option	$	2			$	1.49
	Stock option activity during the period is as follows:
	Number of			Weighted				Weighted	Aggregate
	awards			average				average	intrinsic
				exercise				remaining	value
				price				contractual
								term
								(years)
Balance at January 1, 2012	2,487,105			$	4.76			6.96	$	4,134
Granted	1,263,622			6.24				8	—
Balance at December 31, 2012	3,750,727			$	5.25			6.07	$	5,939
Granted	816,402			7.72				8	—
Balance at December 31, 2013	4,567,129			$	5.7			5.45	$	7,814
Exercisable at December 31, 2013	2,466,008			$	4.9			4.96	$	6,018
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. 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 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 shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 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, 2013, a total of 85,410 common shares (2012 – 54,227) were issued to employees under the ESPP plan.
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 Deferred Share Units (“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 share. 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 at
15	Shareholders’ capital (continued)
(c)	Share-based compensation (continued)
iii)	Directors deferred share units (continued)
December 31, 2013, 74,786 (2012 – 50,172) DSUs were outstanding pursuant to the election of the Directors to defer a percentage of their 2013 and 2012 Director’s fee in the form of DSUs.
iv)	Performance share units
The Company offers a performance share unit plan to its employees as part of the Company’s long-term incentive program. Performance Share Units (“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 shares issued can range from 0% to 184% 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 PSUs will be accounted for as equity awards. The Company has a policy of repurchasing shares on the open market to satisfy PSUs exercises and expects to repurchase approximately 24,928 shares during 2014, based on estimates of PSU exercises for that period.
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.
A summary of the PSUs follows:
	Number of awards			Weighted				Weighted		Aggregate
				Average				Average		intrinsic
				Grant-Date				Remaining		value
				Fair Value				Contractual
								Term (years)
Balance at January 1, 2012	21,123			$	5.62			2		$	136
Granted	68,982			6.78				1.3		467
Forfeited	(6,622	)		5.62				1.5		(37		)
Balance at December 31, 2012	83,483			$	6.58			1.8		$	571
Granted, including dividends	5,537			6.79				1.23		41
Exercised	(20,640	)		6.7				—		(151		)
Forfeited	(2,185	)		6.7				—		(16		)
Balance at December 31, 2013	66,195			$	6.57			0.62		$	486
Exercisable at December 31, 2013	24,928			$	6.14			—		$	183

Accumulated_other_comprehensiv

Accumulated other comprehensive loss	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Accumulated other comprehensive loss	'
		Accumulated other comprehensive loss
	Accumulated other comprehensive loss is comprised of the following balances, net of tax:
		Foreign currency cumulative translation			Unrealized gain on cash flow hedges			Pension and post-retirement actuarial loss			Total
	Balance, January 1, 2012	$	(96,462	)	$	—		$	(48	)	$	(96,510	)
	Other comprehensive income (loss) before reclassifications	(9,495		)	3,596			(2,459		)	(8,358		)
	Amounts reclassified from accumulated other comprehensive loss							1			1
	Net current period other comprehensive income	(9,495		)	3,596			(2,458		)	(8,357		)
	Balance, December 31, 2012	$	(105,957	)	$	3,596		$	(2,506	)	$	(104,867	)
	Other comprehensive income (loss) before reclassifications	39,422			19,421			16,698			75,541
	Amounts reclassified from accumulated other comprehensive loss	—			(2,113		)	29			(2,084		)
	Net current period other comprehensive income	39,422			17,308			16,727			73,457
	Balance, December 31, 2013	$	(66,535	)	$	20,904		$	14,221		$	(31,410	)

Noncontrolling_Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2013
Noncontrolling Interest [Abstract]	'
Noncontrolling Interests	'
	Noncontrolling interests
	Net earnings/(loss) attributable to noncontrolling interests consists of the following:
		2013			2012
	Net earnings/(loss) attributable to Class B partnership units of SponsorCo	$	9,556		$	(4,580	)
	Net earnings/(loss) attributable to Class A partnership units	(20,408		)	10,678
	Other net earnings attributable to noncontrolling interests	39			1,316
	Total net earnings/(loss) attributable to noncontrolling interests	$	(10,813	)	$	7,414

Cash_dividends

Cash dividends	12 Months Ended
	Dec. 31, 2013
Disclosure Cash Dividends [Abstract]	'
Cash dividends	'
	Cash dividends
	All dividends of the Company are made on a discretionary basis as determined by the Board of the Company. For the year ended December 31, 2013, the Company declared dividends to shareholders on common shares totaling $68,291 (2012 - $50,196 ) or $0.3325 per common share (2012 - $0.2950 per common share). The Board declared a dividend on the Company’s common shares of $0.0850 per share payable on January 15, 2014 to the shareholders of record on December 31, 2013.
	For the year ended December 31, 2013, the Company declared and paid dividends to Preferred Share, Series A holders totaling $5,400 (2012 - $769 ) or $1.125 per Series A Preferred share (2012 - $0.1603 per Series A Preferred share).

Income_taxes

Income taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
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% (2012 – 26.5%). The differences are as follows:
		2013			2012
	Expected income tax expense / (recovery) at Canadian statutory rate	$	16,072		$	1,726
	Increase (decrease) resulting from:
	Recognition of deferred credit	(6,676		)	(5,092		)
	Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(2,338		)	(6,282		)
	Non-taxable corporate dividend	(2,896		)	(666		)
	Noncontrolling interests share of income	4,266			(2,835		)
	Production tax credit	(247		)	(676		)
	Allowance for equity funds used during construction	(694		)	(402		)
	State taxes	313			—
	Other	1,355			(140		)
	Income tax recovery	$	9,155		$	(14,367	)
	For the years ended December 31, 2013 and 2012, income/(loss) from continuing operations before taxes consists of the following:
		2013			2012
	Canadian operations	$	19,687		$	12,251
	U.S. operations	40,962			(5,715		)
		$	60,649		$	6,536
	As a result of the business combination transaction in 2009, APUC recorded certain additional tax attributes. These tax attributes have been recognized to the extent management believes they are more likely than not to be realized. The excess of the carrying amount of the tax attributes recorded over the consideration was recorded as a deferred credit of $55,647 on the transaction date. The deferred credit is being recognized in income as a deferred income tax recovery in relative proportion to the amount of the related tax attributes that are utilized in the period.
	Income tax expense (recovery) attributable to income/(loss) consists of:
		Current			Deferred			Total
	Year ended December 31, 2013
	Canada	$	1,532		$	881		$	2,413
	United States	994			5,748			6,742
		$	2,526		$	6,629		$	9,155
	Year ended December 31, 2012
	Canada	$	127		$	(938	)	$	(811	)
	United States	611			(14,167		)	(13,556		)
		$	738		$	(15,105	)	$	(14,367	)
	19	Income taxes (continued)
	The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are presented below:
		2013			2012
	Deferred tax assets:
	Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	226,314		$	184,845
	Pension and OPEB	31,433			5,011
	Acquisition related costs	5,152			5,134
	Outside basis in partnership	—			2,533
	Regulatory accounts	—			4,013
	Financial derivatives	—			211
	Environmental obligation	23,076			22,414
	Production tax credit	1,633			673
	Reserves not currently deductible	2,397			1,276
	Other	2,780			136
	Total deferred income tax assets	292,785			226,246
	Less: Valuation allowance	(15,667		)	(15,062		)
	Total deferred tax assets	277,118			211,184
	Deferred tax liabilities:
	Property, plant and equipment	(267,344		)	(219,573		)
	Intangible assets	(8,321		)	(5,478		)
	Outside basis in partnership	(2,210		)	—
	Regulatory accounts	(24,745		)	—
	Financial derivatives	(7,675		)	—
	Total deferred tax liabilities	(310,295		)	(225,051		)
	Net deferred tax assets/(liabilities)	$	(33,177	)	$	(13,867	)
	The valuation allowance for deferred tax assets as of December 31, 2013 was $(15,667) (2012 $(15,062)). The valuation allowance at December 31, 2013 was primarily related 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 carry back and carry forward periods), projected future taxable income, and tax-planning strategies in making this assessment.
	Deferred income taxes are classified in the financial statements as:
		2013			2012
	Current deferred income tax asset	$	19,652		$	10,567
	Non-current deferred income tax asset	86,632			77,497
	Current deferred income tax liability	(2,308		)	(1,133		)
	Non-current deferred income tax liability	(137,153		)	(100,798		)
		$	(33,177	)	$	(13,867	)
	19	Income taxes (continued)
As at December 31, 2013, the Company had non-capital losses carry forwards available to reduce future year’s taxable income, which expire as follows:
Year of expiry	Non-capital loss carry forwards
2015	$	5,426
2016 and onwards	463,610
	$	469,036

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Divestitures	'
	Divestitures
	(a)	EFW held for sale
	During the second quarter of 2013, the Company initiated a strategic review of the Company’s business plan and opportunities available for its Energy From Waste (“EFW Thermal Facility”) and Brampton Cogeneration Inc. (“BCI Thermal Facility”).  As a result of the review, the Company decided to sell the facilities. In the second quarter of 2013, the net assets of EFW and BCI were written down to their estimated fair value less cost of sale which resulted in a write down of the net assets of $47,651 before tax, or $35,738 net of tax of $11,913.
	Subsequent to year-end, on February 7, 2014, the Company entered into an agreement to sell EFW and BCI Thermal Facilities. Accordingly, the determination of the fair value of the net assets of EFW and BCI Thermal Facilites was revised to reflect the estimated selling price, which resulted in a further write down of the net assets of $9,200 before tax, or $6,800 net of tax of $2,400 as at December 31, 2013. The transaction is subject to regulatory approvals, and is expected to close in the first half of 2014. The final selling price is also subject to customary closing adjustments.
	(b)	Restatement of 2012 comparatives
	As a result of the designation of EFW and BCI Thermal Facilities as discontinued operations in 2013, the Company is required to reclassify these assets as discontinued operations in the comparative 2012 financial statements.    As a result, the assets, PPE and liabilities have been reclassified to assets held for sale and liabilities held for sale in the 2012 comparative figures.   Similarly, the 2012 comparative statement of operations and statement of cash flows have been reclassified to reflect the earnings and cash flow from these assets as discontinued operations. In addition, the 2012 comparative amounts in notes 5, 8, 9, and 19, have also been reclassed from the amounts previously reported in the prior year to reflect this change.
	(c)	Sale of U.S. Hydro facilities
	On June 29, 2013, APCo sold 9 small U.S. hydroelectric generating facilities that were no longer considered strategic to the ongoing operations of the Company, for gross proceeds of U.S. $23,400 for a gain on sale of U.S. $960, net of tax recovery of U.S. $1,605. The sale of the last small U.S. hydroelectric generating facilities is expected to close in 2014 for U.S. $3,600.
	In August 2012, APCo sold a small U.S. Hydro facility for gross proceeds of $350 for a loss on sale, net of tax of $253.
	20	Divestitures (continued)
	(d)	Results from discontinued operations
	The assets of EFW and BCI Thermal Facilities and the small U.S. hydroelectric facilities are presented as assets held for sale on the consolidated balance sheets and the operating results from these facilities are disclosed as discontinued operations on the consolidated financial statements.
	The summary of operating results and cash flows from discontinued operations for the years ended December 31 is as follows:
		2013			2012 as reported			2012 EFW/BCI adjustments			2012 as reclassed
	Non-regulated energy sales	9,327			2,870			6,800			9,670
	Waste disposal fees	8,160			—			14,288			14,288
	Other and interest income	336			—			(6	)		(6	)
	Operating and administrative expenses	(19,720	)		(3,241	)		(12,544	)		(15,785	)
	Foreign exchange	80			—			—			—
	Depreciation of property, plant and equipment	(2,483	)		(1,279	)		(5,194	)		(6,473	)
	Interest expense	(58	)		(4	)		(317	)		(321	)
	Gain on sale of assets	1,016			—			—			—
	Write-off of accounts receivable	(262	)		—			—			—
	Write-down of long-lived assets	(56,898	)		(253	)		(23	)		(276	)
	Gain/(loss) from discontinued operations, before income taxes	(60,502	)		(1,907	)		3,004			1,097
	Income tax recovery/(expense)	18,491			750			(804	)		(54	)
	Gain/(loss) from discontinued operations, net of income taxes	(42,011	)		(1,157	)		2,200			1,043
	Add:
	Depreciation of property, plant and equipment	2,483			1,279			5,194			6,473
	Write-off of accounts receivable	262			—			—			—
	Write-down of long-lived assets	56,898			253			23			276
	Net proceeds of disposition	22,052			—			—			—
	Contingent liability	(613	)		—			—			—
	Income tax expense/(recovery)	(18,491	)		(750	)		804			54
	Increase/(decrease) in cash and cash equivalents from discontinued operations	20,580			(375	)		8,221			7,846
	20	Divestitures (continued)
	(a)	Results from discontinued operations (continued)
	Assets held-for-sale as at December 31, were as follows:
		2013				2012 as reported				2012 EFW/BCI Adjustments			2012 Reclassed
	Property, plant and equipment	$	21,193			$	24,390			$	76,437		$	100,827
	Accounts receivable and prepaid expenses	2,734				—				2,510			2,510
	Total assets held for sale	$	23,927			$	24,390			$	78,947		$	103,337
	Less current assets held for sale	(23,927		)		(24,390		)		(2,510		)	(26,900		)
	Non-current assets held for sale	$	—			$	—			$	76,437		$	76,437
	Liabilities held-for-sale as at December 31, were as follows:
		2013				2012 as reported				2012 EFW/BCI Adjustments			2012 Reclassed
	Accounts payable and accrued liabilities	$	1,471			$	—			$	1,211		$	1,211

Related_party_transactions

Related party transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related party transactions	'
	21	Related party transactions
	Ian Robertson and Chris Jarratt (“Senior Executives”), respectively Chief Executive Officer and Vice-Chair of APUC are indirect shareholders of Algonquin Power Management Inc. (“APMI”), the former manager of the Company and several related affiliates (collectively the “Parties”). Prior to 2010, there were several related party transactions and co-owned assets which existed pursuant to the external management structure before the internalization of management which occurred on December 21, 2009.
	In 2011, the Board formed an independent committee (“Independent Board Committee”) and initiated a process to review all of the remaining business associations with the Parties in order to reduce and/or eliminate these relationships. The Independent Board Committee engaged independent consultants and advisors to assist with this process and to provide advice in respect thereof. Specifically, the independent advisors provided advice to the Independent Board Committee in relation to the valuations of the generating assets, tax and legal matters.
	The process initiated in 2011 was completed in November 2013 and all related party transactions between APUC and the Parties have been addressed to the satisfaction of the Independent Board Committee and the Board as discussed below.
	The following describes the business associations and resolution with APMI and Senior Executives:
	Due to and from related parties
	As at December 31, 2013, due from related parties include $nil (December 31, 2012 - $816) owed to APUC from the Parties and due to related parties include $nil (December 31, 2012 - $1,811) owed to the Parties.
	Prior to 2010, APMI was the manager of Algonquin Power Income Fund (“APIF”); the predecessor organization to APUC; and at the time of the internalization of management, had a number of fees under negotiation as described below:
	•	APMI was a one of the original developers of the Red Lily I wind project and was entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of Red Lily I.  In 2011, APUC acquired APMI’s interest in this royalty.
	•	As part of the project to re-power the Sanger Thermal Facility in 2008, APUC entered into an agreement with APMI to undertake certain construction management services on the project for a performance based contingency fee.
	21	Related party transactions (continued)
	Due to and from related parties (continued)
	•	During 2007, APUC allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee for which APMI was entitled to a portion thereof.
	•	During 2008, APMI provided construction supervision services for the construction of the BCI and was entitled to a construction supervision fee on the BCI project.
	•	As manager of APIF, APMI was entitled to management fees pursuant to a management agreement and the 2009 Q4 management fee was not made to APMI. In addition, pursuant to the management agreement, APMI incurred and was entitled to reimbursement of reasonable expenses in 2009 which was also not reimbursed by APUC.
	Effective December 31, 2013, APUC paid the Parties $1,829 in connection with outstanding fees and the Parties paid APUC $812 in connection with reimbursement of expenses both in full satisfaction of the related party balances.
	Equity interests in Rattle Brook, Long Sault, BCI
	The Parties own interests in three power generation facilities in which APUC also has an interest in. A brief description of the facilities is provided as follows:
	•	Rattle Brook is a 4 MW hydroelectric generating facility (“Rattle Brook”) constructed in 1998 in which APUC owns a 45% interest and Senior Executives hold an equity interest in the remaining 55%.
	•	Long Sault Hydro Facility is an 18MW hydroelectric generating facility constructed in 1997. APUC acquired its interest in Long Sault by way of subscribing to two notes from the original partners. One of the original partners; an affiliate of APMI; is entitled to receive 5% of the equity cash flows commencing in 2014.
	•	Brampton Cogeneration is an energy supply facility which sells steam produced by EFW.  In 2004, APMI acquired 50 Class B partnership units in BCI entitling them to 50% of the cash flow above 15% return on the investment.
	Effective December 31, 2013, APUC acquired the Parties’ shares of Algonquin Power Corporation Inc. ("APC") which owns the partnership interest in the 18MW Long Sault Rapids hydroelectric facility and the partnership interest in the Brampton cogeneration plant for an amount equal to $3,780. As APUC already consolidates Long Sault as a VIE, the acquisition of this partnership interest was treated as an equity transaction. The payment resulted in an adjustment to deferred tax liability of $10,692 in regards to tax attributes acquired with the partnership interests and an adjustment of $14,601 to equity of the shareholders of the Company as the partnership interests had a nominal carrying amount prior to the exchange.
	In addition, APUC sold its 45% interest in the 4MW Rattle Brook hydroelectric facility to the Parties for gross proceeds $3,408 for a loss on sale, net of tax of $422.
	APUC earned a fee of $400 from APC during the year ended December 31, 2013 (2012 -$nil) related to settlement of the related party transactions.
	St Leon LP Units
	Third party investors, including Senior Executives previously held 100 Class B limited partnership units issued by the St. Leon Limited Partnership which is the legal owner of the St. Leon Wind Facility.  The Class B units held by Senior Executives received cash distributions of $nil for the year ended December 31, 2013 (2012 - $175).
	On January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the 100 Class B units (note 10) including 36 units held indirectly by Senior Management. The Series C preferred shares provide dividends identical to what is expected from the Class B units, as determined by independent consultants retained by the Independent Board Committee. As of January 1, 2013, no Senior Executives have any further direct or indirect ownership of the St. Leon Wind Facility.
	Office Facilities
	APUC has leased its head office facilities since 2001 on a triple net basis from an entity partially owned by the Senior Executives. Base lease costs for the year ended December 31, 2013 were $310 (2012 ‑ $333). The current office lease for a portion of its head office facilities expires on December 31, 2015. Subsequent to year-end, on January 31, 2014, APUC, through a wholly owned subsidiary, acquired from a third party a new office facility (note 5) which is suitable for meeting the future head office needs of APUC. Upon occupancy of the new head office facilities which is anticipated to occur in 2014, it is expected that the currently occupied premises will be subleased to third parties.
	21	Related party transactions (continued)
	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 an agreement to charter aircraft in which the Senior Executives have a partial ownership. In 2004 APUC remitted $1,300 to an affiliate of APMI as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. By the end of 2012 the entire advance had been amortized against expense reimbursements and therefore no amortization expense for the year ended December 31, 2013 related to the advance was incurred (2012 - $279). During the year ended December 31, 2013, APUC reimbursed direct costs in connection with the use of the aircraft of $472 (2012 ‑ $598). As of December 31, 2013, the remaining amount of the advance was $nil (December 31, 2012 - $nil) and as a result the Independent Board Committee is satisfied that the advance arrangement has concluded. The Independent Board Committee and the Parties have agreed that all future utilization of chartered aircraft will be undertaken through third party charter operators at fair market value and under arrangements in which the Senior Executives  have no interest.
	Operations Services
	APUC provided supervisory services on a cost recovery basis for one small hydroelectric generating facility where Senior Executives hold an equity interest. The fees paid in relation to the supervisory management services were nominal for the years ended December 31, 2013 and 2012. This agreement terminated on December 31, 2013.
	Trafalgar
	APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”).  In 1997, Trafalgar went into default under its debt obligations and an affiliate of APMI moved to foreclose on the assets.  Subsequently Trafalgar went into bankruptcy.  APUC and the affiliate of APMI have been jointly involved in litigation and in bankruptcy proceedings with Trafalgar since 2004.  APMI initially funded $2 million in legal fees prior to 2004.
	In 2004, the Board reimbursed APMI $1 million of the total third party legal fees (which to that point totalled $2 million), and APUC agreed to fund future legal fees, third party costs and other liabilities. It was agreed that any net proceeds from the lawsuits would be shared proportionally to the quantum of net costs funded by each party.
	Other Related Party Transactions
	A member of the Board of Directors of APUC is an executive at Emera. Related Party Transactions between APUC and Emera are discussed in the section below titled “Transactions with Emera”.
	An individual related to an executive of APUC provided market research consulting services to certain subsidiaries of Liberty Utilities. Related Party Transactions between Liberty Utilities and the consultant are discussed in the section below titled “Other”.
	Transactions with Emera
	•	For the year ended December 31, 2013, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $6,042 (2012 - U.S. $6,096 ). In 2011, APUC provided a corporate guarantee to MPS in an amount of U.S. $3,000 and a letter of credit in an amount of U.S. $100, primarily in conjunction with a three year contract to provide standard offer service to commercial and industrial customers in Northern Maine.
	•	In 2011, APUC provided a corporate guarantee in an amount of U.S. $1,000 to a subsidiary of Emera providing lead market participant services for fuel capacity and forward reserve markets to ISO NE for the Windsor Locks facility. There has not been any transaction under this contract in the last two years.
	The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.
	Other
	An individual related to an executive of APUC provided market research consulting services to certain subsidiaries of Liberty Utilities. During the year ended December 31, 2013 APUC paid $29 (2012 -$nil) in relation to these services.

Basic_and_diluted_net_earnings

Basic and diluted net earnings per share	12 Months Ended
	Dec. 31, 2013
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 outstanding during the year. Diluted net income per share is computed using the weighted-average number of common shares and, if dilutive, potential common shares outstanding during the period. Potential common shares consist of the incremental common shares issuable upon the exercise of stock options, PSUs, DSUs, shareholders’ rights and convertible debentures. The dilutive effect of outstanding stock options, PSUs, DSUs and shareholders’ rights is reflected in diluted earnings per share by application of the treasury stock method while the dilutive effect of convertible debentures is reflected in diluted earnings per share by application of the as if converted method.
	The reconciliation of the net income and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:
		2013			2012
	Net earnings attributable to shareholders of APUC	$	20,296		$	14,532
	Series A preferred shares dividend	5,400			769
	Net earnings attributable to common shareholders of APUC	$	14,896		$	13,763
	Discontinued operations	$	(42,011	)	$	1,043
	Net earnings attributable to common shareholders of APUC from continuing operations - Basic and Diluted	$	56,907		$	12,720
	Weighted average number of shares
	Basic	204,350,689			158,304,340
	Dilutive effect of share-based awards	980,697			605,281
	Diluted	205,331,386			158,909,621
	The shares potentially issuable as a result of the convertible debentures as well as stock options of 885,418 respectively (2012 – 1,354,531) are excluded from this calculation as they are anti-dilutive.

Commitments_and_contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2013
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 financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
	i)	On October 21, 2011 the Québec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (including interest) to the government of Québec 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 $6,000. In 2012, the Company paid an amount of $1,884 to the government of Québec 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.
	ii)	The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency, the New Hampshire Department of Environmental Services and the Massachusetts Department of Environmental Protection.
	23	Commitments and contingencies (continued)
	(a)	Contingencies (continued)
	ii)	Like most other industrial companies, the gas and electric distribution utilities generate some hazardous wastes. Under federal and state laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred. In the case of regulated utilities these costs are often allowed in rate case proceedings to be recovered from rate payers over a specified period.
	Prior to their acquisition by Liberty Utilities, 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 believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.
	The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $77,729 which at discount rates ranging from 3.8% to 4.5% represents the recorded accrual of $69,555 at December 31, 2013 (December 31, 2012 - $57,340). Following resolution of certain environmental liabilities subsequent to year-end, the remaining undiscounted, unescalated costs of these MGP-related environmental cleanup activities should be reduced by $4,200 with a corresponding reduction to the related regulatory asset.
	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, at December 31, 2013 the Company has reflected a regulatory asset of $80,438 (December 31, 2012 - $59,789) for the MGP and related sites (note 7(a)).
	Estimated cash flows for site investigation and remediation costs in the next five years and thereafter are as follows:
	2014	$	10,111
	2015	27,285
	2016	17,873
	2017	2,128
	2018	1,784
	Thereafter to 2046	18,548
		$	77,729
	(b)	Commitments
	In addition to the commitments related to the proposed acquisitions disclosed in note 3 the following significant commitments exist at December 31, 2013.
	As a result of the dam safety legislation passed in Quebec (Bill C93), 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 15,400 over a period of five years related to compliance with the legislation.
	23	Commitments and contingencies (continued)
	(b)	Commitments (continued)
	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
	Purchased power	$	64,626	$	46,865	$	—	$	—	$	—	$	—	$	111,491
	Gas delivery, service and supply agreements	42,125		26,364		13,812		9,869		9,476		54,495		156,141
	Service agreements	24,130		24,371		28,922		29,639		27,897		498,342		633,301
	Capital projects	49,337		2,260		—		—		—		—		51,597
	Operating leases	5,125		4,551		3,944		3,733		3,551		85,213		106,117
	Total	$	185,343	$	104,411	$	46,678	$	43,241	$	40,924	$	638,050	$	1,058,647
	Calpeco Electric System has entered into a five year all-purpose power purchase agreement with NV Energy to provide its full electric requirements at NV Energy’s “system average cost” rates. The PPA has an effective starting date of January 1, 2011 with a five year renewal option. The commitment amounts included in the table above are based on market prices as of December 31, 2013. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. Granite State Electric System has several types of contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.
	Subsequent to year-end on March 11, 2014, APCo entered into a Turbine Supply Agreement with a counterparty with respect to the Morse Wind Project. Amounts related to this contract are included in the above table.

Noncash_operating_items

Non-cash operating items	12 Months Ended
	Dec. 31, 2013
Disclosure Changes In Non Cash Operating Items [Abstract]	'
Non-cash operating items	'
	Non-cash operating items
	The changes in non-cash operating items from discontinued operations is comprised of the following:
		2013			2012
	Accounts receivable	$	(213	)	$	(313	)
	Prepaid expenses	(11		)	135
	Accrued liabilities	260			(230		)
		$	36		$	(408	)
	The changes in non-cash operating items is comprised of the following:
		2013			2012
	Accounts receivable	$	(49,888	)	$	(14,582	)
	Related party balances	(996		)	1,476
	Natural gas inventory	(6,330		)	—
	Supplies and consumable inventory	(525		)	(3,621		)
	Income tax receivable	177			(423		)
	Prepaid expenses	(485		)	(4,764		)
	Accounts payable	(29,292		)	(7,553		)
	Accrued liabilities	37,023			31,335
	Current income tax liability	1,399			131
	Net regulatory assets and liabilities	1,098			(5,475		)
		$	(47,819	)	$	(3,476	)

Segmented_information

Segmented information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segmented information	'
	Segmented information
	APUC has two business units: APCo which owns or has interests in renewable energy facilities and thermal energy facilities and Liberty Utilities which owns and operates utilities in the United States of America providing water, wastewater and local electric and natural gas distribution services.
	Within APCo there are two operating segments: Renewable Energy and Thermal Energy. The Renewable Energy division operates the Company’s hydro-electric and wind power facilities. The Thermal Energy division operates co-generation, energy from waste, steam production and other thermal facilities.
	Within Liberty Utilities there are the following operating segments: Liberty Utilities (West), Liberty Utilities (Central) and Liberty Utilities (East). Liberty Utilities (West) is comprised of Calpeco Electric System and the water distribution and wastewater utilities located in Arizona. Liberty Utilities (Central) is comprised of the Midwest Gas System and the water distribution and wastewater utilities located in Texas, Missouri and Illinois. Liberty Utilities (East) is comprised of the New Hampshire Electric and Gas Systems, Peach State Gas Gystem and New England Gas System.
	The development activities of APCo are reported under Renewable Energy or Thermal Energy as appropriate. 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 derivatives 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 as follows:
	Operational segments (continued)
		Year ended December 31, 2013
		Algonquin Power									Liberty Utilities												Corporate			Total
		Renewable			Thermal			Total			Central			West			East			Total
		Energy			Energy
	Revenue
	Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	77,814		$	88,342		$	166,156		$	—		$	166,156
	Regulated gas sales and distribution	—			—			—			78,857			—			182,815			261,672			—			261,672
	Regulated water reclamation and distribution	—			—			—			18,242			39,108			—			57,350			—			57,350
	Non-regulated energy sales	145,661			34,530			180,191			—			—			—			—			—			180,191
	Other revenue	7,058			2,442			9,500			—			22			—			22			400			9,922
	Total revenue	152,719			36,972			189,691			97,099			116,944			271,157			485,200			400			675,291
	Operating expenses	48,966			8,514			57,480			27,455			36,753			67,264			131,472			—			188,952
	Regulated electricity purchased	—			—			—			—			39,750			57,626			97,376			—			97,376
	Regulated gas purchased	—			—			—			46,018			—			102,766			148,784			—			148,784
	Non-regulated fuel for generation	—			17,151			17,151			—			—			—			—			—			17,151
		103,753			11,307			115,060			23,626			40,441			43,501			107,568			400			223,028
	Depreciation of property, plant and equipment	(45,122		)	(5,439		)	(50,561		)	(9,096		)	(13,596		)	(18,725		)	(41,417		)	—			(91,978		)
	Amortization of intangible assets	(2,652		)	(856		)	(3,508		)	(81		)	(611		)	—			(692		)	—			(4,200		)
	Administration expenses	(13,094		)	(223		)	(13,317		)	(1,677		)	(2,541		)	(3,259		)	(7,477		)	(2,724		)	(23,518		)
	Foreign exchange gain	—			—			—			—			—			—			—			567			567
	Interest expense	(27,391		)	(1,046		)	(28,437		)	(5,069		)	(8,519		)	(10,146		)	(23,734		)	(1,174		)	(53,345		)
	Interest, dividend and other income	1,867			193			2,060			375			1,395			1,458			3,228			2,497			7,785
	Loss on sale of asset	(750		)	—			(750		)	—			—			—			—			—			(750		)
	Acquisition related costs	(628		)	—			(628		)	(68		)	—			(1,444		)	(1,512		)	—			(2,140		)
	Gain/(loss) on derivative financial instruments	(767		)	—			(767		)	—			—			—			—			5,967			5,200
	Earnings from continuing operations before income taxes	15,216			3,936			19,152			8,010			16,569			11,385			35,964			5,533			60,649
	Loss from discontinued operations before income taxes	1,128			(61,630		)	(60,502		)	—			—			—			—			—			(60,502		)
	Earnings/(loss) before income taxes	$	16,344		$	(57,694	)	$	(41,350	)	$	8,010		$	16,569		$	11,385		$	35,964		$	5,533		$	147
	Property, plant and equipment	$	1,364,843		$	79,828		$	1,444,671		$	215,090		$	387,715		$	661,228		$	1,264,033		$	—		$	2,708,704
	Intangible assets	26,802			5,698			32,500			2,709			19,207			—			21,916			—			54,416
	Total Assets held for sale	3,860			20,067			23,927			—			—			—			—			—			23,927
	Total assets	1,492,144			116,922			1,609,066			285,517			460,209			923,981			1,669,707			193,784			3,472,557
	Capital expenditures	46,885			2,631			49,516			28,566			23,743			56,552			108,861			—			158,377
	Acquisition of operating entities	2,083			—			2,083			27,545			—			209,386			236,931			—			239,014
	25	Segmented information (continued)
	Operational segments (continued)
		Year ended December 31, 2012
		Algonquin Power									Liberty Utilities												Corporate			Total
		Renewable			Thermal			Total			Central			West			East			Total
		Energy			Energy
	Revenue
	Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	71,734		$	36,723		$	108,457		$	—		$	108,457
	Regulated gas sales and distribution	—			—			—			25,802			—			49,916			75,718			—			75,718
	Regulated water reclamation and distribution	—			—			—			9,127			37,296			—			46,423			—			46,423
	Non-regulated energy sales	84,236			30,115			114,351			—			—			—			—			—			114,351
	Other revenue	1,925			1,686			3,611			—			152			94			246			—			3,857
	Total revenue	86,161			31,801			117,962			34,929			109,182			86,733			230,844			—			348,806
	Operating expenses	30,308			8,568			38,876			13,096			35,645			30,209			78,950			—			117,826
	Regulated electricity purchased	—			—			—			—			43,861			24,348			68,209			—			68,209
	Regulated gas purchased	—			—			—			13,648			—			23,813			37,461			—			37,461
	Non-regulated fuel for generation	—			14,589			14,589			—			—			—			—			—			14,589
		55,853			8,644			64,497			8,185			29,676			8,363			46,224			—			110,721
	Depreciation of property, plant and equipment	(18,823		)	(4,782		)	(23,605		)	(3,333		)	(11,120		)	(7,129		)	(21,582		)	—			(45,187		)
	Amortization of intangible assets	(2,653		)	(831		)	(3,484		)	(81		)	(586		)	—			(667		)	—			(4,151		)
	Administration expenses	(9,424		)	(2,176		)	(11,600		)	294			(4,091		)	(1,223		)	(5,020		)	(2,952		)	(19,572		)
	Foreign exchange gain	—			—			—			—			—			—			—			561			561
Interest expense	(15,060		)	(1,733		)	(16,793		)	(96		)	(8,066		)	(694		)	(8,856		)	(9,971		)	(35,620		)
Interest, dividend and other income	2,038			509			2,547			—			2,113			461			2,574			2,118			7,239
Acquisition related costs	(3,155		)	21			(3,134		)	(1,442		)	—			(3,112		)	(4,554		)	—			(7,688		)
Gain/(loss) on derivative financial instruments	(2,954		)	—			(2,954		)	—			—			—			—			3,187			233
Earnings from continuing operations before income taxes	5,822			(348		)	5,474			3,527			7,926			(3,334		)	8,119			(7,057		)	6,536
Loss from discontinued operations before income taxes	(1,925		)	3,022			1,097			—			—			—			—			—			1,097
Earnings/(loss) before income taxes	$	3,897		$	2,674		$	6,571		$	3,527		$	7,926		$	(3,334	)	$	8,119		$	(7,057	)	$	7,633
Property, plant and equipment	$	1,157,062		$	77,438		$	1,234,500		$	151,637		$	350,053		$	350,088		$	851,778		$	—		$	2,086,278
Intangible assets	29,480			6,132			35,612			2,613			18,556			—			21,169			—			56,781
Total Assets held for sale	24,390			78,947			103,337			—			—			—			—			—			103,337
Total assets	1,272,037			175,926			1,447,963			212,495			464,201			500,374			1,177,070			153,957			2,778,990
Capital expenditures	21,068			10,348			31,416			10,777			23,181			12,488			46,446			67			77,929
Acquisition of operating entities	245,718			—			245,718			128,890			—			295,297			424,187			—			669,905
25	Segmented information (continued)
Operational segments (continued)
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 2013 or 2012: Hydro Québec 14% (2012 - 17%), Manitoba Hydro 14% (2012 – 20%), and California PG&E 9% (2012 - 10%). The Company has mitigated its credit risk to the extent possible by selling energy to these large utilities in various North American locations.
APUC and its subsidiaries operate in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows:
	2013			2012
Revenue
Canada	$	65,380		$	62,036
United States	609,911			286,770
	$	675,291		$	348,806
Property, plant and equipment
Canada	$	433,153		$	395,896
United States	2,275,551			1,690,382
	$	2,708,704		$	2,086,278
Intangible assets
Canada	$	26,802		$	29,480
United States	27,614			27,301
	$	54,416		$	56,781
Revenues are attributed to the two countries based on the location of the underlying generating and utility facilities.

Financial_instruments

Financial instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial instruments	'
	Financial instruments
	(a)	Fair value of financial instruments
	2013	Carrying			Fair			Level 1			Level 2		Level 3
		amount			Value
	Notes receivable	$	22,678		$	26,321		$	—		$	—	$	26,321
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	31,971			31,971			—			—		31,971
	Energy contracts not designated as a cashflow hedge	3,737			3,737			—			—		3,737
	Cross-currency swap designated as a foreign exchange hedge	109			109			—			109		—
	Commodity contracts for regulated operations	482			482			—			482		—
	Total derivative financial instruments	36,299			36,299			—			591		35,708
	Total financial assets	$	58,977		$	62,620		$	—		$	591	$	62,029
	Long-term liabilities	$	1,255,588		$	1,261,340		$	296,986		$	964,354	$	—
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	4,781			4,781			—			—		4,781
	Cross-currency swap designated as a foreign exchange hedge	7,947			7,947			—			7,947		—
	Interest rate swaps not designated as a hedge	3,180			3,180			—			3,180		—
	Commodity contracts for regulated operations	313			313			—			313		—
	Total derivative financial instruments	16,221			16,221			—			11,440		4,781
	Total financial liabilities	$	1,271,809		$	1,277,561		$	296,986		$	975,794	$	4,781
	26	Financial instruments
	(a)Fair value of financial instruments
	2012	Carrying			Fair			Level 1			Level 2		Level 3
		amount			Value
	Notes receivable	$	22,757		$	25,476		$	—		$	—	$	25,476
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	12,695			12,695			—			—		12,695
	Cross-currency swap designated as a foreign exchange hedge	408			408			—			408		—
	Commodity contracts for regulatory operations	147			147			—			147		—
	Total derivative financial instruments	13,250			13,250			—			555		12,695
	Total financial assets	$	36,007		$	38,726		$	—		$	555	$	38,171
	Long-term liabilities	$	770,826		$	785,473		$	293,348		$	492,125	$	—
	Convertible debentures	960			1,319			1,319			—		—
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	9,012			9,012			—			—		9,012
	Cross-currency swap designated as a foreign exchange hedge	2,078			2,078			—			2,078		—
	Interest rate swaps not designated as a hedge	4,778			4,778			—			4,778		—
	Energy derivative contracts	287			287			—					287
	Commodity contracts for regulated operations	1,661			1,661			—			1,661		—
	Total derivative financial instruments	17,816			17,816			—			8,517		9,299
	Total financial liabilities	$	789,602		$	804,608		$	294,667		$	500,642	$	9,299
	26	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 (a level 2 measurement) at December 31, 2013 and 2012 due to the short-term maturity of these instruments.
	Notes receivable fair values 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. Such estimate is significantly influenced by unobservable data and therefore this fair value is subject to estimation risk.
	APUC has long-term liabilities at fixed interest rates and variable rates. The estimated fair value is calculated using current interest rates. The fair value of convertible debentures is determined using quoted market price.
	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 Red Lily conversion option is measured at fair value on a recurring basis using unobservable inputs (Level 3). The fair value is based on an income approach using an option pricing model that includes various inputs such as energy yield function from wind, estimated cash flows and a discount rate of 8.5%. The Company used a discount rate believed to be most relevant given the business strategy. There was no change in fair value of $nil during the years ended December 31, 2013 or 2012.
	The Company’s Level 3 instruments consist of energy contracts for energy sales. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from USD $21.5 to $181 as of December 31, 2013.  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 are detailed in notes 26(b)(ii) and 26(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, 2013 or 2012.
	(b)	Derivative instruments
	Derivative instruments are recognized on the balance sheet as either assets or liabilities and measured at fair value each reporting period.
	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 sales prices to regulated customers. The accounting for these derivative instruments is subject to current 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 accompanying balance sheets. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7 (d)).
	26	Financial instruments (continued)
	(b)	Derivative instruments (continued)
	(i)	Commodity derivatives – regulated accounting (continued)
	The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:
		2013
	Financial contracts: Gas swaps	2,734,304
	Gas options	2,082,104
		4,816,408
The change in fair value of the derivative instruments is recorded as an offsetting adjustment to regulatory assets and liabilities. 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. The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the accompanying balance sheets:
	2013			2012
Regulatory assets:
Gas swap contracts	$	86		$	1,555
Gas option contracts	$	208		$	106
Regulatory liabilities:
Gas swap contracts	$	416		$	90
Gas option contracts	$	37		$	57
(ii)	Cash flow hedges
APCo 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			Expiry	Receive average				Pay floating price
(MW-hrs)				prices (per MW-hr)				(per MW-hr)
Energy delivered less existing swap			December 2014	U.S. $		32.64		PJM Western HUB
Energy delivered less existing swap			December 2014	U.S. $		25.64		NI HUB
Energy delivered less existing swap			December 2014	U.S. $		27.39		ERCOT North HUB
147,199			December 2016	$		67.36		AESO
1,029,732			December 2022	U.S. $		42.81		PJM Western HUB
4,395,665			December 2022	U.S. $		30.25		NI HUB
4,663,097			December 2027	U.S. $		36.46		ERCOT North HUB
As at December 31, 2013, an amount receivable under the derivatives for Sandy Ridge, Senate and Minonk Wind Facilities of $7,344 (2012 - $nil) was held as collateral by the counterparty.
The effects on the consolidated statements of operations of derivative financial instruments designated as cash flow hedge consist of the following:
	2013			2012
Gain on derivative instruments (ineffective portion)	$	1,304		$	105
26	Financial instruments (continued)
(b)	Derivative instruments (continued)
(ii)	Cash flow hedges (continued)
The following table summarizes changes in other comprehensive income attributable to derivative financial instruments designated as a hedge:
	2013			2012
Effective portion of cash flow hedge, gain	$	17,338		$	5,217
Gain (loss) realized on cash flow hedge	(30		)	(49		)
	$	17,308		$	5,168
Less noncontrolling interest	(9,064		)	(1,572		)
Change in fair value of cash flow hedge in other comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	8,244		$	3,596
The Company expects $4,949 of unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within the next twelve months, as the underlying hedged transactions settle.
(iii)	Foreign exchange hedge of net investment in foreign operation
The Company periodically uses a combination of foreign exchange forward contracts and spot purchases to manage its foreign exchange exposure on cash flows generated from the U.S. operations. 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.
Concurrent with its $150,000 debentures offering in December 2012, APCo entered into a cross currency swap, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. APCo designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term USD payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in APCo’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 USD 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 other comprehensive income) related to the net investment. A foreign currency loss of $5,771 was recorded in other comprehensive income in 2013.
(iv)	Other derivatives
APCo provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Assets 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.
Notional quantity			Expiry	Receive average				Net Asset
(MW-hrs)				prices (per MW-hr)
19,440			Feb-14	U.S. $		61.4		$	1,833
69,154			Mar-15	U.S. $		48.83		1,729
26	Financial instruments (continued)
(b)	Derivative instruments (continued)
(iv)	Other derivatives (continued)
For derivatives that are not designated as cash flow hedges, and for the ineffective portion of gains and losses on derivatives that are accounted as hedges the changes in the fair value are immediately recognized in earnings.
The effects on the statement of operations of derivative financial instruments not designated as hedges consist of the following:
	2013			2012
Change in unrealized loss/(gain) on derivative financial instruments:
Interest rate swaps	$	(1,598	)	$	(2,197	)
Energy derivative contracts	(3,809		)	(825		)
Total change in unrealized loss/(gain) on derivative financial instruments	$	(5,407	)	$	(3,022	)
Realized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	—		$	(187	)
Interest rate swaps	2,024			2,094
Energy derivative contracts	(466		)	987
Total realized loss on derivative financial instruments	$	1,558		$	2,894
Loss/(gain) on derivative financial instruments accounted for as hedges	$	(3,849	)	$	(128	)
Ineffective portion of derivatives financial instruments accounted for as hedges	$	(1,351	)	(105		)
Gain on derivative financial instruments	$	(5,200	)	$	(233	)
(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 to mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes.
This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk, liquidity risk, foreign currency risk and interest rate 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 and notes receivable. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders in Canada all of which have a credit rating of A or better. The Company does not consider the risk associated with 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.
26	Financial instruments (continued)
(c)	Risk management (continued)
The remaining revenue is primarily earned by the Utility Services business unit which consists of water and wastewater utilities, electric utilities and gas utilities in the United States. In this regard, the credit risk related to Utility Services accounts receivable balances of U.S. $101,867 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 Company’s utilities allow for a reasonable bad debt expense to be incorporated in the rates and therefore ultimately recoverable from rate payers.
As at December 31, 2013 the Company’s maximum exposure to credit risk for these financial instruments was as follows:
	December 31, 2013
	Canadian $			US $
Cash and cash equivalents and restricted cash	$	3,465		$	15,415
Accounts receivable	18,948			137,481
Allowance for Doubtful Accounts	—			(7,955		)
Notes Receivable	20,529			2,021
	$	42,942		$	146,962
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 assess each counterparty’s ability to perform on the transactions set forth in the contracts.
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 at December 31, 2013, in addition to cash on hand of $13,839 the Company had $202,665 available to be drawn on its senior debt facilities. The senior credit facilities contain covenants which may limit amounts available to be drawn.
26	Financial instruments (continued)
(c)	Risk management (continued)
The Company’s liabilities mature as follows:
	Due less			Due 2 to 3			Due 4 to 5			Due after		Total
	than 1			years			years			5 years
	year
Long term debt obligations	$	8,339		$	147,076		$	171,907		$	928,266	$	1,255,588
Advances in aid of construction	1,239						—			77,697		78,936
Interest on long term debt	54,804			103,605			89,966			168,448		416,823
Purchase Obligations	156,905						—			—		156,905
Environmental obligation	10,111			45,158			3,912			18,548		77,729
Derivative financial instruments:
Cross- currency swap	—			—			—			7,947		7,947
Interest rate swaps	1,936			1,244			—			—		3,180
Energy derivative and commodity contracts	240			72			—			4,465		4,777
Capital lease payments	125			3,919			—			—		4,044
Other obligations	7,326			—			—			13,809		21,135
Total obligations	$	241,025		$	301,074		$	265,785		$	1,219,180	$	2,027,064
Foreign currency risk
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.
APCo designates the amounts drawn on its bank credit facility denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in APCo’s U.S. operations. The foreign currency transaction gain or loss on the outstanding U.S. dollar denominated balance of APCo’s facility that is designated a hedge of the net investment in its foreign operations is reported in the same manner as a translation adjustment (in other comprehensive income) related to the net investment, to the extent it is effective as a hedge. A foreign currency loss of $1,607 was recorded in other comprehensive income.
Interest rate risk
The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, including certain project specific debt and its revolving credit facility, its interest rate swaps as well as interest earned on its cash on hand. The Company does not currently hedge that risk.
APCo is party to an interest rate swap whereby, the Company pays a fixed interest rate of 4.47% on a notional amount of $62,706 and receives floating interest at 90 day CDOR, up to the expiry of the swap in September 2015. At December 31, 2013, the estimated fair value of the interest rate swap was a liability of $3,180 (2012 – liability of $4,778). This interest rate swap is not being accounted for as a hedge and consequently, changes in fair value are recorded in earnings as they occur.

Comparative_figures

Comparative figures	12 Months Ended
	Dec. 31, 2013
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_policie1

Significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of preparation	'
	(a)	Basis of preparation
	The accompanying consolidated financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosures required under Regulation S-X provided by the Securities and Exchange Commission (“SEC”).
Basis of consolidation	'
	(b)	Basis of consolidation
	The accompanying consolidated financial statements of APUC include the accounts of APUC and its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary. Intercompany transactions and balances have been eliminated.
Accounting for rate regulated operations	'
	(c)	Accounting for rate regulated operations
	The regulated utility operating companies owned by Liberty Utilities are subject to rate regulation generally overseen by the public utility commissions 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 ASC Topic 980 Regulated Operations (“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 revenues 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 Assets & Liabilities 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 (credit) against income for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations.
	The electric and gas utilities’ and the 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, respectively.
Cash and cash equivalents	'
	(d)	Cash and cash equivalents
	Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
Restricted cash	'
	(e)	Restricted cash
	Restricted cash represent 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 13) in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.
Accounts receivable	'
	(f)	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.
Gas in storage	'
	(g)	Gas in storage
	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. Existing rate orders allow the Company to pass through the cost of gas purchased directly to the rate payers 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 (note 7).
Supplies and consumables inventory	'
	(h)	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.
Property, plant and equipment	'
	(i)	Property, plant and equipment:
	Property, plant and equipment, consisting of renewable and thermal generation assets, electrical, gas, water and wastewater distribution assets, equipment and land, are recorded at cost. 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 equity funds used during construction (“AFUDC”) for regulated property. 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 (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). 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. 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 and other income on the consolidated statements of operations.
		2013			2012
	Interest capitalized on non-regulated property	$	669		$	1,036
	AFUDC capitalized on regulated property:
	Allowance for borrowed funds	1,055			628
	Allowance for equity funds	1,786			1,108
	Total	$	3,510		$	2,772
	Improvements that increase or prolong the service life or capacity of an asset are capitalized. Maintenance and repair costs are expensed as incurred.
	1	Significant accounting policies (continued)
	(i)	Property, plant and equipment (continued)
	Investment tax credits and government grants 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. Contributions in aid of construction represent amounts contributed by customers and governments and developers for the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 1(o)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.
	The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method. The range of estimated useful lives and the weighted average useful lives are summarized below:
		Range of useful lives			Weighted average
					useful lives
		2013		2012	2013		2012
	Generation
	Renewable	3 – 60		3 – 60	35		32
	Thermal	3 – 40		3 – 40	24		23
	Distribution
	Gas	5 – 80		5 – 80	38		38
	Electrical	8 – 75		8 – 75	41		42
	Water & wastewater	5 – 50		5 – 50	39		25
	Equipment	5 – 50		5 – 50	24		21
	In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of Liberty Utilities 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 operation 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.
Intangibles	'
	(j)	Intangibles
	The fair value of power sales contracts acquired in business combinations are amortized on a straight-line basis over the remaining term of the contract. These periods range from 6 to 25 years from date of acquisition.
	Customer relationships acquired in business combinations are amortized on a straight-line basis over their estimated life of 40 years.
Goodwill	'
	(k)	Goodwill
	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.
	The Company annually assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit 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, 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.
Impairment of long-lived assets	'
	(l)	Impairment of long-lived assets
	APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
	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 the 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	'
	(m)	Variable interest entities
	The Company performs analyses to assess whether its operations and investments represent variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated.
	Long Sault is a hydroelectric generating facility in which APUC acquired an interest by way of subscribing to two notes from the original developers. The notes receivable effectively provide APUC the right to 65% after tax cash flows of the facility from 2014 to 2027 and 58% thereafter. The Company also has the right to acquire 58% of the equity in the facility at the end of the term of the notes in 2038.  Effective December 31, 2013, APUC acquired an equity interest in Long Sault (note 21). APUC has determined that the facility is a VIE since the Company is the primary beneficiary and therefore the Long Sault entity is subject to consolidation by the Company. Total net book value of generating assets and long-term debt of Long Sault amounts to $44,319 (2012 - $42,566) and to $37,143 (2012 - $38,136), respectively. The Long Sault debt only has recourse over the Long Sault generating assets. The financial performance of Long Sault reflected on the statement of operations includes non-regulated energy sales of $10,155 (2012 - $8,747), operating expenses and amortization of $2,391 (2012 - $2,728) and interest expense of $3,632 (2012 - $3,929).
Long-term investments and notes receivable	'
	(n)	Long-term investments and notes receivable
	Investments in which APUC has significant influence but are not controlled are accounted using the equity method. APUC records its share in the income or loss of its investees in interest, dividend 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 that exceed one year and bear interest at a market rate based on the customer’s credit quality are initially recorded at cost, which is generally face value. Subsequent to acquisition, they 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.
	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.
Advances in aid of construction	'
	(o)	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. These amounts are recorded as Advances in Aid of Construction in other long-term liabilities.
	1	Significant accounting policies (continued)
	(o)	Advances in aid of construction (continued)
	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 2013, $627 (2012 - $3,555) was transferred from advances in aid of construction to contributions in aid of construction.
Deferred water rights and customer deposits	'
	(p)	Deferred water rights and customer deposits
	Deferred water rights are related to a hydroelectric generating facility which has a fifty year water lease with the first ten years of the water lease requiring no payment, which is a form of lease inducement. An annual average rate for water rights was estimated for the entire life of the lease and that average rate is being expensed over the lease term. The result of this policy is that the deferred water rights inducement amount recorded in the first ten years is being drawn down in the last forty years.
	Customer deposits result from the Liberty Utilities’ 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. The deposits bear monthly interest and are applied to the customer account after 12 months if the customer is found to be credit worthy.
Pension and other post employment plans	'
	(q)	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. The Company recognizes the funded status of its defined benefit pension plans and other post employment benefit plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually at 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 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	'
	(r)	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, construction, development 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 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 accumulated obligation.
Stock based compensation	'
	Stock based compensation
	The Company has several share-based compensation plans: a share option plan; an employee common share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company recognizes all employee stock-based compensation as a cost in the financial statements. 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.
Noncontrolling interests	'
	(t)	Noncontrolling interests
	Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent Company. Noncontrolling interests are initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of earnings and other comprehensive income attributable to the noncontrolling interests and any dividends or distributions paid to the noncontrolling interests.
	Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent Company. Noncontrolling interests are initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of earnings and other comprehensive income attributable to the noncontrolling interests and any dividends or distributions paid to the noncontrolling interests.
	If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net earnings or comprehensive income as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.
	Certain of the Company’s U.S. based wind businesses are organized as limited liability corporations and partnerships and have noncontrolling 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 noncontrolling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. HLBV uses a balance sheet approach, which measures the allocation of income or loss of the Class A’s membership 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 17).
Recognition of revenue	'
	(u)	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.
	Revenues related to utility electricity and natural gas sales and distribution are recorded based on metered consumptions by customers, which occur on a systematic basis throughout a month, rather than 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 revenues are calculated. These estimates of unbilled sales and revenues 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.
	Beginning in 2013, in accordance with the revenue decoupling mechanism approved by its regulator, Liberty Utilities (CalPeco Electric) LLC (“Calpeco Electric System ”) is required to charge approved annual delivery revenues evenly over its 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).
	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 waste water collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled revenues 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.
	Revenue is recorded net of sale taxes.
	Interest from long-term investments is recorded as earned.
Foreign currency translation	'
	1	Significant accounting policies (continued)
	(v)	Foreign currency translation
	The Company’s reporting currency is the Canadian dollar.
	The Company’s US 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 while revenues and expenses are converted 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 other comprehensive income (“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	'
	(w)	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 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. Investment tax credits are recorded as an offset to the related long-lived asset. They are amortized over the estimated life of the asset as credits to income tax expense.
	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 follows ASC 740-10 and 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	'
	(x)	Financial instruments and derivatives
	Accounts receivable and notes receivable are measured at amortized cost and there is no liquid market for these investments. Long-term liabilities, convertible debentures, and other long-term liabilities 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 respective asset’s carrying value at inception. Transaction costs for items classified as held-for-trading are expensed immediately. Transaction costs that are directly attributable to the issuance of financial liabilities, costs of arranging the Company’s credit facility and costs considered as commitment fees paid to financial institutions are recorded in deferred financing costs. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to revolving credit facilities are amortized on a straight-line basis over the term of the facility.
	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 sheet. The amounts that could net settle are not significant. The Company applies hedge accounting to financial instruments used to manage its foreign currency risk exposure and price risk exposure associated with sales of generated electricity.
	1	Significant accounting policies (continued)
	(x)	Financial instruments and derivatives (continued)
	For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized as other comprehensive income. The ineffective portion is immediately recognized in earnings. The amount recognized in accumulated other comprehensive income is removed and included in earnings in the same period as the hedged cash flows affect earnings under the same line item in the statement of income 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 recognized in accumulated other comprehensive income is transferred to the income statement in the same period that the hedged item affects profit or loss. If the forecast transaction is no longer expected to occur, then the balance in accumulated other comprehensive income 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 other comprehensive income) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings.
	Calpeco Electric System and Liberty Utilities (Granite State Electric) Corp. (“Granite State Electric System”) enter into Power Purchase Agreements (“PPA”) for load serving 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 on-going basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
Fair value measurements	'
	(y)	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 measurement date.
Commitments and contingencies	'
	(z)	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	'
	(aa)	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 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 and intangible assets, the annual impairment testing of reporting units containing 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, and the fair value of financial instruments, derivatives and share-based compensation. 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	'
	(a)	Recently adopted accounting pronouncements
	The FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. These newly issued accounting standards require an entity to disclose both gross and net information about financial instruments and transactions eligible for offset in the balance sheet including financial instruments and transactions executed under a master netting or similar arrangement. The standards were issued to enable users of the financial statements to understand the effects or potential effects of such arrangements on an entity’s financial position. The adoption of these standards as at January 1, 2013 did not have a material impact on the Company’s consolidated financial statements.
	The FASB issued ASU 2013-02, Comprehensive Income (Topic 220): This newly issued accounting standard requires an entity to provide certain information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes to the financial statements, the effect of, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. Other than the additional disclosure (note 16), the adoption of this standard did not have a material impact on the Company’s consolidated financial statements.
Recent accounting guidance not yet adopted	'
	(b)	Recent accounting guidance not yet adopted
	The FASB issued ASU 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This newly issued accounting standard requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in some specific situations. This ASU is required to be applied prospectively for fiscal years, and interim periods beginning after December 15, 2013. The adoption of this standard is not expected to have an impact the Company’s financial position or results of operations.
	The FASB issued ASU 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. This newly issued accounting standard permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to interest rates on direct Treasury obligations of the U.S. government and the London Interbank Offered Rate. The amendments also remove the restriction on using different benchmark rates for similar hedges. This ASU is required to be applied prospectively for qualifying new or re-designated hedging relationships entered into on or after July 17, 2013. 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 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date. This newly issued accounting standard provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. This ASU is required to be applied retrospectively for fiscal years, and interim periods within those years beginning after December 15, 2013. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

Significant_accounting_policie2

Significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Capitalization of Interest	'
		2013			2012
	Interest capitalized on non-regulated property	$	669		$	1,036
	AFUDC capitalized on regulated property:
	Allowance for borrowed funds	1,055			628
	Allowance for equity funds	1,786			1,108
	Total	$	3,510		$	2,772
Estimated Useful Lives of Depreciable Assets	'
	The range of estimated useful lives and the weighted average useful lives are summarized below:
		Range of useful lives			Weighted average
					useful lives
		2013		2012	2013		2012
	Generation
	Renewable	3 – 60		3 – 60	35		32
	Thermal	3 – 40		3 – 40	24		23
	Distribution
	Gas	5 – 80		5 – 80	38		38
	Electrical	8 – 75		8 – 75	41		42
	Water & wastewater	5 – 50		5 – 50	39		25
	Equipment	5 – 50		5 – 50	24		21

Business_acquisitions_and_deve1

Business acquisitions and development projects (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisition [Line Items]	'
Pro Forma Financial Information	'
	The supplemental pro forma financial information below was prepared using the acquisition method of accounting and is based on the historical financial information of APUC, New England Gas System and Peach State Gas System reflecting results of operations for 2013 and 2012 on a comparative basis as though the aforementioned companies were combined as of January 1, 2012. The acquiree’s pre-acquisition results have been added to APUC’s historical results, and the totals have been adjusted for the pro forma effects of acquisition-related costs, interest expense related to the financing of the business combinations, and related income taxes.
	Pro forma	2013				2012
	Total revenue from continuing operations	$	760,394			$	464,182
	Net earnings from continuing operations	59,698				28,103
	Basic net earnings from continuing operations per share	0.32				0.13
	Diluted net earnings from continuing operations per share	0.32				0.13
Impact on Company Balance Sheet	'
	The impact on the Company’s consolidated balance sheet was as follows:
		2012
	Elimination of noncontrolling interest (net of intercompany balance of $1,297 with Emera)	$	33,726
	Noncontrolling interest portion of currency translation adjustment transferred to AOCI	1,397
	Accumulated deficit	3,633
	Exercise of subscription receipts	$	38,756
New England Gas Company	'
Business Acquisition [Line Items]	'
Allocation of assets acquired and liabilities assumed	'
	The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:
	Cash	$	76
	Working capital	8,175
	Property, plant and equipment	84,636
	Regulatory assets	47,644
	Other assets	1,197
	Long term debt (including current portion)	(25,836		)
	Regulatory liabilities	(15,969		)
	Pension and OPEB	(25,360		)
	Environmental obligation	(10,225		)
	Deferred income tax liability, net	(1,217		)
	Total net assets acquired	$	63,121
Peach State Gas System	'
Business Acquisition [Line Items]	'
Allocation of assets acquired and liabilities assumed	'
	The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:
	Working capital	$	9,605
	Property, plant and equipment	141,983
	Goodwill	12,226
	Deferred income tax asset, net	1,992
	Derivative asset	231
	Regulatory liabilities	(3,807		)
	Other liabilities	(1,853		)
	Pension and OPEB	(4,615		)
	Derivative liabilities	(184		)
	Total net assets acquired	$	155,578
Pine Bluff Water System	'
Business Acquisition [Line Items]	'
Allocation of assets acquired and liabilities assumed	'
	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed.
	Cash	$	8
	Working capital	766
	Property, plant and equipment	28,371
	Regulatory assets	957
	Goodwill	5,034
	Other liabilities	(169		)
	Regulatory liabilities	(135		)
	Pension and OPEB	(4,277		)
	Deferred income tax liability, net	(2,697		)
	Total net assets acquired	$	27,858
Shady Oaks	'
Business Acquisition [Line Items]	'
Allocation of assets acquired and liabilities assumed	'
	The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date. The determination of the fair value is based upon management’s estimates and assumptions with respect to the fair value of the assets acquired and liabilities assumed.
	Cash		$	4,682
	Working capital		(846		)
	Property, plant and equipment		144,243
	Deferred tax asset		2,519
	Long term debt (including current portion)		(149,235		)
	Asset retirement obligation		(1,363		)
	Total net assets acquired		$	—
New Hampshire Electric and Gas Utilities	'
Business Acquisition [Line Items]	'
Allocation of assets acquired and liabilities assumed	'
	In 2013, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed on July 3, 2012 for the New Hampshire electric and gas utilities. The carrying value of those assets and liabilities were retrospectively adjusted to the amounts detailed in the table below. As a result, the total consideration was reduced by $9,216, working capital acquired was reduced by $9,869 and goodwill was increased by $957.
		Granite State				EnergyNorth			Total
	Cash	$	395			$	—		$	395
	Restricted cash	3,252				—			3,252
	Working capital	1,916				15,420			17,336
	Property, plant and equipment	86,935				256,305			343,240
	Regulatory assets	31,683				87,126			118,809
	Deferred financing	31				—			31
	Other assets	—				83			83
	Goodwill	—				28,537			28,537
	Customer deposits	(661		)		(962		)	(1,623		)
	Long-term debt	(15,188		)		—			(15,188		)
	Other long-term liabilities	(1,468		)		(3,287		)	(4,755		)
	Advances in aid of construction	—				(86		)	(86		)
	Derivative liabilities	—				(2,598		)	(2,598		)
	Regulatory liabilities	(5,533		)		(27,456		)	(32,989		)
	Pension and OPEB	(19,108		)		(29,197		)	(48,305		)
	Environmental obligation	—				(54,431		)	(54,431		)
	Deferred income tax liabilities, net	—				(61,484		)	(61,484		)
	Total net assets acquired	$	82,254			$	207,970		$	290,224

Property_plant_and_equipment_T

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	Property, plant and equipment consist of the following:
	2013
		Cost		Accumulated		Net book
				depreciation		value
	Generation
	Renewable	$	1,438,229	$	166,175	$	1,272,054
	Thermal	116,975		43,596		73,379
	Distribution
	Water & wastewater	303,410		63,807		239,603
	Electricity	277,679		16,782		260,897
	Gas	690,034		19,758		670,276
	Land	8,266		—		8,266
	Equipment	71,292		25,111		46,181
	Construction in progress	138,048		—		138,048
		$	3,043,933	$	335,229	$	2,708,704
	2012
		Cost		Accumulated		Net book
				depreciation		value
	Generation
	Renewable	$	1,132,631	$	78,772	$	1,053,859
	Thermal	208,183		78,336		129,847
	Distribution
	Water & wastewater	240,376		52,162		188,214
	Electricity	259,461		7,765		251,696
	Gas	352,491		5,940		346,551
	Land	7,318		—		7,318
	Equipment	67,740		22,712		45,028
	Construction in progress	63,765		—		63,765
		$	2,331,965	$	245,687	$	2,086,278

Intangible_assets_and_goodwill1

Intangible assets and goodwill (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Intangible Assets	'
	Intangible assets consist of the following:
	2013
		Cost				Accumulated				Net book
						amortization				value
	Power sales contracts	$	61,430			$	28,987			$	32,443
	Customer relationships	28,512				6,539				21,973
		$	89,942			$	35,526			$	54,416
	2012
		Cost				Accumulated				Net book
						amortization				value
	Power sales contracts	$	60,435			$	24,881			$	35,554
	Customer relationships	26,674				5,447				21,227
		$	87,109			$	30,328			$	56,781
Goodwill	'
	Changes in goodwill per operating segment are as follows:
		Liberty Utilities
		Central			West			East			Total
	Balance, January 1, 2012	$	192		$	9,517		$	—		$	9,709
	Business acquisitions	25,257			—			26,527			51,784
	Foreign exchange	(357		)	(251		)	574			(34		)
	Balance, December 31, 2012	$	25,092		$	9,266		$	27,101		$	61,459
	Business acquisitions	5,034			—			12,226			17,260
	Adjustments	(209		)	—			957			748
	Foreign exchange	2,056			640			2,484			5,180
	Balance, December 31, 2013	$	31,973		$	9,906		$	42,768		$	84,647

Regulatory_matters_Tables

Regulatory matters (Tables)	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory Assets and Liabilities	'
	Regulatory assets and liabilities consist of the following:
		2013			2012
	Regulatory assets
	Environmental costs (a)	$	80,438		$	59,789
	Pension and post-employment benefits (b)	64,997			47,838
	Storm costs (c)	5,437			6,726
	Energy costs adjustment (d)	20,495			7,962
	Rate case costs (e)	3,119			2,398
	Vegetation management	2,297			2,082
	Debt premium (f)	4,504			—
	Asset retirement obligation (g)	1,468			1,095
	Tax related	2,995			1,160
	Other	4,598			5,342
	Total regulatory assets	$	190,348		$	134,392
	Less current regulatory assets	(34,643		)	(10,644		)
	Non-current regulatory assets	$	155,705		$	123,748
	Regulatory liabilities
	Cost of removal (h)	$	68,698		$	58,852
	Rate-base offset (i)	25,082			15,541
	Energy costs adjustment (d)	17,394			13,891
	Pension and post-employment benefits (b)	6,770			1,127
	Rate adjustment mechanism	1,681			—
	Tax related	133			—
	Other	3,531			1,265
	Total regulatory liabilities	$	123,289		$	90,676
	Less current regulatory liabilities	(21,632		)	(8,626		)
	Non-current regulatory liabilities	$	101,657		$	82,050
	(a)	Environmental remediation costs recovery: Actual expenditures incurred for the cleanup of certain former gas manufacturing facilities (see note 23 (a) (ii)) are recovered through rates over a period of 7 years.
	(b)	Pension and post-employment benefits: As part of a business acquisition, the Regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-retirement benefits that have not yet been recognized in net periodic cost and were presented as accumulated comprehensive income prior to the acquisition. A net portion of $12,213 is currently recovered through rates over the future services years of the employees. The balance of $46,014 relates to recent acquisitions and was authorized for recognition as an asset by the Regulator. Recovery of $23,013 through rates is expected to start in the second quarter of 2014. The remaining $23,001 is anticipated to be approved in a final rate order in 2015.
	(c)	Storm costs: Incurred repair costs resulting from certain storms, which are expected to be recovered through rates.
	7	Regulatory matters (continued)
	(d)	Energy cost adjustment: The revenue of the electric and natural gas utilities include 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 balance sheet. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future time 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 are recoverable through the energy cost adjustment (note 26(b)(i)).
	(e)	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.
	(f)	Debt premium: The value of debt assumed in the acquisition of New England Gas System has been recorded at fair value in accordance with ASC 805 Business Combinations. The Massachusetts regulator allows for recovery of interest at the coupon rate of the debt and a regulatory asset has been recorded for the difference between the fair value and face value of the debt.
	(g)	Asset retirement obligation: Asset retirement obligations incurred by the utilities are expected to be recovered through rates.
	(h)	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.
	(i)	Rate-base offset: The Regulator 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.

Longterm_investments_and_notes1

Long-term investments and notes receivable (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Long Term Investments And Notes Receivable [Abstract]	'
Long-term Investments and Notes Receivable	'
	Long-term investments and notes receivable consist of the following:
		2013			2012
	Long-term investments
	32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	$	4,851		$	4,926
	25% of Class B non-voting shares of Cochrane Power Corporation	3,772			4,669
	45% interest in the Algonquin Power (Rattle Brook) Partnership (b)	—			3,884
	50% interest in the Valley Power Partnership	1,718			1,767
	Other	325			180
	Total long-term investments	$	10,666		$	15,426
	Notes Receivable
	Red Lily Senior loan, interest at 6.31% (a)	$	11,588		$	11,588
	Red Lily Subordinated loan, interest at 12.5% (a)	6,565			6,565
	Chapais Énergie, Société en Commandite interest at 10.789% and 4.91%, respectively	1,928			2,448
	Silverleaf resorts loan, interest at 15.48% maturing July 2020	2,149			2,010
	Other	448			146
		22,678			22,757
	Less: current portion	(598		)	(537		)
	Total long-term notes receivable	$	22,080		$	22,220
	Total long-term investments and notes receivable	$	32,746		$	37,646
	8	Long-term investments and notes receivable (continued)
	The above notes are secured by the underlying assets of the respective facilities.
	(a)	Red Lily I
	The Red Lily I Partnership (“Partnership”) is owned by an independent investor. The Company provides operation and supervision services to the Red Lily I project, a 26.4 megawatt wind energy facility located in south-eastern Saskatchewan.
	The Company’s investment in Red Lily I is in the form of participation in a portion of the senior debt facility, and a subordinated debt facility to the Partnership. In 2011, APUC advanced $13,000 under a senior debt facility to the Partnership and received a pre-payment of $1,412 in 2012. Another third party lender has also advanced $31,000 of senior debt to the Partnership. The Company’s senior loan to the Partnership earns interest at the rate of 6.31% and will mature in 2016. 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%, 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.
	A second tranche of subordinated loan for an amount equal to the amounts outstanding on Tranche 2 of the senior debt but no greater than $17,000 will be advanced in 2016 by the Company. The proceeds from this additional subordinated debt are required to be used to repay Tranche 2 of the Partnership’s senior debt, including APUC’s portion.
	In connection with the subordinated debt facility, the Company has been granted an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loan of up to $19,500, exercisable for a period of 90 days commencing in 2016. The fair value of the conversion option as at December 31, 2013 and 2012 was determined to be negligible.
	(b)	Algonquin Power (Rattle Brook) Partnership
	The Algonquin Power (Rattle Brook) Partnership was sold to related parties effective December 31, 2013 (see note 21).

Longterm_liabilities_Tables

Long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long Term Liabilities	'
	Long term liabilities consist of the following:
		2013			2012
	APCo
	Revolving $200,000 credit facility, revolving line of credit 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 1.75%, maturing November 16, 2015.	$	124,570		$	27,074
	Senior Unsecured Notes:	149,920			149,910
	$150,000 senior unsecured notes, bearing an interest rate of 4.82% maturing February 15, 2021. The notes are interest only, payable semi-annually in arrears.
	Senior Unsecured Notes:	134,837			134,807
	$135,000 senior unsecured notes, bearing an interest rate of 5.50% maturing July 25, 2018. The notes are interest only, payable semi-annually in arrears.
	Senior Debt - Shady Oaks Wind Facility:	129,759			—
	U.S. $122,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points, maturing June 30, 2026.  The facility has principal and interest payments, payable semi-annually in arrears.
	Senior Debt - Long Sault Hydro Facility:	37,143			38,136
	Bonds bearing an interest rate of 10.21% maturing December 31,2027. The bonds have interest and principal payments, monthly in arrears.
		2013			2012
	Senior Debt - Sanger Thermal Facility:	20,421			19,102
	U.S. $19,200 California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bond Series 1990A, bearing an effective interest rate determined by the remarketing agent, maturing September 15, 2020. The bond has interest only payments, payable monthly in arrears. The effective interest rate in 2013 was 1.72% (2012 – 2.29%).
	Senior Debt - Chuteford Hydro Facility:	3,417			3,763
	Bonds bearing an interest rate of 11.6%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears.
	Liberty Utilities
	Revolving U.S. $200,000 credit facility, revolving line of credit 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.	85,620			27,360
	Senior Unsecured Notes:
	Liberty Utilities Co.:	388,214			223,852
	U.S. $50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S. $115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S. $60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S. $15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S. $25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S. $75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; and U.S. $25,000, bearing an interest rate of 4.26%, maturing July 31, 2028. The notes interest only payments, payable semi-annually.
	Calpeco Electric System:	74,452			69,643
	U.S. $45,000 senior unsecured notes bearing an interest rate of 5.19%, maturing December 29, 2020 and U.S. $25,000 senior unsecured notes bearing an interest rate of 5.59%, maturing December 29, 2025. The notes are interest only payments, payable semi-annually in arrears.
	Liberty Water Co:	53,180			49,745
	U.S. $50,000 senior unsecured notes bearing an interest rate of 5.60% maturing December 22, 2020. The note has interest only payments, payable semi-annually in arrears, until June 20, 2016 after which the note will bear semi-annual interest payments thereafter.
	New England Gas System:	25,244			—
	First mortgage bonds, 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 bonds have interest only payments.
	Granite State Electric System:	15,954			14,924
	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; and, U.S. $5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually.
	LPSCo Water System:	11,668			11,269
	1999 and 2001 IDA Bonds bearing interest rates of 5.95% and 6.75% and maturing October 1, 2023 and October 1, 2031 respectively. The bonds have principal and interest payments, payable monthly in arrears.
	Bella Vista Water System:	1,189			1,241
	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.
		$	1,255,588		$	770,826
	Less: current portion	(8,339		)	(1,768		)
		$	1,247,249		$	769,058
Principal Payments	'
	Principal payments due in the next five years and thereafter are:
		2014			2015			2016		2017		2018		Thereafter		Total
	APCo	$	7,864		$	132,508		$	8,212	$	10,540	$	10,767	$	430,176	$	600,067
	Liberty Utilities	475			504			5,852		59,075		91,524		498,091		655,521
	Total	$	8,339		$	133,012		$	14,064	$	69,615	$	102,291	$	928,267	$	1,255,588

Convertible_debentures_Tables

Convertible debentures (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Convertible Debentures [Abstract]	'
Convertible Debentures	'
		Series 2A			Series 3			Total
	Maturity date	2016			2017
		November 30			September 30
	Interest rate	6.35		%	7		%
	Conversion price per share	$	6		$	4.2
	Carrying value at January 1, 2012	$	59,726		$	62,571		$	122,297
	Conversion to common shares (note 15(a)(i)), net of costs	(59,950		)	(61,611		)	(121,561		)
	Amortization and accretion	224			—			224
	Carrying amount at December 31, 2012	$	—		$	960		$	960
	Conversion to common shares (note 15(a)(i)), net of costs	—			(960		)	(960		)
	Amortization and accretion	—			—			—
	Carrying and fair value amount at December 31, 2013	$	—		$	—		$	—

Pension_and_other_postretireme1

Pension and other post-retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2013
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 at December 31:
		Pension benefits								OPEB
		2013				2012				2013			2012
	Change in projected benefit obligation
	Projected benefit obligation, at beginning of year	$	104,291			$	239			$	31,674		$	—
	Projected benefit obligation assumed from business combination	73,601				101,840				17,943			30,637
	Modifications to pension plan	81											—
	Service cost	3,273				1,288				1,602			803
	Interest cost	4,350				1,906				1,508			606
	Actuarial (gain)/loss	(11,395		)		2,736				(8,499		)	857
	Benefits paid	(3,597		)		(1,507		)		(1,158		)	(601		)
	Loss/(gain) on foreign exchange	7,509				(2,211		)		2,329			(628		)
	Projected benefit obligation at end of year	$	178,113			$	104,291			$	45,399		$	31,674
	Change in plan asset
	Fair value of plan assets at beginning of year	66,524				203				10,195			—
	Plan assets acquired in business combination	57,285				68,045				658			10,786
	Actual return on plan assets	10,733				1,223				1,730			—
	Employer contributions	3,013				—				1,208			231
	Benefits paid	(3,597		)		(1,507		)		(1,158		)	(601		)
	Loss/(gain) on foreign exchange	5,322				(1,440		)		762			(221		)
	Fair value of plan assets at end of year	$	139,280			$	66,524			$	13,395		$	10,195
	Unfunded status	$	(38,833	)		$	(37,767	)		$	(32,004	)	$	(21,479	)
	Amounts recognized in the consolidated balance sheets consists of:
	Current liabilities	(305		)		—				—			—
	Non-current liabilities	(38,528		)		(37,767		)		(32,004		)	(21,479		)
	Net amount recognized	$	(38,833	)		$	(37,767	)		$	(32,004	)	$	(21,479	)
Amounts Recognized in Accumulated Other Comprehensive loss	'
	The amounts recognized in accumulated other comprehensive loss before tax were as follows:
		Accumulated other comprehensive income
		Pension				OPEB
	Balance, January 1, 2012	$	53			$	—
	Current year net actuarial gain	3,298				857
	Amortization of net actuarial loss	(2		)		(32		)
	Foreign exchange	(16		)		(4		)
	Balance at December 31, 2012	$	3,333			$	821
	Current year net actuarial loss	(18,011		)		(9,644		)
	Current year prior service loss	82				—
	Amortization of net actuarial loss	(23		)		(26		)
	Foreign exchange	234				(234		)
	Balance at December 31, 2013	$	(14,385	)		$	(9,083	)
Weighted Average Assumptions Used to Determine Net Benefit Obligation	'
	Weighted average assumptions used to determine net benefit cost for 2013 and 2012 were as follows:
		Pension benefits						OPEB
		2013			2012			2013			2012
	Discount rate	3.68	%		3.89	%		3.69	%		3.97	%
	Expected return on assets	5.51	%		5.5	%		5.18	%		4.66	%
	Rate of compensation increase	3.13	%		3.31	%		2.97	%		N/A
	Healthcare cost trend rate
	Before Age 65							7.68	%		8.48	%
	Age 65 and after							7.68	%		7.5	%
	Assumed Ultimate Medical Inflation Rate							4.8	%		5	%
	Year in which Ultimate Rate is reached							2019			2017
	Weighted average assumptions used to determine net benefit obligation for 2013 and 2012 were as
	follows:
		Pension benefits						OPEB
		2013			2012			2013			2012
	Discount rate	4.55	%		3.62	%		4.6	%		3.75	%
	Expected return on assets	7	%		5.5	%		5.53	%		4.66	%
	Rate of compensation increase	2.97	%		3.09	%		2.97	%		N/A
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 2013 is as follows:
		2013
	Effect of a 1 percentage point increase in the HCCTR on:
	Year-end benefit obligation	$	5,829
	Total service and interest cost	580
	Effect of a 1 percentage point decrease in the HCCTR on:
	Year-end benefit obligation	$	(4,427	)
	Total service and interest cost	(456		)
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 administrative expenses in the consolidated statements of operations. The employee benefit costs related to business acquired are recorded in the consolidated statements of operations from the date of acquisition.
		Pension benefits								OPEB
		2013				2012				2013			2012
	Service cost	$	3,273			$	1,288			$	1,602		$	803
	Interest cost	4,350				1,906				1,508			606
	Expected return on plan assets	(4,160		)		(1,785		)		(602		)	—
	Amortization of net actuarial loss	23				2				26			32
	Net benefit cost	$	3,486			$	1,411			$	2,534		$	1,441
Target Asset Allocation	'
	The Company's target asset allocation is as follows:
	Asset Class		Target (%)			Range (%)
	Equity Securities		79	%		48.9%-88.5%
	Debt Securities		17	%		21.1%-51.1%
	Other		4	%		0%-11.5%
	The fair values of investments as at December 31, 2013, by asset category, are as follows:
	Asset Class		Level 1			Percentage
	Equity Securities		110,073			79	%
	Debt Securities		23,173			17	%
	Other		6,035			4	%
Expected Benefit Payments	'
	The expected benefit payments over the next ten years are as follows:
		2014				2015				2016			2017			2018		2019-2023
	Pension plan	$	8,320			$	8,238			$	8,812		$	9,374		$	9,839	$	55,838
	OPEB	1,339				1,247				1,400			1,547			1,727		11,176

Mandatorily_redeemable_Series_1

Mandatorily redeemable Series C preferred shares (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Dividend and Redemption Payments	'
	Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are:
	2014	$	1,109
	2015	1,077
	2016	946
	2017	895
	2018	1,125
	Thereafter to 2031	20,859
	Redemption amount	5,340
		31,351
	Less amounts representing interest	(12,546		)
		18,805
	Less current portion	(1,038		)
		$	17,767

Other_assets_Tables

Other assets (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Other Assets [Abstract]	'
Other Assets	'
	Other assets consist of the following:
		2013		2012
	Restricted cash	$	6,021	$	7,063
	Deferred financing costs	9,011		8,706
	Other	3,752		4,251
		$	18,784	$	20,020

Other_longterm_liabilities_Tab

Other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Other Liabilities Disclosure [Abstract]	'
Other Long Term Liabilities	'
	Other long-term liabilities consist of the following:
		2013			2012
	Asset retirement obligations	$	9,508		$	7,088
	Customer deposits	8,774			5,620
	Provision for injury and damages	1,215			3,480
	Deferred water rights inducement	2,764			2,845
	Contingent consideration	1,102			1,031
	Other	4,580			5,177
		27,943			25,241
	Less: current portion	(7,451		)	(4,352		)
		$	20,492		$	20,889

Shareholders_capital_Tables

Shareholders' capital (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Number of Common Shares	'
	(i)Conversion and redemption of convertible debentures
	In 2013, $960 (2012 - $61,611) of Series 3 Debentures were redeemed for 150,816 (2012 - 14,669,266) shares of APUC.
	In 2012, the remaining principal amount of $59,957 of Series 2A Debentures were redeemed for 10,322,518 common shares of APUC.
	(ii)	Subscription receipts
	On March 26, 2013, in connection with the acquisition of the Peach State Gas system the Company issued 3,960,000 common shares at a price of $7.40 per share for total proceeds of $29,304 pursuant to a subscription receipt agreement with Emera.
	On May 14, 2012, in connection with the acquisition of Granite State Electric System and EnergyNorth Gas System, the Company issued 12,000,000 common shares at a price of $5.00 per share to Emera pursuant to a subscription receipt agreement. The $60,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisitions.
	On June 29, 2012, in connection with the acquisition of Sandy Ridge Wind Facility the Company received $15,000 from Emera relating to 2,614,006 subscription receipts representing a price of $5.74 per share and issued common shares relating to these subscription receipts in July 2012.
	On July 31, 2012, in connection with the acquisition of the Midwest Gas System the Company issued 6,976,744 common shares at a price of $6.45 per share to Emera pursuant to a subscription receipt agreement. The $45,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition.
	On December 10, 2012, in connection with the acquisition of Senate and Minonk Wind Facilities, the Company received $45,000 from Emera relating to the exercise of 7,842,016 subscription receipts at a price of $5.74 per subscription receipt pursuant to a subscription receipt agreement. The subscription receipts were converted to 7,842,016 common shares on February 14, 2013.
	On December 21, 2012, in connection with the acquisition of Emera’s noncontrolling interest in Calpeco Electric System, the Company received $38,756 from Emera related to the exercise of 8,211,000 subscription receipts at a price of $4.72 per subscription receipt pursuant to a subscription receipt agreement. On December 27, 2012, Emera exercised 4,790,000 of these subscription receipts and the Company issued 4,790,000 common shares in exchange. On February 14, 2013, the balance of 3,421,000 subscription receipts were exercised by Emera and the Company issued 3,421,000 common shares in exchange.
	Following the above noted subscription receipts transactions, as of December 31, 2013 all subscriptions receipts had been exercised for cash and converted to common shares.
	15	Shareholders’ capital (continued)
	(a)	Common shares (continued)
	(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 will be purchased in the open market or will be 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 501,818 shares under the dividend reinvestment plan.
	Number of common shares:
			2013			2012
	Common shares, beginning of period		188,763,486			136,122,780
	Conversion and redemption of convertible debentures (i)		150,816			24,991,784
	Conversion of subscription receipts (ii)		15,223,016			26,380,750
	Issuance of shares under the dividend reinvestment (iii) and employee share purchase plans (c(ii))		2,211,667			1,268,172
	Common shares, end of period		206,348,985			188,763,486
Share-Based Compensation Expense	'
	For the year ended December 31, 2013, APUC recorded $2,046 (2012 - $1,833) in total share-based compensation expense detailed as follows:
		2013				2012
	Stock options	$	1,687			$	1,376
	Directors deferred share units	155				155
	Employee share purchase	75				42
	Performance share units	129				260
	Total share-based compensation	$	2,046			$	1,833
Fair Value of Share Options Granted	'
	The following assumptions were used in determining the fair value of share options granted:
		2013				2012
	Risk-free interest rate	1.61		%		1.7		%
	Expected volatility	37		%		38		%
	Expected dividend yield	3.83		%		4.4		%
	Expected life	8 years				8 years
	Weighted average grant date fair value per option	$	2			$	1.49
Stock Option Activity	'
	Stock option activity during the period is as follows:
		Number of			Weighted				Weighted	Aggregate
		awards			average				average	intrinsic
					exercise				remaining	value
					price				contractual
									term
									(years)
	Balance at January 1, 2012	2,487,105			$	4.76			6.96	$	4,134
	Granted	1,263,622			6.24				8	—
	Balance at December 31, 2012	3,750,727			$	5.25			6.07	$	5,939
	Granted	816,402			7.72				8	—
	Balance at December 31, 2013	4,567,129			$	5.7			5.45	$	7,814
	Exercisable at December 31, 2013	2,466,008			$	4.9			4.96	$	6,018
Performance Stock Units	'
	A summary of the PSUs follows:
		Number of awards			Weighted				Weighted		Aggregate
					Average				Average		intrinsic
					Grant-Date				Remaining		value
					Fair Value				Contractual
									Term (years)
	Balance at January 1, 2012	21,123			$	5.62			2		$	136
	Granted	68,982			6.78				1.3		467
	Forfeited	(6,622	)		5.62				1.5		(37		)
	Balance at December 31, 2012	83,483			$	6.58			1.8		$	571
	Granted, including dividends	5,537			6.79				1.23		41
	Exercised	(20,640	)		6.7				—		(151		)
	Forfeited	(2,185	)		6.7				—		(16		)
	Balance at December 31, 2013	66,195			$	6.57			0.62		$	486
	Exercisable at December 31, 2013	24,928			$	6.14			—		$	183

Accumulated_other_comprehensiv1

Accumulated other comprehensive loss (Tables)	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Accumulated other comprehensive loss	'
	Accumulated other comprehensive loss is comprised of the following balances, net of tax:
		Foreign currency cumulative translation			Unrealized gain on cash flow hedges			Pension and post-retirement actuarial loss			Total
	Balance, January 1, 2012	$	(96,462	)	$	—		$	(48	)	$	(96,510	)
	Other comprehensive income (loss) before reclassifications	(9,495		)	3,596			(2,459		)	(8,358		)
	Amounts reclassified from accumulated other comprehensive loss							1			1
	Net current period other comprehensive income	(9,495		)	3,596			(2,458		)	(8,357		)
	Balance, December 31, 2012	$	(105,957	)	$	3,596		$	(2,506	)	$	(104,867	)
	Other comprehensive income (loss) before reclassifications	39,422			19,421			16,698			75,541
	Amounts reclassified from accumulated other comprehensive loss	—			(2,113		)	29			(2,084		)
	Net current period other comprehensive income	39,422			17,308			16,727			73,457
	Balance, December 31, 2013	$	(66,535	)	$	20,904		$	14,221		$	(31,410	)

Noncontrolling_Interests_Table

Noncontrolling Interests (Tables)	12 Months Ended
	Dec. 31, 2013
Noncontrolling Interest [Abstract]	'
Net Earnings (Loss) Attributable to Noncontrolling Interests	'
	Net earnings/(loss) attributable to noncontrolling interests consists of the following:
		2013			2012
	Net earnings/(loss) attributable to Class B partnership units of SponsorCo	$	9,556		$	(4,580	)
	Net earnings/(loss) attributable to Class A partnership units	(20,408		)	10,678
	Other net earnings attributable to noncontrolling interests	39			1,316
	Total net earnings/(loss) attributable to noncontrolling interests	$	(10,813	)	$	7,414

Income_taxes_Tables

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2013
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% (2012 – 26.5%). The differences are as follows:
		2013			2012
	Expected income tax expense / (recovery) at Canadian statutory rate	$	16,072		$	1,726
	Increase (decrease) resulting from:
	Recognition of deferred credit	(6,676		)	(5,092		)
	Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(2,338		)	(6,282		)
	Non-taxable corporate dividend	(2,896		)	(666		)
	Noncontrolling interests share of income	4,266			(2,835		)
	Production tax credit	(247		)	(676		)
	Allowance for equity funds used during construction	(694		)	(402		)
	State taxes	313			—
	Other	1,355			(140		)
	Income tax recovery	$	9,155		$	(14,367	)
Income (Loss) Before Taxes	'
	For the years ended December 31, 2013 and 2012, income/(loss) from continuing operations before taxes consists of the following:
		2013			2012
	Canadian operations	$	19,687		$	12,251
	U.S. operations	40,962			(5,715		)
		$	60,649		$	6,536
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, 2013
	Canada	$	1,532		$	881		$	2,413
	United States	994			5,748			6,742
		$	2,526		$	6,629		$	9,155
	Year ended December 31, 2012
	Canada	$	127		$	(938	)	$	(811	)
	United States	611			(14,167		)	(13,556		)
		$	738		$	(15,105	)	$	(14,367	)
Tax Effect of Temporary Difference Between Assets and Liabilty	'
	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 at December 31, 2013 and 2012 are presented below:
		2013			2012
	Deferred tax assets:
	Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	226,314		$	184,845
	Pension and OPEB	31,433			5,011
	Acquisition related costs	5,152			5,134
	Outside basis in partnership	—			2,533
	Regulatory accounts	—			4,013
	Financial derivatives	—			211
	Environmental obligation	23,076			22,414
	Production tax credit	1,633			673
	Reserves not currently deductible	2,397			1,276
	Other	2,780			136
	Total deferred income tax assets	292,785			226,246
	Less: Valuation allowance	(15,667		)	(15,062		)
	Total deferred tax assets	277,118			211,184
	Deferred tax liabilities:
	Property, plant and equipment	(267,344		)	(219,573		)
	Intangible assets	(8,321		)	(5,478		)
	Outside basis in partnership	(2,210		)	—
	Regulatory accounts	(24,745		)	—
	Financial derivatives	(7,675		)	—
	Total deferred tax liabilities	(310,295		)	(225,051		)
	Net deferred tax assets/(liabilities)	$	(33,177	)	$	(13,867	)
Deferred Income Taxes	'
	Deferred income taxes are classified in the financial statements as:
		2013			2012
	Current deferred income tax asset	$	19,652		$	10,567
	Non-current deferred income tax asset	86,632			77,497
	Current deferred income tax liability	(2,308		)	(1,133		)
	Non-current deferred income tax liability	(137,153		)	(100,798		)
		$	(33,177	)	$	(13,867	)
Non Capital Losses Carry Forwards	'
	As at December 31, 2013, the Company had non-capital losses carry forwards available to reduce future year’s taxable income, which expire as follows:
	Year of expiry	Non-capital loss carry forwards
	2015	$	5,426
	2016 and onwards	463,610
		$	469,036

Divestitures_Tables

Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Summary of Operating Results and Cash Flows from Discontinued Operations	'
	The summary of operating results and cash flows from discontinued operations for the years ended December 31 is as follows:
		2013			2012 as reported			2012 EFW/BCI adjustments			2012 as reclassed
	Non-regulated energy sales	9,327			2,870			6,800			9,670
	Waste disposal fees	8,160			—			14,288			14,288
	Other and interest income	336			—			(6	)		(6	)
	Operating and administrative expenses	(19,720	)		(3,241	)		(12,544	)		(15,785	)
	Foreign exchange	80			—			—			—
	Depreciation of property, plant and equipment	(2,483	)		(1,279	)		(5,194	)		(6,473	)
	Interest expense	(58	)		(4	)		(317	)		(321	)
	Gain on sale of assets	1,016			—			—			—
	Write-off of accounts receivable	(262	)		—			—			—
	Write-down of long-lived assets	(56,898	)		(253	)		(23	)		(276	)
	Gain/(loss) from discontinued operations, before income taxes	(60,502	)		(1,907	)		3,004			1,097
	Income tax recovery/(expense)	18,491			750			(804	)		(54	)
	Gain/(loss) from discontinued operations, net of income taxes	(42,011	)		(1,157	)		2,200			1,043
	Add:
	Depreciation of property, plant and equipment	2,483			1,279			5,194			6,473
	Write-off of accounts receivable	262			—			—			—
	Write-down of long-lived assets	56,898			253			23			276
	Net proceeds of disposition	22,052			—			—			—
	Contingent liability	(613	)		—			—			—
	Income tax expense/(recovery)	(18,491	)		(750	)		804			54
	Increase/(decrease) in cash and cash equivalents from discontinued operations	20,580			(375	)		8,221			7,846
Assets Held-for-sale	'
	Assets held-for-sale as at December 31, were as follows:
		2013				2012 as reported				2012 EFW/BCI Adjustments			2012 Reclassed
	Property, plant and equipment	$	21,193			$	24,390			$	76,437		$	100,827
	Accounts receivable and prepaid expenses	2,734				—				2,510			2,510
	Total assets held for sale	$	23,927			$	24,390			$	78,947		$	103,337
	Less current assets held for sale	(23,927		)		(24,390		)		(2,510		)	(26,900		)
	Non-current assets held for sale	$	—			$	—			$	76,437		$	76,437
Liabilities Held-for-sale	'
	Liabilities held-for-sale as at December 31, were as follows:
		2013				2012 as reported				2012 EFW/BCI Adjustments			2012 Reclassed
	Accounts payable and accrued liabilities	$	1,471			$	—			$	1,211		$	1,211

Basic_and_diluted_net_earnings1

Basic and diluted net earnings per share (Tables)	12 Months Ended
	Dec. 31, 2013
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 income and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:
		2013			2012
	Net earnings attributable to shareholders of APUC	$	20,296		$	14,532
	Series A preferred shares dividend	5,400			769
	Net earnings attributable to common shareholders of APUC	$	14,896		$	13,763
	Discontinued operations	$	(42,011	)	$	1,043
	Net earnings attributable to common shareholders of APUC from continuing operations - Basic and Diluted	$	56,907		$	12,720
	Weighted average number of shares
	Basic	204,350,689			158,304,340
	Dilutive effect of share-based awards	980,697			605,281
	Diluted	205,331,386			158,909,621

Commitments_and_contingencies_

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Estimated Cash Flows For Site Investigation and Redemption Cost	'
	Estimated cash flows for site investigation and remediation costs in the next five years and thereafter are as follows:
	2014	$	10,111
	2015	27,285
	2016	17,873
	2017	2,128
	2018	1,784
	Thereafter to 2046	18,548
		$	77,729
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
	Purchased power	$	64,626	$	46,865	$	—	$	—	$	—	$	—	$	111,491
	Gas delivery, service and supply agreements	42,125		26,364		13,812		9,869		9,476		54,495		156,141
	Service agreements	24,130		24,371		28,922		29,639		27,897		498,342		633,301
	Capital projects	49,337		2,260		—		—		—		—		51,597
	Operating leases	5,125		4,551		3,944		3,733		3,551		85,213		106,117
	Total	$	185,343	$	104,411	$	46,678	$	43,241	$	40,924	$	638,050	$	1,058,647

Noncash_operating_items_Tables

Non-cash operating items (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Changes In Non Cash Operating Items [Abstract]	'
Changes in Non-Cash Operating Items	'
	The changes in non-cash operating items from discontinued operations is comprised of the following:
		2013			2012
	Accounts receivable	$	(213	)	$	(313	)
	Prepaid expenses	(11		)	135
	Accrued liabilities	260			(230		)
		$	36		$	(408	)
	The changes in non-cash operating items is comprised of the following:
		2013			2012
	Accounts receivable	$	(49,888	)	$	(14,582	)
	Related party balances	(996		)	1,476
	Natural gas inventory	(6,330		)	—
	Supplies and consumable inventory	(525		)	(3,621		)
	Income tax receivable	177			(423		)
	Prepaid expenses	(485		)	(4,764		)
	Accounts payable	(29,292		)	(7,553		)
	Accrued liabilities	37,023			31,335
	Current income tax liability	1,399			131
	Net regulatory assets and liabilities	1,098			(5,475		)
		$	(47,819	)	$	(3,476	)

Segmented_information_Tables

Segmented information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Results of Operations and Assets for Segments	'
	Operational segments (continued)
		Year ended December 31, 2013
		Algonquin Power									Liberty Utilities												Corporate			Total
		Renewable			Thermal			Total			Central			West			East			Total
		Energy			Energy
	Revenue
	Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	77,814		$	88,342		$	166,156		$	—		$	166,156
	Regulated gas sales and distribution	—			—			—			78,857			—			182,815			261,672			—			261,672
	Regulated water reclamation and distribution	—			—			—			18,242			39,108			—			57,350			—			57,350
	Non-regulated energy sales	145,661			34,530			180,191			—			—			—			—			—			180,191
	Other revenue	7,058			2,442			9,500			—			22			—			22			400			9,922
	Total revenue	152,719			36,972			189,691			97,099			116,944			271,157			485,200			400			675,291
	Operating expenses	48,966			8,514			57,480			27,455			36,753			67,264			131,472			—			188,952
	Regulated electricity purchased	—			—			—			—			39,750			57,626			97,376			—			97,376
	Regulated gas purchased	—			—			—			46,018			—			102,766			148,784			—			148,784
	Non-regulated fuel for generation	—			17,151			17,151			—			—			—			—			—			17,151
		103,753			11,307			115,060			23,626			40,441			43,501			107,568			400			223,028
	Depreciation of property, plant and equipment	(45,122		)	(5,439		)	(50,561		)	(9,096		)	(13,596		)	(18,725		)	(41,417		)	—			(91,978		)
	Amortization of intangible assets	(2,652		)	(856		)	(3,508		)	(81		)	(611		)	—			(692		)	—			(4,200		)
	Administration expenses	(13,094		)	(223		)	(13,317		)	(1,677		)	(2,541		)	(3,259		)	(7,477		)	(2,724		)	(23,518		)
	Foreign exchange gain	—			—			—			—			—			—			—			567			567
	Interest expense	(27,391		)	(1,046		)	(28,437		)	(5,069		)	(8,519		)	(10,146		)	(23,734		)	(1,174		)	(53,345		)
	Interest, dividend and other income	1,867			193			2,060			375			1,395			1,458			3,228			2,497			7,785
	Loss on sale of asset	(750		)	—			(750		)	—			—			—			—			—			(750		)
	Acquisition related costs	(628		)	—			(628		)	(68		)	—			(1,444		)	(1,512		)	—			(2,140		)
	Gain/(loss) on derivative financial instruments	(767		)	—			(767		)	—			—			—			—			5,967			5,200
	Earnings from continuing operations before income taxes	15,216			3,936			19,152			8,010			16,569			11,385			35,964			5,533			60,649
	Loss from discontinued operations before income taxes	1,128			(61,630		)	(60,502		)	—			—			—			—			—			(60,502		)
	Earnings/(loss) before income taxes	$	16,344		$	(57,694	)	$	(41,350	)	$	8,010		$	16,569		$	11,385		$	35,964		$	5,533		$	147
	Property, plant and equipment	$	1,364,843		$	79,828		$	1,444,671		$	215,090		$	387,715		$	661,228		$	1,264,033		$	—		$	2,708,704
	Intangible assets	26,802			5,698			32,500			2,709			19,207			—			21,916			—			54,416
	Total Assets held for sale	3,860			20,067			23,927			—			—			—			—			—			23,927
	Total assets	1,492,144			116,922			1,609,066			285,517			460,209			923,981			1,669,707			193,784			3,472,557
	Capital expenditures	46,885			2,631			49,516			28,566			23,743			56,552			108,861			—			158,377
	Acquisition of operating entities	2,083			—			2,083			27,545			—			209,386			236,931			—			239,014
	25	Segmented information (continued)
	Operational segments (continued)
		Year ended December 31, 2012
		Algonquin Power									Liberty Utilities												Corporate			Total
		Renewable			Thermal			Total			Central			West			East			Total
		Energy			Energy
	Revenue
	Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	71,734		$	36,723		$	108,457		$	—		$	108,457
	Regulated gas sales and distribution	—			—			—			25,802			—			49,916			75,718			—			75,718
	Regulated water reclamation and distribution	—			—			—			9,127			37,296			—			46,423			—			46,423
	Non-regulated energy sales	84,236			30,115			114,351			—			—			—			—			—			114,351
	Other revenue	1,925			1,686			3,611			—			152			94			246			—			3,857
	Total revenue	86,161			31,801			117,962			34,929			109,182			86,733			230,844			—			348,806
	Operating expenses	30,308			8,568			38,876			13,096			35,645			30,209			78,950			—			117,826
	Regulated electricity purchased	—			—			—			—			43,861			24,348			68,209			—			68,209
	Regulated gas purchased	—			—			—			13,648			—			23,813			37,461			—			37,461
	Non-regulated fuel for generation	—			14,589			14,589			—			—			—			—			—			14,589
		55,853			8,644			64,497			8,185			29,676			8,363			46,224			—			110,721
	Depreciation of property, plant and equipment	(18,823		)	(4,782		)	(23,605		)	(3,333		)	(11,120		)	(7,129		)	(21,582		)	—			(45,187		)
	Amortization of intangible assets	(2,653		)	(831		)	(3,484		)	(81		)	(586		)	—			(667		)	—			(4,151		)
	Administration expenses	(9,424		)	(2,176		)	(11,600		)	294			(4,091		)	(1,223		)	(5,020		)	(2,952		)	(19,572		)
	Foreign exchange gain	—			—			—			—			—			—			—			561			561
	Interest expense	(15,060		)	(1,733		)	(16,793		)	(96		)	(8,066		)	(694		)	(8,856		)	(9,971		)	(35,620		)
	Interest, dividend and other income	2,038			509			2,547			—			2,113			461			2,574			2,118			7,239
	Acquisition related costs	(3,155		)	21			(3,134		)	(1,442		)	—			(3,112		)	(4,554		)	—			(7,688		)
	Gain/(loss) on derivative financial instruments	(2,954		)	—			(2,954		)	—			—			—			—			3,187			233
	Earnings from continuing operations before income taxes	5,822			(348		)	5,474			3,527			7,926			(3,334		)	8,119			(7,057		)	6,536
	Loss from discontinued operations before income taxes	(1,925		)	3,022			1,097			—			—			—			—			—			1,097
Earnings/(loss) before income taxes	$	3,897		$	2,674		$	6,571		$	3,527		$	7,926		$	(3,334	)	$	8,119		$	(7,057	)	$	7,633
Property, plant and equipment	$	1,157,062		$	77,438		$	1,234,500		$	151,637		$	350,053		$	350,088		$	851,778		$	—		$	2,086,278
Intangible assets	29,480			6,132			35,612			2,613			18,556			—			21,169			—			56,781
Total Assets held for sale	24,390			78,947			103,337			—			—			—			—			—			103,337
Total assets	1,272,037			175,926			1,447,963			212,495			464,201			500,374			1,177,070			153,957			2,778,990
Capital expenditures	21,068			10,348			31,416			10,777			23,181			12,488			46,446			67			77,929
Acquisition of operating entities	245,718			—			245,718			128,890			—			295,297			424,187			—			669,905
Information on Operations by Geographic Area	'
	Information on operations by geographic area is as follows:
		2013			2012
	Revenue
	Canada	$	65,380		$	62,036
	United States	609,911			286,770
		$	675,291		$	348,806
	Property, plant and equipment
	Canada	$	433,153		$	395,896
	United States	2,275,551			1,690,382
		$	2,708,704		$	2,086,278
	Intangible assets
	Canada	$	26,802		$	29,480
	United States	27,614			27,301
		$	54,416		$	56,781

Financial_instruments_Tables

Financial instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Instruments	'
	Fair value of financial instruments
	2013	Carrying			Fair			Level 1			Level 2		Level 3
		amount			Value
	Notes receivable	$	22,678		$	26,321		$	—		$	—	$	26,321
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	31,971			31,971			—			—		31,971
	Energy contracts not designated as a cashflow hedge	3,737			3,737			—			—		3,737
	Cross-currency swap designated as a foreign exchange hedge	109			109			—			109		—
	Commodity contracts for regulated operations	482			482			—			482		—
	Total derivative financial instruments	36,299			36,299			—			591		35,708
	Total financial assets	$	58,977		$	62,620		$	—		$	591	$	62,029
	Long-term liabilities	$	1,255,588		$	1,261,340		$	296,986		$	964,354	$	—
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	4,781			4,781			—			—		4,781
	Cross-currency swap designated as a foreign exchange hedge	7,947			7,947			—			7,947		—
	Interest rate swaps not designated as a hedge	3,180			3,180			—			3,180		—
	Commodity contracts for regulated operations	313			313			—			313		—
	Total derivative financial instruments	16,221			16,221			—			11,440		4,781
	Total financial liabilities	$	1,271,809		$	1,277,561		$	296,986		$	975,794	$	4,781
	26	Financial instruments
	(a)Fair value of financial instruments
	2012	Carrying			Fair			Level 1			Level 2		Level 3
		amount			Value
	Notes receivable	$	22,757		$	25,476		$	—		$	—	$	25,476
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	12,695			12,695			—			—		12,695
	Cross-currency swap designated as a foreign exchange hedge	408			408			—			408		—
	Commodity contracts for regulatory operations	147			147			—			147		—
	Total derivative financial instruments	13,250			13,250			—			555		12,695
	Total financial assets	$	36,007		$	38,726		$	—		$	555	$	38,171
	Long-term liabilities	$	770,826		$	785,473		$	293,348		$	492,125	$	—
	Convertible debentures	960			1,319			1,319			—		—
	Derivative financial instruments:
	Energy contracts designated as a cashflow hedge	9,012			9,012			—			—		9,012
	Cross-currency swap designated as a foreign exchange hedge	2,078			2,078			—			2,078		—
	Interest rate swaps not designated as a hedge	4,778			4,778			—			4,778		—
	Energy derivative contracts	287			287			—					287
	Commodity contracts for regulated operations	1,661			1,661			—			1,661		—
	Total derivative financial instruments	17,816			17,816			—			8,517		9,299
	Total financial liabilities	$	789,602		$	804,608		$	294,667		$	500,642	$	9,299
Summary of Commodity Volumes Associated with Derivative Contracts	'
	The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:
		2013
	Financial contracts: Gas swaps	2,734,304
	Gas options	2,082,104
		4,816,408
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 accompanying balance sheets:
		2013			2012
	Regulatory assets:
	Gas swap contracts	$	86		$	1,555
	Gas option contracts	$	208		$	106
	Regulatory liabilities:
	Gas swap contracts	$	416		$	90
	Gas option contracts	$	37		$	57
Long-Term Energy Derivative Contracts	'
	APCo 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			Expiry	Receive average				Pay floating price
	(MW-hrs)				prices (per MW-hr)				(per MW-hr)
	Energy delivered less existing swap			December 2014	U.S. $		32.64		PJM Western HUB
	Energy delivered less existing swap			December 2014	U.S. $		25.64		NI HUB
	Energy delivered less existing swap			December 2014	U.S. $		27.39		ERCOT North HUB
	147,199			December 2016	$		67.36		AESO
	1,029,732			December 2022	U.S. $		42.81		PJM Western HUB
	4,395,665			December 2022	U.S. $		30.25		NI HUB
	4,663,097			December 2027	U.S. $		36.46		ERCOT North HUB
Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Consolidated Statement of Operations	'
	The effects on the consolidated statements of operations of derivative financial instruments designated as cash flow hedge consist of the following:
		2013			2012
	Gain on derivative instruments (ineffective portion)	$	1,304		$	105
	The following table summarizes changes in other comprehensive income attributable to derivative financial instruments designated as a hedge:
		2013			2012
	Effective portion of cash flow hedge, gain	$	17,338		$	5,217
	Gain (loss) realized on cash flow hedge	(30		)	(49		)
		$	17,308		$	5,168
	Less noncontrolling interest	(9,064		)	(1,572		)
	Change in fair value of cash flow hedge in other comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	8,244		$	3,596
Schedule of Other 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.
	Notional quantity			Expiry	Receive average				Net Asset
	(MW-hrs)				prices (per MW-hr)
	19,440			Feb-14	U.S. $		61.4		$	1,833
	69,154			Mar-15	U.S. $		48.83		1,729
Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges	'
	The effects on the statement of operations of derivative financial instruments not designated as hedges consist of the following:
		2013			2012
	Change in unrealized loss/(gain) on derivative financial instruments:
	Interest rate swaps	$	(1,598	)	$	(2,197	)
	Energy derivative contracts	(3,809		)	(825		)
	Total change in unrealized loss/(gain) on derivative financial instruments	$	(5,407	)	$	(3,022	)
	Realized loss/(gain) on derivative financial instruments:
	Foreign exchange contracts	$	—		$	(187	)
	Interest rate swaps	2,024			2,094
	Energy derivative contracts	(466		)	987
	Total realized loss on derivative financial instruments	$	1,558		$	2,894
	Loss/(gain) on derivative financial instruments accounted for as hedges	$	(3,849	)	$	(128	)
	Ineffective portion of derivatives financial instruments accounted for as hedges	$	(1,351	)	(105		)
	Gain on derivative financial instruments	$	(5,200	)	$	(233	)
Maximum Credit Risk Exposure for Financial Instruments	'
	As at December 31, 2013 the Company’s maximum exposure to credit risk for these financial instruments was as follows:
		December 31, 2013
		Canadian $			US $
	Cash and cash equivalents and restricted cash	$	3,465		$	15,415
	Accounts receivable	18,948			137,481
	Allowance for Doubtful Accounts	—			(7,955		)
	Notes Receivable	20,529			2,021
		$	42,942		$	146,962
Liabilities Maturity Profile	'
	The Company’s liabilities mature as follows:
		Due less			Due 2 to 3			Due 4 to 5			Due after		Total
		than 1			years			years			5 years
		year
	Long term debt obligations	$	8,339		$	147,076		$	171,907		$	928,266	$	1,255,588
	Advances in aid of construction	1,239						—			77,697		78,936
	Interest on long term debt	54,804			103,605			89,966			168,448		416,823
	Purchase Obligations	156,905						—			—		156,905
	Environmental obligation	10,111			45,158			3,912			18,548		77,729
	Derivative financial instruments:
	Cross- currency swap	—			—			—			7,947		7,947
	Interest rate swaps	1,936			1,244			—			—		3,180
	Energy derivative and commodity contracts	240			72			—			4,465		4,777
	Capital lease payments	125			3,919			—			—		4,044
	Other obligations	7,326			—			—			13,809		21,135
	Total obligations	$	241,025		$	301,074		$	265,785		$	1,219,180	$	2,027,064

Significant_accounting_policie3

Significant accounting policies - Capitalization of Interest (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Capitalization [Line Items]	'	'
Total	3,510	2,772
Non Regulated Property	'	'
Schedule of Capitalization [Line Items]	'	'
Interest capitalized	669	1,036
Interest expense	'	'
Schedule of Capitalization [Line Items]	'	'
AFUDC capitalized on regulated property	1,055	628
Interest, dividend and other income	'	'
Schedule of Capitalization [Line Items]	'	'
AFUDC capitalized on regulated property	1,786	1,108

Significant_accounting_policie4

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Generation | Renewable Energy	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'35 years	'32 years
Generation | Thermal	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'24 years	'23 years
Generation | Minimum | Renewable Energy	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'3 years	'3 years
Generation | Minimum | Thermal	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'3 years	'3 years
Generation | Maximum | Renewable Energy	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'60 years	'60 years
Generation | Maximum | Thermal	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'40 years	'40 years
Distribution | Gas	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'38 years	'38 years
Distribution | Electrical	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'41 years	'42 years
Distribution | Water & wastewater	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'39 years	'25 years
Distribution | Minimum | Gas	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'5 years	'5 years
Distribution | Minimum | Electrical	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'8 years	'8 years
Distribution | Minimum | Water & wastewater	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'5 years	'5 years
Distribution | Maximum | Gas	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'80 years	'80 years
Distribution | Maximum | Electrical	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'75 years	'75 years
Distribution | Maximum | Water & wastewater	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'50 years	'50 years
Equipment	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Weighted average useful lives	'24 years	'21 years
Equipment | Minimum	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'5 years	'5 years
Equipment | Maximum	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives	'50 years	'50 years

Significant_accounting_policie5

Significant accounting policies - Additional Information (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]	'	'
Non-regulated energy sales	180,191	114,351
Interest expense	53,345	35,620
Contributions in aid of construction	627	3,555
Water lease, term	'50 years	'
Water lease, inducement period	'10 years	'
Description of interest rate on deposits	'The deposits bear monthly interest and are applied to the customer account after 12 months if the customer is found to be credit worthy.	'
Terms of interest rate on deposits	'12 months	'
Long Sault | Long Sault, Hydroelectric generating facility	'	'
Significant Accounting Policies [Line Items]	'	'
Percentage of acquirable equity in 2038	58.00%	'
Generating assets of Long Sault	44,319	42,566
Long-term debt of Long Sault	37,143	38,136
Non-regulated energy sales	10,155	8,747
Operating expense and amortization	2,391	2,728
Interest expense	3,632	3,929
Long Sault | Long Sault, Hydroelectric generating facility | 2014 - 2027	'	'
Significant Accounting Policies [Line Items]	'	'
Percentage of future cash flows of the facility	65.00%	'
Long Sault | Long Sault, Hydroelectric generating facility | Thereafter to 2046	'	'
Significant Accounting Policies [Line Items]	'	'
Percentage of future cash flows of the facility	58.00%	'
Minimum	'	'
Significant Accounting Policies [Line Items]	'	'
Refund period of developer advances	'10 years	'
Maximum	'	'
Significant Accounting Policies [Line Items]	'	'
Refund period of developer advances	'20 years	'
Power sales contracts | Minimum	'	'
Significant Accounting Policies [Line Items]	'	'
Intangible asset, useful life	'6 years	'
Power sales contracts | Maximum	'	'
Significant Accounting Policies [Line Items]	'	'
Intangible asset, useful life	'25 years	'
Customer Relationships	'	'
Significant Accounting Policies [Line Items]	'	'
Intangible asset, useful life	'40 years	'

Business_acquisitions_and_deve2

Business acquisitions and development projects - Additional Information (Details)

12 Months Ended

0 Months Ended

7 Months Ended

12 Months Ended

0 Months Ended

24 Months Ended

0 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Nov. 28, 2013

Dec. 20, 2013

Dec. 20, 2013

Apr. 02, 2013

Apr. 02, 2013

Feb. 01, 2013

Feb. 01, 2013

Jan. 02, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jan. 04, 2012

Dec. 31, 2013

Jan. 04, 2012

CAD

CAD

Wind Portfolio SponsorCo, LLC

New England Gas Company

New England Gas Company

Peach State Gas System

Peach State Gas System

Pine Bluff Water System

Pine Bluff Water System

Shady Oaks

Shady Oaks

Shady Oaks

Shady Oaks

New Hampshire Electric and Gas Utilities

Solar Energy Project

Solar Energy Project

Developed Technology Rights

USD ($)

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

ComEd [Member]

ComEd [Member]

CAD

CAD

CAD

Solar Energy Project

MW

MWh

MWh

MWac

CAD

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interest acquired

'

'

40.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payment to acquire noncontrolling interest

0

38,756

$117,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase price

239,014

669,905

'

59,100

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase price, adjusted

'

'

'

'

'

153,000

155,578

27,934

27,858

'

'

'

'

'

'

'

'

Purchase price, debt assumed

'

'

'

'

'

'

'

'

'

150,000

'

'

'

'

'

'

'

Weighted average useful life of assets acquired

'

'

'

'55 years

'55 years

'55 years

'55 years

'40 years

'40 years

'37 years

'37 years

'

'

'

'

'

'

Supply commitment

'

'

'

'

'

'

'

'

'

'

'

252,617

310,000

'

'

'

'

Contributed revenue

'

'

'

'

3,582

'

37,889

'

8,708

'

17,472

'

'

'

'

'

'

Contributed earnings (loss)

'

'

'

'

1,153

'

5,692

'

1,894

'

3,297

'

'

'

'

'

'

Acquisition of New Hampshire Electric and Gas Systems

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Adjustment to total consideration transferred

'

'

'

'

'

'

'

'

'

'

'

'

'

9,216

'

'

'

Adjustment to working capital acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

9,869

'

'

'

Adjustment to goodwill acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

957

'

'

'

Acquisition of solar energy project

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Solar power capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

'

'

Project power capacity

'

'

'

'

'

'

'

'

'

109.5

109.5

'

'

'

'

'

'

Additions to property, plant and equipment

158,377

75,692

'

'

'

'

'

'

'

'

'

'

'

'

'

33,259

'

Contract term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

Rate per MWh

'

'

'

'

'

'

'

'

'

'

'

'

'

'

443

'

'

Consideration for development rights

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,500

Additional contingent consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,500

'

'

Achieved milestone

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,000

'

Business_acquisitions_and_deve3

Business acquisitions and development projects - Summary of Preliminary Fair Value of Assets Acquired and Liabilities Assumed (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012	Dec. 20, 2013	Apr. 02, 2013	Feb. 01, 2013	Jan. 02, 2013	Jul. 03, 2012	Jul. 03, 2012	Jul. 03, 2012
In Thousands, unless otherwise specified			New England Gas Company	Peach State Gas System	Pine Bluff Water System	Shady Oaks	New Hampshire Electric and Gas Utilities	Granite State	EnergyNorth Natural Gas Inc
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]	'	'	'	'	'	'	'	'	'
Cash	'	'	76	'	8	4,682	395	395	0
Restricted cash	'	'	'	'	'	'	3,252	3,252	0
Working capital	'	'	8,175	9,605	766	-846	17,336	1,916	15,420
Property, plant and equipment	'	'	84,636	141,983	28,371	144,243	343,240	86,935	256,305
Goodwill	84,647	61,459	'	12,226	5,034	'	28,537	0	28,537
Derivative asset	'	'	'	231	'	'	'	'	'
Regulatory assets	'	'	47,644	'	957	'	118,809	31,683	87,126
Deferred financing	'	'	'	'	'	'	31	31	0
Other assets	'	'	1,197	'	'	'	83	0	83
Customer deposits	'	'	'	'	'	'	-1,623	-661	-962
Long term debt (including current portion)	'	'	-25,836	'	'	-149,235	-15,188	-15,188	0
Regulatory liabilities	'	'	-15,969	-3,807	-135	'	-32,989	-5,533	-27,456
Other liabilities	'	'	'	-1,853	-169	'	-4,755	-1,468	-3,287
Advances in aid of construction	'	'	'	'	'	'	-86	0	-86
Pension and OPEB	'	'	-25,360	-4,615	-4,277	'	-48,305	-19,108	-29,197
Derivative liabilities	'	'	'	-184	'	'	-2,598	0	-2,598
Environmental obligation	'	'	-10,225	'	'	'	-54,431	0	-54,431
Asset retirement obligation	'	'	'	'	'	-1,363	'	'	'
Deferred income tax assets (liability), net	'	'	-1,217	1,992	-2,697	2,519	-61,484	0	-61,484
Total net assets acquired	'	'	63,121	155,578	27,858	0	290,224	82,254	207,970

Business_acquisitions_and_deve4

Business acquisitions and development projects - Pro Forma Financial Information (Detail) (CAD)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition, Pro Forma Information [Abstract]	'	'
Total revenue from continuing operations	760,394	464,182
Net earnings from continuing operations	59,698	28,103
Basic net earnings from continuing operations per share	0.32	0.13
Diluted net earnings from continuing operations per share	0.32	0.13

Business_acquisitions_and_deve5

Business acquisitions and development projects - Impact on Company's Balance Sheet (Detail) (CAD)	12 Months Ended		1 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 21, 2012	Dec. 31, 2012	Dec. 31, 2013	Sep. 30, 2013
			Calpeco Electric System	Calpeco Electric System	Calpeco Electric System	Calpeco Electric System
					Intersegment Eliminations	Restatement Adjustment
Business Acquisition [Line Items]	'	'	'	'	'	'
Noncontrolling interest acquired	'	'	50.00%	'	'	'
Payment to acquire noncontrolling interest	0	38,756	38,756	'	'	'
Elimination of noncontrolling interest (net of intercompany balance of $1,297 with Emera)	'	'	'	33,726	'	'
Noncontrolling interest portion of currency translation adjustment transferred to AOCI	'	'	'	1,397	'	'
Accumulated deficit	'	'	'	3,633	'	'
Exercise of subscription receipts	'	'	'	38,756	'	'
Deficit	-488,406	-406,143	'	'	'	3,649
Intercompany balance with Emera Inc	'	'	'	'	1,297	'

Accounts_receivable_Additional

Accounts receivable - Additional Information (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'
Allowance for doubtful accounts receivable	8,461	4,360
Unbilled revenue	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'
Accounts receivable balances	45,274	22,658

Property_plant_and_equipment_D

Property, plant and equipment (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Cost	3,043,933	2,331,965
Accumulated depreciation	335,229	245,687
Net book value	2,708,704	2,086,278
Land	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	8,266	7,318
Accumulated depreciation	0	0
Net book value	8,266	7,318
Equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	71,292	67,740
Accumulated depreciation	25,111	22,712
Net book value	46,181	45,028
Construction in progress	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	138,048	63,765
Accumulated depreciation	0	0
Net book value	138,048	63,765
Generation | Renewable Energy	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	1,438,229	1,132,631
Accumulated depreciation	166,175	78,772
Net book value	1,272,054	1,053,859
Generation | Thermal	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	116,975	208,183
Accumulated depreciation	43,596	78,336
Net book value	73,379	129,847
Distribution | Water & wastewater	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	303,410	240,376
Accumulated depreciation	63,807	52,162
Net book value	239,603	188,214
Distribution | Electricity	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	277,679	259,461
Accumulated depreciation	16,782	7,765
Net book value	260,897	251,696
Distribution | Gas	'	'
Property, Plant and Equipment [Line Items]	'	'
Cost	690,034	352,491
Accumulated depreciation	19,758	5,940
Net book value	670,276	346,551

Property_plant_and_equipment_A

Property, plant and equipment - Additional Information (Detail) (CAD)	12 Months Ended						0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Jan. 03, 2014
			Renewable Energy	Renewable Energy	Water & wastewater	Water & wastewater	Office Building
							Subsequent Event
Property, Plant, and Equipment Disclosure [Line Items]	'	'	'	'	'	'	'
Renewable generation assets related to facilities under capital lease	'	'	86,774	88,198	'	'	'
Accumulated depreciation	'	'	31,739	29,584	'	'	'
Depreciation expense	'	'	2,155	2,244	'	'	'
Contribution received	3,098	6,341	'	'	'	'	'
Expansion cost, distribution cost	'	'	'	'	1,000	1,000	'
Purchase price	158,377	75,692	'	'	'	'	46,800

Intangible_assets_and_goodwill2

Intangible assets and goodwill - Schedule of Intangible Assets (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Indefinite-lived Intangible Assets [Line Items]	'	'
Intangible assets, Cost	89,942	87,109
Intangible assets, Accumulated amortization	35,526	30,328
Intangible assets, Net book value	54,416	56,781
Power sales contracts	'	'
Indefinite-lived Intangible Assets [Line Items]	'	'
Intangible assets, Cost	61,430	60,435
Intangible assets, Accumulated amortization	28,987	24,881
Intangible assets, Net book value	32,443	35,554
Customer relationships	'	'
Indefinite-lived Intangible Assets [Line Items]	'	'
Intangible assets, Cost	28,512	26,674
Intangible assets, Accumulated amortization	6,539	5,447
Intangible assets, Net book value	21,973	21,227

Intangible_assets_and_goodwill3

Intangible assets and goodwill - Additional Information (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]	'
Estimated amortization expense for intangibles in year 1	4,560
Estimated amortization expense for intangibles in year 2	4,560
Estimated amortization expense for intangibles in year 3	4,560
Estimated amortization expense for intangibles in year 4	2,810
Estimated amortization expense for intangibles in year 5	2,470

Intangible_assets_and_goodwill4

Intangible assets and goodwill Intangible assets and goodwill - Schedule of Goodwill (Details) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Roll Forward]	'	'
Goodwill	84,647	61,459
Liberty Utilities	'	'
Goodwill [Roll Forward]	'	'
Goodwill	61,459	9,709
Business acquisitions	17,260	51,784
Adjustments	748	'
Foreign exchange	5,180	-34
Goodwill	84,647	61,459
Liberty Utilities | Central	'	'
Goodwill [Roll Forward]	'	'
Goodwill	25,092	192
Business acquisitions	5,034	25,257
Adjustments	-209	'
Foreign exchange	2,056	-357
Goodwill	31,973	25,092
Liberty Utilities | West	'	'
Goodwill [Roll Forward]	'	'
Goodwill	9,266	9,517
Business acquisitions	0	0
Adjustments	0	'
Foreign exchange	640	-251
Goodwill	9,906	9,266
Liberty Utilities | East	'	'
Goodwill [Roll Forward]	'	'
Goodwill	27,101	0
Business acquisitions	12,226	26,527
Adjustments	957	'
Foreign exchange	2,484	574
Goodwill	42,768	27,101

Regulatory_matters_Regulatory_

Regulatory matters - Regulatory Assets and Liabilities (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	190,348	134,392
Less current regulatory assets	-34,643	-10,644
Non-current regulatory assets	155,705	123,748
Regulatory Liabilities	123,289	90,676
Less current regulatory liabilities	-21,632	-8,626
Non-current regulatory liabilities	101,657	82,050
Removal costs recovered	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	68,698	58,852
Rate-base offset	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	25,082	15,541
Energy costs adjustment	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	17,394	13,891
Pension and post-employment benefits	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	6,770	1,127
Rate adjustment mechanism	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	1,681	0
Tax related	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	133	0
Other	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory Liabilities	3,531	1,265
Environmental costs	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets recovery period	'7 years	'
Regulatory assets	80,438	59,789
Pension and post-employment benefits	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	64,997	47,838
Storm costs deferral	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	5,437	6,726
Energy costs adjustment	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	20,495	7,962
Rate case costs	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	3,119	2,398
Vegetation management	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	2,297	2,082
Debt premium	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	4,504	0
Asset retirement obligation	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	1,468	1,095
Tax related	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	2,995	1,160
Other	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	4,598	5,342

Regulatory_matters_Regulatory_1

Regulatory matters - Regulatory Assets and Liabilities (Parenthetical) (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Pension and post-employment benefits	'
Regulatory Assets And Liabilities [Line Items]	'
Net portion	12,213
Portion related to current acquisition	46,014
Recover in 2014	23,013
Recover in 2015	23,001
Environmental costs	'
Regulatory Assets And Liabilities [Line Items]	'
Regulatory assets recovery period	'7 years

Longterm_investments_and_notes2

Long-term investments and notes receivable (Detail) (CAD)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	10,666		15,426
Notes receivable, carrying amount	22,678		22,757
Less: current portion	-598		-537
Total long-term notes receivable	22,080		22,220
Total long-term investments and notes receivable	32,746		37,646
Notes Receivable | Red Lily Senior loan, interest at 6.31%	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Notes receivable, carrying amount	11,588	[1]	11,588	[1]
Notes Receivable | Red Lily Subordinated loan, interest at 12.5%	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Notes receivable, carrying amount	6,565	[1]	6,565	[1]
Notes Receivable | Chapais Energie, Societe en Commandite interest at 10.789% and 4.91%, respectively	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Notes receivable, carrying amount	1,928		2,448
Notes Receivable | Silverleaf resorts loan, interest at 15.48% maturing July 2020	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Notes receivable, carrying amount	2,149		2,010
Notes Receivable | Other note receivable	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Notes receivable, carrying amount	448		146
32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	4,851		4,926
25% of Class B non-voting shares of Cochrane Power Corporation	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	3,772		4,669
45% interest in the Algonquin Power (Rattle Brook) Partnership	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	0	[2]	3,884	[2]
50% interest in the Valley Power Partnership	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	1,718		1,767
Other	'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'
Long-term Investments	325		180
[1]	Red Lily IThe Red Lily I Partnership (bPartnershipb) is owned by an independent investor. The Company provides operation and supervision services to the Red Lily I project, a 26.4 megawatt wind energy facility located in south-eastern Saskatchewan.The Companybs investment in Red Lily I is in the form of participation in a portion of the senior debt facility, and a subordinated debt facility to the Partnership. In 2011, APUC advanced $13,000 under a senior debt facility to the Partnership and received a pre-payment of $1,412 in 2012. Another third party lender has also advanced $31,000 of senior debt to the Partnership. The Companybs senior loan to the Partnership earns interest at the rate of 6.31% and will mature in 2016. 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%, 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.A second tranche of subordinated loan for an amount equal to the amounts outstanding on Tranche 2 of the senior debt but no greater than $17,000 will be advanced in 2016 by the Company. The proceeds from this additional subordinated debt are required to be used to repay Tranche 2 of the Partnershipbs senior debt, including APUCbs portion.In connection with the subordinated debt facility, the Company has been granted an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loan of up to $19,500, exercisable for a period of 90 days commencing in 2016. The fair value of the conversion option as at DecemberB 31, 2013 and 2012 was determined to be negligible.
[2]	Algonquin Power (Rattle Brook) PartnershipThe Algonquin Power (Rattle Brook) Partnership was sold to related parties effective December 31, 2013 (see note 21).

Longterm_investments_and_notes3

Long-term investments and notes receivable (Parenthetical) (Detail) (CAD)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2012
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Red Lily I Project,wind energy facility, capacity (in megawatt)	26.4	'	'
Maximum	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Subordinated loan to be advanced in 2016	17,000,000	'	'
Red Lily	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Option to subscribe equity interest in partnership, exercisable period	'90 days	'	'
Red Lily | Maximum	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Option to subscribe equity interest in partnership, percentage	75.00%	'	'
Option to subscribe equity interest in partnership, outstanding loan	19,500,000	'	'
Red Lily Senior loan, interest at 6.31% | Notes Receivable	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Prepayment received	'	'	1,412,000
Payments to Acquire Notes Receivable	'	13,000,000	'
Note receivable interest rate	6.31%	'	'
Red Lily Senior loan, interest at 6.31% | Notes Receivable | Third Party Lender	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Payments to Acquire Notes Receivable	31,000,000	'	'
Red Lily Subordinated loan, interest at 12.5% | Notes Receivable	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Note receivable interest rate	12.50%	'	'
Investment,repayment start year	'2016	'	'
Chapais Energie | Notes Receivable	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Note receivable interest rate	10.79%	'	'
Silverleaf resorts loan, interest at 15.48% maturing July 2020	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Loan maturity date	'2020-07	'	'
Silverleaf resorts loan, interest at 15.48% maturing July 2020 | Notes Receivable	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Note receivable interest rate	15.48%	'	'
32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Investment Interest Rate	32.40%	'	'
25% of Class B non-voting shares of Cochrane Power Corporation	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Investment Interest Rate	25.00%	'	'
45% interest in the Algonquin Power (Rattle Brook) Partnership	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Investment Interest Rate	45.00%	'	'
Societe en Commandite interest	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Investment Interest Rate	4.91%	'	'
50% interest in the Valley Power Partnership	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Investment Interest Rate	50.00%	'	'

Longterm_liabilities_Detail

Long-term liabilities (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Total	1,255,588	770,826
Less: current portion	-8,339	-1,768
Long-term liabilities	1,247,249	769,058
Algonquin Power Co	'	'
Debt Instrument [Line Items]	'	'
Total	600,067	'
Algonquin Power Co | Revolving Credit Facility	'	'
Debt Instrument [Line Items]	'	'
Total	124,570	27,074
Algonquin Power Co | Senior Unsecured Notes | 4.82% Senior Unsecured Notes	'	'
Debt Instrument [Line Items]	'	'
Total	149,920	149,910
Algonquin Power Co | Senior Unsecured Notes | 5.5% Senior Unsecured Notes	'	'
Debt Instrument [Line Items]	'	'
Total	134,837	134,807
Algonquin Power Co | Senior Debt | Shady Oaks Wind Facility, Loan Facility	'	'
Debt Instrument [Line Items]	'	'
Total	129,759	0
Algonquin Power Co | Senior Debt | 10.21% Senior Debt Long Sault Rapids	'	'
Debt Instrument [Line Items]	'	'
Total	37,143	38,136
Algonquin Power Co | Senior Debt | Sanger Terminal Facility Bonds	'	'
Debt Instrument [Line Items]	'	'
Total	20,421	19,102
Algonquin Power Co | Senior Debt | 11.6% Senior Debt Chute Ford	'	'
Debt Instrument [Line Items]	'	'
Total	3,417	3,763
Liberty Utilities	'	'
Debt Instrument [Line Items]	'	'
Total	655,521	'
Liberty Utilities | Revolving Credit Facility	'	'
Debt Instrument [Line Items]	'	'
Total	85,620	27,360
Liberty Utilities | Senior Unsecured Notes | Liberty Utilities Co. Senior Unsecured Notes	'	'
Debt Instrument [Line Items]	'	'
Total	388,214	223,852
Liberty Utilities | Senior Unsecured Notes | Calpeco Electric System Senior Unsecured Notes	'	'
Debt Instrument [Line Items]	'	'
Total	74,452	69,643
Liberty Utilities | Senior Unsecured Notes | Liberty Water Co, Senior Unsecured Notes	'	'
Debt Instrument [Line Items]	'	'
Total	53,180	49,745
Liberty Utilities | Senior Unsecured Notes | Granite State, Senior Unsecured Long-term Notes	'	'
Debt Instrument [Line Items]	'	'
Total	15,954	14,924
Liberty Utilities | Bonds | New England Gas System, First Mortgage Bonds	'	'
Debt Instrument [Line Items]	'	'
Total	25,244	0
Liberty Utilities | Bonds | Litchfield Park Service Company Bonds	'	'
Debt Instrument [Line Items]	'	'
Total	11,668	11,269
Liberty Utilities | Loans | Bella Vista Water Loans	'	'
Debt Instrument [Line Items]	'	'
Total	1,189	1,241

Long_Term_liabilities_Parenthe

Long Term liabilities (Parenthetical) (Detail)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Sep. 29, 2013

Jul. 31, 2013

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Mar. 14, 2013

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

Loans

Loans

Loans

Loans

LIBOR

LIBOR

LIBOR

4.82% Senior Unsecured Notes

4.82% Senior Unsecured Notes

5.5% Senior Unsecured Notes

5.5% Senior Unsecured Notes

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

10.21% Senior Debt Long Sault Rapids

10.21% Senior Debt Long Sault Rapids

Sanger Terminal Facility Bonds

Sanger Terminal Facility Bonds

11.6% Senior Debt Chute Ford

11.6% Senior Debt Chute Ford

LIBOR

LIBOR

LIBOR

Liberty Utilities Co. Senior Unsecured Notes

Liberty Utilities Co. Senior Unsecured Notes

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Calpeco Electric System Senior Unsecured Notes

Calpeco Electric System Senior Unsecured Notes

California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.59%

California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.59%

California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.19%

California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.19%

Liberty Water Co, Senior Unsecured Notes

Liberty Water Co, Senior Unsecured Notes

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.30%

Granite State Senior Unsecured Longterm Notes, 7.30%

Granite State Senior Unsecured Longterm Notes, 7.30%

New England Gas System, First Mortgage Bonds, 9.44%

New England Gas System, First Mortgage Bonds, 9.44%

New England Gas System, First Mortgage Bonds, 7.99%

New England Gas System, First Mortgage Bonds, 7.99%

New England Gas System, First Mortgage Bonds, 7.24%

New England Gas System, First Mortgage Bonds, 7.24%

Litchfield Park Service Company Bonds, 5.95%

Litchfield Park Service Company Bonds, 5.95%

Litchfield Park Service Company Bonds, 6.75%

Litchfield Park Service Company Bonds, 6.75%

Bella Vista Water Loans, 6.26%

Bella Vista Water Loans, 6.26%

Bella Vista Water Loans, 6.10%

Bella Vista Water Loans, 6.10%

CAD

CAD

CAD

CAD

CAD

CAD

CAD

USD ($)

USD ($)

LIBOR

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

200,000,000

200,000,000

120,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

$200,000,000

$200,000,000

$100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, basis spread on variable rate

1.75%

'

'

'

'

'

'

'

'

2.80%

'

'

'

'

'

'

1.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility, maturity date

16-Nov-15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, face value

'

'

'

150,000,000

150,000,000

135,000,000

135,000,000

'

150,000,000

'

'

'

19,200,000

19,200,000

'

'

'

'

'

125,000,000

225,000,000

50,000,000

50,000,000

50,000,000

115,000,000

115,000,000

115,000,000

60,000,000

60,000,000

60,000,000

15,000,000

15,000,000

15,000,000

25,000,000

25,000,000

25,000,000

75,000,000

75,000,000

75,000,000

25,000,000

25,000,000

25,000,000

'

'

25,000,000

25,000,000

45,000,000

45,000,000

50,000,000

50,000,000

5,000,000

5,000,000

5,000,000

5,000,000

5,000,000

5,000,000

5,000,000

5,000,000

5,000,000

6,500,000

6,500,000

7,000,000

7,000,000

6,000,000

6,000,000

'

'

'

'

'

'

'

'

Debt instrument, remaining principal amount

'

'

'

'

'

'

'

$122,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate

'

'

'

4.82%

4.82%

5.50%

5.50%

'

'

'

10.21%

10.21%

'

'

11.60%

11.60%

'

'

'

'

'

3.51%

3.51%

3.51%

4.49%

4.49%

4.49%

4.89%

4.89%

4.89%

4.14%

4.14%

4.14%

3.23%

3.23%

3.23%

3.86%

3.86%

3.86%

4.26%

4.26%

4.26%

'

'

5.59%

5.59%

5.19%

5.19%

5.60%

5.60%

7.37%

7.37%

7.37%

7.94%

7.94%

7.94%

7.30%

7.30%

7.30%

9.44%

9.44%

7.99%

7.99%

7.24%

7.24%

5.95%

5.95%

6.75%

6.75%

6.26%

6.26%

6.10%

6.10%

Debt instrument, maturity date

'

'

'

15-Feb-21

15-Feb-21

25-Jul-18

25-Jul-18

'

'

30-Jun-26

31-Dec-27

31-Dec-27

15-Sep-20

15-Sep-20

1-Apr-20

1-Apr-20

'

'

'

'

'

31-Jul-17

31-Jul-17

'

1-Aug-22

1-Aug-22

'

30-Jul-27

30-Jul-27

'

13-Mar-23

13-Mar-23

'

31-Jul-20

31-Jul-20

'

31-Jul-23

31-Jul-23

'

31-Jul-28

31-Jul-28

'

'

'

29-Dec-25

29-Dec-25

29-Dec-20

29-Dec-20

22-Dec-20

22-Dec-20

1-Nov-23

1-Nov-23

'

1-Jul-25

1-Jul-25

'

15-Jun-28

15-Jun-28

'

15-Feb-20

'

15-Sep-26

'

15-Dec-27

'

1-Oct-23

1-Oct-23

1-Oct-31

1-Oct-31

1-Mar-20

1-Mar-20

1-Dec-17

1-Dec-17

Debt instrument, repayment terms

'

'

'

'The notes are interest only, payable semi-annually in arrears.

'The notes are interest only, payable semi-annually in arrears.

'The notes are interest only, payable semi-annually in arrears.

'The notes are interest only, payable semi-annually in arrears.

'

'

'

'

'

'The variable interest rate is determined by the remarketing agent

'The variable interest rate is determined by the remarketing agent

'

'

'

'

'

'

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'The notes are interest only, payable semi-annually.

'The notes are interest only, payable semi-annually.

'

'

'

'

'The notes are interest only, payable semi-annually, until June 2016 with semi-annual interests payments and an annual principal repayment of U.S. $5,000 thereafter.

'The notes are interest only, payable semi-annually, until June 2016 with semi-annual interests payments and an annual principal repayment of U.S. $5,000 thereafter.

'The notes have interest only payments, payable semi-annually.

'The notes have interest only payments, payable semi-annually.

'

'The notes have interest only payments, payable semi-annually.

'The notes have interest only payments, payable semi-annually.

'

'The notes have interest only payments, payable semi-annually.

'The notes have interest only payments, payable semi-annually.

'

'The bonds have interest only payments.

'

'The bonds have interest only payments.

'

'The bonds have interest only payments.

'

'The bonds have principal and interest payments, payable monthly in arrears.

'The bonds have principal and interest payments, payable monthly in arrears.

'The bonds have principal and interest payments, payable monthly in arrears.

'The bonds have principal and interest payments, payable monthly in arrears.

'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.

'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.

Debt instrument, effective interest rate

'

'

'

'

'

'

'

'

'

'

'

'

1.72%

2.29%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Longterm_liabilities_longterm_

Long-term liabilities long-term liabilities - Additional Information (Detail)

12 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 19, 2013

Nov. 18, 2013

Jan. 17, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 03, 2012

Dec. 31, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Feb. 10, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 31, 2013

Jul. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Jul. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jul. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jul. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Mar. 14, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 03, 2012

Dec. 31, 2013

Sep. 30, 2013

Sep. 29, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

CAD

CAD

Parent

Parent

Parent

Parent

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Algonquin Power Co

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

Liberty Utilities

CAD

CAD

Revolving Credit Facility

Revolving Credit Facility

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Senior Debt

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Senior Unsecured Notes

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Bonds

Bonds

Bonds

Bonds

Bonds

Bonds

USD ($)

USD ($)

4.65% Senior Unsecured Debentures Due 2022

4.82% Senior Unsecured Notes

4.82% Senior Unsecured Notes

4.82% Senior Unsecured Notes

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

Shady Oaks Wind Facility, Loan Facility

LIBOR

LIBOR

LIBOR

Liberty Utilities Co. Senior Unsecured Notes

Liberty Utilities Co. Senior Unsecured Notes

Liberty Utilities Co. Senior Unsecured Notes

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.23%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 3.86%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Liberty Utilities Co Senior Unsecured Notes, 4.26%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 4.14%

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 3.51%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.49%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Liberty Utilities Co Senior Unsecured Notes, 4.89%

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.37%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.94%

Granite State Senior Unsecured Longterm Notes, 7.30%

Granite State Senior Unsecured Longterm Notes, 7.30%

Granite State Senior Unsecured Longterm Notes, 7.30%

LIBOR

LIBOR

LIBOR

New England Gas System, First Mortgage Bonds, 7.24%

New England Gas System, First Mortgage Bonds, 7.24%

New England Gas System, First Mortgage Bonds, 7.99%

New England Gas System, First Mortgage Bonds, 7.99%

New England Gas System, First Mortgage Bonds, 9.44%

New England Gas System, First Mortgage Bonds, 9.44%

Subsequent Event

CAD

CAD

USD ($)

USD ($)

Minimum

Maximum

Subsequent Event

CAD

CAD

CAD

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

Tranche

Tranche

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, face value

'

'

'

'

'

'

200,000,000

150,000,000

150,000,000

'

'

$150,000,000

'

'

'

'

'

'

$125,000,000

$225,000,000

'

$25,000,000

$25,000,000

$25,000,000

$75,000,000

$75,000,000

$75,000,000

$25,000,000

$25,000,000

$25,000,000

$15,000,000

$15,000,000

$15,000,000

$50,000,000

$50,000,000

$50,000,000

$115,000,000

$115,000,000

$115,000,000

$60,000,000

$60,000,000

$60,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

$5,000,000

'

'

'

$6,000,000

$6,000,000

$7,000,000

$7,000,000

$6,500,000

$6,500,000

Debt instrument, interest rate

'

'

'

'

'

'

4.65%

4.82%

4.82%

'

'

'

'

'

'

'

'

'

'

'

'

3.23%

3.23%

3.23%

3.86%

3.86%

3.86%

4.26%

4.26%

4.26%

4.14%

4.14%

4.14%

3.51%

3.51%

3.51%

4.49%

4.49%

4.49%

4.89%

4.89%

4.89%

7.37%

7.37%

7.37%

7.94%

7.94%

7.94%

7.30%

7.30%

7.30%

'

'

'

7.24%

7.24%

7.99%

7.99%

9.44%

9.44%

Deferred finance costs

9,011,000

8,706,000

'

'

'

'

940,000

1,057,000

'

'

'

'

'

'

'

'

'

'

'

'

2,663,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in long-term liabilities

685,472,000

75,432,000

'

'

'

'

'

'

'

'

28,000,000

'

'

'

40,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, remaining principal amount

'

'

'

'

'

'

'

'

'

'

122,000,000

'

'

'

82,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, term

'

'

'

'

'

'

'

'

'

'

'12 years 6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, periodic principal payments

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument sold, price per principal amount

'

'

'

'

'

'

0.99864

'

'

0.9994

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

65,000,000

30,000,000

'

'

'

'

'

'

'

'

'

200,000,000

200,000,000

120,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

200,000,000

100,000,000

'

'

'

'

'

'

Debt instrument, number of tranches

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

3

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest on long term debt

416,823,000

'

14,057,000

4,482,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash paid during the period for interest expense

44,185,000

28,635,000

49,746,000

20,671,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovered_Sheet1

Long-term liabilities Long-term liabilities - Principal Payments (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Long-term Debt, Fiscal Year Maturity [Abstract]	'	'
2014	8,339	'
2015	133,012	'
2016	14,064	'
2017	69,615	'
2018	102,291	'
Thereafter	928,267	'
Total	1,255,588	770,826
Algonquin Power Co	'	'
Long-term Debt, Fiscal Year Maturity [Abstract]	'	'
2014	7,864	'
2015	132,508	'
2016	8,212	'
2017	10,540	'
2018	10,767	'
Thereafter	430,176	'
Total	600,067	'
Liberty Utilities	'	'
Long-term Debt, Fiscal Year Maturity [Abstract]	'	'
2014	475	'
2015	504	'
2016	5,852	'
2017	59,075	'
2018	91,524	'
Thereafter	498,091	'
Total	655,521	'

Convertible_debentures_Detail

Convertible debentures (Detail) (Convertible Debt, CAD)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Convertible Debt [Roll Forward]	'	'
Carrying value, beginning balance	960	122,297
Conversion to common shares, net of costs	-960	-121,561
Amortization and accretion	0	224
Carrying value, ending balance	0	960
Series 2A	'	'
Convertible Debt [Abstract]	'	'
Maturity date	30-Nov-16	'
Interest rate	6.35%	'
Conversion price (cad per share)	6	'
Convertible Debt [Roll Forward]	'	'
Carrying value, beginning balance	0	59,726
Conversion to common shares, net of costs	0	-59,950
Amortization and accretion	0	224
Carrying value, ending balance	'	0
Series 3	'	'
Convertible Debt [Abstract]	'	'
Maturity date	30-Sep-17	'
Interest rate	7.00%	'
Conversion price (cad per share)	4.2	'
Convertible Debt [Roll Forward]	'	'
Carrying value, beginning balance	960	62,571
Conversion to common shares, net of costs	-960	-61,611
Amortization and accretion	0	'
Carrying value, ending balance	0	960

Pension_and_other_postretireme2

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Change in projected benefit obligation	'	'
Projected benefit obligation, at beginning of year	104,291	239
Projected benefit obligation assumed from business combination	73,601	101,840
Modifications to pension plan	81	'
Service cost	3,273	1,288
Interest cost	4,350	1,906
Actuarial (gain)/loss	-11,395	2,736
Benefits paid	-3,597	-1,507
Loss/(gain) on foreign exchange	7,509	-2,211
Projected benefit obligation, at end of year	178,113	104,291
Change in plan asset	'	'
Fair value of plan assets, at beginning of year	66,524	203
Plan assets acquired in business combination	57,285	68,045
Actual return on plan assets	10,733	1,223
Employer contributions	3,013	0
Loss/(gain) on foreign exchange	5,322	-1,440
Fair value of plan assets at end of year	139,280	66,524
Unfunded status	-38,833	-37,767
Current liabilities	-305	0
Non-current liabilities	-38,528	-37,767
Net amount recognized	-38,833	-37,767
Other Postretirement Benefit Plans, Defined Benefit	'	'
Change in projected benefit obligation	'	'
Projected benefit obligation, at beginning of year	31,674	0
Projected benefit obligation assumed from business combination	17,943	30,637
Service cost	1,602	803
Interest cost	1,508	606
Actuarial (gain)/loss	-8,499	857
Benefits paid	-1,158	-601
Loss/(gain) on foreign exchange	2,329	-628
Projected benefit obligation, at end of year	45,399	31,674
Change in plan asset	'	'
Fair value of plan assets, at beginning of year	10,195	0
Plan assets acquired in business combination	658	10,786
Actual return on plan assets	1,730	0
Employer contributions	1,208	231
Loss/(gain) on foreign exchange	762	-221
Fair value of plan assets at end of year	13,395	10,195
Unfunded status	-32,004	-21,479
Current liabilities	0	0
Non-current liabilities	-32,004	-21,479
Net amount recognized	-32,004	-21,479

Pension_and_other_postretireme3

Pension and other post-retirement benefits - Additional Information (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Employee Benefits Disclosure [Line Items]	'	'
Accumulated benefit obligation for pension plan	162,179	97,687
Defined contribution pension plan cost	2,437	1,108
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	283	'
Expected employer contributions for next year	7,539	'
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	608	'
Expected employer contributions for next year	1,339	'

Pension_and_other_postretireme4

Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) (CAD)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits	'	'
Beginning balance	3,333,000	53,000
Current year net actuarial gain (loss)	-18,011,000	3,298,000
Current year prior service loss	82,000	'
Amortization of net actuarial loss	-23,000	-2,000
Foreign exchange	234,000	-16,000
Ending balance	-14,385,000	3,333,000
Other Postretirement Benefit Plans, Defined Benefit	'	'
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits	'	'
Beginning balance	821,000	0
Current year net actuarial gain (loss)	-9,644,000	857,000
Current year prior service loss	0	'
Amortization of net actuarial loss	-26,000	-32,000
Foreign exchange	-234,000	-4,000
Ending balance	-9,083,000	821,000

Pension_and_other_postretireme5

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	3.68%	3.89%
Expected return on assets	5.51%	5.50%
Rate of compensation increase	3.13%	3.31%
Other Postretirement Benefit Plans, Defined Benefit	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	3.69%	3.97%
Expected return on assets	5.18%	4.66%
Rate of compensation increase	2.97%	'
Healthcare cost trend rate	'	'
Before Age 65	7.68%	8.48%
Age 65 and after	7.68%	7.50%
Assumed Ultimate Medical Inflation Rate	4.80%	5.00%
Year in which Ultimate Rate is reached	'2019	'2017

Pension_and_other_postretireme6

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	4.55%	3.62%
Expected return on assets	7.00%	5.50%
Rate of compensation increase	2.97%	3.09%
Other Postretirement Benefit Plans, Defined Benefit	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount rate	4.60%	3.75%
Expected return on assets	5.53%	4.66%
Rate of compensation increase	2.97%	'

Pension_and_other_postretireme7

Pension and other post-retirement benefits - Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR) (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Effect of a 1 percentage point increase in the HCCTR on year-end benefit obligation	5,829
Effect of a 1 percentage point increase in the HCCTR on total service and interest cost	580
Effect of a 1 percentage point decrease in the HCCTR on, year-end benefit obligation	-4,427
Effect of a 1 percentage point decrease in the HCCTR on, total service and interest cost	-456

Pension_and_other_postretireme8

Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Service cost	3,273	1,288
Interest cost	4,350	1,906
Expected return on plan assets	-4,160	-1,785
Amortization of net actuarial loss	23	2
Net benefit cost	3,486	1,411
Other Postretirement Benefit Plans, Defined Benefit	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Service cost	1,602	803
Interest cost	1,508	606
Expected return on plan assets	-602	0
Amortization of net actuarial loss	26	32
Net benefit cost	2,534	1,441

Pension_and_other_postretireme9

Pension and other post-retirement benefits - Target Plan Asset Allocation (Details)	12 Months Ended
	Dec. 31, 2013
Equity Securities	'
Defined Benefit Plan Disclosure [Line Items]	'
Target allocation percentage	79.00%
Target allocation percentage range, minimum	48.90%
Target allocation percentage range, maximum	88.50%
Debt Securities	'
Defined Benefit Plan Disclosure [Line Items]	'
Target allocation percentage	17.00%
Target allocation percentage range, minimum	21.10%
Target allocation percentage range, maximum	51.10%
Other	'
Defined Benefit Plan Disclosure [Line Items]	'
Target allocation percentage	4.00%
Target allocation percentage range, minimum	0.00%
Target allocation percentage range, maximum	11.50%

Recovered_Sheet2

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Equity Securities	'
Defined Benefit Plan Disclosure [Line Items]	'
Allocation percentage	79.00%
Equity Securities | Level 1	'
Defined Benefit Plan Disclosure [Line Items]	'
Fair value of plan assets	110,073
Debt Securities	'
Defined Benefit Plan Disclosure [Line Items]	'
Allocation percentage	17.00%
Debt Securities | Level 1	'
Defined Benefit Plan Disclosure [Line Items]	'
Fair value of plan assets	23,173
Other	'
Defined Benefit Plan Disclosure [Line Items]	'
Allocation percentage	4.00%
Other | Level 1	'
Defined Benefit Plan Disclosure [Line Items]	'
Fair value of plan assets	6,035

Recovered_Sheet3

Pension and other post-retirement benefits - Expected Benefit Payments (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Plans	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	8,320
2015	8,238
2016	8,812
2017	9,374
2018	9,839
2019- 2023	55,838
Post Retirement Benefit Plan	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	1,339
2015	1,247
2016	1,400
2017	1,547
2018	1,727
2019- 2023	11,176

Mandatorily_redeemable_Series_2

Mandatorily redeemable Series C preferred shares (Details)	Dec. 31, 2013	Dec. 31, 2012	Jan. 02, 2013	Jan. 02, 2013	Dec. 31, 2013	Jan. 02, 2013	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified	CAD	CAD	Series C Preferred Stock	Series C Preferred Stock	Series C Preferred Stock	Executives of company	Dividends Payable [Member]
			USD ($)	CAD	CAD	Series C Preferred Stock	Series C Preferred Stock
							CAD
Class of Stock [Line Items]	'	'	'	'	'	'	'
Redeemable Preferred stock issued, shares	'	'	100	100	'	36	'
Preferred Stock, Redemption Price Per Share	'	'	$53,400	53,400	'	'	'
Equity, Fair Value Disclosure	'	'	'	18,497	'	'	'
Estimated discount rate used to measure fair value of conversion option	'	'	5.00%	5.00%	'	'	'
Disclosure Estimated Dividend And Redemption Payments [Abstract]	'	'	'	'	'	'	'
2014	8,339	'	'	'	'	'	1,109
2015	133,012	'	'	'	'	'	1,077
2016	14,064	'	'	'	'	'	946
2017	69,615	'	'	'	'	'	895
2018	102,291	'	'	'	'	'	1,125
Thereafter to 2031, including redemption amount	928,267	'	'	'	'	'	20,859
Redemption amount	'	'	'	'	5,340	'	'
Estimated dividend and redemption payments	31,351	'	'	'	'	'	'
Amounts Representing Interest Payments	'	'	'	'	-12,546	'	'
Total Preferred shares series C	'	'	'	'	18,805	'	'
Less current portion	-1,038	0	'	'	-1,038	'	'
Preferred Shares Series C, noncurrent	17,767	0	'	'	17,767	'	'

Other_assets_Detail

Other assets (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Disclosure Other Assets [Abstract]	'	'
Restricted cash	6,021	7,063
Deferred financing costs	9,011	8,706
Other	3,752	4,251
Total	18,784	20,020

Other_longterm_liabilities_Det

Other long-term liabilities (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Schedule of Other Liabilities [Line Items]	'	'
Asset retirement obligations	9,508	7,088
Customer deposits	8,774	5,620
Provision for injury and damages	1,215	3,480
Deferred water rights inducement	17,115	25,816
Contingent consideration	1,102	1,031
Other	4,580	5,177
Other Liabilities	27,943	25,241
Less: current portion	-7,451	-4,352
Other long-term liabilities	20,492	20,889
Water Rights	'	'
Schedule of Other Liabilities [Line Items]	'	'
Deferred water rights inducement	2,764	2,845

Shareholders_capital_Common_Sh

Shareholders' capital - Common Shares (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Common Shares Rollforward	'	'
Beginning balance (in shares)	188,763,486	136,122,780
Conversion and redemption of convertible debentures (in shares)	150,816	24,991,784
Conversion of subscription receipts (in shares)	15,223,016	26,380,750
Issuance of shares under the dividend reinvestment and employee share purchase plans (in shares)	2,211,667	1,268,172
Ending balance (in shares)	206,348,985	188,763,486

Shareholders_capital_Additiona

Shareholders' capital - Additional Information (Detail)

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Apr. 23, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 23, 2013

Mar. 27, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 09, 2012

Dec. 31, 2013

Jan. 02, 2013

Jan. 02, 2013

Jan. 31, 2013

Mar. 05, 2014

Dec. 27, 2012

Dec. 21, 2012

Feb. 14, 2013

Mar. 26, 2013

14-May-12

Jun. 29, 2012

Jul. 31, 2013

Jul. 31, 2012

Feb. 14, 2013

Dec. 10, 2012

Dec. 31, 2013

Mar. 05, 2014

Dec. 31, 2013

Mar. 05, 2014

Right

CAD

CAD

Death Benefits

Resignation or Termination

Maximum

Minimum

Subsequent Event

Employee Stock Option

Employee Stock Option

Share unit awards

Stock Option Plans

Performance Share Units

Employee share purchase

Employee share purchase

Employee share purchase

Employee share purchase

Employee share purchase

Deferred Share Units

Deferred Share Units

Performance share units

Performance share units

Series 2A

Series 3

Series 3

Series A Preferred Stock

Series A Preferred Stock

Series C Preferred Stock

Series C Preferred Stock

Series C Preferred Stock

Series D Preferred Stock

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Common Stock Subscription

Government of Canada Bond Yield

Government of Canada Bond Yield

Government of Canada Treasury Bill Yield

Government of Canada Treasury Bill Yield

Retirement

CAD

CAD

CAD

Maximum

CAD

CAD

Range One

Range Two

Range Three

CAD

CAD

CAD

CAD

CAD

CAD

CAD

USD ($)

CAD

Subsequent Event

Subsequent Event

Emera

Emera

Subsequent Event

Peach State Gas System

Granite State and EnergyNorth

Sandy Ridge

Midwest Gas Utilities

Midwest Gas Utilities

Senate and Minonk

Senate and Minonk

Series A Preferred Stock

Series D Preferred Stock

Series B Preferred Stock

Series E Preferred Stock

CAD

CAD

Emera

CAD

CAD

CAD

CAD

CAD

CAD

Subsequent Event

Subsequent Event

Stockholders Equity Note [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of voting rights per share

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rights Plan Initial term

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of outstanding stock to be purchased to acquire discount

'

'

'

'

'

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discount rate on share purchases

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,790,000

'

3,421,000

3,960,000

12,000,000

2,614,006

6,976,744

'

7,842,016

'

'

'

'

'

Shares Issued, Price Per Share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

25

'

4.72

'

7.4

5

5.74

'

6.45

'

5.74

'

'

'

'

Stock issuance cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,700,000

'

'

'

'

3,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payment of Stock Issuance Costs, Net of Tax

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,454,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal amount of debt converted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

59,957,000

960,000

61,611,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares issued upon conversion of debt

'

15,223,016

26,380,750

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,322,518

150,816

14,669,266

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash proceeds from issuance of shares

'

29,983,000

143,041,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38,756,000

'

29,304,000

60,000,000

15,000,000

45,000,000

'

'

45,000,000

'

'

'

'

Common Stock, Shares Subscribed but Unissued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,211,000

'

'

'

'

'

'

'

7,842,016

'

'

'

'

Total number of subscription receipts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,790,000

'

3,421,000

'

'

'

'

'

'

'

'

'

'

'

Discount rate on share purchases under dividend reinvestment plan

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional shares issued under dividend reinvestment plan

'

'

'

'

'

'

'

501,818

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock issued, shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,800,000

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share proceeds before issuance cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120,000,000

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed cumulative annual dividend per share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.125

'

'

'

1.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred shares, annual dividend rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend variable interest rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.94%

3.28%

2.94%

3.28%

Preferred Stock, Redemption Price Per Share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

$53,400

53,400

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redeemable Preferred stock issued, shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

100

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total share-based compensation expense

'

2,046,000

1,833,000

'

'

'

'

'

1,687,000

1,376,000

'

'

'

75,000

42,000

'

'

'

'

'

129,000

260,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation costs, non-vested options

'

'

'

'

'

'

'

'

1,762,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation costs, non-vested options, period of recognition

'

'

'

'

'

'

'

'

'1 year 6 months 26 days

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation costs, non-vested awards

'

'

'

'

'

'

'

'

'

'

86,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of shares reserves under plan

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock options exercised period

'

'

'

'1 year

'30 days

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employer matching contribution, percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

10.00%

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Vesting period of matching contribution shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum aggregate number of shares reserved for issuance from treasury

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares issued

'

'

'

'

'

'

'

'

'

'

'

'

'

85,410

54,227

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares issued during period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

74,786

50,172

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

184.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Shares to be Repurchased Next Year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,928

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of Performance Goals Achieved

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shareholders_capital_ShareBase

Shareholder's capital - Share-Based Compensation Expense (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]	'	'
Share-based compensation expense	2,046	1,833
Stock options	'	'
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]	'	'
Share-based compensation expense	1,687	1,376
Directors deferred share units	'	'
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]	'	'
Share-based compensation expense	155	155
Employee share purchase	'	'
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]	'	'
Share-based compensation expense	75	42
Performance share units	'	'
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]	'	'
Share-based compensation expense	129	260

Shareholders_capital_Fair_Valu

Shareholders' capital - Fair Value of Share Options Granted (Detail) (CAD)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]	'	'
Risk-free interest rate	1.61%	1.70%
Expected volatility	37.00%	38.00%
Expected dividend yield	3.83%	4.40%
Expected life	'8 years	'8 years
Weighted average grant date fair value per option (CAD per share)	2	1.49

Shareholders_capital_Stock_Opt

Shareholders' capital - Stock Option Activity (Detail) (CAD)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of awards	'	'	'
Beginning balance, Shares	3,750,727	2,487,105	'
Granted, Shares	816,402	1,263,622	'
Ending balance, Shares	4,567,129	3,750,727	2,487,105
Exercisable, Shares	2,466,008	'	'
Weighted average exercise price	'	'	'
Beginning balance (CAD per share)	5.25	4.76	'
Granted (CAD per share)	7.72	6.24	'
Ending balance (CAD per share)	5.7	5.25	4.76
Exercisable (CAD per share)	4.9	'	'
Additional Disclosures	'	'	'
Outstanding shares, weighted average remaining contractual term	'5 years 5 months 12 days	'6 years 0 months 26 days	'6 years 11 months 16 days
Granted, Weighted average remaining contractual term	'8 years	'8 years	'
Exercisable , Weighted average remaining contractual term	'4 years 11 months 16 days	'	'
Beginning balance, aggregate intrinsic value	5,939	4,134	'
Granted, aggregate intrinsic value	0	0	'
Ending balance, aggregate intrinsic value	7,814	5,939	4,134
Exercisable , aggregate intrinsic value	6,018	'	'

Shareholders_capital_Performan

Shareholder's capital - Performance Stock Units (Detail) (Performance share units, CAD)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance share units	'	'	'
Number of awards	'	'	'
Beginning balance, Shares	83,483	21,123	'
Granted, Shares	5,537	68,982	'
Exercised, Shares	-20,640	'	'
Forfeited, Shares	-2,185	-6,622	'
Ending balance, Shares	66,195	83,483	21,123
Exercisable, Shares	24,928	'	'
Weighted Average Grant-Date Fair Value	'	'	'
Beginning balance (CAD per share)	6.58	5.62	'
Granted (CAD per share)	6.79	6.78	'
Exercised (CAD per share)	6.7	'	'
Forfeited (CAD per share)	6.7	5.62	'
Ending balance (CAD per share)	6.57	6.58	5.62
Exercisable (CAD per share)	6.14	'	'
Additional Disclosures	'	'	'
Outstanding, Weighted average remaining contractual term	'7 months 13 days	'1 year 9 months 18 days	'2 years
Granted, Weighted average remaining contractual term	'1 year 2 months 23 days	'1 year 3 months 18 days	'
Forfeited ,Weighted average remaining contractual term	'	'1 year 6 months	'
Outstanding, aggregate intrinsic value	486	571	136
Granted, aggregate intrinsic value	41	467	'
Exercised, aggregate intrinsic value	-151	'	'
Forfeited, aggregate intrinsic value	-16	-37	'
Exercisable, aggregate intrinsic value	183	'	'

Recovered_Sheet4

Accumulated Other Comprehensive loss (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'
Beginning balance	-104,867	'
Other comprehensive income (loss), net of tax	115,632	-6,689
Ending balance	-31,410	-104,867
Foreign currency cumulative translation	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'
Beginning balance	-105,957	-96,462
Other comprehensive income (loss) before reclassifications	39,422	-9,495
Amounts reclassified from accumulated other comprehensive loss	0	'
Other comprehensive income (loss), net of tax	39,422	-9,495
Ending balance	-66,535	-105,957
Unrealized gain on cash flow hedges	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'
Beginning balance	3,596	0
Other comprehensive income (loss) before reclassifications	19,421	3,596
Amounts reclassified from accumulated other comprehensive loss	-2,113	'
Other comprehensive income (loss), net of tax	17,308	3,596
Ending balance	20,904	3,596
Pension and post-retirement actuarial loss	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'
Beginning balance	-2,506	-48
Other comprehensive income (loss) before reclassifications	16,698	-2,459
Amounts reclassified from accumulated other comprehensive loss	29	1
Other comprehensive income (loss), net of tax	16,727	-2,458
Ending balance	14,221	-2,506
Accumulated OCI	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'
Beginning balance	-104,867	-96,510
Other comprehensive income (loss) before reclassifications	75,541	-8,358
Amounts reclassified from accumulated other comprehensive loss	-2,084	1
Other comprehensive income (loss), net of tax	73,457	-8,357
Ending balance	-31,410	-104,867

Noncontrolling_Interests_Detai

Noncontrolling Interests (Details) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Noncontrolling Interest [Line Items]	'	'
Total net earnings/(loss) attributable to noncontrolling interests	-10,813	7,414
Other Noncontrolling Interests	'	'
Noncontrolling Interest [Line Items]	'	'
Total net earnings/(loss) attributable to noncontrolling interests	39	1,316
Class B Units | Noncontrolling Interest, Class B Partnership Units of SponsorCo	'	'
Noncontrolling Interest [Line Items]	'	'
Total net earnings/(loss) attributable to noncontrolling interests	9,556	-4,580
Class A Units | Class A Partnership Units	'	'
Noncontrolling Interest [Line Items]	'	'
Total net earnings/(loss) attributable to noncontrolling interests	-20,408	10,678

Cash_Dividends_Detail

Cash Dividends (Detail) (CAD)	0 Months Ended	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
Dividends [Line Items]	'	'	'
Dividend declared for common share holders	'	68,291	50,196
Cash dividend declared per common share	0.085	0.3325	0.295
Series A Preferred Stock	'	'	'
Dividends [Line Items]	'	'	'
Dividend paid	'	5,400	769
Dividend declared per preferred share	'	1.125	0.1603

Income_taxes_Additional_Inform

Income taxes - Additional Information (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2009
Income Tax Disclosure [Abstract]	'	'	'
Canadian enacted statutory rate	26.50%	26.50%	'
Deferred credit related to business combination	'	'	55,647
Valuation allowance for deferred tax assetS	15,667	15,062	'

Income_taxes_Provision_for_Inc

Income taxes - Provision for Income Taxes (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Expected income tax expense / (recovery) at Canadian statutory rate	16,072	1,726
Increase (decrease) resulting from:	'	'
Recognition of deferred credit	-6,676	-5,092
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	-2,338	-6,282
Non-taxable corporate dividend	-2,896	-666
Noncontrolling interests share of income	4,266	-2,835
Production tax credit	-247	-676
Allowance for equity funds used during construction	-694	-402
State taxes	313	0
Other	1,355	-140
Income tax recovery	9,155	-14,367

Income_taxes_Income_Loss_Befor

Income taxes - Income (Loss) Before Taxes (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]	'	'
Income/(loss) before taxes	60,649	6,536
CANADA	'	'
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]	'	'
Income/(loss) before taxes	19,687	12,251
UNITED STATES	'	'
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]	'	'
Income/(loss) before taxes	40,962	-5,715

Income_taxes_Income_Tax_Expens

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Expenses [Line Items]	'	'
Income tax expenses, current	2,526	738
Income tax expenses, deferred	6,629	-15,105
Income tax recovery	9,155	-14,367
CANADA	'	'
Income Tax Expenses [Line Items]	'	'
Income tax expenses, current	1,532	127
Income tax expenses, deferred	881	-938
Income tax recovery	2,413	-811
UNITED STATES	'	'
Income Tax Expenses [Line Items]	'	'
Income tax expenses, current	994	611
Income tax expenses, deferred	5,748	-14,167
Income tax recovery	6,742	-13,556

Income_taxes_Tax_Effect_on_Sig

Income taxes - Tax Effect on Significant Portions of Deferred Tax Assets and Deferred Tax Liabilities (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets:	'	'
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	226,314	184,845
Pension and OPEB	31,433	5,011
Acquisition related costs	5,152	5,134
Outside basis in partnership	0	2,533
Regulatory accounts	0	4,013
Financial derivatives	0	211
Environmental obligation	23,076	22,414
Production tax credit	1,633	673
Reserves not currently deductible	2,397	1,276
Other	2,780	136
Total deferred income tax assets	292,785	226,246
Less: Valuation allowance	-15,667	-15,062
Total deferred tax assets	277,118	211,184
Deferred tax liabilities:	'	'
Property, plant and equipment	-267,344	-219,573
Intangible assets	-8,321	-5,478
Outside basis in partnership	-2,210	0
Regulatory accounts	-24,745	0
Financial derivatives	7,675	0
Total deferred tax liabilities	-310,295	-225,051
Net deferred income tax assets/(liabilities)	-33,177	-13,867

Income_taxes_Classification_of

Income taxes - Classification of Deferred Income Tax (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]	'	'
Current deferred income tax asset	19,652	10,567
Non-current deferred income tax asset	86,632	77,497
Current deferred income tax liability	-2,308	-1,133
Non-current deferred income tax liability	-137,153	-100,798
Net deferred income tax assets/(liabilities)	-33,177	-13,867

Income_taxes_Non_Capital_Losse

Income taxes - Non Capital Losses Carry Forwards (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Capital Loss Carryforwards [Line Items]	'
Non-capital losses carry forwards	469,036
Expires 2015	'
Capital Loss Carryforwards [Line Items]	'
Non-capital losses carry forwards	5,426
Expires 2016 and onwards	'
Capital Loss Carryforwards [Line Items]	'
Non-capital losses carry forwards	463,610

Divestitures_Additional_Inform

Divestitures - Additional Information (Detail)	12 Months Ended		3 Months Ended		0 Months Ended	1 Months Ended	9 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Jun. 30, 2013	Jun. 29, 2013	Aug. 31, 2012	Dec. 31, 2014
	CAD	CAD	EFW Thermal Facility	EFW Thermal Facility	U.S. Hydro Facilities	U.S. Hydro Facilities	U.S. Hydro Facilities
			CAD	CAD	USD ($)	USD ($)	Forecast
					Facility		USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'
Write down of net assets, before tax	'	'	9,200	47,651	'	'	'
Write down of net assets, net tax	'	'	6,800	35,738	'	'	'
Write down of net assets, tax	'	'	2,400	11,913	'	'	'
Net proceeds of disposition	22,052	0	'	'	23,400	350	3,600
Number of facilities sold	'	'	'	'	9	'	'
Gain (loss) on sale, net of tax	'	'	'	'	960	-253	'
Gain (loss) on sale, tax	'	'	'	'	$1,605	'	'

Divestitures_Summary_of_Operat

Divestitures - Summary of Operating Results and Cash Flows (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'
Non-regulated energy sales	9,327	9,670
Waste disposal fees	8,160	14,288
Other and interest income	336	-6
Operating and administrative expenses	-19,720	-15,785
Foreign exchange	80	0
Depreciation of property, plant and equipment	-2,483	-6,473
Interest expense	-58	-321
Gain on sale of assets	1,016	0
Write-off of accounts receivable	-262	0
Write-down of long-lived assets	-56,898	-276
Gain/(loss) from discontinued operations, before income taxes	-60,502	1,097
Income tax recovery/(expense)	18,491	-54
Gain/(loss) from discontinued operations, net of income taxes	-42,011	1,043
Disposal Group, Including Discontinued Operation, Additional Disclosures [Abstract]	'	'
Depreciation of property, plant and equipment	-2,483	-6,473
Write-off of accounts receivable	-262	0
Write-down of long-lived assets	-56,898	-276
Net proceeds of disposition	22,052	0
Contingent liability	-613	0
Income tax recovery/(expense)	18,491	-54
Increase/(decrease) in cash and cash equivalents from discontinued operations	20,580	7,846
As Reported	'	'
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'
Non-regulated energy sales	'	2,870
Waste disposal fees	'	0
Other and interest income	'	0
Operating and administrative expenses	'	-3,241
Foreign exchange	'	0
Depreciation of property, plant and equipment	'	-1,279
Interest expense	'	-4
Gain on sale of assets	'	0
Write-off of accounts receivable	'	0
Write-down of long-lived assets	'	-253
Gain/(loss) from discontinued operations, before income taxes	'	-1,907
Income tax recovery/(expense)	'	750
Gain/(loss) from discontinued operations, net of income taxes	'	-1,157
Disposal Group, Including Discontinued Operation, Additional Disclosures [Abstract]	'	'
Depreciation of property, plant and equipment	'	-1,279
Write-off of accounts receivable	'	0
Write-down of long-lived assets	'	-253
Net proceeds of disposition	'	0
Contingent liability	'	0
Income tax recovery/(expense)	'	750
Increase/(decrease) in cash and cash equivalents from discontinued operations	'	-375
Adjustments	'	'
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'
Non-regulated energy sales	'	6,800
Waste disposal fees	'	14,288
Other and interest income	'	-6
Operating and administrative expenses	'	-12,544
Foreign exchange	'	0
Depreciation of property, plant and equipment	'	-5,194
Interest expense	'	-317
Gain on sale of assets	'	0
Write-off of accounts receivable	'	0
Write-down of long-lived assets	'	-23
Gain/(loss) from discontinued operations, before income taxes	'	3,004
Income tax recovery/(expense)	'	-804
Gain/(loss) from discontinued operations, net of income taxes	'	2,200
Disposal Group, Including Discontinued Operation, Additional Disclosures [Abstract]	'	'
Depreciation of property, plant and equipment	'	-5,194
Write-off of accounts receivable	'	0
Write-down of long-lived assets	'	-23
Net proceeds of disposition	'	0
Contingent liability	'	0
Income tax recovery/(expense)	'	-804
Increase/(decrease) in cash and cash equivalents from discontinued operations	'	8,221

Divestitures_Assets_Held_for_S

Divestitures - Assets Held for Sale (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Property, plant and equipment	21,193	100,827
Accounts receivable and prepaid expenses	2,734	2,510
Total assets held for sale	23,927	103,337
Less current assets held for sale	-23,927	-26,900
Non-current assets held for sale	0	76,437
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable and accrued liabilities	1,471	1,211
As Reported	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Property, plant and equipment	'	24,390
Accounts receivable and prepaid expenses	'	0
Total assets held for sale	'	24,390
Less current assets held for sale	'	-24,390
Non-current assets held for sale	'	0
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable and accrued liabilities	'	0
Adjustments	'	'
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Property, plant and equipment	'	76,437
Accounts receivable and prepaid expenses	'	2,510
Total assets held for sale	'	78,947
Less current assets held for sale	'	-2,510
Non-current assets held for sale	'	76,437
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'	'
Accounts payable and accrued liabilities	'	1,211

Related_party_transactions_Det

Related party transactions (Detail)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2004

Dec. 31, 2003

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2004

Jan. 02, 2013

Jan. 02, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2004

Dec. 31, 2013

CAD

CAD

Emera

Series C Preferred Stock

Parties

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Management

Maine Public Service Company

Maine Public Service Company

Maine Public Service Company

Subsidiaries of Liberty Utilities Co

Subsidiaries of Liberty Utilities Co

St. Leon Limited Partnership

St. Leon Limited Partnership

Rattlebrook hydroelectric facility

Rattlebrook hydroelectric facility

Long Sault Hydro Facility

Long Sault Hydro Facility

Long Sault Hydro Facility

Brampton Cogeneration Plant

Brampton Cogeneration Plant

Minimum

Facility

USD ($)

CAD

CAD

CAD

CAD

CAD

Advance against expense reimbursements

Advance against expense reimbursements

Legal fees expense

Class B limited partnership units

Series C Preferred Stock

USD ($)

Energy Service

Energy Service

CAD

CAD

Management

Management

CAD

Parties

MW

Algonquin Power Management Inc.

Algonquin Power Co

Algonquin Power Management Inc.

Algonquin Power Management Inc.

Brampton Cogeneration Plant

CAD

CAD

CAD

USD ($)

USD ($)

CAD

CAD

MW

note

CAD

Algonquin Power Management Inc.

Transactions with Third Party [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amounts due from related party

'

816,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amounts due to related party

'

1,811,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost in connection with aircraft

'

'

'

'

'

472,000

598,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Legal fees funded

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reimbursements expenses

'

'

'

'

1,829,000

'

'

1,300,000

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reimbursement of fees

'

'

'

'

812,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of facilities

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated legal fees

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization expense

'

'

'

'

'

'

'

'

'

0

279,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash distributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

175,000

'

'

'

'

'

'

'

'

Preferred stock shares issued (in shares)

'

'

'

100

'

'

'

'

'

'

'

'

'

36

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base lease costs

'

'

'

'

'

310,000

333,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest on hydroelectric generating facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.00%

'

'

'

'

'

'

'

Equity interest in hydroelectric generating facility held by senior executives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

55.00%

'

'

'

'

'

'

Ownership interest exchange

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.00%

'

'

'

'

'

'

'

Project power capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

18

'

'

'

'

'

Proceeds from sale of interest in investment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,408,000

'

'

'

'

'

'

'

Tax

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

422,000

'

'

'

'

'

'

'

Fees received for related party transactions

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment in partnership units (in units)

'

'

'

'

'

'

'

'

'

'

'

'

100

'

'

'

'

'

'

100

'

'

'

'

'

'

'

'

'

Payments to acquire partnership interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,780,000

'

'

'

Number of notes acquired from original partnership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

Percentage of future cash flows of the facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

50.00%

'

'

Units of partnership interests (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

Percent return on investment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

Adjustment of deferred tax liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,692,000

'

'

'

Adjustment to equity for shareholders

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,601,000

'

'

'

Corporate guarantee

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Inter-company Sales

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,042,000

6,096,000

'

'

'

'

'

'

'

'

'

'

'

'

Standard offer service contract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Corporate guarantee and letter of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Related party transactions, expenses paid

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

29,000

'

'

'

'

'

'

'

'

'

'

'

Basic_and_diluted_net_earnings2

Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) (CAD)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Basic and Diluted [Abstract]	'	'
Net earnings attributable to shareholders of APUC	20,296	14,532
Series A preferred shares dividend	5,400	769
Net earnings attributable to common shareholders of APUC - Basic and Diluted	14,896	13,763
Discontinued operations	-42,011	1,043
Net earnings attributable to common shareholders of APUC from continuing operations - Basic and Diluted	56,907	12,720
Weighted average number of shares	'	'
Basic	204,350,689	158,304,340
Dilutive effect of share-based awards	980,697	605,281
Diluted	205,331,386	158,909,621

Basic_and_diluted_net_earnings3

Basic and diluted net earnings per share - Additional Information (Detail) (Options and Convertible Debentures)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Options and Convertible Debentures	'	'
Class of Stock [Line Items]	'	'
Anti-dilutive convertible debentures	885,418	1,354,531

Commitments_and_contingencies_1

Commitments and contingencies - Additional Information (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Oct. 21, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified			Minimum	Maximum	Water Rights	Water Rights	Leases	Environmental costs	Environmental costs	Power Purchase Agreement	Subsequent Event
										Minimum
Commitment And Contingencies [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Loss Contingency, Range of Possible Loss, Minimum	'	'	'	'	'	'	'	'	'	'	'
Water lease claim payment	'	'	'	'	5,400	'	'	'	'	'	'
Potential unrecoverable loss	'	'	'	'	'	6,000	'	'	'	'	'
Claims paid to government of Quebec	'	'	'	'	'	'	1,884	'	'	'	'
Estimated environmental remediation costs	77,729	'	'	'	'	'	'	'	'	'	'
Estimated environmental remediation costs, net	69,555	57,340	'	'	'	'	'	'	'	'	'
Decrease in estimated environmental remediation costs	'	'	'	'	'	'	'	'	'	'	4,200
Accrual environmental cost	'	'	3.80%	4.50%	'	'	'	'	'	'	'
Recovery of actual expenditures for site investigation and remediation over, period	'	'	'	'	'	'	'	'7 years	'	'	'
Amount of regulatory assets	190,348	134,392	'	'	'	'	'	80,438	59,789	'	'
Estimated capital expenditure	15,400	'	'	'	'	'	'	'	'	'	'
Number of contractual years	'	'	'	'	'	'	'	'	'	'5 years	'

Commitments_and_contingencies_2

Commitments and contingencies - Investigation and Remediation Costs in Next Five Years (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Estimated cash flows for site investigation and remediation costs in the next five years and thereafter	'
2014	10,111
2015	27,285
2016	17,873
2017	2,128
2018	1,784
Thereafter to 2046	18,548
Estimated environmental remediation costs	77,729

Commitments_and_contingencies_3

Commitments and contingencies - Estimates of Future Commitments (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments Disclosure [Line Items]	'
Year 1	185,343
Year 2	104,411
Year 3	46,678
Year 4	43,241
Year 5	40,924
Thereafter	638,050
Total	1,058,647
Purchased power	'
Commitments Disclosure [Line Items]	'
Year 1	64,626
Year 2	46,865
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total	111,491
Gas delivery, service and supply agreements	'
Commitments Disclosure [Line Items]	'
Year 1	42,125
Year 2	26,364
Year 3	13,812
Year 4	9,869
Year 5	9,476
Thereafter	54,495
Total	156,141
Service agreements	'
Commitments Disclosure [Line Items]	'
Year 1	24,130
Year 2	24,371
Year 3	28,922
Year 4	29,639
Year 5	27,897
Thereafter	498,342
Total	633,301
Capital projects	'
Commitments Disclosure [Line Items]	'
Year 1	49,337
Year 2	2,260
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total	51,597
Operating leases	'
Commitments Disclosure [Line Items]	'
Year 1	5,125
Year 2	4,551
Year 3	3,944
Year 4	3,733
Year 5	3,551
Thereafter	85,213
Total	106,117

Changes_in_NonCash_Operating_I

Changes in Non-Cash Operating Items (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations	'	'
Accounts receivable	-213	-313
Prepaid expenses	-11	135
Accrued liabilities	260	-230
Changes in non-cash operating items, discontinued operations	36	-408
Continuing Operations	'	'
Accounts receivable	-49,888	-14,582
Related party balances	-996	1,476
Natural gas inventory	-6,330	0
Supplies and consumable inventory	-525	-3,621
Income tax receivable	177	-423
Prepaid expenses	-485	-4,764
Accounts payable	-29,292	-7,553
Accrued liabilities	37,023	31,335
Current income tax liability	1,399	131
Net regulatory assets and liabilities	1,098	-5,475
Changes in non-cash operating items	-47,819	-3,476

Segmented_information_Results_

Segmented information - Results of Operations and Assets for Segments (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenue	'	'
Regulated electricity sales and distribution	166,156	108,457
Regulated gas sales and distribution	261,672	75,718
Regulated water reclamation and distribution	57,350	46,423
Non-regulated energy sales	180,191	114,351
Other revenue	9,922	3,857
Total revenue	675,291	348,806
Operating expenses	188,952	117,826
Regulated electricity purchased	97,376	68,209
Regulated gas purchased	148,784	37,461
Non-regulated fuel for generation	17,151	14,589
Gross Profit, Total	223,028	110,721
Depreciation of property, plant and equipment	-91,978	-45,187
Amortization of intangible assets	-4,200	-4,151
Administration expenses	-23,518	-19,572
Foreign exchange gain	567	561
Interest expense	-53,345	-35,620
Interest, dividend and other income	7,785	7,239
Loss on sale of asset	-750	0
Acquisition related costs	-2,140	-7,688
Gain/(loss) on derivative financial instruments	5,200	233
Earnings from continuing operations before income taxes	60,649	6,536
Loss from discontinued operations before income taxes	-60,502	1,097
Earnings/(loss) before income taxes	147	7,633
Property, plant and equipment	2,708,704	2,086,278
Intangible assets	54,416	56,781
Total Assets held for sale	23,927	103,337
Total assets	3,472,557	2,778,990
Capital expenditures	158,377	77,929
Acquisition of operating entities	239,014	669,905
Algonquin Power Co	'	'
Revenue	'	'
Regulated electricity sales and distribution	0	0
Regulated gas sales and distribution	0	0
Regulated water reclamation and distribution	0	0
Non-regulated energy sales	180,191	114,351
Other revenue	9,500	3,611
Total revenue	189,691	117,962
Operating expenses	57,480	38,876
Regulated electricity purchased	0	0
Regulated gas purchased	0	0
Non-regulated fuel for generation	17,151	14,589
Gross Profit, Total	115,060	64,497
Depreciation of property, plant and equipment	-50,561	-23,605
Amortization of intangible assets	-3,508	-3,484
Administration expenses	-13,317	-11,600
Foreign exchange gain	0	0
Interest expense	-28,437	-16,793
Interest, dividend and other income	2,060	2,547
Loss on sale of asset	-750	'
Acquisition related costs	-628	-3,134
Gain/(loss) on derivative financial instruments	-767	-2,954
Earnings from continuing operations before income taxes	19,152	5,474
Loss from discontinued operations before income taxes	-60,502	1,097
Earnings/(loss) before income taxes	-41,350	6,571
Property, plant and equipment	1,444,671	1,234,500
Intangible assets	32,500	35,612
Total Assets held for sale	23,927	103,337
Total assets	1,609,066	1,447,963
Capital expenditures	49,516	31,416
Acquisition of operating entities	2,083	245,718
Algonquin Power Co | Renewable Energy	'	'
Revenue	'	'
Regulated electricity sales and distribution	0	0
Regulated gas sales and distribution	0	0
Regulated water reclamation and distribution	0	0
Non-regulated energy sales	145,661	84,236
Other revenue	7,058	1,925
Total revenue	152,719	86,161
Operating expenses	48,966	30,308
Regulated electricity purchased	0	0
Regulated gas purchased	0	0
Non-regulated fuel for generation	0	0
Gross Profit, Total	103,753	55,853
Depreciation of property, plant and equipment	-45,122	-18,823
Amortization of intangible assets	-2,652	-2,653
Administration expenses	-13,094	-9,424
Foreign exchange gain	0	0
Interest expense	-27,391	-15,060
Interest, dividend and other income	1,867	2,038
Loss on sale of asset	-750	'
Acquisition related costs	-628	-3,155
Gain/(loss) on derivative financial instruments	-767	-2,954
Earnings from continuing operations before income taxes	15,216	5,822
Loss from discontinued operations before income taxes	1,128	-1,925
Earnings/(loss) before income taxes	16,344	3,897
Property, plant and equipment	1,364,843	1,157,062
Intangible assets	26,802	29,480
Total Assets held for sale	3,860	24,390
Total assets	1,492,144	1,272,037
Capital expenditures	46,885	21,068
Acquisition of operating entities	2,083	245,718
Algonquin Power Co | Thermal Energy	'	'
Revenue	'	'
Regulated electricity sales and distribution	0	0
Regulated gas sales and distribution	0	0
Regulated water reclamation and distribution	0	0
Non-regulated energy sales	34,530	30,115
Other revenue	2,442	1,686
Total revenue	36,972	31,801
Operating expenses	8,514	8,568
Regulated electricity purchased	0	0
Regulated gas purchased	0	0
Non-regulated fuel for generation	17,151	14,589
Gross Profit, Total	11,307	8,644
Depreciation of property, plant and equipment	-5,439	-4,782
Amortization of intangible assets	-856	-831
Administration expenses	-223	-2,176
Foreign exchange gain	0	0
Interest expense	-1,046	-1,733
Interest, dividend and other income	193	509
Loss on sale of asset	0	'
Acquisition related costs	0	21
Gain/(loss) on derivative financial instruments	0	0
Earnings from continuing operations before income taxes	3,936	-348
Loss from discontinued operations before income taxes	-61,630	3,022
Earnings/(loss) before income taxes	-57,694	2,674
Property, plant and equipment	79,828	77,438
Intangible assets	5,698	6,132
Total Assets held for sale	20,067	78,947
Total assets	116,922	175,926
Capital expenditures	2,631	10,348
Acquisition of operating entities	0	0
Liberty Utilities	'	'
Revenue	'	'
Regulated electricity sales and distribution	166,156	108,457
Regulated gas sales and distribution	261,672	75,718
Regulated water reclamation and distribution	57,350	46,423
Non-regulated energy sales	0	0
Other revenue	22	246
Total revenue	485,200	230,844
Operating expenses	131,472	78,950
Regulated electricity purchased	97,376	68,209
Regulated gas purchased	148,784	37,461
Non-regulated fuel for generation	0	0
Gross Profit, Total	107,568	46,224
Depreciation of property, plant and equipment	-41,417	-21,582
Amortization of intangible assets	-692	-667
Administration expenses	-7,477	-5,020
Foreign exchange gain	0	0
Interest expense	-23,734	-8,856
Interest, dividend and other income	3,228	2,574
Loss on sale of asset	0	'
Acquisition related costs	-1,512	-4,554
Gain/(loss) on derivative financial instruments	0	0
Earnings from continuing operations before income taxes	35,964	8,119
Loss from discontinued operations before income taxes	0	0
Earnings/(loss) before income taxes	35,964	8,119
Property, plant and equipment	1,264,033	851,778
Intangible assets	21,916	21,169
Total Assets held for sale	0	0
Total assets	1,669,707	1,177,070
Capital expenditures	108,861	46,446
Acquisition of operating entities	236,931	424,187
Liberty Utilities | Central	'	'
Revenue	'	'
Regulated electricity sales and distribution	0	0
Regulated gas sales and distribution	78,857	25,802
Regulated water reclamation and distribution	18,242	9,127
Non-regulated energy sales	0	0
Other revenue	0	0
Total revenue	97,099	34,929
Operating expenses	27,455	13,096
Regulated electricity purchased	0	0
Regulated gas purchased	46,018	13,648
Non-regulated fuel for generation	0	0
Gross Profit, Total	23,626	8,185
Depreciation of property, plant and equipment	-9,096	-3,333
Amortization of intangible assets	-81	-81
Administration expenses	-1,677	294
Foreign exchange gain	0	0
Interest expense	-5,069	-96
Interest, dividend and other income	375	0
Acquisition related costs	-68	-1,442
Gain/(loss) on derivative financial instruments	0	0
Earnings from continuing operations before income taxes	8,010	3,527
Loss from discontinued operations before income taxes	0	0
Earnings/(loss) before income taxes	8,010	3,527
Property, plant and equipment	215,090	151,637
Intangible assets	2,709	2,613
Total Assets held for sale	0	0
Total assets	285,517	212,495
Capital expenditures	28,566	10,777
Acquisition of operating entities	27,545	128,890
Liberty Utilities | West	'	'
Revenue	'	'
Regulated electricity sales and distribution	77,814	71,734
Regulated gas sales and distribution	0	0
Regulated water reclamation and distribution	39,108	37,296
Non-regulated energy sales	0	0
Other revenue	22	152
Total revenue	116,944	109,182
Operating expenses	36,753	35,645
Regulated electricity purchased	39,750	43,861
Regulated gas purchased	0	0
Non-regulated fuel for generation	0	0
Gross Profit, Total	40,441	29,676
Depreciation of property, plant and equipment	-13,596	-11,120
Amortization of intangible assets	-611	-586
Administration expenses	-2,541	-4,091
Foreign exchange gain	0	0
Interest expense	-8,519	-8,066
Interest, dividend and other income	1,395	2,113
Loss on sale of asset	0	'
Acquisition related costs	0	0
Gain/(loss) on derivative financial instruments	0	0
Earnings from continuing operations before income taxes	16,569	7,926
Loss from discontinued operations before income taxes	0	0
Earnings/(loss) before income taxes	16,569	7,926
Property, plant and equipment	387,715	350,053
Intangible assets	19,207	18,556
Total Assets held for sale	0	0
Total assets	460,209	464,201
Capital expenditures	23,743	23,181
Acquisition of operating entities	0	0
Liberty Utilities | East	'	'
Revenue	'	'
Regulated electricity sales and distribution	88,342	36,723
Regulated gas sales and distribution	182,815	49,916
Regulated water reclamation and distribution	0	0
Non-regulated energy sales	0	0
Other revenue	0	94
Total revenue	271,157	86,733
Operating expenses	67,264	30,209
Regulated electricity purchased	57,626	24,348
Regulated gas purchased	102,766	23,813
Non-regulated fuel for generation	0	0
Gross Profit, Total	43,501	8,363
Depreciation of property, plant and equipment	-18,725	-7,129
Amortization of intangible assets	0	0
Administration expenses	-3,259	-1,223
Foreign exchange gain	0	0
Interest expense	-10,146	-694
Interest, dividend and other income	1,458	461
Loss on sale of asset	0	'
Acquisition related costs	-1,444	-3,112
Gain/(loss) on derivative financial instruments	0	0
Earnings from continuing operations before income taxes	11,385	-3,334
Loss from discontinued operations before income taxes	0	0
Earnings/(loss) before income taxes	11,385	-3,334
Property, plant and equipment	661,228	350,088
Intangible assets	0	0
Total Assets held for sale	0	0
Total assets	923,981	500,374
Capital expenditures	56,552	12,488
Acquisition of operating entities	209,386	295,297
Corporate	'	'
Revenue	'	'
Regulated electricity sales and distribution	0	0
Regulated gas sales and distribution	0	0
Regulated water reclamation and distribution	0	0
Non-regulated energy sales	0	0
Other revenue	400	0
Total revenue	400	0
Operating expenses	0	0
Regulated electricity purchased	0	0
Regulated gas purchased	0	0
Non-regulated fuel for generation	0	0
Gross Profit, Total	400	0
Depreciation of property, plant and equipment	0	0
Amortization of intangible assets	0	0
Administration expenses	-2,724	-2,952
Foreign exchange gain	567	561
Interest expense	-1,174	-9,971
Interest, dividend and other income	2,497	2,118
Loss on sale of asset	0	'
Acquisition related costs	0	0
Gain/(loss) on derivative financial instruments	5,967	3,187
Earnings from continuing operations before income taxes	5,533	-7,057
Loss from discontinued operations before income taxes	0	0
Earnings/(loss) before income taxes	5,533	-7,057
Property, plant and equipment	0	0
Intangible assets	0	0
Total Assets held for sale	0	0
Total assets	193,784	153,957
Capital expenditures	0	67
Acquisition of operating entities	0	0

Segmented_information_Addition

Segmented information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]	'	'
Number of Countries in which Entity Operates	2	'
Percentage of revenue contributed	80.00%	'
Hydro Quebec	'	'
Segment Reporting Information [Line Items]	'	'
Percentage of revenue contributed	14.00%	17.00%
Manitoba Hydro	'	'
Segment Reporting Information [Line Items]	'	'
Percentage of revenue contributed	14.00%	20.00%
Pacific Gas And Electric Company	'	'
Segment Reporting Information [Line Items]	'	'
Percentage of revenue contributed	9.00%	10.00%
Corporate	'	'
Segment Reporting Information [Line Items]	'	'
Number of business units	2	'
Algonquin Power Co	'	'
Segment Reporting Information [Line Items]	'	'
Number of operating segments	2	'

Segmented_information_Informat

Segmented information - Information on Operations by Geographic Area (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]	'	'
Revenue	675,291	348,806
Property, plant and equipment	2,708,704	2,086,278
Intangible assets	54,416	56,781
CANADA	'	'
Segment Reporting Information [Line Items]	'	'
Revenue	65,380	62,036
Property, plant and equipment	433,153	395,896
Intangible assets	26,802	29,480
UNITED STATES	'	'
Segment Reporting Information [Line Items]	'	'
Revenue	609,911	286,770
Property, plant and equipment	2,275,551	1,690,382
Intangible assets	27,614	27,301

Financial_instruments_Fair_Val

Financial instruments - Fair Value of Financial Instruments (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value of Financial Instruments [Line Items]	'	'
Convertible debentures	'	0
Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Notes receivable, fair value	26,321	25,476
Derivative financial instruments, assets	36,299	13,250
Total financial assets, fair value	62,620	38,726
Long-term liabilities	1,261,340	785,473
Convertible debentures	'	1,319
Derivative financial instruments, liabilities	16,221	17,816
Total financial liabilities, fair value	1,277,561	804,608
Level 1	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Long-term liabilities	296,986	293,348
Convertible debentures	'	1,319
Total financial liabilities, fair value	296,986	294,667
Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	591	555
Total financial assets, fair value	591	555
Long-term liabilities	964,354	492,125
Convertible debentures	'	0
Derivative financial instruments, liabilities	11,440	8,517
Total financial liabilities, fair value	975,794	500,642
Level 3	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Notes receivable, fair value	26,321	25,476
Derivative financial instruments, assets	35,708	12,695
Total financial assets, fair value	62,029	38,171
Derivative financial instruments, liabilities	4,781	9,299
Total financial liabilities, fair value	4,781	9,299
Energy contracts | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	'	287
Energy contracts | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	'	'
Energy contracts | Level 3	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	'	287
Energy contracts | Designated as a hedge | Cash flow hedge | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	31,971	12,695
Derivative financial instruments, liabilities	4,781	9,012
Energy contracts | Designated as a hedge | Cash flow hedge | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	'	0
Energy contracts | Designated as a hedge | Cash flow hedge | Level 3	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	31,971	12,695
Derivative financial instruments, liabilities	4,781	9,012
Energy contracts | Not designated as a hedge | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	3,737	'
Energy contracts | Not designated as a hedge | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	0	'
Energy contracts | Not designated as a hedge | Level 3	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	3,737	'
Cross currency swap | Designated as a hedge | Net Investment Hedging | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	109	408
Derivative financial instruments, liabilities	7,947	2,078
Cross currency swap | Designated as a hedge | Net Investment Hedging | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	109	408
Derivative financial instruments, liabilities	7,947	2,078
Interest rate swaps | Not designated as a hedge | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	3,180	4,778
Interest rate swaps | Not designated as a hedge | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	3,180	4,778
Commodity contracts for regulatory operations | Fair Value	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	482	147
Derivative financial instruments, liabilities	313	1,661
Commodity contracts for regulatory operations | Level 2	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	482	147
Derivative financial instruments, liabilities	313	1,661
Carrying amount	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Notes receivable, fair value	22,678	22,757
Derivative financial instruments, assets	36,299	13,250
Total financial assets, fair value	58,977	36,007
Long-term liabilities	1,255,588	770,826
Convertible debentures	'	960
Derivative financial instruments, liabilities	16,221	17,816
Total financial liabilities, fair value	1,271,809	789,602
Carrying amount | Energy contracts	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	'	287
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	31,971	12,695
Derivative financial instruments, liabilities	4,781	9,012
Carrying amount | Energy contracts | Not designated as a hedge	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	3,737	'
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	109	408
Derivative financial instruments, liabilities	7,947	2,078
Carrying amount | Interest rate swaps | Not designated as a hedge	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, liabilities	3,180	4,778
Carrying amount | Commodity contracts for regulatory operations	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Derivative financial instruments, assets	482	147
Derivative financial instruments, liabilities	313	1,661

Financial_instruments_Addition

Financial instruments - Additional Information (Detail)

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

CAD

CAD

Red Lily

Red Lily

Interest rate swaps

Interest rate swaps

Utility Services

Carrying amount

Carrying amount

Minimum

Maximum

Algonquin Power Co

Algonquin Power Co

CAD

CAD

CAD

CAD

USD ($)

Energy contracts

Energy contracts

CAD

4.82% Senior Unsecured Notes

CAD

CAD

CAD

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated discount rate used to measure fair value of conversion option

'

'

8.50%

8.50%

'

'

'

'

'

'

'

'

'

Derivative assets, fair value

'

'

'

'

'

'

'

'

'

'

'

'

'

Forward price

'

'

'

'

'

'

'

'

'

21.5

181

'

'

Derivative, collateral held by third parties

'

'

'

'

'

'

'

7,344,000

'

'

'

'

'

Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months

4,949,000

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, face value

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

Other comprehensive income, foreign currency loss

-81,597,000

9,399,000

'

'

'

'

'

'

'

'

'

5,771,000

'

Major customer revenue percentage

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

Revenue collection period

'45 days

'

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable balances

'

'

'

'

'

'

101,867,000

'

'

'

'

'

'

Cash on hand

13,839,000

'

'

'

'

'

'

'

'

'

'

'

'

Available for drawn on senior debt facilities

202,665,000

'

'

'

'

'

'

'

'

'

'

'

'

Other comprehensive income, foreign currency loss

1,607,000

'

'

'

'

'

'

'

'

'

'

'

'

Fixed interest rate

'

'

'

'

4.47%

'

'

'

'

'

'

'

'

Notional amount

'

'

'

'

62,706,000

'

'

'

'

'

'

'

'

Estimated fair value

'

'

'

'

3,180,000

4,778,000

'

'

'

'

'

'

'

Financial_instruments_Summary_

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)	Dec. 31, 2013
	DTH
Derivative [Line Items]	'
Commodity volumes, Gas	4,816,408
Financial contracts Gas swaps	'
Derivative [Line Items]	'
Commodity volumes, Gas	2,734,304
Gas options	'
Derivative [Line Items]	'
Commodity volumes, Gas	2,082,104

Financial_instruments_Impact_o

Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) (CAD)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Regulatory assets, natural gas derivative contracts	190,348	134,392
Regulatory liabilities, natural gas derivative contracts	123,289	90,676
Gas swap contracts	'	'
Derivative [Line Items]	'	'
Regulatory assets, natural gas derivative contracts	86	1,555
Regulatory liabilities, natural gas derivative contracts	416	90
Gas options	'	'
Derivative [Line Items]	'	'
Regulatory assets, natural gas derivative contracts	208	106
Regulatory liabilities, natural gas derivative contracts	37	57

Financial_instruments_Longterm

Financial instruments - Long-term Energy Derivative Contracts (Detail)	Dec. 31, 2013
PJM Western HUB, Expiry December 2014	'
Derivative [Line Items]	'
Receive average prices (per MW-hr)	32.64
NI HUB, Expiry December 2014	'
Derivative [Line Items]	'
Receive average prices (per MW-hr)	25.64
ERCOT North HUB, Expiry December 2014	'
Derivative [Line Items]	'
Receive average prices (per MW-hr)	27.39
AESO	'
Derivative [Line Items]	'
Notional quantity (MW-hrs)	147,000
Receive average prices (per MW-hr)	67.36
PJM Western HUB	'
Derivative [Line Items]	'
Notional quantity (MW-hrs)	1,030,000
Receive average prices (per MW-hr)	42.81
Senate	'
Derivative [Line Items]	'
Notional quantity (MW-hrs)	4,396,000
Receive average prices (per MW-hr)	30.25
Minonk	'
Derivative [Line Items]	'
Notional quantity (MW-hrs)	4,663,000
Receive average prices (per MW-hr)	36.46

Financial_instruments_Derivati

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'	'
Gain on derivative instruments (ineffective portion)	1,304	105
Effective portion of cash flow hedge, gain	17,338	5,217
Gain (loss) realized on cash flow hedge	-30	-49
Other Comprehensive Income (Loss), before Tax, Total	17,308	5,168
Less noncontrolling interest	-9,064	-1,572
Change in fair value of cash flow hedge in other comprehensive income	8,244	3,596

Financial_instruments_Other_De

Financial instruments - Other Derivatives (Details)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified	Other Derivatives, Expiry February 2014	Other Derivatives, Expiry March 2015	Energy contracts	Energy contracts
	MWh	MWh	Carrying amount	Carrying amount
			Not designated as a hedge	Not designated as a hedge
			Other Derivatives, Expiry February 2014	Other Derivatives, Expiry March 2015
			CAD	CAD
Derivative [Line Items]	'	'	'	'
Notional quantity (MW-hrs)	19,440,000	69,154,000	'	'
Receive average prices (per MW-hr)	61.4	48.83	'	'
Net Asset	'	'	1,833	1,729

Financial_instruments_Effects_

Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) (CAD)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value of Financial Instruments [Line Items]	'	'
Total change in unrealized loss/(gain) on derivative financial instruments	6,758	3,127
Ineffective portion of derivatives financial instruments accounted for as hedges	1,304	105
Not Designated as Hedging Instrument	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Total change in unrealized loss/(gain) on derivative financial instruments	-5,407	-3,022
Total realized loss/(gain) on derivative financial instruments	1,558	2,894
Loss/(gain) on derivative financial instruments	-5,200	-233
Not Designated as Hedging Instrument | Foreign exchange contracts	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Total realized loss/(gain) on derivative financial instruments	0	-187
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	-1,598	-2,197
Total realized loss/(gain) on derivative financial instruments	2,024	2,094
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	-3,809	-825
Total realized loss/(gain) on derivative financial instruments	-466	987
Designated as Hedging Instrument	'	'
Fair Value of Financial Instruments [Line Items]	'	'
Loss/(gain) on derivative financial instruments	-3,849	-128
Ineffective portion of derivatives financial instruments accounted for as hedges	-1,351	-105

Financial_instruments_Maximum_

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail)	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified	USD ($)	CAD
Fair Value Disclosures [Abstract]	'	'
Cash and cash equivalents and restricted cash	$15,415	3,465
Accounts receivable	137,481	18,948
Allowance for Doubtful Accounts	-7,955	0
Notes Receivable	2,021	20,529
Maximum exposure to credit risk for financial instruments	$146,962	42,942

Financial_instruments_Liabilit

Financial instruments - Liabilities Mature (Detail) (CAD)	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]	'
Long term debt obligations	1,255,588
Advances in aid of construction	78,936
Interest on long term debt	416,823
Accounts payable and due to related parties	156,905
Environmental obligation	77,729
Derivative financial instruments:	'
Cross- currency swap	7,947
Interest rate swaps	3,180
Energy derivative and commodity contracts	4,777
Capital lease payments	4,044
Other obligations	21,135
Total obligations	2,027,064
Due less than 1 year	'
Derivative [Line Items]	'
Long term debt obligations	8,339
Advances in aid of construction	1,239
Interest on long term debt	54,804
Accounts payable and due to related parties	156,905
Environmental obligation	10,111
Derivative financial instruments:	'
Interest rate swaps	1,936
Energy derivative and commodity contracts	240
Capital lease payments	125
Other obligations	7,326
Total obligations	241,025
Due 2 to 3 years	'
Derivative [Line Items]	'
Long term debt obligations	147,076
Interest on long term debt	103,605
Environmental obligation	45,158
Derivative financial instruments:	'
Interest rate swaps	1,244
Energy derivative and commodity contracts	72
Capital lease payments	3,919
Other obligations	0
Total obligations	301,074
Due 4 to 5 years	'
Derivative [Line Items]	'
Long term debt obligations	171,907
Interest on long term debt	89,966
Environmental obligation	3,912
Derivative financial instruments:	'
Energy derivative and commodity contracts	0
Other obligations	0
Total obligations	265,785
Due after 5 years	'
Derivative [Line Items]	'
Long term debt obligations	928,266
Advances in aid of construction	77,697
Interest on long term debt	168,448
Environmental obligation	18,548
Derivative financial instruments:	'
Cross- currency swap	7,947
Energy derivative and commodity contracts	4,465
Other obligations	13,809
Total obligations	1,219,180