Atlantic Power 10-Q 7 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 07, 2014
Document and Entity Information	'	'
Entity Registrant Name	'ATLANTIC POWER CORP	'
Entity Central Index Key	'0001419242	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	120,712,916
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$157.60	$158.60
Restricted cash	17.8	96.2
Accounts receivable	61.5	64.3
Current portion of derivative instruments asset (Notes 7 and 8)	1.7	0.2
Inventory	18.6	16
Prepayments and other current assets	15.4	16.1
Refundable income taxes	2.1	4
Total current assets	274.7	355.4
Property, plant, and equipment, net of accumulated depreciation of $241.2 million and $175.1 million at June 30, 2014 and December 31, 2013, respectively	1,751.20	1,813.40
Equity investments in unconsolidated affiliates (Note 4)	368.5	394.3
Other intangible assets, net of accumulated amortization of $177.0 million and $136.9 million at June 30, 2014 and December 31, 2013, respectively	420.6	451.5
Goodwill (Note 5)	291.1	296.3
Derivative instruments asset (Notes 7 and 8)	6.3	13
Other assets	98.3	71.1
Total assets	3,210.70	3,395
Current liabilities:	'	'
Accounts payable	10.5	14
Accrued interest	6.3	17.7
Other accrued liabilities	48.9	58.8
Current portion of long-term debt (Note 6)	26.4	216.2
Current portion of convertible debentures	42	42.1
Current portion of derivative instruments liability (Notes 7 and 8)	28.4	28.5
Dividends payable	3.8	6.8
Other current liabilities	8.1	5.3
Total current liabilities	174.4	389.4
Long-term debt (Note 6)	1,436	1,254.80
Convertible debentures	362.4	363.1
Derivative instruments liability (Notes 7 and 8)	58.2	76.1
Deferred income taxes (Note 9)	95.7	111.5
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $9.9 million and $8.1 million at June 30, 2014 and December 31, 2013, respectively	36.9	38.7
Other non-current liabilities	63.2	65.4
Commitments and contingencies (Note 16)	'	'
Total liabilities	2,226.80	2,299
Equity	'	'
Common shares, no par value, unlimited authorized shares; 120,712,916 and 120,205,813 issued and outstanding at June 30, 2014 and December 31, 2013, respectively (Note 13)	1,286.50	1,286.10
Preferred shares issued by a subsidiary company (Note 13)	221.3	221.3
Accumulated other comprehensive loss	-24.1	-22.4
Retained deficit	-754.3	-655.4
Total Atlantic Power Corporation shareholders' equity	729.4	829.6
Noncontrolling interest (Note 13)	254.5	266.4
Total equity	983.9	1,096
Total liabilities and equity	$3,210.70	$3,395

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
CONSOLIDATED BALANCE SHEETS	'	'
Property, plant, and equipment, accumulated depreciation	$241.20	$175.10
Other intangible assets, accumulated amortization	177	136.9
Power purchase and fuel supply agreement liabilities, accumulated amortization	$9.90	$8.10
Common shares, no par value (in dollars per share)	'	'
Common shares, issued shares (in shares)	120,712,916	120,205,813
Common shares, outstanding shares (in shares)	120,712,916	120,205,813

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Project revenue:	'	'	'	'
Energy sales	$82.40	$76.90	$164.70	$153.80
Energy capacity revenue	41.3	42.9	74.8	77.2
Other	19.5	16.3	49	42.6
Total project revenue	143.2	136.1	288.5	273.6
Project expenses:	'	'	'	'
Fuel	50.4	50	110.2	97.7
Operations and maintenance	34.5	46.4	67.2	73.9
Development	1.1	1.8	1.8	3.5
Depreciation and amortization	40.9	41.8	81.5	82.7
Total project expenses	126.9	140	260.7	257.8
Project other income (expense):	'	'	'	'
Change in fair value of derivative instruments (Notes 7 and 8)	-2.8	24.3	11.9	36.9
Equity in earnings of unconsolidated affiliates (Note 4)	3.3	8.7	11.9	15.9
Interest expense, net	-5.8	-8.8	-20.4	-16.8
Impairment	-14.8	'	-14.8	-4.9
Total project other income (expense)	-20.1	24.2	-11.4	36
Project (loss) income	-3.8	20.3	16.4	51.8
Administrative and other expenses (income):	'	'	'	'
Administration	10.2	11.8	17.5	20.1
Interest, net	27.7	25.3	94.1	51.2
Foreign exchange loss (gain) (Note 8)	15.3	-14.5	-1.5	-22
Other income, net (Note 3)	'	-9.5	-2.1	-9.5
Total administrative and other expenses (income)	53.2	13.1	108	39.8
(Loss) income from continuing operations before income taxes	-57	7.2	-91.6	12
Income tax (benefit) expense (Note 9)	-0.6	0.6	-12.9	-1.9
(Loss) income from continuing operations	-56.4	6.6	-78.7	13.9
Net loss from discontinued operations, net of tax (Note 12)	'	-5.4	-0.1	-4.9
Net (loss) income	-56.4	1.2	-78.8	9
Net (loss) income attributable to noncontrolling interests	-0.3	1.1	-6.7	-0.8
Net income attributable to preferred shares dividends of a subsidiary company	3.1	3.1	5.9	6.3
Net (loss) income attributable to Atlantic Power Corporation	($59.20)	($3)	($78)	$3.50
Basic earnings per share: (Note 11)	'	'	'	'
(Loss) income from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	$0.02	($0.65)	$0.07
Loss from discontinued operations, net of tax (in dollars per share)	'	($0.05)	'	($0.04)
Net loss attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	($0.03)	($0.65)	$0.03
Diluted earnings per share: (Note 11)	'	'	'	'
(Loss) income from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	$0.02	($0.65)	$0.07
Loss from discontinued operations, net of tax (in dollars per share)	'	($0.05)	'	($0.04)
Net (loss) income attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	($0.03)	($0.65)	$0.03
Weighted average number of common shares outstanding: (Note 11)	'	'	'	'
Basic (in shares)	120.6	119.9	120.5	119.7
Diluted (in shares)	120.6	119.9	120.5	120.3

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	'	'	'	'
Net (loss) income	($56.40)	$1.20	($78.80)	$9
Other comprehensive (loss) income, net of tax:	'	'	'	'
Unrealized (loss) income on hedging activities	-0.3	0.6	-0.7	0.6
Net amount reclassified to earnings	0.1	0.1	0.4	0.4
Net unrealized (loss) gain on derivatives	-0.2	0.7	-0.3	1
Foreign currency translation adjustments	17.3	-18	-1.4	-30.1
Other comprehensive income (loss), net of tax	17.1	-17.3	-1.7	-29.1
Comprehensive loss	-39.3	-16.1	-80.5	-20.1
Less: Comprehensive (loss) income attributable to noncontrolling interests	2.8	4.2	-0.8	5.5
Comprehensive loss attributable to Atlantic Power Corporation	($42.10)	($20.30)	($79.70)	($25.60)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS(USD ($))	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Cash flows from operating activities:	'	'
Net (loss) income	($78.80)	$9
Adjustments to reconcile to net cash provided by operating activities:	'	'
Depreciation and amortization	81.5	92.8
Loss of discontinued operations	'	32.8
Gain on sale of asset	-2.1	-4.4
Long-term incentive plan expense	0.9	1.2
Impairment charges	14.8	4.9
Equity in earnings from unconsolidated affiliates	-11.9	-15.9
Distributions from unconsolidated affiliates	37.8	18
Unrealized foreign exchange gain	-1.4	-8.7
Change in fair value of derivative instruments	-11.9	-47.7
Change in deferred income taxes	-15.5	-6.5
Change in other operating balances	'	'
Accounts receivable	2.8	-3.6
Inventory	-2.6	-1.3
Prepayments, refundable income taxes and other assets	14.7	46.3
Accounts payable	-4.6	-9.4
Accruals and other liabilities	-18.2	-10.6
Cash provided by operating activities	5.5	96.9
Cash flows provided by investing activities:	'	'
Change in restricted cash	78.4	-19.4
Proceeds from sale of asset, net	1	148.3
Proceeds from treasury grant	'	53.7
Biomass development costs	'	-0.1
Construction in progress	-1.5	-28.5
Purchase of property, plant and equipment	-2.5	-2.7
Cash provided by investing activities	75.4	151.3
Cash flows used in financing activities:	'	'
Proceeds from senior secured term loan facility	600	'
Proceeds from project-level debt	'	20.8
Repayment of corporate and project-level debt	-608	-64.2
Payments for revolving credit facility borrowings	'	-67
Deferred financing costs	-38.8	'
Equity contribution from noncontrolling interest	'	44.6
Offering costs related to tax equity	'	-1
Dividends paid to common shareholders	-20.9	-43.2
Dividends paid to noncontrolling interests	-14.2	-9.3
Cash used in financing activities	-81.9	-119.3
Net (decrease) increase in cash and cash equivalents	-1	128.9
Cash and cash equivalents at beginning of period at discontinued operations	'	6.5
Cash and cash equivalents at beginning of period	158.6	60.2
Cash and cash equivalents at end of period	157.6	195.6
Supplemental cash flow information	'	'
Interest paid	114.7	65.3
Income taxes paid, net	1	1.4
Accruals for construction in progress	$8.20	$8.60

Nature_of_business_and_basis_o

Nature of business and basis of presentation	6 Months Ended
	Jun. 30, 2014
Nature of business and basis of presentation	'
Nature of business and basis of presentation	'
	1. Nature of business and basis of presentation
	Nature of business
	Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of June 30, 2014, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,945 megawatts ("MW") in which our aggregate ownership interest is approximately 2,024 MW. These totals exclude our 40% interest in the Delta-Person generating station ("Delta-Person") which we sold in a transaction that closed in July 2014. Our current portfolio consists of interests in twenty-eight operational power generation projects across eleven states in the United States and two provinces in Canada. We also own Ridgeline Energy Holdings, Inc. ("Ridgeline"), a wind and solar developer based in Seattle, Washington. Twenty of our projects are majority-owned subsidiaries.
	Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 Canada and our headquarters is located at One Federal Street, 30th Floor, Boston, Massachusetts 02110, USA. Our telephone number in Boston is (617) 977-2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power's website or that can be accessed through its website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website. We make available on our website, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission ("SEC"). Additionally, we make available on our website our Canadian securities filings, which are not incorporated by reference into our Exchange Act filings.
	Basis of presentation
	The interim consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2013. Interim results are not necessarily indicative of results for the full year.
	In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of June 30, 2014, the results of operations and comprehensive income (loss) for the three and six months ended June 30, 2014 and 2013, and our cash flows for the six months ended June 30, 2014 and 2013. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
	Use of estimates
	The preparation of financial statements requires us 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 the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and the allocation of taxable income and losses, tax credits and cash distributions using the hypothetical liquidation book value ("HLBV") method. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Annual Report on Form 10-K for the year ended December 31, 2013. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
	Reclassifications
	Certain prior year amounts have been reclassified to conform to the current period presentation.
	Recently issued accounting standards
	Adopted
	In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	In March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income (loss) into net income (loss) in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income (loss). These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income (loss) if the amount being reclassified is required to be reclassified in its entirety to net income (loss). For other amounts that are not required to be reclassified in their entirety to net income (loss) in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income (loss). Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.
	Issued
	In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity's financial statements. The threshold is defined as a strategic shift that has, or will have, a major effect on an entity's operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes become effective on January 1, 2015. The adoption of these changes will not have an immediate impact on the consolidated financial statements. This guidance will need to be considered in the event that we initiate a disposal transaction.
	In May 2014, the FASB issued changes to the recognition of revenue from contracts with customers. These changes created a comprehensive framework for all entities in all industries to apply in the determination of when to recognize revenue, and, therefore, supersede virtually all existing revenue recognition requirements and guidance. This framework is expected to result in less complex guidance in application while providing a consistent and comparable methodology for revenue recognition. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this principle, an entity should apply the following steps: (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. These changes become effective on January 1, 2017. We are currently evaluating the potential impact of these changes on the consolidated financial statements.

Changes_in_accumulated_other_c

Changes in accumulated other comprehensive loss by component	6 Months Ended
	Jun. 30, 2014
Changes in accumulated other comprehensive loss by component	'
Changes in accumulated other comprehensive loss by component	'
	2. Changes in accumulated other comprehensive loss by component
	The changes in accumulated other comprehensive loss by component were as follows:
		Three months ended
		June 30,
		2014			2013
	Foreign currency translation
	Balance at beginning of period	$	(40.9	)	$	0.5
	Other comprehensive income (loss):
	Foreign currency translation adjustments(1)		17.3			(18.0	)
	Balance at end of period	$	(23.6	)	$	(17.5	)
	Pension
	Balance at beginning of period	$	(0.4	)	$	(1.8	)
	Other comprehensive loss:
	Amortization of net actuarial gain		—			—
	Balance at end of period	$	(0.4	)	$	(1.8	)
	Cash flow hedges
	Balance at beginning of period	$	0.1		$	(1.1	)
	Other comprehensive (loss) income:
	Net change from periodic revaluations		(0.5	)		1
	Tax benefit (expense)		0.2			(0.4	)
	Total Other comprehensive income (loss) before reclassifications, net of tax		(0.3	)		0.6
	Net amount reclassified to earnings (loss):
	Interest rate swaps(2)		0.3			0.4
	Fuel commodity swaps(3)		—			(0.1	)
	Sub-total		0.3			0.3
	Tax expense		0.2			0.2
	Total amount reclassified from Accumulated other comprehensive loss, net of tax		0.1			0.1
	Total Other comprehensive (loss) income		(0.2	)		0.7
	Balance at end of period	$	(0.1	)	$	(0.4	)
		Six months ended
		June 30,
		2014			2013
	Foreign currency translation
	Balance at beginning of period	$	(22.2	)	$	12.6
	Other comprehensive loss:
	Foreign currency translation adjustments(1)		(1.4	)		(30.1	)
	Balance at end of period	$	(23.6	)	$	(17.5	)
	Pension
	Balance at beginning of period	$	(0.4	)	$	(1.8	)
	Other comprehensive loss:
	Amortization of net actuarial gain		—			—
	Balance at end of period	$	(0.4	)	$	(1.8	)
	Cash flow hedges
	Balance at beginning of period	$	0.2		$	(1.4	)
	Other comprehensive (loss) income:
	Net change from periodic revaluations		(1.1	)		1
	Tax benefit (expense)		0.4			(0.4	)
	Total Other comprehensive (loss) income before reclassifications, net of tax		(0.7	)		0.6
	Net amount reclassified to earnings (loss):
	Interest rate swaps(2)		0.7			0.8
	Fuel commodity swaps(3)		—			(0.2	)
	Sub-total		0.7			0.6
	Tax expense		0.3			0.2
	Total amount reclassified from Accumulated other comprehensive loss, net of tax		0.4			0.4
	Total Other comprehensive (loss) income		(0.3	)		1
	Balance at end of period	$	(0.1	)	$	(0.4	)
	-1
	In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).
	-2
	This amount was included in Interest expense, net on the accompanying consolidated statements of operations.
	-3
	A positive amount indicates a corresponding charge to earnings (loss) and a negative amount indicates a corresponding benefit to earnings (loss). These amounts were reflected on the accompanying consolidated statements of operations in the line items indicated in footnotes 1 and 2.

Acquisitions_and_divestments

Acquisitions and divestments	6 Months Ended
	Jun. 30, 2014
Acquisitions and divestments	'
Acquisitions and divestments	'
	3. Acquisitions and divestments
	2014 Divestments
	(a)
	Delta-Person
	In December 2012, we and the owners of Delta-Person, entered into a purchase and sale agreement with BHB Power, LLC and Public Service Company of New Mexico to sell the project for approximately $37.2 million including working capital adjustments. We received net cash proceeds in July 2014 for our ownership interest of approximately $7.2 million in the aggregate. We expect to receive an additional $1.4 million of cash proceeds held in escrow for up to twelve months after the close of the transaction. We intend to use the net proceeds from the sale for general corporate purposes. The sale of Delta-Person closed in July 2014 resulting in a gain on sale of approximately $8.6 million that will be recorded as a component of other income in the consolidated statement of operations for the three months ended September 30, 2014.
	(b)
	Greeley
	In March 2014, we closed a transaction with Initium Power Partners, LLC. ("Initium"), whereby Initium agreed to purchase all of the issued and outstanding membership interests in Greeley for approximately $1.0 million. We recorded a $2.1 million non-cash gain on the sale in the consolidated statement of operations. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the six months ended June 30, 2014.
	2013 Divestments
	(a)
	Gregory
	In April 2013, we and the other owners of Gregory, entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million including working capital adjustments. We received net cash proceeds for our ownership interest of approximately $34.6 million in the aggregate, after repayment of project-level debt and transaction expenses. Approximately $5.0 million of these proceeds will be held in escrow for up to one year after the closing date. We used the net proceeds from the sale for general corporate purposes. The sale of Gregory closed in August 2013 resulting in a gain on sale of approximately $31.0 million, which was recorded as a component of other income in the consolidated statement of operations for the three months ended September 30, 2013.
	(b)
	Auburndale, Lake and Pasco
	In January 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco CoGen, Ltd. ("Pasco") projects (collectively, the "Florida Projects") for approximately $140.0 million, with working capital adjustments. The sale closed in April 2013 and we received net cash proceeds of approximately $117.0 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. This includes approximately $92.0 million received at closing and cash distributions from the Florida Projects of approximately $25.0 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date. The remaining cash proceeds were used for general corporate purposes. The Florida Projects were accounted for as a component of discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2013. See Note 12, Discontinued Operations, for further information.
	(c)
	Path 15
	In March 2013, we entered into a purchase and sales agreement with Duke Energy Corporation and American Transmission Co., to sell our interests in the Path 15 transmission line ("Path 15"). The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52.0 million, plus a management agreement termination fee of $4.0 million, for a total sale price of approximately $56.0 million. The cash proceeds were used for general corporate purposes. All project level debt issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 was accounted for as a component of discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2013. See Note 12, Discontinued Operations, for further information.

Equity_method_investments_in_u

Equity method investments in unconsolidated affiliates	6 Months Ended
	Jun. 30, 2014
Equity method investments in unconsolidated affiliates	'
Equity method investments in unconsolidated affiliates	'
	4. Equity method investments in unconsolidated affiliates
	The following summarizes the operating results for the three and six months ended June 30, 2014 and 2013, respectively, for earnings in our equity method investments:
		Three months ended						Six months ended
		June 30,						June 30,
	Operating results	2014			2013			2014			2013
	Revenue
	Chambers	$	12.6		$	13.4		$	30.6		$	26.6
	Other(1)		33.5			41.2			73.2			80.6
			46.1			54.6			103.8			107.2
	Project expenses
	Chambers		10.8			11.1			25.1			20.7
	Other(1)		28.8			34.5			61.4			68.1
			39.6			45.6			86.5			88.8
	Project other expense
	Chambers		(1.5	)		(0.6	)		(2.1	)		(1.2	)
	Other(1)		(1.7	)		0.3			(3.3	)		(1.3	)
			(3.2	)		(0.3	)		(5.4	)		(2.5	)
	Project income
	Chambers	$	0.3		$	1.7		$	3.4		$	4.7
	Other(1)		3			7			8.5			11.2
			3.3			8.7			11.9			15.9
	-1
	Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

Goodwill

Goodwill	6 Months Ended
	Jun. 30, 2014
Goodwill	'
Goodwill	'
	5. Goodwill
	Our goodwill balance was $291.1 million and $296.3 million as of June 30, 2014 and December 31, 2013, respectively. We recorded $331.1 million of goodwill in connection with the acquisition of Capital Power Income L.P. (the "Partnership") in 2011. We apply an accounting standard under which goodwill has an indefinite life and is not amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which discrete financial information is available. For reporting units that fail step 1 of the goodwill impairment test, we will initiate a step 2 test to quantify the amount, if any, of non-cash impairment to record.
	Under our accounting policies for long-lived assets and goodwill impairment, we also perform an impairment analysis at the earlier of (i) executing a new PPA (or other arrangement) and (ii) six months prior to the expiration of an existing PPA. The Tunis project's PPA expires on December 31, 2014 and accordingly, we performed a long-lived assets impairment test and a goodwill impairment test as of June 30, 2014.
	Based on the results of our long-lived asset impairment test, it was determined that the weighted average estimated undiscounted cash flows for Tunis over its remaining useful life did not exceed the carrying value of the property, plant and equipment at the Tunis reporting unit. As a result, the project recorded a $9.6 million long-lived asset impairment charge in the three months ended June 30, 2014 which was the difference between the carrying value of the project's property, plant and equipment and its estimated fair market value.
	Subsequent to adjusting the carrying value of the Tunis reporting unit for the $9.6 million long-lived asset impairment, we performed an impairment analysis for the project's goodwill. The project failed step 1 of the impairment test because the weighted average estimated discounted cash flows over its remaining useful life did not exceed the carrying value of the Tunis reporting unit. We performed step 2 of the goodwill impairment test and wrote off all of the projects goodwill because the carrying value of goodwill exceeded its implied fair value. As a result, Tunis, a component of the East segment, recorded a $5.2 million goodwill impairment charge in the three months ended June 30, 2014. The implied fair value of goodwill was determined in the same manner as the value of goodwill is determined in a business combination, using the fair value of the reporting unit as if it were the purchase price.
	The total $14.8 million long-lived asset and goodwill impairment was primarily due to our assessment of the forecasted cash flows from re-contracting and other strategic outcomes.
	We determine the fair value of our reporting units using an income approach with discounted cash flow ("DCF") models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery and step 1 goodwill impairment tests for Tunis were determined using our best estimate of the weighted average probability of several re-contracting scenarios and other strategic outcomes. The fair value of Tunis used to calculate the long-lived asset impairment amount and to perform step 2 of the goodwill impairment test was determined using market participant assumptions. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements.
	The valuations of long-lived assets and goodwill for the long-lived assets and goodwill impairment analyses are considered level 3 fair value measurements, which means that the valuation of the assets and liabilities reflect management's own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities.
	The discount rate applied to the DCF models represents the weighted average cost of capital ("WACC") consistent with the risk inherent in future cash flows and based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third party sources.
	Based on the continued deficit of our market capitalization as compared to our book carrying value, we determined that it was appropriate to initiate a test of the remaining goodwill at our reporting units to determine if it is more likely than not that the fair value of our reporting units do not exceed their carrying amounts. For reporting units, if any, that fail step 1 of the goodwill impairment test, we will initiate a step 2 test to quantify the amount, if any, of non-cash impairment to record. As of the date of this Quarterly Report on Form 10-Q, we are currently gathering the necessary information to perform these tests and expect to complete them during the three months ended September 30, 2014.
	The following table is a rollforward of goodwill for the six months ended June 30, 2014:
	(in millions)	East			West		Wind		Un-allocated		Total
									corporate
	Balance at December 31, 2013	$	107.8		$	188.5	$	—	$	—	$	296.3
	Impairment of Goodwill		(5.2	)		—		—		—		(5.2	)
	Balance at June 30, 2014	$	102.6		$	188.5	$	—	$	—	$	291.1

Longterm_debt

Long-term debt	6 Months Ended
	Jun. 30, 2014
Long-term debt	'
Long-term debt	'
	6. Long-term debt
	Long-term debt consists of the following:
		June 30,			December 31,			Interest Rate
		2014			2013
	Recourse Debt:
	Senior secured term loan facility, due 2021	$	562.5		$	—		LIBOR(1) plus 3.8%
	Senior unsecured notes, due 2018(2)		319.9			460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		196.8			197.4		6.00%
	Senior unsecured notes, due July 2014(3)		—			190		5.90%
	Series A senior unsecured notes, due August 2015(3)		—			150		5.90%
	Series B senior unsecured notes, due August 2017(3)		—			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		28			30.5		LIBOR plus 3.1%
	Cadillac term loan, due 2025		34.4			35.4		6.0% – 8.0%
	Piedmont term loan, due 2018(4)		68.3			76.6		5.20%
	Meadow Creek term loan, due 2024		167.3			169.8		2.9% – 5.6%
	Rockland term loan, due 2027		84.4			85.3		6.40%
	Other long-term debt		0.8			1		5.5% – 6.7%
	Less: current maturities		(26.4	)		(216.2	)
	Total long-term debt	$	1,436.00		$	1,254.80
	Current maturities consist of the following:
		June 30,			December 31,			Interest Rate
		2014			2013
	Current Maturities:
	Senior secured term loan facility, due 2021	$	6		$	—		LIBOR(1) plus 3.8%
	Senior unsecured notes, due July 2014(3)		—			190		5.90%
	Epsilon Power Partners term facility, due 2019		5.3			5		LIBOR plus 3.1%
	Cadillac term loan, due 2025		3.6			2		6.0% – 8.0%
	Piedmont term loan, due 2018(4)		4.9			12.6		5.20%
	Meadow Creek term loan, due 2024		4.8			4.9		2.9% – 5.6%
	Rockland term loan, due 2027		1.6			1.5		6.40%
	Other short-term debt		0.2			0.2		5.5 – 6.7%
	Total current maturities	$	26.4		$	216.2
	-1
	LIBOR cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount of the $568.5 million outstanding aggregate borrowings. See Note 8, Accounting for derivative instruments and hedging activities for further details.
	-2
	We repurchased approximately $140.1 million aggregate principal amount of the 9.0% Notes in March 2014 with a portion of the proceeds from the New Senior Secured Credit Facilities and cash on hand, as further described below.
	-3
	The Curtis Palmer Notes due July 2014, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes due August 2017 were retired on February 26, 2014 with proceeds from the New Senior Secured Credit Facilities described below.
	-4
	On February 14, 2014, we paid down $8.1 million of principal on the Piedmont construction loan and converted the remaining $68.5 million to a term loan due August 2018.
	New Senior Secured Credit Facilities
	On February 24, 2014, Atlantic Power Limited Partnership ("the Partnership"), our wholly-owned indirect subsidiary, entered into a new senior secured term loan facility (the "New Term Loan Facility"), comprising of $600 million in aggregate principal amount, and a new senior secured revolving credit facility (the "New Revolving Credit Facility") with a capacity of $210 million (collectively, the "New Senior Secured Credit Facilities"). Borrowings under the New Senior Secured Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate (LIBOR), the Base Rate or the Canadian Prime Rate, each as defined in the credit agreement governing the New Senior Secured Credit Facilities (the "Credit Agreement"), as applicable, plus an applicable margin between 2.75% and 3.75% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The applicable margin for term loans bearing interest at the Adjusted Eurodollar Rate and the Base Rate is 3.75% and 2.75% respectively and was 3.75% at June 30, 2014. The Adjusted Eurodollar Rate cannot be less than 1.00% (1.00% at June 30, 2014). As further described in Note 8, the Partnership entered into interest rate swap agreements on May 5, 2014 to mitigate the exposure to changes in the Adjusted Eurodollar Rate for a portion of the New Term Loan Facility.
	In connection with the funding of the New Senior Secured Credit Facilities, we terminated our prior revolving credit facility on February 26, 2014.
	The New Term Loan Facility matures on February 24, 2021. The revolving commitments under the New Revolving Credit Facility terminate on February 24, 2018. Letters of credit are available to be issued under the revolving commitments until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The Partnership is required to pay a commitment fee with respect to the commitments under the New Revolving Credit Facility equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding revolving loans (excluding swing line loans) plus amounts available to be drawn under letters of credit and all outstanding reimbursement obligations with respect to drawn letters of credit.
	The New Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its subsidiaries, guaranties from the Partnership subsidiary guarantors and a limited recourse guaranty from the entity that holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain exceptions), and certain other assets. The New Senior Secured Credit Facilities are not otherwise guaranteed or secured by us or any of our subsidiaries (other than the Partnership subsidiary guarantors). The New Senior Secured Credit Facilities have a debt service reserve account, which is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. The debt service reserve requirement was funded with a $15.8 million letter of credit.
	The Partnership's existing Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due June 23, 2036 (the "MTNs") prohibit the Partnership (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, the Partnership has granted an equal and ratable security interest in the collateral package securing the New Senior Secured Credit Facilities under the indenture governing the MTNs for the benefit of the holders of the MTNs.
	The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The covenants include a requirement that the Partnership and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 5.50:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement includes customary restrictions and limitations on the Partnership's and its subsidiaries' ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to customary carve-outs and exceptions and various thresholds.
	Under the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the Partnership elects to make a voluntary prepayment of the term loans under the New Senior Secured Credit Facilities, it will be required to offer each electing lender to prepay such lender's term loans under the New Senior Secured Credit Facilities at a price equal to 101% of par. In addition, in the event that the Partnership elects to repay, prepay or refinance all or any portion of the term loan facilities within one year from the initial funding date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid or refinanced.
	The Credit Agreement also contains a mandatory amortization feature and customary mandatory prepayment provisions, including: (i) from proceeds of assets sales, insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as defined in the Credit Agreement, of the Partnership and its subsidiaries.
	Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect, non-payment or acceleration of other material debt of the Partnership and its subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral documents securing the New Senior Secured Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods.
	On February 26, 2014, $600 million was drawn under the New Term Loan Facility, and letters of credit in an aggregate face amount of $144.1 million ($107.0 million as of June 30, 2014) were issued (but not drawn) pursuant to the revolving commitments under the New Revolving Credit Facility and used to (i) satisfy a debt service reserve requirement in an amount equivalent to six months of debt service (approximately $15.8 million) and (ii) support contractual credit support obligations of the Partnership and its subsidiaries and of certain other of our affiliates.
	We and our subsidiaries have used the proceeds from the New Term Loan Facility under the New Senior Secured Credit Facilities to:
	•
	redeem in whole, at a price equal to par plus $31.1 million of accrued interest and make-whole premiums (i) the $150 million aggregate principal amount outstanding of 5.87% Senior Guaranteed Notes, Series A, due 2015 (the "Series A Notes") and the $75 million aggregate principal amount outstanding of 5.97% Senior Guaranteed Notes, Series B, due 2017 (the "Series B Notes") issued by Atlantic Power (US) GP, and (ii) the $190 million aggregate principal amount outstanding of 5.9% Senior Notes due 2014 issued by Curtis Palmer LLC;
	•
	pay transaction costs and expenses of approximately $40.0 million including banking, legal and consulting fees which were capitalized as deferred financing costs; and
	•
	make a distribution to us in the amount of $122 million which was used, in addition to cash on hand, to repurchase $140.1 million aggregate principal amount of the 9.0% Notes (as defined below) of Atlantic Power Corporation, make $15.7 million in accrued interest and premium payments as part of the aggregate repurchase price, and $0.1 million in commission fees associated with the repurchases.
	In connection with the termination of our prior credit facility, we terminated the interest rate swap at Epsilon Power Partners, a wholly owned subsidiary, a portion of our natural gas swaps at Orlando and foreign exchange forward contracts at the Partnership. As a result of the termination of these contracts, we recorded $2.6 million of interest expense, $4.0 million of fuel expense and $0.4 million of foreign exchange loss, respectively.
	The prior credit facility contained certain guaranties, which were terminated in connection with the termination of the prior credit facility. In addition, the terms of the 9.0% Notes provide that the guarantors of the prior credit facility guarantee the 9.0% Notes. As a result, upon termination of our prior credit facility and its related guaranties, the guaranties under the 9.0% Notes were cancelled and the guarantors of the 9.0% Notes were automatically released from all of their obligations under such guaranties.
	Notes of Atlantic Power Corporation
	On November 5, 2011, we completed a private placement of $460.0 million aggregate principal amount of 9.0% senior notes due 2018 (the "9.0% Notes") to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"), and to non-U.S. persons outside of the United States in compliance with Regulation S under the Securities Act. The 9.0% Notes were issued at an issue price of 97.471% of the face amount of the Atlantic Notes for aggregate gross proceeds to us of $448.0 million.
On March 25, 2014, we agreed, in privately-negotiated transactions, to repurchase approximately $140.1 million aggregate principal amount of the 9.0% Notes from certain holders. We paid $15.7 million in accrued interest and premiums as part of the aggregate repurchase price, paid $0.1 million in commission fees associated with the repurchases, and wrote off $5.3 million of deferred financing costs related to the repurchase. The premiums, accrued interest and write-off of deferred financing costs were recorded to interest expense.
As previously disclosed with respect to the impact of the New Senior Secured Credit Facilities in our Current Report on Form 8-K filed on January 30, 2014, in our Annual Report on Form 10-K for the year ended December 31, 2013 and in our Quarterly Report on Form 10-Q for the three months ended March 31, 2014, due to the aggregate impact of the up-front costs resulting from the prepayments on our indebtedness described above, including the premium payment and charges for unamortized debt discount and fee expenses and premiums as part of the overall purchase price in respect of the repurchases of the 9.0% Notes (all such up-front costs, collectively, the "Prepayment Charges"), which were reflected as interest expense in our 2014 first quarter results, we no longer satisfy the fixed charge coverage ratio test included in the restricted payments covenant of the indenture governing the 9.0% Notes. The fixed charge coverage ratio must be at least 1.75 to 1.00 and is measured on a rolling four quarter basis, including after giving effect to certain pro forma adjustments. As a consequence, further dividend payments, which are declared and paid at the discretion of our board of directors, in the aggregate cannot exceed the covenant's "basket" provision of the greater of $50 million and 2% of consolidated net assets (approximately $61 million at June 30, 2014) until such time that we satisfy the fixed charge coverage ratio test. We have declared seven monthly dividends in January through July 2014 totaling approximately $25.6 million that were subject to the basket provision.
For the trailing twelve months ended June 30, 2014, dividend payments to our shareholders totaled approximately Cdn$48.1 million, reflecting the lower Cdn$0.03333 per common share monthly dividend first declared in March 2013. The Prepayment Charges would no longer be reflected in the calculation of the fixed charge coverage ratio test after the passage of four additional successive quarters following the quarter in which the Prepayment Charges are incurred. In addition, any similar prepayment charges incurred in connection with any further debt reduction would also be reflected in the calculation of the fixed charge coverage ratio test on a rolling four quarter basis, beginning with the quarter in which such charges are incurred, as would any associated reduction in interest expense.
Non-Recourse Debt
Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue generating contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available cash. At June 30, 2014, all of our projects with the exception of Piedmont were in compliance with the covenants contained in project-level debt. During the first quarter of 2014, Piedmont underwent forced maintenance outages that resulted in the project not meeting its debt service coverage ratio covenant as of June 30, 2014. We do not expect Piedmont to meet its debt service coverage ratio covenant or make distributions for at least the next twelve months.

Fair_value_of_financial_instru

Fair value of financial instruments	6 Months Ended
	Jun. 30, 2014
Fair value of financial instruments	'
Fair value of financial instruments	'
	7. Fair value of financial instruments
	The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of June 30, 2014 and December 31, 2013. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
		June 30, 2014
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	157.6	$	—	$	—	$	157.6
	Restricted cash		35.7		—		—		35.7
	Derivative instruments asset		—		8		—		8
	Total	$	193.3	$	8	$	—	$	201.3
	Liabilities:
	Derivative instruments liability	$	—	$	86.6	$	—	$	86.6
	Total	$	—	$	86.6	$	—	$	86.6
		December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	158.6	$	—	$	—	$	158.6
	Restricted cash		114.2		—		—		114.2
	Derivative instruments asset		—		13.2		—		13.2
	Total	$	272.8	$	13.2	$	—	$	286
	Liabilities:
	Derivative instruments liability	$	—	$	104.6	$	—	$	104.6
	Total	$	—	$	104.6	$	—	$	104.6
	The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.
	The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk free interest rate.
	We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of June 30, 2014, the credit valuation adjustments resulted in an $8.1 million net increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive income (loss) and a $7.6 million gain in change in fair value of derivative instruments. As of December 31, 2013, the credit valuation adjustments resulted in an $11.1 million net increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive income (loss) and a $10.6 million gain in change in fair value of derivative instruments.

Accounting_for_derivative_inst

Accounting for derivative instruments and hedging activities	6 Months Ended
	Jun. 30, 2014
Accounting for derivative instruments and hedging activities	'
Accounting for derivative instruments and hedging activities	'
	8. Accounting for derivative instruments and hedging activities
	We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss).
	For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). The guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.
	Gas purchase agreements
	Gas purchase agreements at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales ("NPNS") exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration on December 31, 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
	In June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules ("Gj") of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each of 2014 and 2015 and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2014. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
	Natural gas swaps
	Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
	The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. We previously entered into natural gas swaps to effectively fix the price of 4.5 million Mmbtu of future natural gas purchases. On February 20, 2014, we paid $4.0 million to terminate a portion of these contracts in connection with the termination of our prior revolving credit facility. We recorded fuel expense related to the settlement of these contracts in the consolidated statement of operations.
	We have entered into various natural gas swaps to effectively fix the price of 7.1 million Mmbtu of future natural gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas purchases at the project through 2016 or approximately 89%, 62% and 63% of our share of the expected base load natural gas purchases for 2014, 2015 and 2016, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2014. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
	Interest rate swaps
	The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).
	The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in November 2017 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont's construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. We recorded $1.0 million of deferred financing costs related to this transaction in the consolidated balance sheets. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
	Rockland Wind Farm, LLC ("Rockland") entered into interest rate swaps to manage interest rate risk exposure. These swaps effectively modify the project's exposure by converting the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap 100% of the expected interest payments from floating LIBOR to fixed rates structured in two tranches. The first tranche is for the expected interest payments for the current period through December 31, 2026 and fixes the interest rate at 4.2% plus an applicable margin of 2.3%-2.8%. The second tranche is for the expected interest payments for the period beginning December 31, 2026 and ending December 31, 2031, fixing the interest rate at 7.8%. The interest rate swap agreements are not designated as a hedge and changes in their fair market value are recorded in the consolidated statements of operations.
	The Meadow Creek project ("Meadow Creek") has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements effectively convert 75% of the floating rate debt to a fixed interest rate of 2.3% plus an applicable margin of 2.8%-3.3% through December 31, 2024. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2024 and ends on December 31, 2030, fixing the interest rate at 7.2%. The interest rate swaps were both executed on September 17, 2012 and expire on December 31, 2024 and December 31, 2030, respectively. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
	Epsilon Power Partners, our wholly owned subsidiary, previously had an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July 2019. The notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon Power Partners' debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement of operations. This interest rate swap agreement was not designated as a hedge and changes in its fair market value were recorded in the consolidated statements of operations.
	On May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount of the $600 million aggregate principal amount of borrowings under the New Term Loan Facility. Borrowings under the $600 million New Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the New Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the New Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual Adjusted Eurodollar Rate and 1.16%.
	The interest rate swap agreements are effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations.
	Foreign currency forward contracts
	From time to time, we use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars. On February 20, 2014, we paid $0.4 million to terminate all of our remaining foreign currency forward contracts in connection with the termination of our prior revolving credit facility and recorded their settlement in foreign exchange gain in the consolidated statement of operations for the three months ended March 31, 2014. On April 2, 2014, we executed a new foreign currency forward contract in which we agreed to sell $41.0 million on September 30, 2014 and receive Cdn$45.3 million at a foreign exchange rate of Cdn$1.105 per U.S. dollar in order to mitigate the foreign exchange risk on the retirement of the Cdn$44.8 million convertible debentures due in October 2014.
	Volume of forecasted transactions
	We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption as of June 30, 2014 and December 31, 2013:
		Units		June 30,			December 31,
				2014			2013
	Natural gas swaps	Natural Gas (Mmbtu)			7.1			5.6
	Gas purchase agreements	Natural Gas (Gj)			38.9			41.1
	Interest rate swaps	Interest (US$)			152.4			161.2
	Currency forwards	Cdn$			45.3			34.9
	Fair value of derivative instruments
	We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
		June 30, 2014
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			3
	Total derivative instruments designated as cash flow hedges		—			4.3
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.8
	Interest rate swaps long-term		6.3			12.6
	Foreign currency forward contracts current		1.4			—
	Foreign currency forward contracts long-term		—			—
	Natural gas swaps current		0.3			0.2
	Natural gas swaps long-term		—			0.7
	Gas purchase agreements current		—			19.1
	Gas purchase agreements long-term		—			41.9
	Total derivative instruments not designated as cash flow hedges		8			82.3
	Total derivative instruments	$	8		$	86.6
		December 31, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			2.6
	Total derivative instruments designated as cash flow hedges		—			3.9
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		11.5			8.1
	Foreign currency forward contracts current		0.5			0.7
	Foreign currency forward contracts long-term		1.2			—
	Natural gas swaps current		0.3			1.3
	Natural gas swaps long-term		—			3.5
	Gas purchase agreements current		0.2			18.4
Gas purchase agreements long-term		—			61.9
Total derivative instruments not designated as cash flow hedges		13.7			101.2
Total derivative instruments	$	13.7		$	105.1
Accumulated other comprehensive income (loss)
The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax:
For the three months ended June 30, 2014	Interest Rate
	Swaps
Accumulated OCI balance at March 31, 2014	$	0.1
Change in fair value of cash flow hedges		(0.3	)
Realized from OCI during the period		0.1
Accumulated OCI balance at June 30, 2014	$	(0.1	)
For the three months ended June 30, 2013	Interest Rate			Natural Gas			Total
	Swaps			Swaps
Accumulated OCI balance at March 31, 2013	$	(1.2	)	$	0.1		$	(1.1	)
Change in fair value of cash flow hedges		0.6			—			0.6
Realized from OCI during the period		0.2			(0.1	)		0.1
Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
For the six months ended June 30, 2014	Interest Rate
	Swaps
Accumulated OCI balance at January 1, 2014	$	0.2
Change in fair value of cash flow hedges		(0.7	)
Realized from OCI during the period		0.4
Accumulated OCI balance at June 30, 2014	$	(0.1	)
For the six months ended June 30, 2013	Interest Rate			Natural Gas			Total
	Swaps			Swaps
Accumulated OCI balance at January 1, 2013	$	(1.5	)	$	0.1		$	(1.4	)
Change in fair value of cash flow hedges		0.6			—			0.6
Realized from OCI during the period		0.5			(0.1	)		0.4
Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:
			Three months ended
	Classification of (gain) loss		June 30,
	recognized in income		2014			2013
Natural gas swaps	Fuel		$	(0.2	)	$	—
Gas purchase agreements	Fuel			13.4			14.1
Interest rate swaps	Interest, net			(3.6	)		(10.8	)
Foreign currency forwards	Foreign exchange loss			—			4
			Six months ended
	Classification of (gain) loss		June 30,
	recognized in income		2014			2013
Natural gas swaps	Fuel		$	3.7		$	—
Gas purchase agreements	Fuel			29.3			30.4
Interest rate swaps	Interest, net			(7.8	)		(13.3	)
Foreign currency forwards	Foreign exchange (gain) loss			(0.1	)		6.6
The following table summarizes the unrealized (gains) and losses resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
			Three months ended
	Classification of (gain) loss		June 30,
	recognized in income		2014			2013
Natural gas swaps	Change in fair value of derivatives		$	1		$	1.1
Gas purchase agreements	Change in fair value of derivatives			(2.6	)		(7.4	)
Interest rate swaps	Change in fair value of derivatives			4.4			(18.0	)
Total change in fair value of derivative instruments			$	2.8		$	(24.3	)
Foreign currency forwards	Foreign exchange (gain) loss		$	(1.4	)	$	12.8
			Six months ended
	Classification of (gain) loss		June 30,
	recognized in income		2014			2013
Natural gas swaps	Change in fair value of derivatives		$	(3.5	)	$	0.7
Gas purchase agreements	Change in fair value of derivatives			(18.6	)		(15.5	)
Interest rate swaps	Change in fair value of derivatives			10.2			(22.1	)
Total change in fair value of derivative instruments			$	(11.9	)	$	(36.9	)
Foreign currency forwards	Foreign exchange (gain) loss		$	(0.3	)	$	18.8

Income_taxes

Income taxes	6 Months Ended
	Jun. 30, 2014
Income taxes	'
Income taxes	'
	9. Income taxes
		Three months ended						Six months ended
		June 30,						June 30,
		2014			2013			2014			2013
	Current income tax expense	$	1.4		$	3.4		$	2.6		$	5.4
	Deferred tax benefit		(2.0	)		(2.8	)		(15.5	)		(7.3	)
	Total income tax (benefit), net	$	(0.6	)	$	0.6		$	(12.9	)	$	(1.9	)
	Income tax benefit for the three months ended June 30, 2014 was $0.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $14.8 million. The primary items impacting the tax rate for the three months ended June 30, 2014 were $14.2 million relating to a change in the valuation allowance, $2.4 million relating to foreign exchange, and $1.1 million of other permanent differences. These items were partially offset by $3.5 million relating to operating in higher tax rate jurisdictions.
	Income tax benefit for the six months ended June 30, 2014 was $12.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $23.8 million. The primary items impacting the tax rate for the six months ended June 30, 2014 were $29.3 million relating to a change in the valuation allowance, $2.6 million relating to minority interest adjustments, and $0.5 million of other permanent differences. These items were partially offset by $11.1 million of capital losses recognized on tax restructuring, $9.2 million relating to operating in higher tax rate jurisdictions, and $1.2 million relating to foreign exchange.
	As of June 30, 2014, we have recorded a valuation allowance of $157.4 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

Equity_compensation_plans

Equity compensation plans	6 Months Ended
	Jun. 30, 2014
Equity compensation plans	'
Equity compensation plans	'
	10. Equity compensation plans
	Long-Term Incentive Program
	The following table summarizes the changes in LTIP notional units during the three months ended June 30, 2014:
		Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2013		766,988		$	7.86
	Granted		1,776,083			2.64
	Reinvested		99,452			4.12
	Forfeited		(182,783	)		8
	Vested		(242,160	)		8.72
	Outstanding at June 30, 2014		2,217,580		$	3.41
	Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies and, in some cases, Project Adjusted EBITDA per common share compared to budget. Compensation expense for notional units granted in 2014 is recorded net of estimated forfeitures. See Note 16 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2013 for further details. Cash payments made for vested notional units for the six months ended June 30, 2014 and 2013 was $0.2 million and $0.9 million, respectively. Compensation expense for LTIP was $1.0 million and $0.9 million for the three and six months ended June 30, 2014, respectively and $0.8 million and $1.2 million for the three and six months ended June 30, 2013, respectively.

Basic_and_diluted_earnings_los

Basic and diluted earnings (loss) per share	6 Months Ended
	Jun. 30, 2014
Basic and diluted earnings (loss) per share	'
Basic and diluted earnings (loss) per share	'
	11. Basic and diluted earnings (loss) per share
	Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2013. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. The following table sets forth the diluted net income (loss) and potentially dilutive shares utilized in the per share calculation for the three and six months ended June 30, 2014 and 2013:
		Three months ended						Six months ended
		June 30,						June 30,
		2014			2013			2014			2013
	Numerator:
	(Loss) income from continuing operations attributable to Atlantic Power Corporation	$	(59.2	)	$	2.4		$	(77.9	)	$	8.4
	Loss from discontinued operations, net of tax		—			(5.4	)		(0.1	)		(4.9	)
	Net (loss) income attributable to Atlantic Power Corporation	$	(59.2	)	$	(3.0	)	$	(78.0	)	$	3.5
	Denominator:
	Weighted average basic shares outstanding		120.6			119.9			120.5			119.7
	Dilutive potential shares:
	Convertible debentures		27.7			27.7			27.7			27.7
	LTIP notional units		0.4			0.8			0.2			0.6
	Potentially dilutive shares		148.7			148.4			148.4			148
	Diluted (loss) earnings per share from continuing operations attributable to Atlantic Power Corporation	$	(0.49	)	$	0.02		$	(0.65	)	$	0.07
	Diluted loss per share from discontinued operations		—			(0.05	)		—			(0.04	)
	Diluted (loss) income per share attributable to Atlantic Power Corporation	$	(0.49	)	$	(0.03	)	$	(0.65	)	$	0.03
	Potentially dilutive shares from convertible debentures and LTIP notional units have been excluded from fully diluted shares for the three and six months ended June 30, 2014 and 2013 because their impact would be anti-dilutive.

Discontinued_operations

Discontinued operations	6 Months Ended
	Jun. 30, 2014
Discontinued operations	'
Discontinued operations	'
	12. Discontinued operations
	On March 6, 2014, we sold our outstanding membership interests in Greeley for approximately $1.0 million and recorded a $2.1 million non-cash gain on the sale related to the write-off of asset retirement obligations. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2014 and 2013, respectively.
	On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was provided by us to Rollcast to fund working capital during 2013. Rollcast's net loss is recorded as loss from discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2013.
	The Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly, the projects' net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the three and six months ended June 30, 2013.
	The following tables summarize the revenue, income (loss) from operations, and income tax expense of Greeley, Rollcast, Path 15 and the Florida Projects for the three and six months ended June 30, 2014 and 2013:
		Three months ended					Six months ended
		June 30,					June 30,
		2014		2013			2014			2013
	Revenue	$	—	$	11.4		$	—		$	77.2
	(Loss) income from operations of discontinued businesses		—		(5.0	)		(0.1	)		(4.1	)
	Income tax expense		—		0.4			—			0.8
	(Loss) income from operations of discontinued businesses, net of tax	$	—	$	(5.4	)	$	(0.1	)	$	(4.9	)
	Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for Greeley, Rollcast, the Florida Projects and Path 15 was $0.00 and $(0.05) for the three months ended June 30, 2014 and 2013, respectively, and $0.00 and $0.04 for the six months ended June 30, 2014 and 2013, respectively.

Equity

Equity	6 Months Ended
	Jun. 30, 2014
Equity	'
Equity	'
	13. Equity
	The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the six months ended June 30, 2014 and 2013:
		Six months ended June 30, 2014
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	608.3		$	221.3		$	266.4		$	1,096.00
	Net (loss) income		(78.0	)		5.9			(6.7	)		(78.8	)
	Realized and unrealized gain on hedging activities, net of tax		(0.2	)		—			—			(0.2	)
	Foreign currency translation adjustment, net of tax		(1.5	)		—			—			(1.5	)
	Common shares issued for LTIP		0.6			—			—			0.6
	Dividends paid to noncontrolling interest		—			—			(5.2	)		(5.2	)
	Dividends declared on common shares		(21.1	)		—			—			(21.1	)
	Dividends declared on preferred shares of a subsidiary company		—			(5.9	)		—			(5.9	)
	Balance at June 30	$	508.1		$	221.3		$	254.5		$	983.9
		Six months ended June 30, 2013
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	729.7		$	221.3		$	235.4		$	1,186.40
	Net income (loss)		3.5			6.3			(0.8	)		9
	Realized and unrealized gain on hedging activities, net of tax		1			—			—			1
	Foreign currency translation adjustment, net of tax		(30.1	)		—			—			(30.1	)
	Common shares issued for LTIP		0.9			—			—			0.9
	Contribution by and sale of noncontrolling interest		—			—			44.5			44.5
	Costs associated with tax equity raise		(0.9	)		—			—			(0.9	)
	Dividends paid to noncontrolling interest		—			—			(2.9	)		(2.9	)
	Dividends declared on common shares		(35.5	)		—			—			(35.5	)
	Dividends declared on preferred shares of a subsidiary company		—			(6.3	)		—			(6.3	)
	Balance at June 30	$	668.6		$	221.3		$	276.2		$	1,166.10

Segment_and_geographic_informa

Segment and geographic information	6 Months Ended
	Jun. 30, 2014
Segment and geographic information	'
Segment and geographic information	'
	14. Segment and geographic information
	We have four reportable segments: East, West, Wind and Un-allocated Corporate. We revised our reportable business segments in the fourth quarter of 2013 as a result of significant project asset sales and in order to align our reportable business segments with changes in management's structure, resource allocation and performance assessment in making decisions regarding our operations. Our financial results for the three and six months ended June 30, 2014 and 2013 have been presented to reflect these changes in operating segments. We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Greeley and Path 15, which are components of the West segment, the Florida Projects, components of the East segment, and Rollcast, which is a component of Un-allocated Corporate, are included in the income (loss) from discontinued operations line item in the table below. We have adjusted prior periods to reflect this reclassification. A reconciliation of project income (loss) to Project Adjusted EBITDA is included in the table below:
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Three months ended June 30, 2014
	Project revenues	$	76.2		$	46.8		$	20		$	0.2		$	143.2
	Segment assets		1,192.30			977.6			818.1			222.7			3,210.70
	Project Adjusted EBITDA	$	38.5		$	22.9		$	17.2		$	(3.6	)	$	75
	Change in fair value of derivative instruments		(0.8	)		—			2.8			1.1			3.1
	Depreciation and amortization		24.4			16.2			11.5			0.2			52.3
	Interest, net		3.7			—			4.8			0.1			8.6
	Other project expense		14.8			—			—			—			14.8
	Project income (loss)		(3.6	)		6.7			(1.9	)		(5.0	)		(3.8	)
	Administration		—			—			—			10.2			10.2
	Interest, net		—			—			—			27.7			27.7
	Foreign exchange (loss) gain		—			—			—			15.3			15.3
	Other income, net		—			—			—			—			—
	Income (loss) from continuing operations before income taxes		(3.6	)		6.7			(1.9	)		(58.2	)		(57.0	)
	Income tax benefit		—			—			—			(0.6	)		(0.6	)
	Net income (loss)	$	(3.6	)	$	6.7		$	(1.9	)	$	(57.6	)	$	(56.4	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Three months ended June 30, 2013
	Project revenues	$	71.9		$	45.8		$	18.2		$	0.2		$	136.1
	Segment assets		1,468.70			1,056.00			907.4			135.3			3,567.40
	Project Adjusted EBITDA	$	29.4		$	14.1		$	15.5		$	(3.1	)	$	55.9
	Change in fair value of derivative instruments		(10.6	)		—			(15.3	)		(0.9	)		(26.8	)
	Depreciation and amortization		21.8			17.1			11.4			0.2			50.5
	Interest, net		5.5			0.1			4.9			(1.0	)		9.5
	Other project expense		0.5			—			—			1.9			2.4
	Project income (loss)		12.2			(3.1	)		14.5			(3.3	)		20.3
	Administration		—			—			—			11.8			11.8
	Interest, net		—			—			—			25.3			25.3
	Foreign exchange gain		—			—			—			(14.5	)		(14.5	)
	Other income, net		—			—			—			(9.5	)		(9.5	)
	Income (loss) from continuing operations before income taxes		12.2			(3.1	)		14.5			(16.4	)		7.2
	Income tax expense		—			—			—			0.6			0.6
	Net income (loss) from continuing operations		12.2			(3.1	)		14.5			(17.0	)		6.6
	Loss from discontinued operations		(1.2	)		1.2			—			(5.4	)		(5.4	)
	Net income (loss)	$	11		$	(1.9	)	$	14.5		$	(22.4	)	$	1.2
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Six months ended June 30, 2014
	Project revenues	$	162.8		$	85.3		$	40.1		$	0.3		$	288.5
	Segment assets		1,192.30			977.6			818.1			222.7			3,210.70
	Project Adjusted EBITDA	$	84		$	34.1		$	35.1		$	(3.6	)	$	149.6
	Change in fair value of derivative instruments		(22.6	)		—			10.4			1.2			(11.0	)
	Depreciation and amortization		48.8			32.6			22.8			0.5			104.7
	Interest, net		15.3			—			9.4			—			24.7
	Other project expense		14.8			—			—			—			14.8
	Project income (loss)		27.7			1.5			(7.5	)		(5.3	)		16.4
	Administration		—			—			—			17.5			17.5
	Interest, net		—			—			—			94.1			94.1
	Foreign exchange (loss) gain		—			—			—			(1.5	)		(1.5	)
	Other income, net		—			—			—			(2.1	)		(2.1	)
	Income (loss) from continuing operations before income taxes		27.7			1.5			(7.5	)		(113.3	)		(91.6	)
	Income tax benefit		—			—			—			(12.9	)		(12.9	)
	Net income (loss) from continuing operations		27.7			1.5			(7.5	)		(100.4	)		(78.7	)
	Loss from discontinued operations		—			(0.1	)		—			—			(0.1	)
	Net income (loss)	$	27.7		$	1.4		$	(7.5	)	$	(100.4	)	$	(78.8	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Six months ended June 30, 2013
Project revenues	$	151.7		$	86.4		$	35.7		$	(0.2	)	$	273.6
Segment assets		1,468.70			1,056.00			907.4			135.3			3,567.40
Project Adjusted EBITDA	$	78.5		$	34.7		$	30.5		$	(7.6	)	$	136.1
Change in fair value of derivative instruments		(20.0	)		—			(18.3	)		—			(38.3	)
Depreciation and amortization		44.2			34.2			23.7			0.2			102.3
Interest, net		9.9			0.1			9.8			(0.1	)		19.7
Other project expense		1			—			—			(0.4	)		0.6
Project income (loss)		43.4			0.4			15.3			(7.3	)		51.8
Administration		—			—			—			20.1			20.1
Interest, net		—			—			—			51.2			51.2
Foreign exchange gain		—			—			—			(22.0	)		(22.0	)
Other income, net		—			—			—			(9.5	)		(9.5	)
Income (loss) from continuing operations before income taxes		43.4			0.4			15.3			(47.1	)		12
Income tax benefit		—			—			—			(1.9	)		(1.9	)
Net income (loss) from continuing operations		43.4			0.4			15.3			(45.2	)		13.9
Loss from discontinued operations		(0.9	)		1.8			—			(5.8	)		(4.9	)
Net income (loss)	$	42.5		$	2.2		$	15.3		$	(51.0	)	$	9
The table below provides information, by country, about our consolidated operations for the three and six months ended June 30, 2014 and 2013 and Property, Plant & Equipment as of June 30, 2014 and December 31, 2013, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
													Property, Plant and
													Equipment, net of
	Project Revenue						Project Revenue						accumulated depreciation
	Three months ended						Six months ended
	June 30,						June 30,						June 30,			December 31,
	2014			2013			2014			2013			2014			2013
United States	$	98.2		$	91		$	191.3		$	161.1		$	1,296.60		$	1,330.50
Canada		45			45.1			97.2			112.5			454.6			482.9
Total	$	143.2		$	136.1		$	288.5		$	273.6		$	1,751.20		$	1,813.40
Ontario Electricity Financial Corp ("OEFC"), San Diego Gas & Electric, and BC Hydro provided 21.9%, 16.7%, and 9.6%, respectively, of total consolidated revenues for the three months ended June 30, 2014 and 25.0%, 15.0%, and 8.7%, respectively, of total consolidated revenues for the six months ended June 30, 2014. OEFC, San Diego Gas & Electric and BC Hydro provided 22.6%, 15.9%, and 10.3%, respectively, of total consolidated revenues for the three months ended June 30, 2013 and 29.7%, 13.7%, and 11.3%, respectively, of total consolidated revenues for the six months ended June 30, 2013. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the East segment. San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West segment. BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the West segment.

Guarantees

Guarantees	6 Months Ended
	Jun. 30, 2014
Guarantees	'
Guarantees	'
	15. Guarantees
	We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.
	In connection with the tax equity investments in our Canadian Hills project, we have expressly indemnified the investors for certain representations and warranties made by a wholly-owned subsidiary with respect to matters which we believe are remote. The expiration dates of these guarantees vary from less than one year through the indefinite termination date of the project. Our maximum undiscounted potential exposure is limited to the amount of tax equity investment less cash distributions made to the investors and any amount equal to the net federal income tax benefits arising from production tax credits.

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2014
Contingencies	'
Contingencies	'
	16. Contingencies
	Shareholder class action lawsuits
	Massachusetts District Court Actions
	On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our President and Chief Executive Officer and a Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Proposed Individual Defendants," and together with Atlantic Power, the "Proposed Defendants") (the "U.S. Actions").
	The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleged, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.
	The parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking: (i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013.
	On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff's selection of counsel. The Court also granted the parties' joint motion regarding initial case scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this requested schedule.
	On June 6, 2014, Lead Plaintiff filed the amended complaint (the "Amended Complaint"). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the "Individual Defendants") and Atlantic Power (together with the Individual Defendants, the "Defendants") and alleges a class period of June 20, 2011 to March 4, 2013 (the "Class Period"). The Amended Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend, which artificially inflated the price of Atlantic Power's common shares during the class period. The Amended Complaint continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated U.S. Action on August 5, 2014.
	Canadian Actions
	On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the "Canadian Actions").
	On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.
	On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim names the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs seeks leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserts common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased and held securities through a proposed class period of November 5, 2012 to February 28, 2013.
	On October 4, 2013, the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the statutory and common claims as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.
	The Defendants are preparing materials to contest leave and certification.
	A schedule for the Plaintiffs' motions and the action is set that contemplates a hearing on leave and certification during the week of March 30, 2015.
	The proposed class action in Quebec is stayed until March 30, 2015 to follow the action in Ontario.
	Pursuant to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S. Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously against each of the actions.
	IRS Examination
	In 2011, the Internal Revenue Service ("IRS") began an examination of our federal income tax returns for the tax years ended December 31, 2007 and 2009. On April 2, 2012, the IRS issued various Notices of Proposed Adjustments. The principal area of the proposed adjustments pertain to the classification of U.S. real property in the calculation of the gain related to our 2009 conversion from the previous Income Participating Security structure to our current traditional common share structure. At June 30, 2014, the examination is before the IRS Office of Appeals.
	We continue to vigorously contest these proposed adjustments, including pursuing all administrative and judicial remedies available to us. We expect to be successful in sustaining our positions with no material impact to our financial results. We believe an adjustment, if any, would be offset by net operating loss carry forwards. No accrual has been made for any contingency related to any of the proposed adjustments as of June 30, 2014.
	Other
	In addition to the other matters listed, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of June 30, 2014.

Nature_of_business_and_basis_o1

Nature of business and basis of presentation (Policies)	6 Months Ended
	Jun. 30, 2014
Nature of business and basis of presentation	'
Basis of presentation	'
	Basis of presentation
	The interim consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2013. Interim results are not necessarily indicative of results for the full year.
	In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of June 30, 2014, the results of operations and comprehensive income (loss) for the three and six months ended June 30, 2014 and 2013, and our cash flows for the six months ended June 30, 2014 and 2013. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
Use of estimates	'
	Use of estimates
	The preparation of financial statements requires us 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 the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and the allocation of taxable income and losses, tax credits and cash distributions using the hypothetical liquidation book value ("HLBV") method. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Annual Report on Form 10-K for the year ended December 31, 2013. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Reclassifications	'
	Reclassifications
	Certain prior year amounts have been reclassified to conform to the current period presentation.
Recently issued accounting standards	'
	Recently issued accounting standards
	Adopted
	In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	In March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income (loss) into net income (loss) in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
	On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income (loss). These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income (loss) if the amount being reclassified is required to be reclassified in its entirety to net income (loss). For other amounts that are not required to be reclassified in their entirety to net income (loss) in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income (loss). Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.
	Issued
	In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity's financial statements. The threshold is defined as a strategic shift that has, or will have, a major effect on an entity's operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes become effective on January 1, 2015. The adoption of these changes will not have an immediate impact on the consolidated financial statements. This guidance will need to be considered in the event that we initiate a disposal transaction.
	In May 2014, the FASB issued changes to the recognition of revenue from contracts with customers. These changes created a comprehensive framework for all entities in all industries to apply in the determination of when to recognize revenue, and, therefore, supersede virtually all existing revenue recognition requirements and guidance. This framework is expected to result in less complex guidance in application while providing a consistent and comparable methodology for revenue recognition. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this principle, an entity should apply the following steps: (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. These changes become effective on January 1, 2017. We are currently evaluating the potential impact of these changes on the consolidated financial statements.

Changes_in_accumulated_other_c1

Changes in accumulated other comprehensive loss by component (Tables)	6 Months Ended
	Jun. 30, 2014
Changes in accumulated other comprehensive loss by component	'
Schedule of changes in accumulated other comprehensive loss by component	'
		Three months ended
		June 30,
		2014			2013
	Foreign currency translation
	Balance at beginning of period	$	(40.9	)	$	0.5
	Other comprehensive income (loss):
	Foreign currency translation adjustments(1)		17.3			(18.0	)
	Balance at end of period	$	(23.6	)	$	(17.5	)
	Pension
	Balance at beginning of period	$	(0.4	)	$	(1.8	)
	Other comprehensive loss:
	Amortization of net actuarial gain		—			—
	Balance at end of period	$	(0.4	)	$	(1.8	)
	Cash flow hedges
	Balance at beginning of period	$	0.1		$	(1.1	)
	Other comprehensive (loss) income:
	Net change from periodic revaluations		(0.5	)		1
	Tax benefit (expense)		0.2			(0.4	)
	Total Other comprehensive income (loss) before reclassifications, net of tax		(0.3	)		0.6
	Net amount reclassified to earnings (loss):
	Interest rate swaps(2)		0.3			0.4
	Fuel commodity swaps(3)		—			(0.1	)
	Sub-total		0.3			0.3
	Tax expense		0.2			0.2
	Total amount reclassified from Accumulated other comprehensive loss, net of tax		0.1			0.1
	Total Other comprehensive (loss) income		(0.2	)		0.7
	Balance at end of period	$	(0.1	)	$	(0.4	)
		Six months ended
		June 30,
		2014			2013
	Foreign currency translation
	Balance at beginning of period	$	(22.2	)	$	12.6
	Other comprehensive loss:
	Foreign currency translation adjustments(1)		(1.4	)		(30.1	)
	Balance at end of period	$	(23.6	)	$	(17.5	)
	Pension
	Balance at beginning of period	$	(0.4	)	$	(1.8	)
	Other comprehensive loss:
	Amortization of net actuarial gain		—			—
	Balance at end of period	$	(0.4	)	$	(1.8	)
	Cash flow hedges
	Balance at beginning of period	$	0.2		$	(1.4	)
	Other comprehensive (loss) income:
	Net change from periodic revaluations		(1.1	)		1
	Tax benefit (expense)		0.4			(0.4	)
	Total Other comprehensive (loss) income before reclassifications, net of tax		(0.7	)		0.6
	Net amount reclassified to earnings (loss):
	Interest rate swaps(2)		0.7			0.8
	Fuel commodity swaps(3)		—			(0.2	)
	Sub-total		0.7			0.6
	Tax expense		0.3			0.2
	Total amount reclassified from Accumulated other comprehensive loss, net of tax		0.4			0.4
	Total Other comprehensive (loss) income		(0.3	)		1
	Balance at end of period	$	(0.1	)	$	(0.4	)
	-1
	In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).
	-2
	This amount was included in Interest expense, net on the accompanying consolidated statements of operations.
	-3
	A positive amount indicates a corresponding charge to earnings (loss) and a negative amount indicates a corresponding benefit to earnings (loss). These amounts were reflected on the accompanying consolidated statements of operations in the line items indicated in footnotes 1 and 2.

Equity_method_investments_in_u1

Equity method investments in unconsolidated affiliates (Tables)	6 Months Ended
	Jun. 30, 2014
Equity method investments in unconsolidated affiliates	'
Summarized operating results information	'
		Three months ended						Six months ended
		June 30,						June 30,
	Operating results	2014			2013			2014			2013
	Revenue
	Chambers	$	12.6		$	13.4		$	30.6		$	26.6
	Other(1)		33.5			41.2			73.2			80.6
			46.1			54.6			103.8			107.2
	Project expenses
	Chambers		10.8			11.1			25.1			20.7
	Other(1)		28.8			34.5			61.4			68.1
			39.6			45.6			86.5			88.8
	Project other expense
	Chambers		(1.5	)		(0.6	)		(2.1	)		(1.2	)
	Other(1)		(1.7	)		0.3			(3.3	)		(1.3	)
			(3.2	)		(0.3	)		(5.4	)		(2.5	)
	Project income
	Chambers	$	0.3		$	1.7		$	3.4		$	4.7
	Other(1)		3			7			8.5			11.2
			3.3			8.7			11.9			15.9
	-1
	Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

Goodwill_Tables

Goodwill (Tables)	6 Months Ended
	Jun. 30, 2014
Goodwill	'
Schedule of rollforward of goodwill	'
	(in millions)	East			West		Wind		Un-allocated		Total
									corporate
	Balance at December 31, 2013	$	107.8		$	188.5	$	—	$	—	$	296.3
	Impairment of Goodwill		(5.2	)		—		—		—		(5.2	)
	Balance at June 30, 2014	$	102.6		$	188.5	$	—	$	—	$	291.1

Longterm_debt_Tables

Long-term debt (Tables)	6 Months Ended
	Jun. 30, 2014
Long-term debt	'
Schedule of long-term debt	'
		June 30,			December 31,			Interest Rate
		2014			2013
	Recourse Debt:
	Senior secured term loan facility, due 2021	$	562.5		$	—		LIBOR(1) plus 3.8%
	Senior unsecured notes, due 2018(2)		319.9			460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		196.8			197.4		6.00%
	Senior unsecured notes, due July 2014(3)		—			190		5.90%
	Series A senior unsecured notes, due August 2015(3)		—			150		5.90%
	Series B senior unsecured notes, due August 2017(3)		—			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		28			30.5		LIBOR plus 3.1%
	Cadillac term loan, due 2025		34.4			35.4		6.0% – 8.0%
	Piedmont term loan, due 2018(4)		68.3			76.6		5.20%
	Meadow Creek term loan, due 2024		167.3			169.8		2.9% – 5.6%
	Rockland term loan, due 2027		84.4			85.3		6.40%
	Other long-term debt		0.8			1		5.5% – 6.7%
	Less: current maturities		(26.4	)		(216.2	)
	Total long-term debt	$	1,436.00		$	1,254.80
	-1
	LIBOR cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount of the $568.5 million outstanding aggregate borrowings. See Note 8, Accounting for derivative instruments and hedging activities for further details.
	-2
	We repurchased approximately $140.1 million aggregate principal amount of the 9.0% Notes in March 2014 with a portion of the proceeds from the New Senior Secured Credit Facilities and cash on hand, as further described below.
	-3
	The Curtis Palmer Notes due July 2014, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes due August 2017 were retired on February 26, 2014 with proceeds from the New Senior Secured Credit Facilities described below.
	-4
	On February 14, 2014, we paid down $8.1 million of principal on the Piedmont construction loan and converted the remaining $68.5 million to a term loan due August 2018.
Schedule of current maturities	'
		June 30,			December 31,			Interest Rate
		2014			2013
	Current Maturities:
	Senior secured term loan facility, due 2021	$	6		$	—		LIBOR(1) plus 3.8%
	Senior unsecured notes, due July 2014(3)		—			190		5.90%
	Epsilon Power Partners term facility, due 2019		5.3			5		LIBOR plus 3.1%
	Cadillac term loan, due 2025		3.6			2		6.0% – 8.0%
	Piedmont term loan, due 2018(4)		4.9			12.6		5.20%
	Meadow Creek term loan, due 2024		4.8			4.9		2.9% – 5.6%
	Rockland term loan, due 2027		1.6			1.5		6.40%
	Other short-term debt		0.2			0.2		5.5 – 6.7%
	Total current maturities	$	26.4		$	216.2
	-1
	LIBOR cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount of the $568.5 million outstanding aggregate borrowings. See Note 8, Accounting for derivative instruments and hedging activities for further details.
	-2
	We repurchased approximately $140.1 million aggregate principal amount of the 9.0% Notes in March 2014 with a portion of the proceeds from the New Senior Secured Credit Facilities and cash on hand, as further described below.
	-3
	The Curtis Palmer Notes due July 2014, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes due August 2017 were retired on February 26, 2014 with proceeds from the New Senior Secured Credit Facilities described below.
	-4
	On February 14, 2014, we paid down $8.1 million of principal on the Piedmont construction loan and converted the remaining $68.5 million to a term loan due August 2018.

Fair_value_of_financial_instru1

Fair value of financial instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Fair value of financial instruments	'
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	'
		June 30, 2014
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	157.6	$	—	$	—	$	157.6
	Restricted cash		35.7		—		—		35.7
	Derivative instruments asset		—		8		—		8
	Total	$	193.3	$	8	$	—	$	201.3
	Liabilities:
	Derivative instruments liability	$	—	$	86.6	$	—	$	86.6
	Total	$	—	$	86.6	$	—	$	86.6
		December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	158.6	$	—	$	—	$	158.6
	Restricted cash		114.2		—		—		114.2
	Derivative instruments asset		—		13.2		—		13.2
	Total	$	272.8	$	13.2	$	—	$	286
	Liabilities:
	Derivative instruments liability	$	—	$	104.6	$	—	$	104.6
	Total	$	—	$	104.6	$	—	$	104.6

Accounting_for_derivative_inst1

Accounting for derivative instruments and hedging activities (Tables)	6 Months Ended
	Jun. 30, 2014
Accounting for derivative instruments and hedging activities	'
Schedule of notional volumes of forecasted transactions	'
		Units		June 30,			December 31,
				2014			2013
	Natural gas swaps	Natural Gas (Mmbtu)			7.1			5.6
	Gas purchase agreements	Natural Gas (Gj)			38.9			41.1
	Interest rate swaps	Interest (US$)			152.4			161.2
	Currency forwards	Cdn$			45.3			34.9
Schedule of fair value of derivative instruments	'
		June 30, 2014
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			3
	Total derivative instruments designated as cash flow hedges		—			4.3
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.8
	Interest rate swaps long-term		6.3			12.6
	Foreign currency forward contracts current		1.4			—
	Foreign currency forward contracts long-term		—			—
	Natural gas swaps current		0.3			0.2
	Natural gas swaps long-term		—			0.7
	Gas purchase agreements current		—			19.1
	Gas purchase agreements long-term		—			41.9
	Total derivative instruments not designated as cash flow hedges		8			82.3
	Total derivative instruments	$	8		$	86.6
		December 31, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			2.6
	Total derivative instruments designated as cash flow hedges		—			3.9
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		11.5			8.1
	Foreign currency forward contracts current		0.5			0.7
	Foreign currency forward contracts long-term		1.2			—
	Natural gas swaps current		0.3			1.3
	Natural gas swaps long-term		—			3.5
	Gas purchase agreements current		0.2			18.4
	Gas purchase agreements long-term		—			61.9
	Total derivative instruments not designated as cash flow hedges		13.7			101.2
	Total derivative instruments	$	13.7		$	105.1
Schedule of changes in OCI attributable to derivative financial instruments	'
	For the three months ended June 30, 2014	Interest Rate
		Swaps
	Accumulated OCI balance at March 31, 2014	$	0.1
	Change in fair value of cash flow hedges		(0.3	)
	Realized from OCI during the period		0.1
	Accumulated OCI balance at June 30, 2014	$	(0.1	)
	For the three months ended June 30, 2013	Interest Rate			Natural Gas			Total
		Swaps			Swaps
	Accumulated OCI balance at March 31, 2013	$	(1.2	)	$	0.1		$	(1.1	)
	Change in fair value of cash flow hedges		0.6			—			0.6
	Realized from OCI during the period		0.2			(0.1	)		0.1
	Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
	For the six months ended June 30, 2014	Interest Rate
		Swaps
	Accumulated OCI balance at January 1, 2014	$	0.2
	Change in fair value of cash flow hedges		(0.7	)
	Realized from OCI during the period		0.4
	Accumulated OCI balance at June 30, 2014	$	(0.1	)
	For the six months ended June 30, 2013	Interest Rate			Natural Gas			Total
		Swaps			Swaps
	Accumulated OCI balance at January 1, 2013	$	(1.5	)	$	0.1		$	(1.4	)
	Change in fair value of cash flow hedges		0.6			—			0.6
	Realized from OCI during the period		0.5			(0.1	)		0.4
	Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
Summary of realized (gains) and losses for derivative instruments not designated as cash flow hedges	'
				Three months ended
		Classification of (gain) loss		June 30,
		recognized in income		2014			2013
	Natural gas swaps	Fuel		$	(0.2	)	$	—
	Gas purchase agreements	Fuel			13.4			14.1
	Interest rate swaps	Interest, net			(3.6	)		(10.8	)
	Foreign currency forwards	Foreign exchange loss			—			4
				Six months ended
		Classification of (gain) loss		June 30,
		recognized in income		2014			2013
	Natural gas swaps	Fuel		$	3.7		$	—
	Gas purchase agreements	Fuel			29.3			30.4
	Interest rate swaps	Interest, net			(7.8	)		(13.3	)
	Foreign currency forwards	Foreign exchange (gain) loss			(0.1	)		6.6
Summary of the unrealized (gains) and losses resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges	'
				Three months ended
		Classification of (gain) loss		June 30,
		recognized in income		2014			2013
	Natural gas swaps	Change in fair value of derivatives		$	1		$	1.1
	Gas purchase agreements	Change in fair value of derivatives			(2.6	)		(7.4	)
	Interest rate swaps	Change in fair value of derivatives			4.4			(18.0	)
	Total change in fair value of derivative instruments			$	2.8		$	(24.3	)
	Foreign currency forwards	Foreign exchange (gain) loss		$	(1.4	)	$	12.8
				Six months ended
		Classification of (gain) loss		June 30,
		recognized in income		2014			2013
	Natural gas swaps	Change in fair value of derivatives		$	(3.5	)	$	0.7
	Gas purchase agreements	Change in fair value of derivatives			(18.6	)		(15.5	)
	Interest rate swaps	Change in fair value of derivatives			10.2			(22.1	)
	Total change in fair value of derivative instruments			$	(11.9	)	$	(36.9	)
	Foreign currency forwards	Foreign exchange (gain) loss		$	(0.3	)	$	18.8

Income_taxes_Tables

Income taxes (Tables)	6 Months Ended
	Jun. 30, 2014
Income taxes	'
Schedule of components of income tax expenses (benefit)	'
		Three months ended						Six months ended
		June 30,						June 30,
		2014			2013			2014			2013
	Current income tax expense	$	1.4		$	3.4		$	2.6		$	5.4
	Deferred tax benefit		(2.0	)		(2.8	)		(15.5	)		(7.3	)
	Total income tax (benefit), net	$	(0.6	)	$	0.6		$	(12.9	)	$	(1.9	)

Equity_compensation_plans_Tabl

Equity compensation plans (Tables)	6 Months Ended
	Jun. 30, 2014
Equity compensation plans	'
Schedule of changes in LTIP notional shares	'
		Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2013		766,988		$	7.86
	Granted		1,776,083			2.64
	Reinvested		99,452			4.12
	Forfeited		(182,783	)		8
	Vested		(242,160	)		8.72
	Outstanding at June 30, 2014		2,217,580		$	3.41

Basic_and_diluted_earnings_los1

Basic and diluted earnings (loss) per share (Tables)	6 Months Ended
	Jun. 30, 2014
Basic and diluted earnings (loss) per share	'
Schedule of diluted net income (loss) and potentially dilutive shares utilized in the per share calculation	'
		Three months ended						Six months ended
		June 30,						June 30,
		2014			2013			2014			2013
	Numerator:
	(Loss) income from continuing operations attributable to Atlantic Power Corporation	$	(59.2	)	$	2.4		$	(77.9	)	$	8.4
	Loss from discontinued operations, net of tax		—			(5.4	)		(0.1	)		(4.9	)
	Net (loss) income attributable to Atlantic Power Corporation	$	(59.2	)	$	(3.0	)	$	(78.0	)	$	3.5
	Denominator:
	Weighted average basic shares outstanding		120.6			119.9			120.5			119.7
	Dilutive potential shares:
	Convertible debentures		27.7			27.7			27.7			27.7
	LTIP notional units		0.4			0.8			0.2			0.6
	Potentially dilutive shares		148.7			148.4			148.4			148
	Diluted (loss) earnings per share from continuing operations attributable to Atlantic Power Corporation	$	(0.49	)	$	0.02		$	(0.65	)	$	0.07
	Diluted loss per share from discontinued operations		—			(0.05	)		—			(0.04	)
	Diluted (loss) income per share attributable to Atlantic Power Corporation	$	(0.49	)	$	(0.03	)	$	(0.65	)	$	0.03

Discontinued_operations_Tables

Discontinued operations (Tables)	6 Months Ended
	Jun. 30, 2014
Discontinued operations	'
Summary of the revenue, income (loss) from operations, and income tax expense of Greelay Rollcast, Path 15 and the Florida Projects	'
		Three months ended					Six months ended
		June 30,					June 30,
		2014		2013			2014			2013
	Revenue	$	—	$	11.4		$	—		$	77.2
	(Loss) income from operations of discontinued businesses		—		(5.0	)		(0.1	)		(4.1	)
	Income tax expense		—		0.4			—			0.8
	(Loss) income from operations of discontinued businesses, net of tax	$	—	$	(5.4	)	$	(0.1	)	$	(4.9	)

Equity_Tables

Equity (Tables)	6 Months Ended
	Jun. 30, 2014
Equity	'
Schedule of reconciliation of equity	'
		Six months ended June 30, 2014
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	608.3		$	221.3		$	266.4		$	1,096.00
	Net (loss) income		(78.0	)		5.9			(6.7	)		(78.8	)
	Realized and unrealized gain on hedging activities, net of tax		(0.2	)		—			—			(0.2	)
	Foreign currency translation adjustment, net of tax		(1.5	)		—			—			(1.5	)
	Common shares issued for LTIP		0.6			—			—			0.6
	Dividends paid to noncontrolling interest		—			—			(5.2	)		(5.2	)
	Dividends declared on common shares		(21.1	)		—			—			(21.1	)
	Dividends declared on preferred shares of a subsidiary company		—			(5.9	)		—			(5.9	)
	Balance at June 30	$	508.1		$	221.3		$	254.5		$	983.9
		Six months ended June 30, 2013
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	729.7		$	221.3		$	235.4		$	1,186.40
	Net income (loss)		3.5			6.3			(0.8	)		9
	Realized and unrealized gain on hedging activities, net of tax		1			—			—			1
	Foreign currency translation adjustment, net of tax		(30.1	)		—			—			(30.1	)
	Common shares issued for LTIP		0.9			—			—			0.9
	Contribution by and sale of noncontrolling interest		—			—			44.5			44.5
	Costs associated with tax equity raise		(0.9	)		—			—			(0.9	)
	Dividends paid to noncontrolling interest		—			—			(2.9	)		(2.9	)
	Dividends declared on common shares		(35.5	)		—			—			(35.5	)
	Dividends declared on preferred shares of a subsidiary company		—			(6.3	)		—			(6.3	)
	Balance at June 30	$	668.6		$	221.3		$	276.2		$	1,166.10

Segment_and_geographic_informa1

Segment and geographic information (Tables)	6 Months Ended
	Jun. 30, 2014
Segment and geographic information	'
Schedule of a reconciliation of project income (loss) to Project Adjusted EBITDA	'
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Three months ended June 30, 2014
	Project revenues	$	76.2		$	46.8		$	20		$	0.2		$	143.2
	Segment assets		1,192.30			977.6			818.1			222.7			3,210.70
	Project Adjusted EBITDA	$	38.5		$	22.9		$	17.2		$	(3.6	)	$	75
	Change in fair value of derivative instruments		(0.8	)		—			2.8			1.1			3.1
	Depreciation and amortization		24.4			16.2			11.5			0.2			52.3
	Interest, net		3.7			—			4.8			0.1			8.6
	Other project expense		14.8			—			—			—			14.8
	Project income (loss)		(3.6	)		6.7			(1.9	)		(5.0	)		(3.8	)
	Administration		—			—			—			10.2			10.2
	Interest, net		—			—			—			27.7			27.7
	Foreign exchange (loss) gain		—			—			—			15.3			15.3
	Other income, net		—			—			—			—			—
	Income (loss) from continuing operations before income taxes		(3.6	)		6.7			(1.9	)		(58.2	)		(57.0	)
	Income tax benefit		—			—			—			(0.6	)		(0.6	)
	Net income (loss)	$	(3.6	)	$	6.7		$	(1.9	)	$	(57.6	)	$	(56.4	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Three months ended June 30, 2013
	Project revenues	$	71.9		$	45.8		$	18.2		$	0.2		$	136.1
	Segment assets		1,468.70			1,056.00			907.4			135.3			3,567.40
	Project Adjusted EBITDA	$	29.4		$	14.1		$	15.5		$	(3.1	)	$	55.9
	Change in fair value of derivative instruments		(10.6	)		—			(15.3	)		(0.9	)		(26.8	)
	Depreciation and amortization		21.8			17.1			11.4			0.2			50.5
	Interest, net		5.5			0.1			4.9			(1.0	)		9.5
	Other project expense		0.5			—			—			1.9			2.4
	Project income (loss)		12.2			(3.1	)		14.5			(3.3	)		20.3
	Administration		—			—			—			11.8			11.8
	Interest, net		—			—			—			25.3			25.3
	Foreign exchange gain		—			—			—			(14.5	)		(14.5	)
	Other income, net		—			—			—			(9.5	)		(9.5	)
	Income (loss) from continuing operations before income taxes		12.2			(3.1	)		14.5			(16.4	)		7.2
	Income tax expense		—			—			—			0.6			0.6
	Net income (loss) from continuing operations		12.2			(3.1	)		14.5			(17.0	)		6.6
	Loss from discontinued operations		(1.2	)		1.2			—			(5.4	)		(5.4	)
	Net income (loss)	$	11		$	(1.9	)	$	14.5		$	(22.4	)	$	1.2
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Six months ended June 30, 2014
	Project revenues	$	162.8		$	85.3		$	40.1		$	0.3		$	288.5
	Segment assets		1,192.30			977.6			818.1			222.7			3,210.70
	Project Adjusted EBITDA	$	84		$	34.1		$	35.1		$	(3.6	)	$	149.6
	Change in fair value of derivative instruments		(22.6	)		—			10.4			1.2			(11.0	)
	Depreciation and amortization		48.8			32.6			22.8			0.5			104.7
	Interest, net		15.3			—			9.4			—			24.7
	Other project expense		14.8			—			—			—			14.8
	Project income (loss)		27.7			1.5			(7.5	)		(5.3	)		16.4
	Administration		—			—			—			17.5			17.5
	Interest, net		—			—			—			94.1			94.1
	Foreign exchange (loss) gain		—			—			—			(1.5	)		(1.5	)
	Other income, net		—			—			—			(2.1	)		(2.1	)
	Income (loss) from continuing operations before income taxes		27.7			1.5			(7.5	)		(113.3	)		(91.6	)
	Income tax benefit		—			—			—			(12.9	)		(12.9	)
	Net income (loss) from continuing operations		27.7			1.5			(7.5	)		(100.4	)		(78.7	)
	Loss from discontinued operations		—			(0.1	)		—			—			(0.1	)
	Net income (loss)	$	27.7		$	1.4		$	(7.5	)	$	(100.4	)	$	(78.8	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Six months ended June 30, 2013
	Project revenues	$	151.7		$	86.4		$	35.7		$	(0.2	)	$	273.6
	Segment assets		1,468.70			1,056.00			907.4			135.3			3,567.40
Project Adjusted EBITDA	$	78.5		$	34.7		$	30.5		$	(7.6	)	$	136.1
Change in fair value of derivative instruments		(20.0	)		—			(18.3	)		—			(38.3	)
Depreciation and amortization		44.2			34.2			23.7			0.2			102.3
Interest, net		9.9			0.1			9.8			(0.1	)		19.7
Other project expense		1			—			—			(0.4	)		0.6
Project income (loss)		43.4			0.4			15.3			(7.3	)		51.8
Administration		—			—			—			20.1			20.1
Interest, net		—			—			—			51.2			51.2
Foreign exchange gain		—			—			—			(22.0	)		(22.0	)
Other income, net		—			—			—			(9.5	)		(9.5	)
Income (loss) from continuing operations before income taxes		43.4			0.4			15.3			(47.1	)		12
Income tax benefit		—			—			—			(1.9	)		(1.9	)
Net income (loss) from continuing operations		43.4			0.4			15.3			(45.2	)		13.9
Loss from discontinued operations		(0.9	)		1.8			—			(5.8	)		(4.9	)
Net income (loss)	$	42.5		$	2.2		$	15.3		$	(51.0	)	$	9
Schedule of revenue and property, plant and equipment by country	'
														Property, Plant and
														Equipment, net of
		Project Revenue						Project Revenue						accumulated depreciation
		Three months ended						Six months ended
		June 30,						June 30,						June 30,			December 31,
		2014			2013			2014			2013			2014			2013
	United States	$	98.2		$	91		$	191.3		$	161.1		$	1,296.60		$	1,330.50
	Canada		45			45.1			97.2			112.5			454.6			482.9
	Total	$	143.2		$	136.1		$	288.5		$	273.6		$	1,751.20		$	1,813.40

Nature_of_business_and_basis_o2

Nature of business and basis of presentation (Details)	6 Months Ended
	Jun. 30, 2014
	MW
	state
	province
	project
Basis of presentation and summary of significant accounting policies	'
Gross generating capacity of project (in MW)	2,945
Ownership interest in operational power generation projects (in MW)	2,024
Number of operational power generation projects	28
Number of states in which power generation projects operate	11
Number of provinces in which power generation projects operate	2
Number of projects Which are wholly owned subsidiaries	20
Delta-Person	'
Basis of presentation and summary of significant accounting policies	'
Percentage of ownership interest	40.00%

Changes_in_accumulated_other_c2

Changes in accumulated other comprehensive loss by component (Details) (USD $)

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Foreign currency translation

Foreign currency translation

Foreign currency translation

Foreign currency translation

Pension

Pension

Pension

Pension

Pension

Pension

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Cash flow hedges

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Amount reclassified from accumulated other comprehensive income

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Fuel commodity swaps

Fuel commodity swaps

Changes in accumulated other comprehensive loss by component

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at beginning of period

'

'

($22.40)

'

($40.90)

$0.50

($22.20)

$12.60

($0.40)

($0.40)

($0.40)

($1.80)

($1.80)

($1.80)

$0.10

($1.10)

$0.20

($1.40)

'

'

'

'

'

'

'

'

'

'

Other comprehensive (Loss):

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Foreign currency translation adjustments

17.3

-18

-1.4

-30.1

17.3

-18

-1.4

-30.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net change from periodic revaluations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-0.5

1

-1.1

1

'

'

'

'

'

'

'

'

'

'

Tax benefit (expense)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.2

-0.4

0.4

-0.4

'

'

'

'

'

'

'

'

'

'

Total Other comprehensive income (loss) before reclassifications, net of tax

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-0.3

0.6

-0.7

0.6

'

'

'

'

'

'

'

'

'

'

Net amount reclassified to earnings (loss):

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.3

0.3

0.7

0.6

0.3

0.4

0.7

0.8

-0.1

-0.2

Tax expense

-0.6

0.6

-12.9

-1.9

'

'

'

'

'

'

'

'

'

'

0.2

0.2

0.3

0.2

'

'

'

'

'

'

'

'

'

'

Total amount reclassified from Accumulated other comprehensive loss, net of tax

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.1

0.1

0.4

0.4

'

'

'

'

'

'

'

'

'

'

Total Other comprehensive (loss) income

17.1

-17.3

-1.7

-29.1

'

'

'

'

'

'

'

'

'

'

-0.2

0.7

-0.3

1

'

'

'

'

'

'

'

'

'

'

Balance at end of period

-24.1

'

-24.1

'

-23.6

-17.5

-23.6

-17.5

-0.4

-0.4

-0.4

-1.8

-1.8

-1.8

-0.1

-0.4

-0.1

-0.4

'

'

'

'

'

'

'

'

'

'

Accumulated other comprehensive loss, tax impacts related to rate changes

'

'

'

'

$0

$0

$0

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisitions_and_divestments_D

Acquisitions and divestments (Details) (USD $)

6 Months Ended

1 Months Ended

6 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

4 Months Ended

0 Months Ended

1 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2012

Jun. 30, 2014

Jul. 14, 2014

Apr. 02, 2013

Apr. 30, 2013

Sep. 30, 2013

Apr. 30, 2013

Jan. 31, 2013

Apr. 30, 2013

Apr. 30, 2013

Apr. 30, 2013

Mar. 31, 2014

Jun. 30, 2014

Delta-Person

Delta-Person

Delta-Person

Gregory

Gregory

Gregory

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Path 15

Path 15

Greeley

Greeley

Expected

Acquisition and divestments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total price

'

'

$37.20

'

'

'

$274.20

'

'

$140

'

'

$56

'

'

Expected proceeds from sale

'

'

7.2

'

'

'

34.6

'

'

'

'

'

'

'

'

Gain on sale of equity method investment

'

'

'

8.6

'

'

'

31

'

'

'

'

'

'

'

Sale of issued and outstanding membership interests

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

Gain (loss) on sale

'

-32.8

'

'

'

'

'

'

'

'

'

'

'

2.1

2.1

Net cash proceeds from sale

'

'

'

'

'

'

'

'

92

'

117

'

52

'

'

Proceeds from sale to be held in escrow account

'

'

'

'

1.4

'

5

'

'

'

'

'

'

'

'

Term Of Escrow Account

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

Outstanding balance of senior credit facility

'

'

'

'

'

'

'

'

64.1

'

64.1

'

'

'

'

Management termination fee

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

Distributions from unconsolidated affiliates

37.8

18

'

'

'

'

'

'

'

'

25

'

'

'

'

Debt transferred with the sale of business

'

'

'

'

'

'

'

'

'

'

'

$137.20

'

'

'

Equity_method_investments_in_u2

Equity method investments in unconsolidated affiliates (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating results	'	'	'	'
Revenue	$46.10	$54.60	$103.80	$107.20
Project expenses	39.6	45.6	86.5	88.8
Project other expense	-3.2	-0.3	-5.4	-2.5
Project income	3.3	8.7	11.9	15.9
Chambers	'	'	'	'
Operating results	'	'	'	'
Revenue	12.6	13.4	30.6	26.6
Project expenses	10.8	11.1	25.1	20.7
Project other expense	-1.5	-0.6	-2.1	-1.2
Project income	0.3	1.7	3.4	4.7
Other	'	'	'	'
Operating results	'	'	'	'
Revenue	33.5	41.2	73.2	80.6
Project expenses	28.8	34.5	61.4	68.1
Project other expense	-1.7	0.3	-3.3	-1.3
Project income	$3	$7	$8.50	$11.20

Goodwill_Details

Goodwill (Details) (USD $)	3 Months Ended	6 Months Ended		12 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2011	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Dec. 31, 2013
				Partnership	Tunis	East	East	West	West
							Tunis
Goodwill	'	'	'	'	'	'	'	'	'
Goodwill recorded in connection with the acquisition	'	'	'	$331.10	'	'	'	'	'
Long-lived asset impairment charge	'	'	'	'	9.6	'	'	'	'
Impairment charges	14.8	14.8	4.9	'	14.8	'	'	'	'
Changes in the carrying amount of goodwill	'	'	'	'	'	'	'	'	'
Balance at the beginning of the period	'	296.3	'	'	'	107.8	'	188.5	188.5
Impairment of Goodwill	'	-5.2	'	'	'	-5.2	5.2	'	'
Balance at the end of the period	$291.10	$291.10	'	'	'	$102.60	'	$188.50	$188.50

Longterm_debt_Details

Long-term debt (Details)

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

0 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

In Millions, except Per Share data, unless otherwise specified

Mar. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jul. 31, 2014

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Mar. 25, 2014

Nov. 05, 2011

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Feb. 26, 2014

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Feb. 14, 2014

Feb. 14, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 24, 2014

5-May-14

5-May-14

Jun. 30, 2014

Feb. 24, 2014

Feb. 24, 2014

Jun. 30, 2014

Feb. 26, 2014

Feb. 24, 2014

Jun. 30, 2014

Feb. 24, 2014

Jun. 30, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 26, 2014

Jun. 30, 2014

CAD

USD ($)

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

Interest rate swaps

Interest rate swaps

Senior secured term loan facility, due 2021

Senior secured term loan facility, due 2021

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

5.95% Medium Term Notes due June 23, 2036

Senior unsecured notes, due July 2014

Senior unsecured notes, due July 2014

Series A senior unsecured notes, due August 2015

Series B senior unsecured notes, due August 2017

Epsilon Power Partners term facility, due 2019

Epsilon Power Partners term facility, due 2019

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Piedmont term loan, due 2018

Piedmont term loan, due 2018

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Rockland term loan, due 2027

Rockland term loan, due 2027

Other long-term debt

Other long-term debt

Other long-term debt

Other long-term debt

Term loan due August 2018

Piedmont construction loan, due 2014

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

Existing notes

5.87% senior guaranteed notes, Series A, due August 15, 2017

5.97% senior guaranteed notes, Series B, due August 15, 2019

Prior credit facility

item

USD ($)

USD ($)

USD ($)

London Interbank Offered Rate (LIBOR)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

CAD

USD ($)

CAD

The Partnership

USD ($)

Curtis Palmer

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

London Interbank Offered Rate (LIBOR)

USD ($)

The Partnership

The Partnership

The Partnership

The Partnership

Minimum

Maximum

Adjusted Eurodollar Rate

Base Rate

Canadian Prime Rate

The Partnership

The Partnership

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

The Partnership

The Partnership

The Partnership

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

Base Rate

Base Rate

The Partnership

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

Effect of change of control

Repayment of loan facility within one year

The Partnership

The Partnership

The Partnership

The Partnership

The Partnership

USD ($)

USD ($)

Interest rate swaps

The Partnership

Minimum

USD ($)

USD ($)

The Partnership

The Partnership

The Partnership

The Partnership

USD ($)

USD ($)

The Partnership

Long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt

'

'

'

'

'

'

'

'

'

'

$562.50

'

'

$460

$319.90

'

$460

$196.80

210

$197.40

210

'

$190

'

$150

$75

$28

$30.50

$34.40

$35.40

'

'

$68.30

$76.60

$167.30

$169.80

'

'

$84.40

$85.30

$0.80

$1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less: current maturities

'

-26.4

'

-26.4

'

'

'

-216.2

'

'

-6

'

'

'

'

'

'

'

'

'

'

'

-190

'

'

'

-5.3

-5

-3.6

-2

'

'

-4.9

-12.6

-4.8

-4.9

'

'

-1.6

-1.5

-0.2

-0.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt

'

1,436

'

1,436

'

'

'

1,254.80

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount of debt repurchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

140.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount

'

'

'

'

'

'

'

'

152.4

161.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

199

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

210

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

568.5

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

9.00%

9.00%

9.00%

'

'

6.00%

6.00%

'

'

5.95%

'

5.90%

'

'

'

'

'

'

6.00%

8.00%

5.20%

'

'

'

2.90%

5.60%

6.40%

'

'

'

5.50%

6.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.87%

5.97%

'

Variable interest rate basis

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'

'

'

'

'

'Adjusted Eurodollar Rate

'Base Rate

'Canadian Prime Rate

'

'

'Adjusted Eurodollar Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum percentage of variable rate base

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

3.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.75%

3.75%

'

'

'

'

'

3.75%

'

3.75%

1.00%

'

'

'

3.75%

3.75%

2.75%

3.75%

'

'

'

'

Maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

'

'

'

'

'

'

'

'

'

210

'

'

'

Principal amount of debt repaid

'

'

'

'

'

'

'

'

'

'

'

'

140.1

'

'

'

'

'

'

'

'

'

'

190

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150

75

'

Amount of commission fees paid

'

'

'

'

'

'

'

'

'

'

'

'

0.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt converted to term loan due August 2018

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

68.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fee (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

'

'

'

'

'

'

'

'

'

'

Period prior to expiration date of facility letters of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 days

'

'

'

'

'

'

'

'

'

'

Debt service reserve requirement period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio of total debt to adjusted EBITDA in 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio of total debt to adjusted EBITDA in 2021

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio of adjusted EBITDA to cash interest expense in 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio of adjusted EBITDA to cash interest expense in 2021

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price as percentage of principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101.00%

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Mandatory prepayment as a percentage of excess cash flows

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount drawn under facility

'

'

'

'

20.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit issued but not drawn

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

107

144.1

'

'

'

'

'

'

'

'

Debt service reserve requirement amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued interest and make-whole premiums

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution amount to be received from proceeds of issuance of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

122

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable redemption make whole premium

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transaction costs and expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued interest and premium payments

'

'

'

'

'

'

'

'

'

'

'

'

15.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.6

Fuel expense

'

50.4

50

110.2

97.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

Foreign exchange loss

'

15.3

-14.5

-1.5

-22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.4

Percentage of par value at which debt was issued

'

'

'

'

'

'

'

'

'

'

'

'

'

97.47%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross proceeds from senior notes

'

'

'

600

'

'

'

'

'

'

'

'

'

448

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repurchase of aggregate principal amount of debt

'

'

'

'

'

'

'

'

'

'

'

'

140.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Write off of deferred financing cost related to repurchase

'

'

'

'

'

'

'

'

'

'

'

'

5.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed charge coverage ratio

'

'

'

1.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of rolling quarters used in measurement of fixed charge coverage ratio

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum dividend payments, amount

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum dividend payments as a percentage of consolidated net assets

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of maximum dividend payments derived from specified percentage of consolidated net assets

'

'

'

61

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend payments

'

'

'

20.9

43.2

48.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total dividends declared

'

'

'

'

'

'

$25.60

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend payments per common share (in dollars per share)

0.03333

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of additional successive quarters following the quarter in which the prepayment charges are incurred, after which prepayment charges not reflected in the calculation of the fixed charge coverage ratio

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_value_of_financial_instru2

Fair value of financial instruments (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets:	'	'
Restricted cash	$17.80	$96.20
Recurring | Level 1	'	'
Assets:	'	'
Cash and cash equivalents	157.6	158.6
Restricted cash	35.7	114.2
Total	193.3	272.8
Recurring | Level 2	'	'
Assets:	'	'
Derivative instruments asset	8	13.2
Total	8	13.2
Liabilities:	'	'
Derivative instruments liability	86.6	104.6
Total	86.6	104.6
Recurring | Total	'	'
Assets:	'	'
Cash and cash equivalents	157.6	158.6
Restricted cash	35.7	114.2
Derivative instruments asset	8	13.2
Total	201.3	286
Liabilities:	'	'
Derivative instruments liability	86.6	104.6
Total	$86.60	$104.60

Fair_value_of_financial_instru3

Fair value of financial instruments (Details 2) (Credit valuation adjustments, USD $)	6 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Credit valuation adjustments	'	'
Recurring measurements of fair value hierarchy of financial assets and liabilities	'	'
Net increase in fair value	$8.10	$11.10
Pre-tax increase in other comprehensive income (loss)	0.5	0.5
Increase in change in fair value of derivatives	$7.60	$10.60

Fair_value_of_financial_instru4

Fair value of financial instruments (Details 3) (Interest rate swaps, USD $)	Jun. 30, 2014	Dec. 31, 2013	5-May-14	5-May-14
In Millions, unless otherwise specified			Adjusted Eurodollar Rate	Adjusted Eurodollar Rate
			New term loan facility	New term loan facility
				Derivative instruments
Derivative instruments	'	'	'	'
Swaption interest rate (as a percent)	'	'	'	1.16%
Notional amount	$152.40	$161.20	$199	'
Aggregate principal amount of debt	'	'	$568.50	'

Accounting_for_derivative_inst2

Accounting for derivative instruments and hedging activities (Details)

Jun. 30, 2014

5-May-14

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

5-May-14

5-May-14

5-May-14

Jun. 30, 2014

Jun. 30, 2014

Feb. 14, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Apr. 02, 2014

Apr. 02, 2014

Dec. 31, 2013

Apr. 02, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Millions, unless otherwise specified

USD ($)

New term loan facility

Gas purchase agreements

Expected uncontracted gas requirements for 2014

Expected uncontracted gas requirements for 2015

Expected uncontracted gas requirements for 2016

Expected uncontracted gas requirements for 2017

Natural gas swaps

Natural gas swaps

Natural gas swaps

Natural gas swaps during 2014 and 2015

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Natural gas swaps during remainder of 2014

Natural gas swaps during 2015

Natural gas swaps during 2016

item

Adjusted Eurodollar Rate

Ontario project

Ontario project

Ontario project

Ontario project

Ontario project

MMBTU

MMBTU

Orlando project

Orlando project

USD ($)

USD ($)

New term loan facility

New term loan facility

New term loan facility

Epsilon

Rockland Wind Farm

Piedmont

Swaption interest rate until February 15, 2015

Swaption interest rate from February 16, 2015 to February 15, 2019

Swaption interest rate from February 16, 2019 to February 15, 2023

Swaption interest rate after February 15, 2023

Swaption interest rate until February 29, 2016

Swaption interest rate from February, 2016 to November, 2017

Swaption interest rate from November, 2017 to November, 2030

Swaption interest rate until December 31, 2026

Swaption interest rate from December 31, 2026 to December 31, 2031

Swaption interest rate until December 31, 2024

Swaption interest rate from December 2024 to December 2030

CAD

USD ($)

CAD

CAD

6.5% Debentures due October 2014

gigajoule

MMBTU

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

item

Piedmont construction loan, due 2014

Cadillac Project

Cadillac Project

Cadillac Project

Cadillac Project

Piedmont

Piedmont

Piedmont

Rockland Wind Farm

Rockland Wind Farm

Meadow Creek Project

Meadow Creek Project

CAD

USD ($)

Derivative instruments

USD ($)

Accounting for derivative instruments and hedging activities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative number of contracts designated as cash flow hedges

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instruments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount (in Mmbtu)

'

'

2,900,000

'

'

'

'

7,100,000

5,600,000

'

4,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of the entity's expected uncontracted gas requirements

'

'

'

98.00%

98.00%

32.00%

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of the entity's share in required natural gas purchases hedge

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

89.00%

62.00%

63.00%

Swaption interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.16%

7.37%

'

'

6.00%

6.10%

6.30%

6.40%

1.70%

4.47%

4.47%

'

'

'

'

'

'

'

'

'

'

'

'

Total debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$68.50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred financing cost

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Swap percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

4.20%

7.80%

2.30%

7.20%

'

'

'

'

'

'

'

'

Number of tranches

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin, low end of range (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

'

'

2.30%

'

2.80%

'

'

'

'

'

'

'

'

'

Applicable margin, high end of range (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.80%

'

'

2.80%

'

3.30%

'

'

'

'

'

'

'

'

'

Percentage of floating rate debt converted to a fixed interest rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Swaption interest rate after addition of applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount

'

'

'

'

'

'

'

'

'

'

'

152.4

161.2

'

199

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.3

'

'

34.9

'

'

'

'

Aggregate principal amount of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

568.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

44.8

'

'

'

Variable interest rate basis

'

'Adjusted Eurodollar Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

3.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum percentage of variable rate base

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum fixed interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

4.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum fixed interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

4.91%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of contract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$41

45.3

'

'

'

'

'

Foreign exchange rate (Canadian dollars per US dollar)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.105

'

'

'

'

'

Accounting_for_derivative_inst3

Accounting for derivative instruments and hedging activities (Details 2)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Natural gas swaps	Natural gas swaps	Gas purchase agreements	Gas purchase agreements	Interest rate swaps	Interest rate swaps	Foreign currency forwards	Foreign currency forwards
	MMBTU	MMBTU	gigajoule	gigajoule	USD ($)	USD ($)	CAD	CAD
Derivative instruments	'	'	'	'	'	'	'	'
Volume of forecasted transactions	7,100,000	5,600,000	38,900,000	41,100,000	'	'	'	'
Volume of forecasted transactions, (in dollars)	'	'	'	'	$152.40	$161.20	45.3	34.9

Accounting_for_derivative_inst4

Accounting for derivative instruments and hedging activities (Details 3) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair value of derivative instruments	'	'
Derivative Assets	$8	$13.70
Derivative Liabilities	86.6	105.1
Derivative instruments designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	4.3	3.9
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	1.3	1.3
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	3	2.6
Derivative instruments not designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Assets	8	13.7
Derivative Liabilities	82.3	101.2
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	7.8	7.3
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	6.3	11.5
Derivative Liabilities	12.6	8.1
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	1.4	0.5
Derivative Liabilities	'	0.7
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	'	1.2
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	0.3	0.3
Derivative Liabilities	0.2	1.3
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	0.7	3.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	'	0.2
Derivative Liabilities	19.1	18.4
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	$41.90	$61.90

Accounting_for_derivative_inst5

Accounting for derivative instruments and hedging activities (Details 4) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	'	($1.10)	'	($1.40)
Change in fair value of cash flow hedges	-0.3	0.6	-0.7	0.6
Realized from OCI during the period	0.1	0.1	0.4	0.4
Accumulated OCI balance at end of period	'	-0.4	'	-0.4
Interest Rate Swaps	'	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	0.1	-1.2	0.2	-1.5
Change in fair value of cash flow hedges	-0.3	0.6	-0.7	0.6
Realized from OCI during the period	-0.1	0.2	-0.4	0.5
Accumulated OCI balance at end of period	-0.1	-0.4	-0.1	-0.4
Natural Gas Swaps	'	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	'	0.1	'	0.1
Realized from OCI during the period	'	($0.10)	'	($0.10)

Accounting_for_derivative_inst6

Accounting for derivative instruments and hedging activities (Details 5) (USD $)

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Feb. 20, 2014

Feb. 20, 2014

Feb. 20, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Natural gas swaps

Interest rate swaps

Foreign currency forward contracts

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Natural gas swaps

Natural gas swaps

Natural gas swaps

Natural gas swaps

Gas purchase agreements

Gas purchase agreements

Gas purchase agreements

Gas purchase agreements

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Impact of derivative instruments on the consolidated statements of operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Realized (gains) and losses of derivative instruments

'

'

'

'

'

'

'

'

'

'

'

($0.20)

'

$3.70

'

$13.40

$14.10

$29.30

$30.40

($3.60)

($10.80)

($7.80)

($13.30)

'

$4

($0.10)

$6.60

Amount paid for termination of contracts

'

'

'

'

4

2.6

0.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Change in fair value of derivative instruments

$2.80

($24.30)

($11.90)

($36.90)

'

'

'

($2.80)

($24.30)

($11.90)

($36.90)

$1

$1.10

($3.50)

$0.70

($2.60)

($7.40)

($18.60)

($15.50)

$4.40

($18)

$10.20

($22.10)

($1.40)

$12.80

($0.30)

$18.80

Income_taxes_Details

Income taxes (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Components of income tax expenses (benefit)	'	'	'	'
Current income tax expense	$1.40	$3.40	$2.60	$5.40
Deferred tax benefit	-2	-2.8	-15.5	-7.3
Total income tax (benefit), net	-0.6	0.6	-12.9	-1.9
Canadian enacted statutory rate (as a percent)	26.00%	'	26.00%	'
Computed income taxes at Canadian statutory rate	14.8	'	23.8	'
Valuation allowance	14.2	'	29.3	'
Minority interest	'	'	2.6	'
Capital losses recognized on tax restructuring	'	'	11.1	'
Operating in higher tax rate jurisdictions	3.5	'	9.2	'
Foreign exchange	2.4	'	1.2	'
Other permanent differences	1.1	'	0.5	'
Valuations allowance	$157.40	'	$157.40	'

Equity_compensation_plans_Deta

Equity compensation plans (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Grant Date Weighted-Average Fair Value per Unit	'	'	'	'
Cash payments made for vested notional units	'	'	$0.20	$0.90
Compensation expense related to LTIP	$1	$0.80	$0.90	$1.20
Long-term incentive plan	'	'	'	'
Units	'	'	'	'
Outstanding at the beginning of the period (in shares)	'	'	766,988	'
Granted (in shares)	'	'	1,776,083	'
Reinvested (in shares)	'	'	99,452	'
Forfeitures (in shares)	'	'	-182,783	'
Vested (in shares)	'	'	-242,160	'
Outstanding at the end of the period (in shares)	2,217,580	'	2,217,580	'
Grant Date Weighted-Average Fair Value per Unit	'	'	'	'
Outstanding at the beginning of the period (in dollars per share)	'	'	$7.86	'
Granted (in dollars per share)	'	'	$2.64	'
Reinvested (in dollars per share)	'	'	$4.12	'
Forfeitures (in dollars per share)	'	'	$8	'
Vested (in dollars per share)	'	'	$8.72	'
Outstanding at the end of the period (in dollars per share)	$3.41	'	$3.41	'

Basic_and_diluted_earnings_los2

Basic and diluted earnings (loss) per share (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Numerator:	'	'	'	'
(Loss) income from continuing operations attributable to Atlantic Power Corporation	($59.20)	$2.40	($77.90)	$8.40
Loss from discontinued operations, net of tax	'	-5.4	-0.1	-4.9
Net (loss) income attributable to Atlantic Power Corporation	($59.20)	($3)	($78)	$3.50
Denominator:	'	'	'	'
Weighted average basic shares outstanding	120.6	119.9	120.5	119.7
Dilutive potential shares:	'	'	'	'
Convertible debentures (in shares)	27.7	27.7	27.7	27.7
LTIP notional units (in shares)	0.4	0.8	0.2	0.6
Potentially dilutive shares	148.7	148.4	148.4	148
Diluted (loss) earnings per share from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	$0.02	($0.65)	$0.07
Diluted loss per share from discontinued operations (in dollars per share)	'	($0.05)	'	($0.04)
Net (loss) income attributable to Atlantic Power Corporation (in dollars per share)	($0.49)	($0.03)	($0.65)	$0.03

Discontinued_operations_Detail

Discontinued operations (Details) (USD $)	6 Months Ended	0 Months Ended			3 Months Ended		6 Months Ended		0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2013	Nov. 05, 2013	Nov. 05, 2013	Nov. 05, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Mar. 06, 2014
		Cadillac and Piedmont Projects	Piedmont	Rollcast	Greeley, Rollcast, Path 15 and the Florida Projects	Greeley, Rollcast, Path 15 and the Florida Projects	Greeley, Rollcast, Path 15 and the Florida Projects	Greeley, Rollcast, Path 15 and the Florida Projects	Greeley
Discontinued operations	'	'	'	'	'	'	'	'	'
Interest sold (as a percent)	'	'	'	60.00%	'	'	'	'	'
Value of asset management contracts assigned	'	$0.50	'	'	'	'	'	'	'
Percentage acquired in entity	'	'	2.00%	'	'	'	'	'	'
Ownership interest (as a percent)	'	'	100.00%	'	'	'	'	'	'
Amount paid to minority owner	'	'	'	0.5	'	'	'	'	'
Outstanding debt forgive	'	'	'	1	'	'	'	'	'
Revenue	'	'	'	'	'	11.4	'	77.2	'
(Loss) income from operations of discontinued businesses	'	'	'	'	'	-5	-0.1	-4.1	'
Income tax expense	'	'	'	'	'	0.4	'	0.8	'
Proceeds from sale of our outstanding membership interest	'	'	'	'	'	'	'	'	1
Non-cash gain on the sale related to the write-off of asset retirement obligations	($32.80)	'	'	'	'	($5.40)	($0.10)	($4.90)	'
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share)	'	'	'	'	$0	($0.05)	$0	$0.04	'

Equity_Details

Equity (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Increase (decrease) in shareholders' equity	'	'	'	'
Balance at the beginning of the period	'	'	$1,096	$1,186.40
Net (loss) income	'	'	-78.8	9
Realized and unrealized gain on hedging activities, net of tax	-0.2	0.7	-0.3	1
Foreign currency translation adjustment, net of tax	17.3	-18	-1.4	-30.1
Common shares issued for LTIP	'	'	0.6	0.9
Contribution by and sale of noncontrolling interest	'	'	'	44.5
Costs associated with tax equity raise	'	'	'	-0.9
Dividends paid to noncontrolling interests	'	'	-5.2	-2.9
Dividends declared on common shares	'	'	-21.1	-35.5
Dividends declared on preferred shares of a subsidiary company	'	'	-5.9	-6.3
Balance at the end of the period	983.9	1,166.10	983.9	1,166.10
Total Atlantic Power Corporation Shareholders' Equity	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance at the beginning of the period	'	'	608.3	729.7
Net (loss) income	'	'	-78	3.5
Realized and unrealized gain on hedging activities, net of tax	'	'	-0.2	1
Foreign currency translation adjustment, net of tax	'	'	-1.5	-30.1
Common shares issued for LTIP	'	'	0.6	0.9
Costs associated with tax equity raise	'	'	'	-0.9
Dividends declared on common shares	'	'	-21.1	-35.5
Balance at the end of the period	508.1	668.6	508.1	668.6
Preferred shares issued by a subsidiary company	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance at the beginning of the period	'	'	221.3	221.3
Net (loss) income	'	'	5.9	6.3
Dividends declared on preferred shares of a subsidiary company	'	'	-5.9	-6.3
Balance at the end of the period	221.3	221.3	221.3	221.3
Noncontrolling Interests	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance at the beginning of the period	'	'	266.4	235.4
Net (loss) income	'	'	-6.7	-0.8
Contribution by and sale of noncontrolling interest	'	'	'	44.5
Dividends paid to noncontrolling interests	'	'	-5.2	-2.9
Balance at the end of the period	$254.50	$276.20	$254.50	$276.20

Segment_and_geographic_informa2

Segment and geographic information (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
			item
Segment and geographic information	'	'	'	'	'
Number of Reportable Segments	'	'	4	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	$143.20	$136.10	$288.50	$273.60	'
Segment assets	3,210.70	3,567.40	3,210.70	3,567.40	3,395
Project Adjusted EBITDA	75	55.9	149.6	136.1	'
Change in fair value of derivative instruments	3.1	-26.8	-11	-38.3	'
Depreciation and amortization	52.3	50.5	104.7	102.3	'
Interest, net	8.6	9.5	24.7	19.7	'
Other project expense	14.8	2.4	14.8	0.6	'
Project (loss) income	-3.8	20.3	16.4	51.8	'
Administration	10.2	11.8	17.5	20.1	'
Interest, net	27.7	25.3	94.1	51.2	'
Foreign exchange (loss) gain	-15.3	14.5	1.5	22	'
Other income, net	'	-9.5	-2.1	-9.5	'
(Loss) income from continuing operations before income taxes	-57	7.2	-91.6	12	'
Income tax expense	-0.6	0.6	-12.9	-1.9	'
(Loss) income from continuing operations	-56.4	6.6	-78.7	13.9	'
Loss from discontinued operations	'	-5.4	-0.1	-4.9	'
Net income (loss)	-56.4	1.2	-78.8	9	'
Operating Segments | East	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	76.2	71.9	162.8	151.7	'
Segment assets	1,192.30	1,468.70	1,192.30	1,468.70	'
Project Adjusted EBITDA	38.5	29.4	84	78.5	'
Change in fair value of derivative instruments	-0.8	-10.6	-22.6	-20	'
Depreciation and amortization	24.4	21.8	48.8	44.2	'
Interest, net	3.7	5.5	15.3	9.9	'
Other project expense	14.8	0.5	14.8	1	'
Project (loss) income	-3.6	12.2	27.7	43.4	'
(Loss) income from continuing operations before income taxes	-3.6	12.2	27.7	43.4	'
(Loss) income from continuing operations	'	12.2	27.7	43.4	'
Loss from discontinued operations	'	-1.2	'	-0.9	'
Net income (loss)	-3.6	11	27.7	42.5	'
Operating Segments | West	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	46.8	45.8	85.3	86.4	'
Segment assets	977.6	1,056	977.6	1,056	'
Project Adjusted EBITDA	22.9	14.1	34.1	34.7	'
Depreciation and amortization	16.2	17.1	32.6	34.2	'
Interest, net	'	0.1	'	0.1	'
Project (loss) income	6.7	-3.1	1.5	0.4	'
(Loss) income from continuing operations before income taxes	6.7	-3.1	1.5	0.4	'
(Loss) income from continuing operations	'	-3.1	1.5	0.4	'
Loss from discontinued operations	'	1.2	-0.1	1.8	'
Net income (loss)	6.7	-1.9	1.4	2.2	'
Operating Segments | Wind	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	20	18.2	40.1	35.7	'
Segment assets	818.1	907.4	818.1	907.4	'
Project Adjusted EBITDA	17.2	15.5	35.1	30.5	'
Change in fair value of derivative instruments	2.8	-15.3	10.4	-18.3	'
Depreciation and amortization	11.5	11.4	22.8	23.7	'
Interest, net	4.8	4.9	9.4	9.8	'
Project (loss) income	-1.9	14.5	-7.5	15.3	'
(Loss) income from continuing operations before income taxes	-1.9	14.5	-7.5	15.3	'
(Loss) income from continuing operations	'	14.5	-7.5	15.3	'
Net income (loss)	-1.9	14.5	-7.5	15.3	'
Un-allocated Corporate	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	0.2	0.2	0.3	-0.2	'
Segment assets	222.7	135.3	222.7	135.3	'
Project Adjusted EBITDA	-3.6	-3.1	-3.6	-7.6	'
Change in fair value of derivative instruments	1.1	-0.9	1.2	'	'
Depreciation and amortization	0.2	0.2	0.5	0.2	'
Interest, net	0.1	-1	'	-0.1	'
Other project expense	'	1.9	'	-0.4	'
Project (loss) income	-5	-3.3	-5.3	-7.3	'
Administration	10.2	11.8	17.5	20.1	'
Interest, net	27.7	25.3	94.1	51.2	'
Foreign exchange (loss) gain	15.3	-14.5	-1.5	-22	'
Other income, net	'	-9.5	-2.1	-9.5	'
(Loss) income from continuing operations before income taxes	-8.2	-16.4	-113.3	-47.1	'
Income tax expense	-0.6	-0.6	-12.9	-1.9	'
(Loss) income from continuing operations	'	-17	-100.4	-45.2	'
Loss from discontinued operations	'	-5.4	'	-5.8	'
Net income (loss)	($57.60)	($22.40)	($100.40)	($51)	'

Segment_and_geographic_informa3

Segment and geographic information (Details 2) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Revenue and Assets	'	'	'	'	'
Project Revenue	$143.20	$136.10	$288.50	$273.60	'
Property, Plant and Equipment, net of accumulated depreciation	1,751.20	'	1,751.20	'	1,813.40
United States	'	'	'	'	'
Revenue and Assets	'	'	'	'	'
Project Revenue	98.2	91	191.3	161.1	'
Property, Plant and Equipment, net of accumulated depreciation	1,296.60	'	1,296.60	'	1,330.50
Canada	'	'	'	'	'
Revenue and Assets	'	'	'	'	'
Project Revenue	45	45.1	97.2	112.5	'
Property, Plant and Equipment, net of accumulated depreciation	$454.60	'	$454.60	'	$482.90

Segment_and_geographic_informa4

Segment and geographic information (Details 3) (Revenues, net, Consolidated revenue)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Ontario Electricity Financial Corp (OEFC)	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	16.70%	22.60%	15.00%	29.70%
San Diego Gas & Electric	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	21.90%	15.90%	25.00%	13.70%
BC Hydro	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	9.60%	10.30%	8.70%	11.30%

Guarantees_Details

Guarantees (Details) (Maximum)	6 Months Ended
	Jun. 30, 2014
Maximum	'
Guarantees	'
Expiration term of guarantees	'P1Y

Contingencies_Details

Contingencies (Details) (USD $)	0 Months Ended			3 Months Ended	6 Months Ended
In Millions, unless otherwise specified	Sep. 09, 2013	Aug. 19, 2013	7-May-13	Mar. 31, 2014	Jun. 30, 2014	Oct. 04, 2013
	item	item	item	item	item
Commitments and contingencies	'	'	'	'	'	'
Number of District Court actions alleged from July 23, 2010 to March 4, 2013	'	'	'	'	3	'
Number of District Court actions alleged from August 8, 2012 to February 28, 2013	'	'	'	'	2	'
Number of actions were succeeded by specific action with an amended claim	'	'	'	'	3	'
Number of actions by which specific Ontario actions were succeeded	'	'	'	'	1	'
Accrual related to proposed adjustments pertaining to the classification of U.S. real property	'	'	'	'	0	'
Shareholder class action lawsuits	'	'	'	'	'	'
Commitments and contingencies	'	'	'	'	'	'
Number of purported securities fraud class action complaints filed	'	'	'	'	5	'
Number of action complaints filed ordered to consolidate	'	5	'	5	'	'
Number of plaintiff applicants directed to file supplemental submissions	2	'	'	'	'	'
Number of notices of actions relating to Canadian securities class action claims	'	'	'	'	3	'
Estimate damages claimed for statutory misrepresentation	'	'	'	'	'	$197.40
Number of District Court actions in which discoveries are stayed	'	'	'	'	5	'
Number of District Court actions alleged in specific period	'	'	'	'	5	'
Number of plaintiff applicants directed resubmit a proposed schedule that contains specific dates	'	'	'	'	1	'
Number of investors filed motion	'	'	6	6	'	'
Number of pending matters having material adverse impact on financial position or results of operations or have been reserved	'	'	'	'	0	'