Atlantic Power 10-Q7 May 152015 Q1 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 2015	5-May-15
Document and Entity Information
Entity Registrant Name	ATLANTIC POWER CORP
Entity Central Index Key	1419242
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		121,894,047
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$100.10	$106
Restricted cash	14.1	22.5
Accounts receivable	40.2	46.2
Inventory	15.7	19.3
Prepayments and other current assets	13.1	13.9
Assets held for sale (Note 3)	780.8	792.1
Refundable income taxes		0.2
Total current assets	964	1,000.20
Property, plant, and equipment, net of accumulated depreciation of $202.5 million and $195.9 million at March 31, 2015 and December 31, 2014, respectively	914.9	962.9
Equity investments in unconsolidated affiliates (Note 4)	310.1	305.2
Other intangible assets, net of accumulated amortization of $206.2 million and $199.8 million at March 31, 2015 and December 31, 2014, respectively	356	377.1
Goodwill	197.2	197.2
Derivative instruments asset (Notes 7 and 8)	0.3	1.1
Deferred financing cost	59.2	62.8
Other assets	10.4	10.1
Total assets	2,812.10	2,916.60
Current liabilities:
Accounts payable	6.7	9.4
Income taxes payable	0.6
Accrued interest	17.8	5.3
Other accrued liabilities	25.8	30.7
Current portion of long-term debt (Note 5)	19.4	20
Current portion of derivative instruments liability (Notes 7 and 8)	34.7	36.1
Liabilities held for sale (Note 3)	281.1	271.8
Other current liabilities	5.7	6.8
Total current liabilities	391.8	380.1
Long-term debt (Note 5)	1,098.40	1,145.90
Convertible debentures (Note 6)	315.7	340.6
Derivative instruments liability (Notes 7 and 8)	44.6	47.5
Deferred income taxes (Note 9)	86.3	92.4
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $11.8 million and $11.4 million at March 31, 2015 and December 31, 2014, respectively	31	33.4
Other non-current liabilities	58.4	60.2
Commitments and contingencies (Note 15)
Total liabilities	2,026.20	2,100.10
Equity
Common shares, no par value, unlimited authorized shares; 121,747,980 and 121,323,614 issued and outstanding at March 31, 2015 and December 31, 2013, respectively (Note 12)	1,288.90	1,288.40
Accumulated other comprehensive loss (Note 2)	-103.7	-68.3
Retained deficit (Note 12)	-849.4	-863.9
Total Atlantic Power Corporation shareholders' equity	335.8	356.2
Preferred shares issued by a subsidiary company (Note 12)	221.3	221.3
Noncontrolling interests held for sale (Notes 3 and 12)	228.8	239
Total equity	785.9	816.5
Total liabilities and equity	$2,812.10	$2,916.60

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
CONSOLIDATED BALANCE SHEETS
Property, plant, and equipment, net of accumulated depreciation	$202.50	$195.90
Other intangible assets, net of accumulated amortization	206.2	199.8
Power purchase and fuel supply agreement liabilities, net of accumulated amortization	$11.80	$11.40
Common shares, no par value (in dollars per share)	$0	$0
Common shares, issued shares (in shares)	121,747,980	121,323,614
Common shares, outstanding shares (in shares)	121,747,980	121,323,614

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Project revenue:
Energy sales	$54	$64.30
Energy capacity revenue	33.5	33.5
Other	23.8	27.5
Total project revenue	111.3	125.3
Project expenses:
Fuel	46.2	59.8
Operations and maintenance	21.5	27.8
Development	1.1	0.7
Depreciation and amortization	28	30.5
Total project expenses	96.8	118.8
Project other income (expense):
Change in fair value of derivative instruments (Notes 7 and 8)	-1.7	22
Equity in earnings of unconsolidated affiliates (Note 4)	10.8	8.4
Interest expense, net	-2.1	-11.1
Other expense		-0.1
Total project other income (expense)	7	19.2
Project income	21.5	25.7
Administrative and other expenses (income):
Administration	9.4	7.1
Interest, net	25.7	66.5
Foreign exchange gain (Note 8)	-32.2	-16.8
Other income (Note 6)	-1.4
Total administrative and other expenses (income)	1.5	56.8
Income (loss) from continuing operations before income taxes	20	-31.1
Income tax benefit (Note 9)	-4.6	-16.9
Income (loss) from continuing operations	24.6	-14.2
Net loss from discontinued operations, net of tax (Note 3)	-12.3	-8.3
Net income (loss)	12.3	-22.5
Net loss attributable to noncontrolling interests designated as discontinued operations (Note 3)	-7.5	-6.4
Net income attributable to preferred shares dividends of a subsidiary company	2.3	2.8
Net income (loss) attributable to Atlantic Power Corporation	$17.50	($18.90)
Basic earnings (loss) per share: (Note 11)
Income (loss) from continuing operations attributable to Atlantic Power Corporation	$0.17	($0.15)
Loss from discontinued operations, net of tax	($0.03)	($0.01)
Net income (loss) attributable to Atlantic Power Corporation	$0.14	($0.16)
Diluted earnings (loss) per share: (Note 11)
Income (loss) from continuing operations attributable to Atlantic Power Corporation	$0.17	($0.15)
Loss from discontinued operations, net of tax	($0.03)	($0.01)
Net income (loss) attributable to Atlantic Power Corporation	$0.14	($0.16)
Weighted average number of common shares outstanding: (Note 11)
Basic (in shares)	121.5	120.3
Diluted (in shares)	122.4	120.3

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
Net income (loss)	$12.30	($22.50)
Other comprehensive income, net of tax:
Unrealized loss on hedging activities	-0.5	-0.3
Net amount reclassified to earnings	0.2	0.2
Net unrealized loss on derivatives	-0.3	-0.1
Foreign currency translation adjustments	-35.1	-18.7
Other comprehensive loss, net of tax	-35.4	-18.8
Less: comprehensive loss attributable to noncontrolling interests	-5.2	-3.6
Comprehensive loss attributable to Atlantic Power Corporation	($17.90)	($37.70)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net income (loss)	$12.30	($22.50)
Adjustments to reconcile to net cash provided by (used in) operating activities:
Depreciation and amortization	38.1	40.5
Gain on sale of asset		-2.1
Gain on repurchase of convertible debentures and other	-1.4
Long-term incentive plan expense	0.5	-0.1
Equity in earnings from unconsolidated affiliates	-9.9	-8.6
Distributions from unconsolidated affiliates	7.2	11.8
Unrealized foreign exchange gain	-32.8	-16.7
Change in fair value of derivative instruments	9	-14.7
Change in deferred income taxes	-3.9	-13.5
Change in other operating balances
Accounts receivable	6	7.1
Inventory	3.6	-0.1
Prepayments, refundable income taxes and other assets	4.3	7.4
Accounts payable	-5.6	-2.9
Accruals and other liabilities	7.7	-14.3
Cash provided by (used in) operating activities	35.1	-28.7
Cash flows provided by investing activities:
Change in restricted cash	9.7	73.6
Proceeds from sale of asset, net		1
Construction in progress		-0.4
Capitalized development costs	-0.8
Purchase of property, plant and equipment	-1.3	-2.6
Cash provided by investing activities	7.6	71.6
Cash flows used in financing activities:
Proceeds from senior secured term loan facility		600
Repayment of corporate and project-level debt	-32.8	-565
Repayment of convertible debentures	-5.7
Deferred financing costs		-38.3
Dividends paid to common shareholders	-2.9	-10.2
Dividends paid to noncontrolling interests	-5	-8
Cash used in financing activities	-46.4	-21.5
Net (decrease) increase in cash and cash equivalents	-3.7	21.4
Less cash at discontinued operations	-6.2	-9.4
Cash and cash equivalents at beginning of period at discontinued operations	3.9
Cash and cash equivalents at beginning of period	106	158.6
Cash and cash equivalents at end of period	100.1	170.6
Supplemental cash flow information
Interest paid	11.7	66.8
Income taxes paid, net	0.4	0.2
Accruals for construction in progress		$9.40

Nature_of_business

Nature of business	3 Months Ended
Nature of business	Mar. 31, 2015
Nature of business
Nature of business
	1. Nature of business
	General
	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 March 31, 2015, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,137 megawatts ("MW") in which our aggregate ownership interest is approximately 1,502 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada. Eighteen of our projects are majority-owned subsidiaries. These totals exclude an aggregate of 521 MWs from our 100% ownership interest in Meadow Creek Project Company, LLC ("Meadow Creek"), our 99% ownership in Canadian Hills Wind, LLC ("Canadian Hills"), our 50% ownership interest in Rockland Wind Farm, LLC ("Rockland"), our 27.6% ownership interest in Idaho Wind Partners 1, LLC ("Idaho Wind") and our 12.5% ownership interest in Goshen Phase II, LLC ("Goshen") (collectively, the "Wind Projects"), for which we entered into an agreement to sell on March 31, 2015, and which are designated as assets held for sale and discontinued operations at March 31, 2015.
	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 215-10451 Shellbridge Way, Richmond, British Columbia V6X 2W8 Canada and our headquarters is located at 3 Allied Drive, Suite 220, Dedham, Massachusetts 02026, USA. Our telephone number in Dedham 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, 2014. 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 March 31, 2015, the results of operations and comprehensive loss for the three months ended March 31, 2015 and 2014, and our cash flows for the three months ended March 31, 2015 and 2014. 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, equity-based compensation 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, 2014. 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.
	Revision to the presentation of preferred shares issued by a subsidiary company
	The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic Power Corporation shareholder's equity on the Consolidated Balance Sheets at March 31, 2015 and December 31, 2014 to a separate line item in the non-controlling interests section of equity. The revision does not impact total equity in either period presented. The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the consolidated balance sheet. The revision is not considered material to any previously issued financial statements.
	Recently issued accounting standards
	Adopted
	In April 2014, the Financial Accounting Standards Board ("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 became effective on January 1, 2015 and were implemented when designating the Wind Projects as assets held for sale and discontinued operations on March 31, 2015. See Note 3, Assets held for sale and discontinued operations.
	Issued
	In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes become effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements.
	In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity's income statement, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become effective for us on January 1, 2016. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements.
	In August 2014, the FASB issued changes to the disclosure of uncertainties about an entity's ability to continue as a going concern. Under generally accepted accounting principles in the United States ("GAAP"), continuation of a reporting entity as a going concern is presumed as the basis for preparing financial statements unless and until the entity's liquidation becomes imminent. Even if an entity's liquidation is not imminent, there may be conditions or events that raise substantial doubt about the entity's ability to continue as a going concern. Because there is no guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern or to provide related note disclosures, there is diversity in practice whether, when, and how an entity discloses the relevant conditions and events in its financial statements. As a result, these changes require an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that financial statements are issued. Substantial doubt is defined as an indication that it is probable that an entity will be unable to meet its obligations as they become due within one year after the date that financial statements are issued. If management has concluded that substantial doubt exists, then the following disclosures should be made in the financial statements: (i) principal conditions or events that raised the substantial doubt, (ii) management's evaluation of the significance of those conditions or events in relation to the entity's ability to meet its obligations, (iii) management's plans that alleviated the initial substantial doubt or, if substantial doubt was not alleviated, management's plans that are intended to at least mitigate the conditions or events that raise substantial doubt, and (iv) if the latter in (iii) is disclosed, an explicit statement that there is substantial doubt about the entity's ability to continue as a going concern. These changes become effective for us for financial statements issued after December 15, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements. Subsequent to adoption, this guidance will need to be applied by management at the end of each annual period and interim period therein to determine what, if any, impact there will be on the consolidated financial statements in a given reporting period.
	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	3 Months Ended
	Mar. 31, 2015
Equity
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
			March 31,
			2015			2014
	Foreign currency translation
	Balance at beginning of period		$	(66.3	)	$	(22.2	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)			(35.1	)		(18.7	)

	Balance at end of period		$	(101.4	)	$	(40.9	)

	Pension
	Balance at beginning of period		$	(2.1	)	$	(0.4	)
	Other comprehensive loss:
	Amortization of net actuarial gain			—			—

	Balance at end of period		$	(2.1	)	$	(0.4	)

	Cash flow hedges
	Balance at beginning of period		$	0.1		$	0.2
	Other comprehensive loss:
	Net change from periodic revaluations			(0.9	)		(0.5	)
	Tax benefit			0.4			0.2

	Total Other comprehensive loss before reclassifications, net of tax			(0.5	)		(0.3	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)			0.3			0.4

	Sub-total			0.3			0.4
	Tax expense			(0.1	)		(0.2	)

	Total amount reclassified from Accumulated other comprehensive income, net of tax			0.2			0.2
	Total Other comprehensive loss			(0.3	)		(0.1	)

	Balance at end of period		$	(0.2	)	$	0.1



	-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.

Assets_held_for_sale_and_disco

Assets held for sale and discontinued operations	3 Months Ended
Assets held for sale and discontinued operations	Mar. 31, 2015
Assets held for sale and discontinued operations
Assets held for sale and discontinued operations

	3. Assets held for sale and discontinued operations
	Wind Projects
	On March 31, 2015, Atlantic Power Transmission, Inc. ("APT"), our wholly-owned, direct subsidiary, entered into a definitive agreement (the "Purchase Agreement") with TerraForm AP Acquisition Holdings, LLC ("TerraForm"), an indirect subsidiary of TerraForm Power, Inc., to sell our wind generation projects for cash proceeds of approximately $350 million, subject to certain adjustments. Terraform will, subject to the terms and conditions in the Purchase Agreement, purchase from APT 100% of its direct membership interests in a holding company formed to facilitate the sale, thereby acquiring our indirect interests in our portfolio of wind projects consisting of five operating wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50% economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest).
	In addition to the receipt of approximately $350 million in cash proceeds, we will deconsolidate approximately $249 million of project debt (or approximately $275 million as adjusted for our proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $229 million of non-controlling interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian Hills. We expect to receive net proceeds of approximately $338 million in the aggregate, after estimated transaction fees and transaction-related taxes.
	On January 1, 2015, we adopted the FASB's issued changes to reporting discontinued operations and determined that the sale of the Wind Projects meets the threshold to be reported as discontinued operations in our consolidated financial statements. Our determination was based on the impact the sale will have on our operations and financial results and because the Wind Projects make up the entirety of our Wind reportable Segment. The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the date we established a firm commitment to a plan to sell the wind assets. We stopped depreciating the property, plant and equipment of the Wind Projects on the designation date. We did not adjust the carrying value on the designation date because we expect to record a gain on sale when the transaction closes. The consolidated balance sheet as of December 31, 2014 and the consolidated statement of operations for the three months ended March 31, 2014 have been reclassified for these changes.
	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 resulting from the write-off of asset retirement obligations in the consolidated statement of operations as of March 31, 2014. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the three months ended March 31, 2014.
	The following table summarizes the revenue and loss from operations of the Wind Projects and Greeley for the three months ended March 31, 2015 and 2014:

			Three months
			ended
			March 31,
			2015			2014
	Revenue		$	16.7		$	20

	Project expenses:
	Operations and maintenance			5.6			5.1
	Depreciation and amortization			10.1			10

				15.7			15.1
	Project other income (expense):
	Project other income (expense):
	Change in fair value of derivatives			(7.3	)		(7.3	)
	Equity in (loss) earnings of unconsolidated affiliates			(0.9	)		0.2
	Interest expense, net			(3.4	)		(3.6	)
	Gain on sale of asset			—			2.1

				(11.6	)		(8.6	)

	Loss from operations of discontinued businesses			(10.6	)		(3.7	)
	Income tax expense			1.7			4.6

	Loss from operations of discontinued businesses, net of tax			(12.3	)		(8.3	)
	Net loss attributable to noncontrolling interests of discontinued businesses			(7.5	)		(6.4	)

	Loss from operations of discontinued businesses, net of noncontrolling interests		$	(4.8	)	$	(1.9	)


	Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for the Wind Projects and Greeley was $(0.03) and $(0.01) for the three months ended March 31, 2015 and 2014 respectively.
	The following table summarizes the operating and investing cash flows of the Wind Projects for the three months ended March 31, 2015 and 2014:

			Three months
			ended
			March 31,
			2015			2014
	Cash provided by operating activities		$	10.8		$	8.8
	Cash provided by investing activities			1.4			1.2
	The following table summarizes the financial position of the Wind Projects at March 31, 2015 and December 31, 2014:

			March 31,			December 31,
			2015			2014
	Current assets:
	Cash and cash equivalents		$	6.2		$	3.9
	Accounts receivable			11.2			11.2
	Other current assets			2.4			2.4

				19.8			17.5
	Non-current assets assets:
	Non-current assets assets:
	Property, plant & equipment			700.5			710.5
	Equity investments in unconsolidated affiliates			36.5			38.7
	Other intangible assets, net			4.3			4.3
Restricted cash			17.9			19.1
Other assets			1.8			2.0

Assets held for sale			780.8			792.1
Current liabilities:
Current liabilities:
Accounts payable and other accrued liabilities		$	7.7		$	5.9
Current portion of long-term debt			6.4			6.4
Current portion of derivative instruments liability			4.8			3.1

			18.9			15.4
Long term liabilities
Long term liabilities
Long-term debt			242.4			242.4
Derivative instruments liability			15.7			10.0
Other long-term liabilities			4.1			4.0

Liabilities held for sale			281.1			271.8
Noncontrolling interests held for sale			228.8			239.0

Equity_method_investments_in_u

Equity method investments in unconsolidated affiliates	3 Months Ended
Equity method investments in unconsolidated affiliates	Mar. 31, 2015
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 months ended March 31, 2015 and 2014, respectively, for earnings in our equity method investments:

			Three months
			ended
			March 31,
	Operating results		2015			2014
	Revenue
	Orlando		$	12.8		$	13.3
	Chambers			15.4			17.9
	Other(1)			9.6			22.5

				37.8			53.7
	Project expenses
	Project expenses
	Orlando			6.6			8.7
	Chambers			11.4			14.2
	Other(1)			8.6			21.7

				26.6			44.6
	Project other (expense) income
	Project other (expense) income
	Orlando			—			—
	Chambers			(0.5	)		(0.6	)
	Other(1)			0.1			(0.1	)

				(0.4	)		(0.7	)
	Project income
	Project income
	Orlando		$	6.2		$	4.6
	Chambers			3.5			3.1
	Other(1)			1.1			0.7

				10.8			8.4




	-1	Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

Longterm_debt

Long-term debt	3 Months Ended
Long-term debt	Mar. 31, 2015
Long-term debt
Long-term debt
	5. Long-term debt
	Long-term debt consists of the following:

			March 31,			December 31,			Interest Rate
			2015			2014			Interest Rate
	Recourse Debt:
	Senior secured term loan facility, due 2021		$	520.2		$	541.5		LIBOR(1) plus 3.8%
	Senior unsecured notes, due 2018(2)			310.9			319.9		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)			165.8			181		6.00%
	Non-Recourse Debt:(3)
	Epsilon Power Partners term facility, due 2019			24			25.5		LIBOR plus 3.1%
	Cadillac term loan, due 2025			32.8			33.4		6.0% – 8.0%
	Piedmont term loan, due 2018			63.6			64		5.20%
	Other long-term debt			0.5			0.6		5.5% – 6.7%
	Less: current maturities			(19.4	)		(20.0	)

	Total long-term debt		$	1,098.40		$	1,145.90


	Current maturities consist of the following:

			March 31,			December 31,			Interest Rate
			2015			2014			Interest Rate
	Current Maturities:
	Senior secured term loan facility, due 2021		$	5.2		$	5.4		LIBOR(1) plus 3.8%
	Epsilon Power Partners term facility, due 2019			6.0			6.1		LIBOR plus 3.1%
	Cadillac term loan, due 2025			3.9			3.9		6.0% – 8.0%
	Piedmont term loan, due 2018			4.1			4.5		5.2%
	Other short-term debt			0.2			0.1		5.5 – 6.7%

	Total current maturities		$	19.4		$	20.0




	-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 ($172.4 million at March 31, 2015) of the $600.0 million ($520.2 million at March 31, 2015) outstanding aggregate borrowings under our senior secured term loan facility. See Note 8, Accounting for derivative instruments and hedging activities for further details.
	-2	We repurchased approximately $9.0 million aggregate principal amount of the 9.0% Notes in January 2015 with cash on hand.
	-3	The table does not include non-recourse debt at the Wind Projects which have been classified as held for sale at March 31, 2015 and December 31, 2014.
	Notes of Atlantic Power Corporation
	As previously disclosed with respect to the impact of the Senior Secured Credit Facilities in our Annual Report on Form 10-K for the years ended December 31, 2014 and 2013, due to the aggregate impact of the up-front costs resulting from the prepayments on our indebtedness further described in our Annual Report on Form 10-K for the year ended December 31, 2014, 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 in March 2014, which were reflected as interest expense in our 2014 first quarter results, through March 31, 2015, we did not 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 of March 31, 2015, we are again in compliance with the fixed charge ratio test. During the period we were not in compliance, March 31, 2014 through March 31, 2015, dividend payments, in the aggregate, could not exceed the covenant's "basket" provision of the greater of $50 million and 2% of consolidated net assets (approximately $46.7 million at March 31, 2015) until we satisfied the fixed charge coverage ratio test. Through March 31, 2015, we declared cumulative dividends totaling approximately $35.4 million that were subject to the basket provision. As long as we remain in compliance with the ratio test, we are not subject to the basket provision. However, the basket does not reset if we were to fall out of compliance at any point in the future. Dividends to shareholders are paid, if and when declared by, and subject to the discretion of, the board of directors.
	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 March 31, 2015, all of our projects with the exception of Piedmont were in compliance with the covenants contained in project-level debt. We do not expect our Piedmont project to meet its debt service coverage ratio covenants limiting the project's ability to make distributions to us before 2017 at the earliest, due to continued operational issues that have resulted in higher forecasted maintenance and fuel expenses than initially expected.

Convertible_debentures

Convertible debentures	3 Months Ended
Convertible debentures	Mar. 31, 2015
Convertible debentures
Convertible debentures
	6. Convertible debentures
	The following table provides details related to outstanding convertible debentures:

		6.25% Debentures			5.6% Debentures			5.75% Debentures			6.00% Debentures			Total
		due March 2017			due June 2017			due June 2019			due December 2019			Total
	Balance at December 31, 2014	$	58		$	68.6		$	128.4		$	85.6		$	340.6
	Repayment of convertible debentures		—			(0.3	)		(3.4	)		(2.0	)		(5.7	)
	Foreign exchange gain		(4.9	)		(5.8	)		—			(7.2	)		(17.9	)
	Gain on repurchase of convertible debentures		—			—			(0.8	)		(0.5	)		(1.3	)

	Balance at March 31, 2015	$	53.1		$	62.5		$	124.2		$	75.9		$	315.7


	During the fourth quarter of 2014, we announced a Normal Course Issuer Bid ("NCIB") for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures. The NCIB commenced on November 11, 2014 and will expire on November 10, 2015 or such earlier date as we complete our purchases pursuant to the NCIB. The actual amount of convertible debentures that may be purchased under the NCIB cannot exceed approximately $31 million and is further limited based on the outstanding principal of the individual outstanding tranches. As of December 31, 2014, we had repurchased and cancelled $3.1 million of convertible debentures and recorded a gain of $0.7 million in the consolidated statement of operations related to these transactions. During the first quarter of 2015, we repurchased and cancelled $7.0 million aggregate principal amount of convertible debentures at a cost of $5.7 million and recorded a gain of $1.3 million in the consolidated statement of operations for the three months ended March 31, 2015. In April 2015, we repurchased and cancelled an additional $10.3 million aggregate principal amount of convertible debentures at a cost of $8.6 million. The associated gain will be recorded in the statement of operations for the three and six months ended June 30, 2015.

Fair_value_of_financial_instru

Fair value of financial instruments	3 Months Ended
Fair value of financial instruments	Mar. 31, 2015
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 March 31, 2015 and December 31, 2014. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

		March 31, 2015
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	100.1	$	—	$	—	$	100.1
	Restricted cash		14.1		—		—		14.1
	Derivative instruments asset		—		0.3		—		0.3

	Total	$	114.2	$	0.3	$	—	$	114.5


	Liabilities:
	Derivative instruments liability	$	—	$	79.3	$	—	$	79.3

	Total	$	—	$	79.3	$	—	$	79.3




		December 31, 2014
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	106.0	$	—	$	—	$	106.0
	Restricted cash		22.5		—		—		22.5
	Derivative instruments asset		—		1.1		—		1.1

	Total	$	128.5	$	1.1	$	—	$	129.6


	Liabilities:
	Derivative instruments liability	$	—	$	83.6	$	—	$	83.6

	Total	$	—	$	83.6	$	—	$	83.6


	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 March 31, 2015, the credit valuation adjustments resulted in a $5.5 million net increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive income and a $5.0 million gain in change in fair value of derivative instruments. As of December 31, 2014, the credit valuation adjustments resulted in an $8.3 million net increase in fair value, which consists of a $0.7 million pre-tax gain in other comprehensive income and a $7.6 million gain in change in fair value of derivative instruments.
	The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.

Accounting_for_derivative_inst

Accounting for derivative instruments and hedging activities	3 Months Ended
	Mar. 31, 2015
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 in 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). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.
	Gas purchase agreements
	Gas purchase agreements to purchase gas forward 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, Atlantic Power Limited Partnership (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 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 March 31, 2015. 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.
	We have entered into various natural gas swaps to effectively fix the price of 6.3 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 96% and 65% of our share of the expected base load natural gas purchases for 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 March 31, 2015. Changes in the fair market value of these contracts are recorded in the consolidated statement 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 for the three months ended March 31, 2014.
	Interest rate swaps
	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 ($172.4 million at March 31, 2015) of the $600 million aggregate principal amount of borrowings ($520.2 million of borrowings at March 31, 2015) under the Term Loan Facility. Borrowings under the $600 million 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 Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the 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 were 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.
	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. 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.
	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 loss.
	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 for the three months ended March 31, 2014.
	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.
	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 the three months ended March 31, 2015 and the year ended December 31, 2014:

			Units		March 31,			December 31,
			Units		2015			2014
	Natural gas swaps		Natural Gas (Mmbtu)			5.3			6.3
	Gas purchase agreements		Natural Gas (Gj)			31.6			33.9
	Interest rate swaps		Interest (US$)			151.0			152.1
	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:

			March 31, 2015
			Derivative			Derivative
			Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current		$	—		$	1.2
	Interest rate swaps long-term			—			3.3

	Total derivative instruments designated as cash flow hedges			—			4.5

	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current			—			1.9
	Interest rate swaps long-term			0.3			8.9
	Natural gas swaps current			—			4.9
	Natural gas swaps long-term			—			2.3
	Gas purchase agreements current			—			26.7
	Gas purchase agreements long-term			—			30.1

	Total derivative instruments not designated as cash flow hedges			0.3			74.8

	Total derivative instruments		$	0.3		$	79.3




			December 31, 2014
			Derivative			Derivative
			Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current		$	—		$	1.1
	Interest rate swaps long-term			—			2.9

	Total derivative instruments designated as cash flow hedges			—			4.0

	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current			—			2.0
	Interest rate swaps long-term			1.1			6.9
Natural gas swaps current			—			4.4
Natural gas swaps long-term			—			2.2
Gas purchase agreements current			—			28.6
Gas purchase agreements long-term			—			35.5

Total derivative instruments not designated as cash flow hedges			1.1			79.6

Total derivative instruments		$	1.1		$	83.6


Accumulated other comprehensive income
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 March 31, 2015		Interest Rate
For the three months ended March 31, 2015		Swaps
Accumulated OCI balance at January 1, 2015		$	0.1
Change in fair value of cash flow hedges			(0.5	)
Realized from OCI during the period			0.2

Accumulated OCI balance at March 31, 2015		$	(0.2	)




For the three months ended March 31, 2014		Interest Rate
For the three months ended March 31, 2014		Swaps
Accumulated OCI balance at January 1, 2014		$	0.2
Change in fair value of cash flow hedges			(0.3	)
Realized from OCI during the period			0.2

Accumulated OCI balance at March 31, 2014		$	0.1


Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges:

				Three months
				ended
		Classification of (gain) loss		March 31,
		recognized in income		2015			2014
Natural gas swaps		Fuel		$	1.3		$	3.9
Gas purchase agreements		Fuel			12			15.9
Interest rate swaps		Interest, net			(1.0	)		(4.2	)
Foreign currency forwards		Foreign exchange gain			—			(0.1	)
The following table summarizes the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

				Three months
				ended
		Classification of loss (gain)		March 31,
		recognized in income		2015			2014
Natural gas swaps		Change in fair value of derivatives		$	(0.6	)	$	4.6
Gas purchase agreements		Change in fair value of derivatives			1.6			16
Interest rate swaps		Change in fair value of derivatives			(2.7	)		1.4

Total change in fair value of derivative instruments				$	(1.7	)	$	22

Foreign currency forwards		Foreign exchange loss		$	—		$	1

Income_taxes

Income taxes	3 Months Ended
	Mar. 31, 2015
Income taxes
Income taxes
	9. Income taxes

		Three months
		ended
		March 31,
		2015			2014
	Current income tax expense from continuing operations	$	1.1		$	1.3
	Deferred tax benefit from continuing operations		(5.7	)		(18.2	)

	Total income tax benefit, net	$	(4.6	)	$	(16.9	)
	Income tax benefit from continuing operations for the three months ended March 31, 2015 was $4.6 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $5.2 million. The primary items impacting the tax rate for the three months ended March 31, 2015 were $2.9 million relating to a decrease in the valuation allowance, $2.4 million relating to operating in higher tax rate jurisdictions, $1.8 million relating to foreign exchange and $2.7 million of other permanent differences.
	Income tax benefit for the three months ended March 31, 2014 was $16.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $8.1 million. The primary items impacting the tax rate for the three months ended March 31, 2014 were $10.7 million of capital losses recognized on tax restructuring, $5.2 million relating to operating in higher tax rate jurisdictions, $3.6 million relating to foreign exchange, and $4.4 million of other permanent differences. These items were partially offset by $15.1 million relating to a change in the valuation allowance.
	As of March 31, 2015, we have recorded a valuation allowance of $165.7 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	3 Months Ended
Equity compensation plans	Mar. 31, 2015
Equity compensation plans
Equity compensation plans
	10. Equity compensation plans
	Long-term incentive plan ("LTIP")
	The following table summarizes the changes in outstanding LTIP notional units during the three months ended March 31, 2015:

		Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2014		1,443,254		$	3.28
	Granted		1,007,726			2.75
	Reinvested		15,085			2.85
	Forfeited		(63,499	)		4.19
	Exercised		(597,406	)		3.61

	Outstanding at March 31, 2015		1,805,160		$	2.85


	Certain awards have a market condition based on our total shareholder return during the performance period as 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 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, 2014 for further details.
	Transition Equity Participation Agreement
	On January 22, 2015, we granted James J. Moore, Jr., our President, Chief Executive Officer and a Director of the Company, 523,256 transition notional shares subject to the terms of his employment agreement. Fifty percent of the transition notional shares granted to Mr. Moore with respect to fiscal year 2015 will vest upon the four-year anniversary of the date of grant, provided he remains employed by the Company upon the vesting date, and the remaining portion will vest on or any time after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares on the TSX for at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015 ($2.58) by at least 50%.

Basic_and_diluted_earnings_los

Basic and diluted earnings (loss) per share	3 Months Ended
Basic and diluted earnings (loss) per share	Mar. 31, 2015
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 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.
	Because we reported a loss for the three months ended March 31, 2014, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
	The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three months ended March 31, 2015 and 2014:

		Three months ended
		March 31,
		2015			2014
	Numerator:
	Income (loss) from continuing operations attributable to Atlantic Power Corporation	$	22.3		$	(17.0	)
	Loss from discontinued operations, net of tax		(4.8	)		(1.9	)

	Net income (loss) attributable to Atlantic Power Corporation	$	17.5		$	(18.9	)
	Denominator:
	Denominator:
	Weighted average basic shares outstanding		121.5			120.3
	Dilutive potential shares:
	Convertible debentures		—			—
	LTIP notional units		0.9			—

	Potentially dilutive shares		122.4			120.3


	Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.17		$	(0.15	)
	Diluted loss per share from discontinued operations		(0.03	)		(0.01	)

	Diluted income (loss) per share attributable to Atlantic Power Corporation	$	0.14		$	(0.16	)


	Potentially dilutive shares from convertible debentures of 23.5 million and 27.7 million have been excluded from fully diluted shares in the three months ended March 31, 2015 and 2014, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the three months ended March 31, 2014 because their impact would be anti-dilutive.

Equity

Equity	3 Months Ended
Equity	Mar. 31, 2015
Equity
Equity
	12. 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 three months ended March 31, 2015 and 2014:

		Three months ended March 31, 2015
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	356.2		$	221.3		$	239		$	816.5
	Net income (loss)		17.5			2.3			(7.5	)		12.3
	Realized and unrealized gain on hedging activities, net of tax		(0.3	)		—			—			(0.3	)
	Foreign currency translation adjustment, net of tax		(35.1	)		—			—			(35.1	)
	Common shares issued for LTIP		0.4			—			—			0.4
	Dividends paid to noncontrolling interests		—			—			(2.7	)		(2.7	)
	Dividends declared on common shares		(2.9	)		—			—			(2.9	)
	Dividends declared on preferred shares of a subsidiary company		—			(2.3	)		—			(2.3	)

	Balance at March 31	$	335.8		$	221.3		$	228.8		$	785.9




		Three months ended March 31, 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		(18.9	)		2.8			(6.4	)		(22.5	)
	Realized and unrealized gain on hedging activities, net of tax		(0.1	)		—			—			(0.1	)
	Foreign currency translation adjustment, net of tax		(18.7	)		—			—			(18.7	)
	Dividends paid to noncontrolling interest		—			—			(2.2	)		(2.2	)
	Dividends declared on common shares		(10.3	)		—			—			(10.3	)
	Dividends declared on preferred shares of a subsidiary company		—			(2.8	)		—			(2.8	)

	Balance at March 31	$	560.3		$	221.3		$	257.8		$	1,039.40

Segment_and_geographic_informa

Segment and geographic information	3 Months Ended
Segment and geographic information	Mar. 31, 2015
Segment and geographic information
Segment and geographic information
	13. Segment and geographic information
	We had four reportable segments: East, West, Wind and Un-allocated Corporate. The Wind Projects, which make up the entirety of the Wind segment, are designated as assets held for sale and discontinued operations. We have adjusted the prior period to reflect this reclassification. 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. Our equity investments in unconsolidated affiliates are presented based on our share of Project Adjusted EBITDA in the reconciliation of Project Adjusted EBITDA to project income (loss). A reconciliation of Project Adjusted EBITDA to project income (loss) is included in the table below:

			East			West			Wind			Un-allocated			Consolidated
									(Discontinued			Corporate
									Operations)
	Three months ended March 31, 2015
	Project revenues		$	75		$	36		$	—		$	0.3		$	111.3
	Segment assets			1,148.20			791			854.8			18.1			2,812.10
	Project Adjusted EBITDA		$	43.2		$	17.2		$	—		$	(1.8	)	$	58.6
	Change in fair value of derivative instruments			1			—			—			0.7			1.7
	Depreciation and amortization			17.5			15.2			—			0.2			32.9
	Interest, net			2.5			—			—			—			2.5

	Project income (loss)			22.2			2			—			(2.7	)		21.5
	Administration			—			—			—			9.4			9.4
	Interest, net			—			—			—			25.7			25.7
	Foreign exchange gain			—			—			—			(32.2	)		(32.2	)
	Other income, net			—			—			—			(1.4	)		(1.4	)

	Income (loss) from continuing operations before income taxes			22.2			2			—			(4.2	)		20
	Income tax benefit			—			—			—			(4.6	)		(4.6	)

	Net income (loss) from continuing operations			22.2			2			—			0.4			24.6
	Loss from discontinued operations			—			—			(12.3	)		—			(12.3	)

	Net income (loss)		$	22.2		$	2		$	12.3		$	0.4		$	12.3




			East			West			Wind			Un-allocated			Consolidated
									(Discontinued			Corporate
									Operations)
	Three months ended March 31, 2014
	Project revenues		$	86.7		$	38.5		$	—		$	0.1		$	125.3
	Segment assets			1,409.50			973.3			849			65			3,296.80
	Project Adjusted EBITDA		$	45.6		$	11.3		$	—		$	(0.5	)	$	56.4
	Change in fair value of derivative instruments			(21.9	)		—			—			—			(21.9	)
	Depreciation and amortization			24.4			16.4			—			—			40.8
	Interest, net			11.5			—			—			—			11.5
	Other project expense			—			—			—			0.3			0.3

	Project income (loss)			31.6			(5.1	)		—			(0.8	)		25.7
	Administration			—			—			—			7.1			7.1
	Interest, net			—			—			—			66.5			66.5
	Foreign exchange gain			—			—			—			(16.8	)		(16.8	)
	Other income, net						—			—			—			—

	Income (loss) from continuing operations before income taxes			31.6			(5.1	)		—			(57.6	)		(31.1	)
	Income tax benefit			—			—			—			(16.9	)		(16.9	)

	Net income (loss) from continuing operations			31.6			(5.1	)		—			(40.7	)		(14.2	)
	(Loss) income from discontinued operations			—			2			(10.3	)		—			(8.3	)

	Net income (loss)		$	31.6		$	(3.1	)	$	(10.3	)	$	(40.7	)	$	(22.5	)


	The table below provides information, by country, about our consolidated operations for each of the three months ended March 31, 2015 and 2014 and Property, Plant & Equipment as of March 31, 2015 and December 31, 2014, 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						accumulated depreciation
Three months ended
			March 31,							March 31,			December 31,
			2015			2014		2015		2014
United States		$	60.8		$	73.0		$		546.7		$	553.5
Canada			50.5			52.3			368.2			409.4

Total		$	111.3		$	125.3		$	914.9		$	962.9
Independent Electricity System Operator ("IESO"), San Diego Gas & Electric, and BC Hydro provided 33.7%, 14.4%, and 11.7%, respectively, of total consolidated revenues for the three months ended March 31, 2015. IESO, San Diego Gas & Electric and BC Hydro provided 32.8%, 15.4%, and 9.0%, respectively, of total consolidated revenues for the three months ended March 31, 2014. IESO purchases electricity from the Calstock, Kapuskasing, Nipigon and North Bay 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	3 Months Ended
Guarantees	Mar. 31, 2015
Guarantees
Guarantees
	14. Guarantees
	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 and improbable to occur. 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. Upon closing of the sale of the Wind Projects, we will not be liable under the guarantee agreements.
	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, including the Purchase Agreement to sell the Wind Projects, 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.

Contingencies

Contingencies	3 Months Ended
Contingencies	Mar. 31, 2015
Contingencies
Contingencies
	15. 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 former President and Chief Executive Officer and a former 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 (the "Motion to Dismiss") U.S. Action on August 5, 2014.
	On September 30, 2014, citing Atlantic Power's September 16, 2014 announcement of changes to its dividend and its President and CEO transition, Lead Plaintiff filed a motion (the "Extension Motion") requesting a thirty-day extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending Lead Plaintiff's deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014, Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the Motion to Dismiss (the "Opposition") and also filed a motion for leave to amend the Amended Complaint, attaching a proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff's motion for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and Extension Motion.
	On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to Defendants' motion to dismiss (the "Motion for Leave"). The Court denied the Motion for Leave in an order entered on February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.
	On March 13, 2015, the District Court entered an order granting Defendants' motion to dismiss and denying Lead Plaintiff's motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order dismissing the Amended Complaint with prejudice. On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First Circuit. The Company will oppose that appeal.
	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 seek leave to commence an action for statutory misrepresentation under the Ontario Securities Act and assert 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 and Plaintiffs subsequently exchanged responding and reply materials in respect of the leave and certification motions. These motions will be heard on May 20-21, 2015.
	The proposed class action in Quebec is stayed until June 18, 2015.
	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.
	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 March 31, 2015.

Subsequent_events

Subsequent events	3 Months Ended
Subsequent events	Mar. 31, 2015
Subsequent events
Subsequent events
	16. Subsequent events
	On April 22, 2015, our indirect wholly-owned subsidiary, Ridgeline Energy LLC ("Ridgeline"), closed a transaction with CRE-Frontier Solar California LLC, ("CRE") a subsidiary of Centaurus Renewable Energy LLC, whereby CRE agreed to purchase 100% of Ridgeline's equity interests in Frontier Solar, LLC ("Frontier"), which is developing an approximately 20 MW solar electric generating facility in California, for net cash proceeds of $4.3 million. If Frontier achieves commercial operations and meets certain operating performance metrics, we could receive additional cash proceeds.

Nature_of_business_Policies

Nature of business (Policies)	3 Months Ended
Nature of business (Policies)	Mar. 31, 2015
Nature of business
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, 2014. 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 March 31, 2015, the results of operations and comprehensive loss for the three months ended March 31, 2015 and 2014, and our cash flows for the three months ended March 31, 2015 and 2014. 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, equity-based compensation 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, 2014. 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.

Revision to the Presentation of Preferred Shares in a Subsidiary Company
	Revision to the presentation of preferred shares issued by a subsidiary company
	The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic Power Corporation shareholder's equity on the Consolidated Balance Sheets at March 31, 2015 and December 31, 2014 to a separate line item in the non-controlling interests section of equity. The revision does not impact total equity in either period presented. The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the consolidated balance sheet. The revision is not considered material to any previously issued financial statements.

Recently issued accounting standards
	Recently issued accounting standards
	Adopted
	In April 2014, the Financial Accounting Standards Board ("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 became effective on January 1, 2015 and were implemented when designating the Wind Projects as assets held for sale and discontinued operations on March 31, 2015. See Note 3, Assets held for sale and discontinued operations.
	Issued
	In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes become effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements.
	In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity's income statement, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become effective for us on January 1, 2016. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements.
	In August 2014, the FASB issued changes to the disclosure of uncertainties about an entity's ability to continue as a going concern. Under generally accepted accounting principles in the United States ("GAAP"), continuation of a reporting entity as a going concern is presumed as the basis for preparing financial statements unless and until the entity's liquidation becomes imminent. Even if an entity's liquidation is not imminent, there may be conditions or events that raise substantial doubt about the entity's ability to continue as a going concern. Because there is no guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern or to provide related note disclosures, there is diversity in practice whether, when, and how an entity discloses the relevant conditions and events in its financial statements. As a result, these changes require an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that financial statements are issued. Substantial doubt is defined as an indication that it is probable that an entity will be unable to meet its obligations as they become due within one year after the date that financial statements are issued. If management has concluded that substantial doubt exists, then the following disclosures should be made in the financial statements: (i) principal conditions or events that raised the substantial doubt, (ii) management's evaluation of the significance of those conditions or events in relation to the entity's ability to meet its obligations, (iii) management's plans that alleviated the initial substantial doubt or, if substantial doubt was not alleviated, management's plans that are intended to at least mitigate the conditions or events that raise substantial doubt, and (iv) if the latter in (iii) is disclosed, an explicit statement that there is substantial doubt about the entity's ability to continue as a going concern. These changes become effective for us for financial statements issued after December 15, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements. Subsequent to adoption, this guidance will need to be applied by management at the end of each annual period and interim period therein to determine what, if any, impact there will be on the consolidated financial statements in a given reporting period.
	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)	3 Months Ended
	Mar. 31, 2015
Changes in accumulated other comprehensive loss by component
Schedule of changes in accumulated other comprehensive loss by component

			Three months
			ended
			March 31,
			2015			2014
	Foreign currency translation
	Balance at beginning of period		$	(66.3	)	$	(22.2	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)			(35.1	)		(18.7	)

	Balance at end of period		$	(101.4	)	$	(40.9	)

	Pension
	Balance at beginning of period		$	(2.1	)	$	(0.4	)
	Other comprehensive loss:
	Amortization of net actuarial gain			—			—

	Balance at end of period		$	(2.1	)	$	(0.4	)

	Cash flow hedges
	Balance at beginning of period		$	0.1		$	0.2
	Other comprehensive loss:
	Net change from periodic revaluations			(0.9	)		(0.5	)
	Tax benefit			0.4			0.2

	Total Other comprehensive loss before reclassifications, net of tax			(0.5	)		(0.3	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)			0.3			0.4

	Sub-total			0.3			0.4
	Tax expense			(0.1	)		(0.2	)

	Total amount reclassified from Accumulated other comprehensive income, net of tax			0.2			0.2
	Total Other comprehensive loss			(0.3	)		(0.1	)

	Balance at end of period		$	(0.2	)	$	0.1



	-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.

Assets_held_for_sale_and_disco1

Assets held for sale and discontinued operations (Tables)	3 Months Ended
Assets held for sale and discontinued operations (Tables)	Mar. 31, 2015
Assets held for sale and discontinued operations
Summary of the revenue, loss from operations, cash flows and financial position of Wind Projects and Greelay
	The following table summarizes the revenue and loss from operations of the Wind Projects and Greeley for the three months ended March 31, 2015 and 2014:

		Three months
		ended
		March 31,
		2015			2014
	Revenue	$	16.7		$	20

	Project expenses:
	Operations and maintenance		5.6			5.1
	Depreciation and amortization		10.1			10

			15.7			15.1
	Project other income (expense):
	Project other income (expense):
	Change in fair value of derivatives		(7.3	)		(7.3	)
	Equity in (loss) earnings of unconsolidated affiliates		(0.9	)		0.2
	Interest expense, net		(3.4	)		(3.6	)
	Gain on sale of asset		—			2.1

			(11.6	)		(8.6	)

	Loss from operations of discontinued businesses		(10.6	)		(3.7	)
	Income tax expense		1.7			4.6

	Loss from operations of discontinued businesses, net of tax		(12.3	)		(8.3	)
	Net loss attributable to noncontrolling interests of discontinued businesses		(7.5	)		(6.4	)

	Loss from operations of discontinued businesses, net of noncontrolling interests	$	(4.8	)	$	(1.9	)


	The following table summarizes the operating and investing cash flows of the Wind Projects for the three months ended March 31, 2015 and 2014:

		Three months
		ended
		March 31,
		2015			2014
	Cash provided by operating activities	$	10.8		$	8.8
	Cash provided by investing activities		1.4			1.2
	The following table summarizes the financial position of the Wind Projects at March 31, 2015 and December 31, 2014:

		March 31,			December 31,
		2015			2014
	Current assets:
	Cash and cash equivalents	$	6.2		$	3.9
	Accounts receivable		11.2			11.2
	Other current assets		2.4			2.4

			19.8			17.5
	Non-current assets assets:
	Non-current assets assets:
	Property, plant & equipment		700.5			710.5
	Equity investments in unconsolidated affiliates		36.5			38.7
	Other intangible assets, net		4.3			4.3
	Restricted cash		17.9			19.1
	Other assets		1.8			2.0

	Assets held for sale		780.8			792.1
	Current liabilities:
	Current liabilities:
	Accounts payable and other accrued liabilities	$	7.7		$	5.9
	Current portion of long-term debt		6.4			6.4
	Current portion of derivative instruments liability		4.8			3.1

		18.9			15.4
Long term liabilities
Long term liabilities
Long-term debt		242.4			242.4
Derivative instruments liability		15.7			10.0
Other long-term liabilities		4.1			4.0

Liabilities held for sale		281.1			271.8
Noncontrolling interests held for sale		228.8			239.0

Equity_method_investments_in_u1

Equity method investments in unconsolidated affiliates (Tables)	3 Months Ended
	Mar. 31, 2015
Equity method investments in unconsolidated affiliates
Summary of operating results

			Three months
			ended
			March 31,
	Operating results		2015			2014
	Revenue
	Orlando		$	12.8		$	13.3
	Chambers			15.4			17.9
	Other(1)			9.6			22.5

				37.8			53.7
	Project expenses
	Project expenses
	Orlando			6.6			8.7
	Chambers			11.4			14.2
	Other(1)			8.6			21.7

				26.6			44.6
	Project other (expense) income
	Project other (expense) income
	Orlando			—			—
	Chambers			(0.5	)		(0.6	)
	Other(1)			0.1			(0.1	)

				(0.4	)		(0.7	)
	Project income
	Project income
	Orlando		$	6.2		$	4.6
	Chambers			3.5			3.1
	Other(1)			1.1			0.7

				10.8			8.4




	-1	Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

Longterm_debt_Tables

Long-term debt (Tables)	3 Months Ended
Long-term debt (Tables)	Mar. 31, 2015
Long-term debt
Schedule of long-term debt

			March 31,			December 31,			Interest Rate
			2015			2014			Interest Rate
	Recourse Debt:
	Senior secured term loan facility, due 2021		$	520.2		$	541.5		LIBOR(1) plus 3.8%
	Senior unsecured notes, due 2018(2)			310.9			319.9		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)			165.8			181		6.00%
	Non-Recourse Debt:(3)
	Epsilon Power Partners term facility, due 2019			24			25.5		LIBOR plus 3.1%
	Cadillac term loan, due 2025			32.8			33.4		6.0% – 8.0%
	Piedmont term loan, due 2018			63.6			64		5.20%
	Other long-term debt			0.5			0.6		5.5% – 6.7%
	Less: current maturities			(19.4	)		(20.0	)

	Total long-term debt		$	1,098.40		$	1,145.90




Schedule of current maturities

			March 31,			December 31,			Interest Rate
			2015			2014			Interest Rate
	Current Maturities:
	Senior secured term loan facility, due 2021		$	5.2		$	5.4		LIBOR(1) plus 3.8%
	Epsilon Power Partners term facility, due 2019			6.0			6.1		LIBOR plus 3.1%
	Cadillac term loan, due 2025			3.9			3.9		6.0% – 8.0%
	Piedmont term loan, due 2018			4.1			4.5		5.2%
	Other short-term debt			0.2			0.1		5.5 – 6.7%

	Total current maturities		$	19.4		$	20.0




	-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 ($172.4 million at March 31, 2015) of the $600.0 million ($520.2 million at March 31, 2015) outstanding aggregate borrowings under our senior secured term loan facility. See Note 8, Accounting for derivative instruments and hedging activities for further details.
	-2	We repurchased approximately $9.0 million aggregate principal amount of the 9.0% Notes in January 2015 with cash on hand.
	-3	The table does not include non-recourse debt at the Wind Projects which have been classified as held for sale at March 31, 2015 and December 31, 2014.

Convertible_debentures_Tables

Convertible debentures (Tables)	3 Months Ended
Convertible debentures (Tables)	Mar. 31, 2015
Convertible debentures
Schedule of outstanding convertible debentures
		6.25% Debentures			5.6% Debentures			5.75% Debentures			6.00% Debentures			Total
		due March 2017			due June 2017			due June 2019			due December 2019			Total
	Balance at December 31, 2014	$	58		$	68.6		$	128.4		$	85.6		$	340.6
	Repayment of convertible debentures		—			(0.3	)		(3.4	)		(2.0	)		(5.7	)
	Foreign exchange gain		(4.9	)		(5.8	)		—			(7.2	)		(17.9	)
	Gain on repurchase of convertible debentures		—			—			(0.8	)		(0.5	)		(1.3	)

	Balance at March 31, 2015	$	53.1		$	62.5		$	124.2		$	75.9		$	315.7

Fair_value_of_financial_instru1

Fair value of financial instruments (Tables)	3 Months Ended
Fair value of financial instruments (Tables)	Mar. 31, 2015
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities
		March 31, 2015
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	100.1	$	—	$	—	$	100.1
	Restricted cash		14.1		—		—		14.1
	Derivative instruments asset		—		0.3		—		0.3

	Total	$	114.2	$	0.3	$	—	$	114.5


	Liabilities:
	Derivative instruments liability	$	—	$	79.3	$	—	$	79.3

	Total	$	—	$	79.3	$	—	$	79.3




		December 31, 2014
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	106.0	$	—	$	—	$	106.0
	Restricted cash		22.5		—		—		22.5
	Derivative instruments asset		—		1.1		—		1.1

	Total	$	128.5	$	1.1	$	—	$	129.6


	Liabilities:
	Derivative instruments liability	$	—	$	83.6	$	—	$	83.6

	Total	$	—	$	83.6	$	—	$	83.6

Accounting_for_derivative_inst1

Accounting for derivative instruments and hedging activities (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions

		Units		March 31,			December 31,
		Units		2015			2014
	Natural gas swaps	Natural Gas (Mmbtu)			5.3			6.3
	Gas purchase agreements	Natural Gas (Gj)			31.6			33.9
	Interest rate swaps	Interest (US$)			151.0			152.1


Schedule of fair value of derivative instruments
		March 31, 2015
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.2
	Interest rate swaps long-term		—			3.3

	Total derivative instruments designated as cash flow hedges		—			4.5

	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			1.9
	Interest rate swaps long-term		0.3			8.9
	Natural gas swaps current		—			4.9
	Natural gas swaps long-term		—			2.3
	Gas purchase agreements current		—			26.7
	Gas purchase agreements long-term		—			30.1

	Total derivative instruments not designated as cash flow hedges		0.3			74.8

	Total derivative instruments	$	0.3		$	79.3




		December 31, 2014
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.1
	Interest rate swaps long-term		—			2.9

	Total derivative instruments designated as cash flow hedges		—			4.0

	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			2.0
	Interest rate swaps long-term		1.1			6.9
	Natural gas swaps current		—			4.4
	Natural gas swaps long-term		—			2.2
	Gas purchase agreements current		—			28.6
	Gas purchase agreements long-term		—			35.5

	Total derivative instruments not designated as cash flow hedges		1.1			79.6

	Total derivative instruments	$	1.1		$	83.6




Schedule of changes in OCI attributable to derivative financial instruments
	For the three months ended March 31, 2015	Interest Rate
	For the three months ended March 31, 2015	Swaps
	Accumulated OCI balance at January 1, 2015	$	0.1
	Change in fair value of cash flow hedges		(0.5	)
	Realized from OCI during the period		0.2

	Accumulated OCI balance at March 31, 2015	$	(0.2	)




	For the three months ended March 31, 2014	Interest Rate
	For the three months ended March 31, 2014	Swaps
	Accumulated OCI balance at January 1, 2014	$	0.2
	Change in fair value of cash flow hedges		(0.3	)
	Realized from OCI during the period		0.2

	Accumulated OCI balance at March 31, 2014	$	0.1




Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges

				Three months
				ended
		Classification of (gain) loss		March 31,
		recognized in income		2015			2014
	Natural gas swaps	Fuel		$	1.3		$	3.9
	Gas purchase agreements	Fuel			12			15.9
	Interest rate swaps	Interest, net			(1.0	)		(4.2	)
	Foreign currency forwards	Foreign exchange gain			—			(0.1	)


Summary of the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges

				Three months
				ended
		Classification of loss (gain)		March 31,
		recognized in income		2015			2014
	Natural gas swaps	Change in fair value of derivatives		$	(0.6	)	$	4.6
	Gas purchase agreements	Change in fair value of derivatives			1.6			16
	Interest rate swaps	Change in fair value of derivatives			(2.7	)		1.4

	Total change in fair value of derivative instruments			$	(1.7	)	$	22

	Foreign currency forwards	Foreign exchange loss		$	—		$	1

Income_taxes_Tables

Income taxes (Tables)	3 Months Ended
	Mar. 31, 2015
Income taxes
Schedule of components of income tax expense (benefit)

		Three months
		ended
		March 31,
		2015			2014
	Current income tax expense from continuing operations	$	1.1		$	1.3
	Deferred tax benefit from continuing operations		(5.7	)		(18.2	)

	Total income tax benefit, net	$	(4.6	)	$	(16.9	)

Equity_compensation_plans_Tabl

Equity compensation plans (Tables)	3 Months Ended
Equity compensation plans (Tables)	Mar. 31, 2015
Equity compensation plans
Schedule of changes in LTIP notional shares

		Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2014		1,443,254		$	3.28
	Granted		1,007,726			2.75
	Reinvested		15,085			2.85
	Forfeited		(63,499	)		4.19
	Exercised		(597,406	)		3.61

	Outstanding at March 31, 2015		1,805,160		$	2.85

Basic_and_diluted_earnings_los1

Basic and diluted earnings (loss) per share (Tables)	3 Months Ended
Basic and diluted earnings (loss) per share (Tables)	Mar. 31, 2015
Basic and diluted earnings (loss) per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation

		Three months ended
		March 31,
		2015			2014
	Numerator:
	Income (loss) from continuing operations attributable to Atlantic Power Corporation	$	22.3		$	(17.0	)
	Loss from discontinued operations, net of tax		(4.8	)		(1.9	)

	Net income (loss) attributable to Atlantic Power Corporation	$	17.5		$	(18.9	)
	Denominator:
	Denominator:
	Weighted average basic shares outstanding		121.5			120.3
	Dilutive potential shares:
	Convertible debentures		—			—
	LTIP notional units		0.9			—

	Potentially dilutive shares		122.4			120.3


	Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.17		$	(0.15	)
	Diluted loss per share from discontinued operations		(0.03	)		(0.01	)

	Diluted income (loss) per share attributable to Atlantic Power Corporation	$	0.14		$	(0.16	)

Equity_Tables

Equity (Tables)	3 Months Ended
Equity (Tables)	Mar. 31, 2015
Equity
Schedule of reconciliation of equity

		Three months ended March 31, 2015
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	356.2		$	221.3		$	239		$	816.5
	Net income (loss)		17.5			2.3			(7.5	)		12.3
	Realized and unrealized gain on hedging activities, net of tax		(0.3	)		—			—			(0.3	)
	Foreign currency translation adjustment, net of tax		(35.1	)		—			—			(35.1	)
	Common shares issued for LTIP		0.4			—			—			0.4
	Dividends paid to noncontrolling interests		—			—			(2.7	)		(2.7	)
	Dividends declared on common shares		(2.9	)		—			—			(2.9	)
	Dividends declared on preferred shares of a subsidiary company		—			(2.3	)		—			(2.3	)

	Balance at March 31	$	335.8		$	221.3		$	228.8		$	785.9




		Three months ended March 31, 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		(18.9	)		2.8			(6.4	)		(22.5	)
	Realized and unrealized gain on hedging activities, net of tax		(0.1	)		—			—			(0.1	)
	Foreign currency translation adjustment, net of tax		(18.7	)		—			—			(18.7	)
	Dividends paid to noncontrolling interest		—			—			(2.2	)		(2.2	)
	Dividends declared on common shares		(10.3	)		—			—			(10.3	)
	Dividends declared on preferred shares of a subsidiary company		—			(2.8	)		—			(2.8	)

	Balance at March 31	$	560.3		$	221.3		$	257.8		$	1,039.40

Segment_and_geographic_informa1

Segment and geographic information (Tables)	3 Months Ended
Segment and geographic information (Tables)	Mar. 31, 2015
Segment and geographic information
Schedule of a reconciliation of Project Adjusted EBITDA to project income (loss)

		East			West			Wind			Un-allocated			Consolidated
								(Discontinued			Corporate
								Operations)
	Three months ended March 31, 2015
	Project revenues	$	75		$	36		$	—		$	0.3		$	111.3
	Segment assets		1,148.20			791			854.8			18.1			2,812.10
	Project Adjusted EBITDA	$	43.2		$	17.2		$	—		$	(1.8	)	$	58.6
	Change in fair value of derivative instruments		1			—			—			0.7			1.7
	Depreciation and amortization		17.5			15.2			—			0.2			32.9
	Interest, net		2.5			—			—			—			2.5

	Project income (loss)		22.2			2			—			(2.7	)		21.5
	Administration		—			—			—			9.4			9.4
	Interest, net		—			—			—			25.7			25.7
	Foreign exchange gain		—			—			—			(32.2	)		(32.2	)
	Other income, net		—			—			—			(1.4	)		(1.4	)

	Income (loss) from continuing operations before income taxes		22.2			2			—			(4.2	)		20
	Income tax benefit		—			—			—			(4.6	)		(4.6	)

	Net income (loss) from continuing operations		22.2			2			—			0.4			24.6
	Loss from discontinued operations		—			—			(12.3	)		—			(12.3	)

	Net income (loss)	$	22.2		$	2		$	12.3		$	0.4		$	12.3




		East			West			Wind			Un-allocated			Consolidated
								(Discontinued			Corporate
								Operations)
	Three months ended March 31, 2014
	Project revenues	$	86.7		$	38.5		$	—		$	0.1		$	125.3
	Segment assets		1,409.50			973.3			849			65			3,296.80
	Project Adjusted EBITDA	$	45.6		$	11.3		$	—		$	(0.5	)	$	56.4
	Change in fair value of derivative instruments		(21.9	)		—			—			—			(21.9	)
	Depreciation and amortization		24.4			16.4			—			—			40.8
	Interest, net		11.5			—			—			—			11.5
	Other project expense		—			—			—			0.3			0.3

	Project income (loss)		31.6			(5.1	)		—			(0.8	)		25.7
	Administration		—			—			—			7.1			7.1
	Interest, net		—			—			—			66.5			66.5
	Foreign exchange gain		—			—			—			(16.8	)		(16.8	)
	Other income, net					—			—			—			—

	Income (loss) from continuing operations before income taxes		31.6			(5.1	)		—			(57.6	)		(31.1	)
	Income tax benefit		—			—			—			(16.9	)		(16.9	)

	Net income (loss) from continuing operations		31.6			(5.1	)		—			(40.7	)		(14.2	)
	(Loss) income from discontinued operations		—			2			(10.3	)		—			(8.3	)

	Net income (loss)	$	31.6		$	(3.1	)	$	(10.3	)	$	(40.7	)	$	(22.5	)




Schedule of revenue and property, plant and equipment by country

								Property, Plant and
								Equipment, net of
		Project Revenue						accumulated depreciation
		Three months ended
		March 31,						March 31,			December 31,
		2015			2014			2015			2014
	United States	$	60.8		$	73.0		$	546.7		$	553.5
	Canada		50.5			52.3			368.2			409.4

	Total	$	111.3		$	125.3		$	914.9		$	962.9

Nature_of_business_Details

Nature of business (Details)	3 Months Ended
	Mar. 31, 2015
	MW
	project
	item
	state
Nature of business
Gross generating capacity of project (in MW)	2,137
Ownership interest in operational power generation projects (in MW)	1,502
Number of operational power generation projects	23
Number of states in which power generation projects operate	9
Number of provinces in which power generation projects operate	2
Number of projects Which are wholly owned subsidiaries	18
Meadow Creek
Nature of business
Percentage of ownership interest	100.00%
Wind power project capacity of disposed projects (in MW)	521
Canadian Hills
Nature of business
Percentage of ownership interest	99.00%
Rockland
Nature of business
Percentage of ownership interest	50.00%
Idaho Wind
Nature of business
Percentage of ownership interest	27.60%
Goshen
Nature of business
Percentage of ownership interest	12.50%

Changes_in_accumulated_other_c2

Changes in accumulated other comprehensive loss by component (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Changes in accumulated other comprehensive loss by component
Balance at beginning of period	($68.30)
Other comprehensive loss:
Foreign currency translation adjustments	-35.1	-18.7
Tax expense	-4.6	-16.9
Total Other comprehensive loss	-35.4	-18.8
Balance at end of period	-103.7
Foreign currency translation
Changes in accumulated other comprehensive loss by component
Balance at beginning of period		-66.3	-22.2
Other comprehensive loss:
Foreign currency translation adjustments	-35.1	-18.7
Accumulated other comprehensive loss, tax impacts related to rate changes	0	0
Balance at end of period	-101.4	-40.9	-22.2
Foreign currency translation \| Amount reclassified from accumulated other comprehensive income
Other comprehensive loss:
Net amount reclassified to earnings:	0	0
Cash flow hedges
Changes in accumulated other comprehensive loss by component
Balance at beginning of period		0.1	0.2
Other comprehensive loss:
Net change from periodic revaluations	-0.9	-0.5
Tax benefit	0.4	0.2
Total Other comprehensive loss before reclassifications, net of tax	-0.5	-0.3
Tax expense	-0.1	-0.2
Total amount reclassified from Accumulated other comprehensive income, net of tax	0.2	0.2
Total Other comprehensive loss	-0.3	-0.1
Balance at end of period	-0.2	0.1	0.2
Cash flow hedges \| Amount reclassified from accumulated other comprehensive income
Other comprehensive loss:
Net amount reclassified to earnings:	0.3	0.4
Cash flow hedges \| Amount reclassified from accumulated other comprehensive income \| Interest rate swaps
Other comprehensive loss:
Net amount reclassified to earnings:	0.3	0.4
Pension
Changes in accumulated other comprehensive loss by component
Balance at beginning of period			-0.4	-2.1
Other comprehensive loss:
Balance at end of period	($2.10)	($0.40)	($0.40)	($2.10)

Assets_held_for_sale_and_disco2

Assets held for sale and discontinued operations (Details) (USD $)	3 Months Ended		1 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2015	Dec. 31, 2014
				MW
				item
Project other income (expense):
Loss from operations of discontinued businesses, net of tax	($12.30)	($8.30)
Net loss attributable to noncontrolling interests	-7.5	-6.4
Loss from operations of discontinued businesses, net of noncontrolling interests	-4.8	-1.9
Greeley, Rollcast, Path 15 and the Florida Projects
Discontinued operations
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share)	($0.03)	($0.01)
Summary of revenue and loss from discontinued operations
Revenue	16.7	20
Project expenses:
Operations and maintenance	5.6	5.1
Depreciation and amortization	10.1	10
Total Project expenses	15.7	15.1
Project other income (expense):
Change in fair value of derivatives	-7.3	-7.3
Equity in (loss) earnings of unconsolidated affiliates	-0.9	0.2
Interest expense, net	-3.4	-3.6
Gain on sale of asset		2.1
Total Project other income (expense)	-11.6	-8.6
Loss from operations of discontinued businesses	-10.6	-3.7
Income tax expense	1.7	4.6
Loss from operations of discontinued businesses, net of tax	-12.3	-8.3
Net loss attributable to noncontrolling interests	-7.5	-6.4
Loss from operations of discontinued businesses, net of noncontrolling interests	-4.8	-1.9
Discontinued Operations Held-for-sale \| Greeley
Discontinued operations
Proceeds from sale of our outstanding membership interest			1
Non-cash gain on the sale related to the write-off of asset retirement obligations			2.1
Discontinued Operations Held-for-sale \| APT \| Terra Form AP Holdings LLC
Discontinued operations
Expected consideration to be received on disposal of interests	350			350
Ownership interest sold (as a percent)	100.00%			100.00%
Number of operating wind projects sold				5
Wind power project capacity of disposed projects (in MW)				521
Project debt deconsolidated	249			249
Project debt deconsolidated, including adjustment for entities with proportional ownership interest	275			275
Non-controlling interests deconsolidated	229			229
Expected consideration to be received on disposal of interests, net of transaction fees and taxes	338			338
Operating and investing cash flows:
Cash provided by operating activities	10.8	8.8
Cash provided by investing activities	1.4	1.2
Current assets:
Cash and cash equivalents	6.2			6.2	3.9
Accounts receivable	11.2			11.2	11.2
Other current assets	2.4			2.4	2.4
Total current assets	19.8			19.8	17.5
Non-current assets:
Plant, property & equipment	700.5			700.5	710.5
Equity investments in unconsolidated affiliates	36.5			36.5	38.7
Other intangible assets, net	4.3			4.3	4.3
Restricted cash	17.9			17.9	19.1
Other assets	1.8			1.8	2
Assets held for sale	780.8			780.8	792.1
Current liabilities:
Accounts payable and other accrued liabilities	7.7			7.7	5.9
Current portion of long-term debt	6.4			6.4	6.4
Current portion of derivative instruments liability	4.8			4.8	3.1
Total current liabilities	18.9			18.9	15.4
Long term liabilities
Long-term debt	242.4			242.4	242.4
Derivative instruments liability	15.7			15.7	10
Other long-term liabilities	4.1			4.1	4
Liabilities of held for sale	$281.10			$281.10	$271.80
Discontinued Operations Held-for-sale \| APT \| Goshen
Discontinued operations
Ownership interest sold (as a percent)	12.50%			12.50%
Discontinued Operations Held-for-sale \| APT \| Idaho Wind
Discontinued operations
Ownership interest sold (as a percent)	27.60%			27.60%
Discontinued Operations Held-for-sale \| APT \| Meadow Creek
Discontinued operations
Ownership interest sold (as a percent)	100.00%			100.00%
Discontinued Operations Held-for-sale \| APT \| Rockland Wind Farm
Discontinued operations
Ownership interest sold (as a percent)	50.00%			50.00%
Consolidated ownership interest sold (as a percent)				100
Discontinued Operations Held-for-sale \| APT \| Canadian Hills
Discontinued operations
Consolidated ownership interest sold (as a percent)				99

Equity_method_investments_in_u2

Equity method investments in unconsolidated affiliates (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating results
Revenue	$37.80	$53.70
Project expenses	26.6	44.6
Project other (expense) income	-0.4	-0.7
Project income	10.8	8.4
Orlando
Operating results
Revenue	12.8	13.3
Project expenses	6.6	8.7
Project income	6.2	4.6
Chambers Cogen, LP
Operating results
Revenue	15.4	17.9
Project expenses	11.4	14.2
Project other (expense) income	-0.5	-0.6
Project income	3.5	3.1
Other
Operating results
Revenue	9.6	22.5
Project expenses	8.6	21.7
Project other (expense) income	0.1	-0.1
Project income	$1.10	$0.70
Other \| Maximum
Operating results
Percentage of ownership interest	10.00%
Goshen
Operating results
Percentage of ownership interest	12.50%
Idaho Wind
Operating results
Percentage of ownership interest	27.60%
Rockland
Operating results
Percentage of ownership interest	50.00%

Longterm_debt_Details

Long-term debt (Details) (USD $)	3 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	5-May-14	Dec. 31, 2014	Nov. 05, 2011
	item	Mar. 31, 2014	5-May-14	Dec. 31, 2014	Nov. 05, 2011
Long-term debt
Less: current maturities	($19.40)			($20)
Total long-term debt	1,098.40			1,145.90
Fuel expense	46.2	59.8
Foreign exchange gain	-32.2	-16.8
Fixed charge coverage ratio	1.75
Number of rolling quarters used in measurement of fixed charge coverage ratio	4
Interest rate swaps
Long-term debt
Notional amount	151			152.1
Senior secured term loan, due 2021
Long-term debt
Total debt	520.2			541.5
Less: current maturities	-5.2			-5.4
Variable interest rate basis	LIBOR
Applicable margin (as a percent)	3.80%
Senior secured term loan, due 2021 \| London Interbank Offered Rate (LIBOR)
Long-term debt
Minimum percentage of variable rate base	1.00%
Senior Notes
Long-term debt
Total debt	310.9			319.9
Aggregate principal amount of debt repurchased	9
Interest rate (as a percent)	9.00%				9.00%
Senior unsecured notes, due June 2036
Long-term debt
Total debt	165.8			181
Interest rate (as a percent)	6.00%
Epsilon Power Partners term facility, due 2019
Long-term debt
Total debt	24			25.5
Less: current maturities	-6			-6.1
Variable interest rate basis	LIBOR
Applicable margin (as a percent)	3.10%
Cadillac term loan, due 2025
Long-term debt
Total debt	32.8			33.4
Less: current maturities	-3.9			-3.9
Cadillac term loan, due 2025 \| Minimum
Long-term debt
Interest rate (as a percent)	6.00%
Cadillac term loan, due 2025 \| Maximum
Long-term debt
Interest rate (as a percent)	8.00%
Piedmont term loan, due 2018
Long-term debt
Total debt	63.6			64
Less: current maturities	-4.1			-4.5
Interest rate (as a percent)	5.20%
Other long-term debt
Long-term debt
Total debt	0.5			0.6
Less: current maturities	-0.2			-0.1
Other long-term debt \| Minimum
Long-term debt
Interest rate (as a percent)	5.50%
Other long-term debt \| Maximum
Long-term debt
Interest rate (as a percent)	6.70%
New term loan facility \| Adjusted Eurodollar Rate
Long-term debt
Minimum percentage of variable rate base			1.00%
Applicable margin (as a percent)			3.75%
New term loan facility \| Adjusted Eurodollar Rate \| Interest rate swaps
Long-term debt
Notional amount	172.4		199	172.4
Aggregate principal amount of debt	520.2		600
Existing notes \| Maximum
Long-term debt
Maximum dividend payments, amount	50
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	$46.70

Longterm_debt_Details_2

Long-term debt (Details 2) (USD $)	3 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	5-May-14	Dec. 31, 2014	Nov. 05, 2011
	item	Mar. 31, 2014	5-May-14	Dec. 31, 2014	Nov. 05, 2011
Long-term debt
Less: current maturities	($19.40)			($20)
Total long-term debt	1,098.40			1,145.90
Fuel expense	46.2	59.8
Foreign exchange gain	-32.2	-16.8
Fixed charge coverage ratio	1.75
Number of rolling quarters used in measurement of fixed charge coverage ratio	4
Dividend payments	2.9	10.2
Interest rate swaps
Long-term debt
Notional amount	151			152.1
Senior secured term loan, due 2021
Long-term debt
Total debt	520.2			541.5
Less: current maturities	-5.2			-5.4
Variable interest rate basis	LIBOR
Applicable margin (as a percent)	3.80%
Principal payments on the maturities of debt due in next five years
Total debt	520.2			541.5
Senior secured term loan, due 2021 \| London Interbank Offered Rate (LIBOR)
Long-term debt
Minimum percentage of variable rate base	1.00%
Senior Notes
Long-term debt
Total debt	310.9			319.9
Interest rate (as a percent)	9.00%				9.00%
Repayment of debt from proceeds from 1603 grant with U.S. Treasury	9
Aggregate principal amount of debt repurchased	9
Principal payments on the maturities of debt due in next five years
Total debt	310.9			319.9
Senior unsecured notes, due June 2036
Long-term debt
Total debt	165.8			181
Interest rate (as a percent)	6.00%
Principal payments on the maturities of debt due in next five years
Total debt	165.8			181
Epsilon Power Partners term facility, due 2019
Long-term debt
Total debt	24			25.5
Less: current maturities	-6			-6.1
Variable interest rate basis	LIBOR
Applicable margin (as a percent)	3.10%
Principal payments on the maturities of debt due in next five years
Total debt	24			25.5
Cadillac term loan, due 2025
Long-term debt
Total debt	32.8			33.4
Less: current maturities	-3.9			-3.9
Principal payments on the maturities of debt due in next five years
Total debt	32.8			33.4
Cadillac term loan, due 2025 \| Minimum
Long-term debt
Interest rate (as a percent)	6.00%
Cadillac term loan, due 2025 \| Maximum
Long-term debt
Interest rate (as a percent)	8.00%
Piedmont term loan, due 2018
Long-term debt
Total debt	63.6			64
Less: current maturities	-4.1			-4.5
Interest rate (as a percent)	5.20%
Principal payments on the maturities of debt due in next five years
Total debt	63.6			64
Other long-term debt
Long-term debt
Total debt	0.5			0.6
Less: current maturities	-0.2			-0.1
Principal payments on the maturities of debt due in next five years
Total debt	0.5			0.6
Other long-term debt \| Minimum
Long-term debt
Interest rate (as a percent)	5.50%
Other long-term debt \| Maximum
Long-term debt
Interest rate (as a percent)	6.70%
New term loan facility \| Adjusted Eurodollar Rate
Long-term debt
Applicable margin (as a percent)			3.75%
Minimum percentage of variable rate base			1.00%
New term loan facility \| Adjusted Eurodollar Rate \| Interest rate swaps
Long-term debt
Notional amount	172.4		199	172.4
Aggregate principal amount of debt	520.2		600
Existing notes
Long-term debt
Dividend payments		35.4
Existing notes \| Maximum
Long-term debt
Maximum dividend payments, amount	50
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	$46.70

Convertible_debentures_Details

Convertible debentures (Details) (USD $)	3 Months Ended		1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Apr. 30, 2015	Dec. 31, 2014
Movement in convertible debentures
Balance at the beginning of the period	$340.60
Repayment of convertible debentures	-5.7
Foreign exchange gain	-32.2	-16.8
Gain on repurchase of convertible debentures	-1.4
Balance at the end of the period	315.7
NCIB
Movement in convertible debentures
Repayment of convertible debentures	5.7		10.3	3.1
Gain on repurchase of convertible debentures	-1.3			-0.7
Aggregate principal amount of debt repurchased	7		8.6
NCIB \| Maximum
Movement in convertible debentures
Aggregate principal amount of debt repurchased	31
6.25% Debentures due March 2017
Movement in convertible debentures
Balance at the beginning of the period	58
Foreign exchange gain	-4.9
Balance at the end of the period	53.1
5.6% Debentures due June 2017
Movement in convertible debentures
Balance at the beginning of the period	68.6
Repayment of convertible debentures	-0.3
Foreign exchange gain	-5.8
Balance at the end of the period	62.5
5.75% Debentures due June 2019
Movement in convertible debentures
Balance at the beginning of the period	128.4
Repayment of convertible debentures	-3.4
Gain on repurchase of convertible debentures	-0.8
Balance at the end of the period	124.2
6.00% Debenture due December 2019
Movement in convertible debentures
Balance at the beginning of the period	85.6
Repayment of convertible debentures	-2
Foreign exchange gain	-7.2
Gain on repurchase of convertible debentures	-0.5
Balance at the end of the period	$75.90

Fair_value_of_financial_instru2

Fair value of financial instruments (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Assets:
Restricted cash	$14.10	$22.50
Recurring \| Level 1
Assets:
Cash and cash equivalents	100.1	106
Restricted cash	14.1	22.5
Total	114.2	128.5
Recurring \| Level 2
Assets:
Derivative instruments asset	0.3	1.1
Total	0.3	1.1
Liabilities:
Derivative instruments liability	79.3	83.6
Total	79.3	83.6
Recurring \| Fair Value
Assets:
Cash and cash equivalents	100.1	106
Restricted cash	14.1	22.5
Derivative instruments asset	0.3	1.1
Total	114.5	129.6
Liabilities:
Derivative instruments liability	79.3	83.6
Total	$79.30	$83.60

Fair_value_of_financial_instru3

Fair value of financial instruments (Details 2) (Credit valuation adjustments, USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Credit valuation adjustments
Recurring measurements of fair value hierarchy of financial assets and liabilities
Net increase in fair value	$5.50	$8.30
Pre-tax gain in other comprehensive income	0.5	0.7
Gain in change in fair value of derivatives	$5	$7.60

Accounting_for_derivative_inst2

Accounting for derivative instruments and hedging activities (Details) (USD $)	0 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	5-May-14	Jun. 30, 2014	Mar. 31, 2015	Feb. 20, 2014	Dec. 31, 2014	Feb. 14, 2014
	5-May-14	MMBTU	Mar. 31, 2015	Feb. 20, 2014	MMBTU	Feb. 14, 2014
Accounting for derivative instruments and hedging activities
Derivative Number of Contracts Designated as Cash Flow Hedges			1
New term loan facility \| Adjusted Eurodollar Rate
Derivative instruments
Applicable margin (as a percent)	3.75%
Minimum percentage of variable rate base	1.00%
Gas purchase agreements \| Ontario project
Derivative instruments
Notional amount (in Mmbtu)		2,900,000
Expected uncontracted gas requirements for 2014 \| Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements			98.00%
Expected uncontracted gas requirements for 2015 \| Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements			98.00%
Expected uncontracted gas requirements for 2016 \| Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements			32.00%
Expected uncontracted gas requirements for 2017 \| Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements			30.00%
Natural gas swaps
Derivative instruments
Notional amount (in Mmbtu)			5,300,000		6,300,000
Amount paid for termination of contracts				$4
Natural gas swaps \| Orlando project
Derivative instruments
Notional amount (in Mmbtu)			6,300,000
Percentage of ownership interest			50.00%
Natural gas swaps during 2014 and 2015 \| Orlando project
Derivative instruments
Notional amount (in Mmbtu)			4,500,000
Interest rate swaps
Derivative instruments
Amount paid for termination of contracts				2.6
Notional amount			151		152.1
Interest rate swaps \| New term loan facility
Derivative instruments
Minimum fixed interest rate (as a percent)	4.75%
Maximum fixed interest rate (as a percent)	4.91%
Interest rate swaps \| New term loan facility \| Adjusted Eurodollar Rate
Derivative instruments
Notional amount	199		172.4		172.4
Aggregate principal amount of debt	600		520.2
Interest rate swaps \| New term loan facility \| Adjusted Eurodollar Rate \| Derivative instruments not designated as cash flow hedges
Derivative instruments
Swaption interest rate (as a percent)	1.16%
Interest rate swaps \| Epsilon Power Partners
Derivative instruments
Swaption interest rate (as a percent)			7.37%
Interest rate swaps \| Piedmont \| Piedmont construction loan, due 2014
Derivative instruments
Total debt						68.5
Interest rate swaps \| Swaption interest rate until February 15, 2015 \| Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)			6.00%
Interest rate swaps \| Swaption interest rate from February 16, 2015 to February 15, 2019 \| Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)			6.10%
Interest rate swaps \| Swaption interest rate from February 16, 2019 to February 15, 2023 \| Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)			6.30%
Interest rate swaps \| Swaption interest rate after February 15, 2023 \| Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)			6.40%
Interest rate swaps \| Swaption interest rate until February 29, 2016 \| Piedmont
Derivative instruments
Swaption interest rate (as a percent)			1.70%
Applicable margin, low end of range (as a percent)			3.50%
Applicable margin, high end of range (as a percent)			3.80%
Interest rate swaps \| Swaption interest rate from February, 2016 to November, 2017 \| Piedmont
Derivative instruments
Swaption interest rate (as a percent)			4.47%
Applicable margin of derivative (as a percent)			4.00%
Swaption interest rate after addition of applicable margin (as a percent)			8.50%
Interest rate swaps \| Swaption interest rate from November, 2017 to November, 2030 \| Piedmont
Derivative instruments
Swaption interest rate (as a percent)			4.47%
Foreign currency forward contracts
Derivative instruments
Amount paid for termination of contracts				$0.40
Natural gas swaps during remainder of 2014
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge			100.00%
Natural gas swaps during 2015
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge			96.00%
Natural gas swaps during 2016
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge			65.00%

Accounting_for_derivative_inst3

Accounting for derivative instruments and hedging activities (Details 2) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
	MMBTU	MMBTU	kJ
Natural gas swaps
Derivative instruments
Volume of forecasted transactions	5,300,000	6,300,000
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions	316,000,000		339,000,000
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars)	151	152.1

Accounting_for_derivative_inst4

Accounting for derivative instruments and hedging activities (Details 3) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair value of derivative instruments
Derivative Assets	$0.30	$1.10
Derivative Liabilities	79.3	83.6
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	4.5	4
Derivative instruments designated as cash flow hedges \| Interest rate swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	1.2	1.1
Derivative instruments designated as cash flow hedges \| Interest rate swaps \| Long-term
Fair value of derivative instruments
Derivative Liabilities	3.3	2.9
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets	0.3	1.1
Derivative Liabilities	74.8	79.6
Derivative instruments not designated as cash flow hedges \| Interest rate swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	1.9	2
Derivative instruments not designated as cash flow hedges \| Interest rate swaps \| Long-term
Fair value of derivative instruments
Derivative Assets	0.3	1.1
Derivative Liabilities	8.9	6.9
Derivative instruments not designated as cash flow hedges \| Natural gas swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	4.9	4.4
Derivative instruments not designated as cash flow hedges \| Natural gas swaps \| Long-term
Fair value of derivative instruments
Derivative Liabilities	2.3	2.2
Derivative instruments not designated as cash flow hedges \| Gas purchase agreements \| Current
Fair value of derivative instruments
Derivative Liabilities	26.7	28.6
Derivative instruments not designated as cash flow hedges \| Gas purchase agreements \| Long-term
Fair value of derivative instruments
Derivative Liabilities	$30.10	$35.50

Accounting_for_derivative_inst5

Accounting for derivative instruments and hedging activities (Details 4) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Changes in accumulated other comprehensive loss by component
Change in fair value of cash flow hedges	($0.50)	($0.30)
Realized from OCI during the period	0.2	0.2
Interest rate swaps
Changes in accumulated other comprehensive loss by component
Accumulated OCI balance at beginning of period	0.1	0.2
Change in fair value of cash flow hedges	-0.5	-0.3
Realized from OCI during the period	0.2	0.2
Accumulated OCI balance at end of period	($0.20)	$0.10

Accounting_for_derivative_inst6

Accounting for derivative instruments and hedging activities (Details 5) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	($1.70)	$22
Derivative instruments not designated as cash flow hedges
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	-1.7	22
Derivative instruments not designated as cash flow hedges \| Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	1.3	3.9
Change in fair value of derivative instruments	-0.6	4.6
Derivative instruments not designated as cash flow hedges \| Gas purchase agreements
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	12	15.9
Change in fair value of derivative instruments	1.6	16
Derivative instruments not designated as cash flow hedges \| Interest rate swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	-1	-4.2
Change in fair value of derivative instruments	-2.7	1.4
Derivative instruments not designated as cash flow hedges \| Foreign currency forward contracts
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments		-0.1
Change in fair value of derivative instruments		$1

Income_taxes_Details

Income taxes (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Components of income tax expenses (benefit)
Current income tax expense from continuing operations	$1.10	$1.30
Deferred tax benefit from continuing operations	-5.7	-18.2
Total income tax benefit, net	-4.6	-16.9
Canadian enacted statutory rate (as a percent)	26.00%	26.00%
Computed income taxes at Canadian statutory rate	5.2	8.1
Capital losses		10.7
Change in tax rates in various tax jurisdictions	2.4	5.2
Foreign exchange	1.8	3.6
Permanent differences	2.7	4.4
Change in valuation allowance	2.9	15.1
Valuation allowance	$165.70

Equity_compensation_plans_Deta

Equity compensation plans (Details) (USD $)	0 Months Ended	3 Months Ended
Equity compensation plans (Details) (USD $)	Jan. 26, 2015	Mar. 31, 2015	Jan. 22, 2015
Transition equity participation agreement
Units
Granted (in shares)	523,256
Transition equity participation agreement
Granted (in shares)	523,256
Vesting percentage		50.00%
Vesting period		4 years
Period after which remaining portions vests		2 years
Market price (in dollars per share)			$2.58
Minimum percentage by which weighted average Canadian dollar price exceeds market price		50.00%
Minimum \| Transition equity participation agreement
Transition equity participation agreement
Number of consecutive months, weighted average Canadian dollar price exceeds market price of share by 50%		3
Long-term incentive plan
Units
Outstanding at the beginning of the period (in shares)		1,443,254
Granted (in shares)		1,007,726
Reinvested (in shares)		15,085
Forfeited (in shares)		-63,499
Exercised (in shares)		-597,406
Outstanding at the end of the period (in shares)		1,805,160
Weighted-Average Price per Unit
Outstanding at the beginning of the period (in dollars per share)		3.28
Granted (in dollars per share)		2.75
Reinvested (in dollars per share)		2.85
Forfeited (in dollars per share)		4.19
Exercised (in dollars per share)		3.61
Outstanding at the end of the period (in dollars per share)		2.85
Transition equity participation agreement
Granted (in shares)		1,007,726

Basic_and_diluted_earnings_los2

Basic and diluted earnings (loss) per share (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Numerator:
Income (loss) from continuing operations attributable to Atlantic Power Corporation	$22.30	($17)
Loss from discontinued operations, net of tax	-4.8	-1.9
Net income (loss) attributable to Atlantic Power Corporation	$17.50	($18.90)
Denominator:
Weighted average basic shares outstanding	121.5	120.3
Dilutive potential shares:
LTIP notional units (in shares)	0.9
Potentially dilutive shares	122.4	120.3
Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$0.17	($0.15)
Diluted loss per share from discontinued operations	($0.03)	($0.01)
Diluted income (loss) per share attributable to Atlantic Power Corporation	$0.14	($0.16)
Potentially dilutive convertible debenture excluded from calculation of EPS	23.5	27.7

Equity_Details

Equity (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	$816.50	$1,096
Net (loss) income	12.3	-22.5
Realized and unrealized gain on hedging activities, net of tax	-0.3	-0.1
Foreign currency translation adjustment, net of tax	-35.1	-18.7
Common shares issued for LTIP	0.4
Dividends paid to noncontrolling interests	-2.7	-2.2
Dividends declared on common shares	-2.9	-10.3
Dividends declared on preferred shares of a subsidiary company	-2.3	-2.8
Balance at the end of the period	785.9	1,039.40
Total Atlantic Power Corporation Shareholder's Equity
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	356.2	608.3
Net (loss) income	17.5	-18.9
Realized and unrealized gain on hedging activities, net of tax	-0.3	-0.1
Foreign currency translation adjustment, net of tax	-35.1	-18.7
Common shares issued for LTIP	0.4
Dividends declared on common shares	-2.9	-10.3
Balance at the end of the period	335.8	560.3
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	2.3	2.8
Dividends declared on preferred shares of a subsidiary company	-2.3	-2.8
Balance at the end of the period	221.3	221.3
Noncontrolling Interests
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	239	266.4
Net (loss) income	-7.5	-6.4
Dividends paid to noncontrolling interests	-2.7	-2.2
Balance at the end of the period	$228.80	$257.80

Segment_and_geographic_informa2

Segment and geographic information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	item	Mar. 31, 2014	Dec. 31, 2014
Segment and geographic information
Number of Reportable Segments	4
Segment and geographic information
Project revenues	$111.30	$125.30
Segment assets	2,812.10	3,296.80	2,916.60
Project Adjusted EBITDA	58.6	56.4
Change in fair value of derivative instruments	1.7	-21.9
Depreciation and amortization	32.9	40.8
Interest, net	2.5	11.5
Other project expense (income)		0.3
Project income	21.5	25.7
Administration	9.4	7.1
Interest, net	25.7	66.5
Foreign exchange gain	-32.2	-16.8
Other income, net	-1.4
(Loss) income from continuing operations before income taxes	20	-31.1
Income tax benefit	-4.6	-16.9
Income (loss) from continuing operations	24.6	-14.2
(Loss) income from discontinued operations	-12.3	-8.3
Net income (loss)	12.3	-22.5
Operating Segments \| East
Segment and geographic information
Project revenues	75	86.7
Segment assets	1,148.20	1,409.50
Project Adjusted EBITDA	43.2	45.6
Change in fair value of derivative instruments	1	-21.9
Depreciation and amortization	17.5	24.4
Interest, net	2.5	11.5
Project income	22.2	31.6
(Loss) income from continuing operations before income taxes	22.2	31.6
Income (loss) from continuing operations	22.2	31.6
Net income (loss)	22.2	31.6
Operating Segments \| West
Segment and geographic information
Project revenues	36	38.5
Segment assets	791	973.3
Project Adjusted EBITDA	17.2	11.3
Depreciation and amortization	15.2	16.4
Project income	2	-5.1
(Loss) income from continuing operations before income taxes	2	-5.1
Income (loss) from continuing operations	2	-5.1
(Loss) income from discontinued operations		2
Net income (loss)	2	-3.1
Operating Segments \| Wind (Discontinued Operations)
Segment and geographic information
Segment assets	854.8	849
(Loss) income from discontinued operations	-12.3	-10.3
Net income (loss)	-12.3	-10.3
Un-allocated Corporate
Segment and geographic information
Project revenues	0.3	0.1
Segment assets	18.1	65
Project Adjusted EBITDA	-1.8	-0.5
Change in fair value of derivative instruments	0.7
Depreciation and amortization	0.2
Other project expense (income)		0.3
Project income	-2.7	-0.8
Administration	9.4	7.1
Interest, net	25.7	66.5
Foreign exchange gain	-32.2	-16.8
Other income, net	-1.4
(Loss) income from continuing operations before income taxes	-4.2	-57.6
Income tax benefit	-4.6	-16.9
Income (loss) from continuing operations	0.4	-40.7
Net income (loss)	$0.40	($40.70)

Segment_and_geographic_informa3

Segment and geographic information (Details 2) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Revenue and Assets
Project revenue	$111.30	$125.30
Property, Plant and Equipment, net of accumulated depreciation	914.9	962.9	962.9
United States
Revenue and Assets
Project revenue	60.8	73
Property, Plant and Equipment, net of accumulated depreciation	546.7	553.5
Canada
Revenue and Assets
Project revenue	50.5	52.3
Property, Plant and Equipment, net of accumulated depreciation	$368.20	$409.40

Segment_and_geographic_informa4

Segment and geographic information (Details 3) (Revenues, net, Consolidated revenue)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	33.70%	32.80%
San Diego Gas & Electric
Consolidated revenue concentration
Percentage of consolidated revenue	14.40%	15.40%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	11.70%	9.00%

Guarantees_Details

Guarantees (Details) (Maximum)	3 Months Ended
Guarantees (Details) (Maximum)	Mar. 31, 2015
Maximum
Guarantees
Expiration term of guarantees	P1Y

Contingencies_Details

Contingencies (Details) (USD $)	0 Months Ended				3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 09, 2013	Aug. 19, 2013	7-May-13	Mar. 31, 2015	Oct. 04, 2013
	Sep. 30, 2014	item	item	item	item	Oct. 04, 2013
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
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
Extension term	30 days
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 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
Number of District Court actions alleged in specific period					5
Number of plaintiff applicants directed resubmit a proposed schedule that contains specific dates					1

Subsequent_events_Details

Subsequent events (Details) (Frontier, Subsequent event, Ridgeline, USD $)	Apr. 22, 2015
In Millions, unless otherwise specified	MW
Frontier \| Subsequent event \| Ridgeline
Subsequent events
Ownership interest sold (as a percent)	100.00%
Potential solar projects capacity provided under acquisition (in MW)	20
Expected consideration to be received on disposal of interests	$4.30