Atlantic Power 10-Q 7 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 07, 2013
Document and Entity Information	'	'
Entity Registrant Name	'ATLANTIC POWER CORP	'
Entity Central Index Key	'0001419242	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-13	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	120,044,879
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$170.70	$60.20
Restricted cash	119.8	28.6
Accounts receivable	63.3	58.5
Current portion of derivative instruments asset (Notes 6 and 7)	0.3	9.5
Inventory	18.3	16.9
Prepayments and other current assets	13.3	13.4
Security deposits	'	19
Assets held for sale (Note 11)	0.5	351.4
Refundable income taxes	1.9	4.2
Total current assets	388.1	561.7
Property, plant, and equipment, net of accumulated depreciation of $152.1 million and $79.2 million at September 30, 2013 and December 31, 2012, respectively	1,873.90	2,055.50
Equity investments in unconsolidated affiliates	404.5	428.7
Other intangible assets, net of accumulated amortization of $123.4 million and $76.9 million at September 30, 2013 and December 31, 2012, respectively	471.1	524.9
Goodwill (Note 4)	296.3	334.7
Derivative instruments asset (Notes 6 and 7)	9.5	11.1
Other assets	53.3	86.1
Total assets	3,496.70	4,002.70
Current liabilities:	'	'
Accounts payable	11.1	17.8
Accrued interest	30	19
Other accrued liabilities	49	73.7
Senior credit facility (Note 5)	'	67
Current portion of long-term debt (Note 5)	206.7	121.2
Current portion of derivative instruments liability (Notes 6 and 7)	32.9	33
Dividends payable	3.9	11.5
Liabilities held for sale (Note 11)	0.1	189
Other current liabilities	6	3.3
Total current liabilities	339.7	535.5
Long-term debt (Note 5)	1,274.10	1,459.10
Convertible debentures	414.1	424.2
Derivative instruments liability (Notes 6 and 7)	87	118.1
Deferred income taxes	151.2	164
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $7.2 million and $4.4 million at September 30, 2013 and December 31, 2012, respectively	40.3	44
Other non-current liabilities	69.3	71.4
Commitments and contingencies (Note 14)	'	'
Total liabilities	2,375.70	2,816.30
Equity	'	'
Common shares, no par value, unlimited authorized shares; 120,044,879 and 119,446,865 issued and outstanding at September 30, 2013 and December 31, 2012, respectively (Note 12)	1,285.70	1,285.50
Preferred shares issued by a subsidiary company (Note 12)	221.3	221.3
Accumulated other comprehensive income (loss)	-8.7	9.4
Retained deficit	-649.6	-565.2
Total Atlantic Power Corporation shareholders' equity	848.7	951
Noncontrolling interest (Note 12)	272.3	235.4
Total equity	1,121	1,186.40
Total liabilities and equity	$3,496.70	$4,002.70

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
CONSOLIDATED BALANCE SHEETS	'	'
Property, plant, and equipment, accumulated depreciation	$152.10	$79.20
Other intangible assets, accumulated amortization	123.4	76.9
Power purchase and fuel supply agreement liabilities, accumulated amortization	$7.20	$4.40
Common shares, no par value (in dollars per share)	$0	$0
Common shares, issued shares (in shares)	120,044,879	119,446,865
Common shares, outstanding shares (in shares)	120,044,879	119,446,865

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Project revenue:	'	'	'	'
Energy sales	$73.40	$49.60	$228.60	$159
Energy capacity revenue	51.1	42.8	132.2	117.3
Other	17.3	13.9	60.2	50.1
Total project revenue	141.8	106.3	421	326.4
Project expenses:	'	'	'	'
Fuel	47.2	40.1	148.8	123.6
Operations and maintenance	38	26.5	112.3	88
Development	1.4	'	4.9	'
Depreciation and amortization	42.2	30.6	125.7	87.3
Total project expenses	128.8	97.2	391.7	298.9
Project other income (expense):	'	'	'	'
Change in fair value of derivative instruments (Notes 6 and 7)	-3.5	10.7	33.4	-51.3
Equity in earnings of unconsolidated affiliates (Note 3)	39.1	4	55	12.4
Interest expense, net	-9	-4.1	-25.7	-12.3
Impairment of goodwill (Note 4)	-34.9	'	-34.9	'
Other, net	0.1	'	0.2	'
Total project other income (expense)	-8.2	10.6	28	-51.2
Project income (loss)	4.8	19.7	57.3	-23.7
Administrative and other expenses (income):	'	'	'	'
Administration	8.4	6.3	28.5	22
Interest, net	27.5	25.8	78.7	69.3
Foreign exchange loss (gain) (Note 7)	9.1	7.7	-12.9	4.4
Other expense (income), net	'	0.3	-9.5	-5.7
Total administrative and other expenses (income)	45	40.1	84.8	90
Loss from continuing operations before income taxes	-40.2	-20.4	-27.5	-113.7
Income tax expense (benefit) (Note 8)	'	3.1	-1.9	-19.1
Loss from continuing operations	-40.2	-23.5	-25.6	-94.6
Net income (loss) from discontinued operations, net of tax (Note 11)	-0.4	19	-6.1	48.8
Net loss	-40.6	-4.5	-31.7	-45.8
Net loss attributable to noncontrolling interests	-2.5	-0.4	-3.3	-0.7
Net income attributable to preferred shares dividends of a subsidiary company	3.2	3.4	9.5	9.8
Net loss attributable to Atlantic Power Corporation	($41.30)	($7.50)	($37.90)	($54.90)
Basic earnings (loss) per share: (Note 10)	'	'	'	'
Loss from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.22)	($0.27)	($0.90)
Income (loss) from discontinued operations, net of tax (in dollars per share)	$0	$0.16	($0.05)	$0.42
Net loss attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.06)	($0.32)	($0.48)
Diluted earnings (loss) per share: (Note 10)	'	'	'	'
Loss from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.22)	($0.27)	($0.90)
Income (loss) from discontinued operations, net of tax (in dollars per share)	$0	$0.16	($0.05)	$0.42
Net loss attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.06)	($0.32)	($0.48)
Weighted average number of common shares outstanding: (Note 10)	'	'	'	'
Basic (in shares)	120	119	119.8	115.4
Diluted (in shares)	120	119	119.8	115.4

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	'	'	'	'
Net loss	($40.60)	($4.50)	($31.70)	($45.80)
Other comprehensive income (loss), net of tax:	'	'	'	'
Unrealized gain (loss) on hedging activities	-0.1	-0.3	0.5	-0.8
Net amount reclassified to earnings	0.2	0.1	0.6	0.5
Net unrealized gain (loss) on derivatives	0.1	-0.2	1.1	-0.3
Foreign currency translation adjustments	10.7	19.3	-19.3	22.6
Other comprehensive income (loss), net of tax	10.8	19.1	-18.2	22.3
Comprehensive income (loss)	-29.8	14.6	-49.9	-23.5
Less: Comprehensive income attributable to noncontrolling interest	0.7	3	6.2	9.1
Comprehensive income (loss) attributable to Atlantic Power Corporation	($30.50)	$11.60	($56.10)	($32.60)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:	'	'
Net loss	($31.70)	($45.80)
Adjustments to reconcile to net cash provided by operating activities:	'	'
Depreciation and amortization	135	117.5
Loss of discontinued operations	32.8	'
(Gain) loss on sale of assets & other charges	-4.6	0.8
Long-term incentive plan expense	1.7	2.3
Impairment charges	39.8	3
Gain on sale of equity investments	-30.4	-0.6
Equity in earnings from unconsolidated affiliates	-24.6	-14.8
Distributions from unconsolidated affiliates	28.5	26.8
Unrealized foreign exchange loss	1.5	21.7
Change in fair value of derivative instruments	-44.1	41
Change in deferred income taxes	-11.9	-24.4
Change in other operating balances	'	'
Accounts receivable	4.5	-2.9
Inventory	-1.5	-5.5
Prepayments, refundable income taxes and other assets	54.2	-13.2
Accounts payable	-11.9	14.9
Accruals and other liabilities	6	3.3
Cash provided by operating activities	143.3	124.1
Cash flows provided by (used in) investing activities:	'	'
Change in restricted cash	-99.1	-105.5
Proceeds from sale of assets and equity investments, net	183	27.9
Cash paid for equity investment	'	-0.3
Proceeds from treasury grant	103.2	'
Biomass development costs	-0.1	-0.4
Construction in progress	-32.2	-336
Purchase of property, plant and equipment	-7.2	-1.2
Cash provided by (used in) investing activities	147.6	-415.5
Cash flows (used in) provided by financing activities:	'	'
Proceeds from issuance of convertible debentures	'	130
Proceeds from issuance of equity, net of offering costs	'	67.7
Proceeds from project-level debt	20.8	261.3
Repayment of project-level debt	-115.4	-12.1
Offering costs related to tax equity	-1	'
Payments for revolving credit facility borrowings	-67	-60.8
Proceeds from revolving credit facility borrowings	'	22.8
Equity contribution from noncontrolling interest	44.6	'
Deferred financing costs	-0.5	-25.3
Dividends paid to common shareholders	-54.2	-108.2
Dividends paid to noncontrolling interests	-13.9	'
Cash (used in) provided by financing activities	-186.6	275.4
Net increase (decrease) in cash and cash equivalents	104.3	-16
Less cash at discontinued operations	-0.3	-1.8
Cash and cash equivalents at beginning of period at discontinued operations	6.5	'
Cash and cash equivalents at beginning of period	60.2	60.7
Cash and cash equivalents at end of period	170.7	42.9
Supplemental cash flow information	'	'
Interest paid	87	77.7
Income taxes paid, net	4.6	3.1
Accruals for construction in progress	$8.30	$40.10

Basis_of_presentation_and_summ

Basis of presentation and summary of significant accounting policies	9 Months Ended
	Sep. 30, 2013
Basis of presentation and summary of significant accounting policies	'
Basis of presentation and summary of significant accounting policies	'
	1. Basis of presentation and summary of significant accounting policies
	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 September 30, 2013, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 3,018 megawatts ("MW") in which our aggregate ownership interest is approximately 2,098 MW. These totals exclude our 40% interest in the Delta-Person generating station ("Delta-Person") for which we entered into an agreement to sell in December 2012. Our current portfolio consists of interests in twenty-nine operational power generation projects across eleven states in the United States and two provinces in Canada. We also own Ridgeline Energy Holdings, Inc. ("Ridgeline"), a wind and solar developer in Seattle, and we own a majority interest in Rollcast Energy Inc. ("Rollcast"), a biomass power plant developer in North Carolina for which we have initiated a plan to sell our interest. Twenty-three of our projects are wholly owned subsidiaries.
	Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 Canada and our headquarters is located at One Federal Street, 30th Floor, Boston, Massachusetts 02110, USA. Our telephone number in Boston is (617) 977-2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power's website or that can be accessed through its website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website. We make available on our website, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission ("SEC"). Additionally, we make available on our website our Canadian securities filings, which are not incorporated by reference into our Exchange Act filings.
	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, 2012. 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 September 30, 2013, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2013 and 2012, and our cash flows for the nine months ended September 30, 2013 and 2012. 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, 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 valuation of shares associated with our Long-Term Incentive Plan ("LTIP") and the fair value of financial instruments and derivatives. 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, 2012. 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.
	Recently issued accounting standards
	Adopted
	In July 2012, the Financial Accounting Standards Board ("FASB") issued changes to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. These changes became effective for us for any indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes did not impact the consolidated financial statements.
	On January 1, 2012, we adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between U.S. generally accepted accounting principles ("GAAP") and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. The adoption of these changes had no impact on the consolidated financial statements.
	In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The enhanced disclosures will enable users of an entity's financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity's financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the adoption of these changes did not impact the consolidated financial statements.
	On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income. These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income. Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.
	The changes in accumulated other comprehensive loss by component were as follows:
		Three months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	(17.4	)	$	(0.1	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)	$	10.7			19.3
	Balance at end of period	$	(6.7	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(0.4	)	$	(1.5	)
	Other comprehensive income (loss):
	Net change from periodic revaluations		(0.2	)		(0.5	)
	Tax benefit		0.1			0.2
	Total Other comprehensive loss before reclassifications, net of tax		(0.1	)		(0.3	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		0.3			0.4
	Fuel commodity swaps(3)		—			(0.3	)
	Sub-total		0.3			0.1
	Tax expense(4)		(0.1	)		—
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.2			0.1
	Total Other comprehensive income (loss)		0.1			(0.2	)
	Balance at end of period		(0.3	)		(1.7	)
		Nine months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	12.7		$	(3.4	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)		(19.3	)		22.6
	Balance at end of period	$	(6.6	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(1.4	)	$	(1.4	)
	Other comprehensive loss:
	Net change from periodic revaluations		0.9			(1.4	)
	Tax (expense) benefit		(0.4	)		0.6
	Total Other comprehensive income (loss) before reclassifications, net of tax		0.5			(0.8	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		1.2			1.2
	Fuel commodity swaps(3)		(0.2	)		(0.4	)
	Sub-total		1			0.8
	Tax expense(4)		(0.4	)		(0.3	)
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.6			0.5
	Total Other comprehensive income (loss)		1.1			(0.3	)
	Balance at end of period		(0.3	)		(1.7	)
	-1
	In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings.
	-2
	This amount was included in Interest, net on the accompanying Statement of Consolidated Operations.
-3
These amounts were included in Fuel on the accompanying Statement of Consolidated Operations.
-4
These amounts were included in Income tax expense (benefit) on the accompanying Statement of Consolidated Operations.
-5
A positive amount indicates a corresponding charge to earnings and a negative amount indicates a corresponding benefit to earnings. These amounts were reflected on the accompanying Statement of Consolidated Operations in the line items indicated in footnotes 1 through 4.
Issued
In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes become effective for us on January 1, 2014. Management has determined that the adoption of these changes will not have a material impact on the consolidated financial statements.
In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.
In March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income into net income in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

Acquisitions_and_divestments

Acquisitions and divestments	9 Months Ended
	Sep. 30, 2013
Acquisitions and divestments	'
Acquisitions and divestments	'
	2. Acquisitions and divestments
	2012 Acquisitions
	(a)
	Canadian Hills
	On January 31, 2012, Atlantic Oklahoma Wind, LLC ("Atlantic OW"), a Delaware limited liability company and our wholly owned subsidiary, entered into a purchase and sale agreement with Apex Wind Energy Holdings, LLC, a Delaware limited liability company ("Apex"), pursuant to which Atlantic OW acquired a 51% interest in Canadian Hills Wind, LLC, an Oklahoma limited liability company ("Canadian Hills") for a nominal sum. Canadian Hills is the owner of a 300 MW wind energy project in the state of Oklahoma.
	On March 30, 2012, we completed the purchase of an additional 48% interest in Canadian Hills for a nominal amount, bringing our total interest in the project to 99%. Apex retained a 1% interest in the project. We also closed a $310 million non-recourse, project-level construction financing facility for the project, which included a $290 million construction loan and a $20 million 5-year letter of credit facility. In July 2012, we funded approximately $190 million of our equity contribution (net of financing costs). In December 2012, the project received tax equity investments in aggregate of $225 million from a consortium of four institutional tax equity investors along with an approximately $44 million tax equity investment of our own. The project's outstanding construction loan was repaid by the proceeds from these tax equity investments, decreasing the project's short-term debt by $265 million as of December 31, 2012. Canadian Hills has no debt at September 30, 2013. On May 2, 2013, we syndicated our $44 million tax equity investment in Canadian Hills to an institutional investor and received net cash proceeds of $42.1 million. The syndication of our interest completes the sale of 100% of Canadian Hills' $269 million of tax equity interests. The cash proceeds will be held for general corporate purposes.
	We own 99% of the project and consolidate it in our consolidated financial statements. Income attributable to the tax equity investors is classified as noncontrolling interests and is allocated utilizing the hypothetical liquidation book value method ("HLBV").
	2013 Divestments
	(a)
	Gregory
	On April 2, 2013, we and the other owners of Gregory, entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million, including working capital adjustments. The sale of Gregory closed on August 7, 2013 resulting in a gain on sale of $30.4 million that was recorded in equity in earnings of unconsolidated affiliates in the consolidated statements of operations for the three and nine months ended September 30, 2013. We received net cash proceeds for our ownership interest of approximately $34.6 million in the aggregate, after repayment of project-level debt and transaction expenses. Approximately $5 million of these proceeds will be held in escrow for up to one year after the closing date. We intend to use the net proceeds from the sale for general corporate purposes.
	(b)
	Path 15
	On March 11, 2013, we entered into a purchase and sale agreement with Duke-American Transmission Company, a joint venture between Duke Energy Corporation and American Transmission Co., to sell our interests in the Path 15 transmission line ("Path 15"). The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52.0 million, plus a management agreement termination fee of $4.0 million, for a total sale price of approximately $56.0 million. The cash proceeds will be used for general corporate purposes. All project level debt issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 was accounted for as an asset held for sale in the consolidated balance sheet at December 31, 2012 and as a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012. See Note 11, Assets held for sale and discontinued operations, for further information.
	(c)
	Auburndale, Lake and Pasco
	On January 30, 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco CoGen, Ltd. ("Pasco") projects (collectively, the "Florida Projects") for approximately $140 million, including working capital adjustments. The sale closed on April 12, 2013 and we received net cash proceeds of approximately $117 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. This includes approximately $92 million received at closing and cash distributions from the Florida Projects of approximately $25 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date. The remaining cash proceeds will be used for general corporate purposes. The Florida Projects were accounted for as assets held for sale in the consolidated balance sheets at December 31, 2012 and are a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012. See Note 11, Assets held for sale and discontinued operations, for further information.
	2012 Divestments
	(a)
	Badger Creek
	On August 2, 2012, we entered into a purchase and sale agreement for the sale of our 50% ownership interest in the Badger Creek project. On September 4, 2012, the transaction closed and we received gross proceeds of $3.7 million. As a result of the pending sale, we recorded an impairment charge in the second quarter of 2012 of $3.0 million in equity in earnings from unconsolidated affiliates in the consolidated statements of operations.
	(b)
	Primary Energy Recycling Corporation
	On February 16, 2012, we entered into an agreement with Primary Energy Recycling Corporation ("Primary Energy" or "PERC"), whereby PERC agreed to purchase our 7,462,830.33 common membership interests in Primary Energy Recycling Holdings, LLC ("PERH") (14.3% of PERH total interests) for approximately $24.2 million, plus a management agreement termination fee of approximately $6.0 million, for a total sale price of $30.2 million. The transaction closed in May 2012 and we recorded a $0.6 million gain on sale of our equity investment.

Equity_method_investments

Equity method investments	9 Months Ended
	Sep. 30, 2013
Equity method investments	'
Equity method investments	'
	3. Equity method investments
	The following summarizes the operating results for the three and nine months ended September 30, 2013 and 2012, respectively, for earnings in our equity method investments:
		Three months					Nine months
		ended					ended
		September 30,					September 30,
	(in millions)	2013			2012		2013			2012
	Project revenue
	Chambers	$	13.4		$	12.2	$	40		$	40.1
	Other		37.2			39.4		117.7			118.4
			50.6			51.6		157.7			158.5
	Project expenses
	Chambers		10.1			9.6		30.8			28.1
	Other		29.3			38.5		97.5			110.8
			39.4			48.1		128.3			138.9
	Project other income (expense)
	Chambers		(0.7	)		0.2		(1.8	)		(1.4	)
	Other		28.6			0.3		27.4			(5.8	)
			27.9			0.5		25.6			(7.2	)
	Project income
	Chambers		2.6			2.8		7.4			10.6
	Other		36.5			1.2		47.6			1.8
			39.1			4		55			12.4

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2013
Goodwill	'
Goodwill	'
	4. Goodwill
	Our goodwill balance was $296.3 million and $334.7 million as of September 30, 2013 and December 31, 2012, respectively. We recorded $331.1 million of goodwill in connection with the acquisition of Capital Power Income L.P. (the "Partnership") in 2011 and $3.5 million associated with the step-up acquisition of Rollcast in March 2010.
	We apply an accounting standard under which goodwill has an indefinite life and is not amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which discrete financial information is available. Based on a prolonged decline in our market capitalization, we determined that it was appropriate to initiate a test of goodwill to determine if the fair value of each of our reporting units' goodwill does not exceed their carrying amounts. The impairment analysis was performed as of August 31, 2013. For reporting units that failed step 1 of the goodwill impairment test, we performed a step 2 test to quantify the amount, if any, of non-cash impairment to record.
	Based on the results of our impairment analysis, it was determined that goodwill was impaired at the Kenilworth reporting unit (Northeast segment) and the Naval Station, Naval Training Center and North Island reporting units ("The Naval reporting units") (Southwest segment). The total impairment recorded in the three months ended September 30, 2013 was $34.9 million.
	The $30.8 million impairment at Kenilworth was due to lower forecasted capacity and energy prices compared to the assumptions at the time of the acquisition in November 2011. When performing our step 2 quantitative analysis, the increase in the intangible value associated with the new Energy Service Agreement ("ESA") entered into in July 2013 resulted in a lower implied goodwill value. At the time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Kenilworth project were valued assuming a merchant basis for the period subsequent to the expiration of the project's original PPA in July 2012. As discussed above, these forecasted energy revenues on a merchant basis were higher than the current forecasted energy prices subsequent to the expiration of the new ESA. The $4.1 million impairment at the Naval reporting units was primarily due to increased uncertainty, not assumed at the time of the reporting units acquisition in 2011, in our ability to extend two of the projects lease and steam agreements upon their expiration. In addition, lower currently forecasted capacity and energy prices in California after the expiration of the PPAs compared to the forecast at the time of the acquisition in 2011 result in a lower business enterprise value which resulted in a lower implied goodwill value.
	During the three months ended June 30, 2013, we recorded a $3.5 million impairment of goodwill at Rollcast which is a component of our Un-allocated corporate segment. We determined, based on the results of the two-step process, that the carrying amount of goodwill exceeded the implied fair value of goodwill. We also wrote-off $1.4 million of capitalized development costs at Rollcast related to the Greenway development project. The determination to impair goodwill and write-off the capitalized development costs was based on the reduced expectation of the Greenway project being further developed.
	The following table is a roll-forward of goodwill for the nine months ended September 30, 2013:
	(in millions)	Northeast			Northwest		Southwest			Un-allocated			Total
										corporate
	Balance at December 31, 2012	$	135.3		$	138.3	$	57.6		$	3.5		$	334.7
	Impairment of goodwill		(30.8	)		—		(4.1	)		(3.5	)		(38.4	)
	Balance at September 30, 2013	$	104.5		$	138.3	$	53.5		$	—		$	296.3

Longterm_debt

Long-term debt	9 Months Ended
	Sep. 30, 2013
Long-term debt	'
Long-term debt	'
	5. Long-term debt
	Long-term debt consists of the following:
	(in millions)	September 30,			December 31,			Interest Rate
		2013			2012
	Recourse Debt:
	Senior unsecured notes, due 2018	$	460		$	460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		203.8			211.1		6.00%
	Senior unsecured notes, due July 2014		190			190		5.90%
	Series A senior unsecured notes, due August 2015		150			150		5.90%
	Series B senior unsecured notes, due August 2017		75			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		31.2			33.5		7.40%
	Cadillac term loan, due 2025		36			37.8		6.0% – 8.0%
	Piedmont construction loan, due 2013		76.6	-1		127.4		Libor plus 3.5%
	Meadow Creek term loan, due 2024		171.4	-2		208.7		2.9% – 5.1%
	Rockland term loan, due 2027		85.8			86.5		6.40%
	Other long-term debt		1			0.3		5.5% – 6.7%
	Less: current maturities		(206.7	)		(121.2	)
	Total long-term debt	$	1,274.10		$	1,459.10
	Current maturities consist of the following:
		September 30, 2013			December 31, 2012			Interest Rate
	Current Maturities:
	Senior unsecured notes, due July 2014	$	190			—		5.90%
	Epsilon Power Partners term facility, due 2019		4.5			3		7.40%
	Cadillac term loan, due 2025		2.1			2.4		6.0% – 8.0%
	Piedmont construction loan, due 2013		4.4	-1		55.1		Libor plus 3.5%
	Meadow Creek term loan, due 2024		4.1	-2		59.5		2.9% – 5.1%
	Rockland term loan, due 2027		1.4			1.2		6.40%
	Other short-term debt		0.2			—		5.5 – 6.7%
	Total current maturities	$	206.7		$	121.2
	-1
	The terms of the Piedmont project-level debt financing include a $51.0 million bridge loan and an $82.0 million construction loan ($76.6 million at September 30, 2013) that is expected to convert to a term loan in the fourth quarter of 2013. On April 19, 2013, Piedmont achieved commercial operations and submitted an application under the 1603 federal grant program to recover approximately 30% of its capital cost. The grant application was approved and we received a $49.5 million grant from the U.S. Treasury in July 2013. Upon receipt of the grant, we repaid in full the $51.0 million bridge loan with the proceeds of the grant and a $1.5 million contribution from us to cover the shortfall resulting from the federal sequester on spending. We expect to commence the repayment of the term loan in the fourth quarter of 2013.
	-2
	Meadow Creek debt consists of $171.4 million term loan and a $56.5 million cash grant loan. The cash grant loan was repaid in April 2013 with $49.0 million of proceeds from the 1603 grant with the U.S. Treasury, $4.7 million from the former owners to cover the shortfall resulting from the federal sequester on spending and a $2.8 million contribution from us to cover the shortfall from lower grant-eligible costs than anticipated, primarily as a result of a lower project cost versus budget.
	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.
	Senior Credit Facility
	At September 30, 2013, we had a senior credit facility of $150.0 million on a senior secured basis, which was amended on August 2, 2013, as further described below (the "senior credit facility"). All $150.0 million of capacity could have been utilized for letters of credit and a sublimit of $25.0 million could have been utilized for other borrowings. At September 30, 2013, the senior credit facility was undrawn and the applicable LIBOR margin was 4.25%. At September 30, 2013, $91.2 million was issued in letters of credit, but not drawn, to support contractual credit requirements at several of our projects.
	On August 2, 2013 we entered into an amendment to our prior senior credit facility with our lenders (the "amendment"). The most significant changes to the prior senior credit facility as a result of the amendment include the following:
	•
	a decrease in capacity from $300 million to $150 million, all of which may be utilized for letters of credit (as compared to the previous $200 million that could have been utilized for letters of credit) and a sublimit of $25 million which may be utilized for other borrowings;
	•
	a requirement to cash collateralize outstanding letters of credit in an amount equal to the excess above $125 million if the aggregate amount of letters of credit and borrowings outstanding under the senior credit facility exceeds $125 million;
	•
	a requirement to maintain at all times unrestricted cash and cash equivalents of at least $75 million (inclusive of any cash collateral provided as described above), which shall be pledged to the lenders as security for the senior credit facility;
	•
	an amendment to the maximum permissible Consolidated Total Net Debt to Consolidated EBITDA (each as defined in the senior credit facility) to 7.75 to 1.00 (as compared to a prior ratio of 7.50 to 1.00 declining to 7.00 to 1.00 over time);
	•
	an amendment to the minimum permissible Consolidated EBITDA to Consolidated Interest Expense (each as defined in the senior credit facility) ratio to 1.60 to 1.00 (as compared to a prior ratio of 2.25 to 1.00);
	•
	a requirement to pay a commitment fee of between 0.75% and 1.75% per year based on a percentage of the amount committed under the senior credit facility, which fee varies based on our unsecured debt rating (at September 30, 2013, the applicable commitment fee is 1.50%); and
	•
	an amendment to the maturity date from November 4, 2015 to March 4, 2015.
	Among other restrictions set forth in the senior credit facility, we are restricted from paying cash dividends to our shareholders if we do not comply with the financial covenants specified above. The senior credit facility is secured by pledges of certain assets and interests in certain subsidiaries. The prior senior credit facility contained customary representations, warranties, terms and conditions, and covenants, certain of which were amended in connection with the amendment to the senior credit facility. The covenants in the senior credit facility limit our ability to, among other things, incur additional indebtedness, merge or consolidate with others, make acquisitions, change our business and sell or dispose of assets. These covenants also include limitations on investments, limitations on dividends and other restricted payments, limitations on entering into certain types of restrictive agreements, limitations on transactions with affiliates and limitations on the use of proceeds from the senior credit facility. Specifically, under the senior credit facility, we are effectively only permitted to make voluntary prepayments or repurchases of our outstanding debt (including for these purposes subsidiary debt guaranteed by us) from the proceeds of debt permitted to be incurred to refinance that outstanding debt or during the 60-day period preceding the maturity of that outstanding debt. Under the prior senior credit facility, we had the right generally to repurchase substantially more of our outstanding debt issuances, subject to the satisfaction of certain conditions. In the amendment, the lenders also consented to (i) our previously announced sale of Delta-Person and (ii) the sale of AP Onondaga, LLC, Onondaga Renewables, LLC and their property.
	Borrowings under the senior credit facility are available in U.S. dollars and Canadian dollars and bear interest at a variable rate equal to the US Prime Rate, the Eurocurrency LIBOR Rate or the Cdn. Prime Rate (each as defined in the senior credit facility), as applicable, plus a margin of between 2.75% and 4.75% that varies based on our unsecured debt rating. At September 30, 2013, the applicable margin for loans bearing interest at the Eurocurrency LIBOR Rate and for outstanding letters of credit was 4.25%. The foregoing summary is qualified in its entirety by reference to the senior credit facility, which was filed as an exhibit to our Current Report on Form 8-K on August 5, 2013 and is incorporated by reference as an exhibit to this Quarterly Report on Form 10-Q.

Fair_value_of_financial_instru

Fair value of financial instruments	9 Months Ended
	Sep. 30, 2013
Fair value of financial instruments	'
Fair value of financial instruments	'
	6. 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 September 30, 2013 and December 31, 2012. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
		September 30, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	170.7	$	—	$	—	$	170.7
	Restricted cash		119.8		—		—		119.8
	Derivative instruments asset		—		9.8		—		9.8
	Total	$	290.5	$	9.8	$	—	$	300.3
	Liabilities:
	Derivative instruments liability	$	—	$	119.9	$	—	$	119.9
	Total	$	—	$	119.9	$	—	$	119.9
		December 31, 2012
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	60.2	$	—	$	—	$	60.2
	Restricted cash		28.6		—		—		28.6
	Derivative instruments asset		—		20.6		—		20.6
	Total	$	88.8	$	20.6	$	—	$	109.4
	Liabilities:
	Derivative instruments liability	$	—	$	151.1	$	—	$	151.1
	Total	$	—	$	151.1	$	—	$	151.1
	The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.
	The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk free interest rate.
	We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of September 30, 2013, the credit valuation adjustments resulted in a $13.0 million net increase in fair value, which consists of a $0.6 million pre-tax gain in other comprehensive income and a $12.4 million gain in change in fair value of derivative instruments. As of December 31, 2012, the credit valuation adjustments resulted in an $18.4 million net increase in fair value, which consists of a $1.0 million pre-tax gain in other comprehensive income, a $13.8 million gain in change in fair value of derivative instruments and a $3.6 million increase related to interest rate swaps assumed in the acquisition of Ridgeline.

Derivative_instruments_and_hed

Derivative instruments and hedging activities	9 Months Ended
	Sep. 30, 2013
Derivative instruments and hedging activities	'
Derivative instruments and hedging activities	'
	7. Derivative instruments and hedging activities
	We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. For certain contracts designated as cash flow hedges, 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. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
	For derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings. The guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.
	Gas purchase agreements
	On March 12, 2012, we discontinued the application of the normal purchase normal sales ("NPNS") exemption on gas purchase agreements at our North Bay, Kapuskasing and Nipigon projects. On that date, we entered into an agreement with a third party that resulted in the gas purchase agreements no longer qualifying for the NPNS exemption. The agreements at North Bay and Kapuskasing expire on December 31, 2016. These gas purchase agreements 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.
	In May 2012, the Nipigon project entered into a long-term contract for the purchase of natural gas beginning on January 1, 2013 and expiring on December 31, 2022. This contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value at September 30, 2013 and December 31, 2012. Changes in the fair market value of the contract are recorded in the consolidated statements of operations.
	In April, June and August 2013, the Tunis project entered into contracts for the purchase of natural gas beginning on October 1, 2013 and expiring on March 31, 2014. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value as of September 30, 2013. Changes in the fair market value of the contracts are recorded in the consolidated statement of operations.
	Natural gas swaps
	Our strategy to mitigate a portion of the future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
	The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. We have entered into natural gas swaps to effectively fix the price of 3.2 million Mmbtu of future natural gas purchases, or approximately 74% of our share of the expected natural gas purchases at the project during 2014 and 2015. We also entered into natural gas swaps to effectively fix the price of 1.3 million Mmbtu of future natural gas purchases representing approximately 38% of our share of the expected natural gas purchases at the project during 2016 and 2017.
	Interest rate swaps
	Cadillac Renewable Energy, LLC ("Cadillac") has an interest rate swap agreement that effectively fixes the interest rate at 6.0% from February 16, 2011 to February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).
	Piedmont 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 November 2017, the fixed rate of the swap is 4.5% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.5% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility that will convert to a term loan. 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. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
	Epsilon Power Partners ("Epsilon") has 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 7.4% and has a maturity date of July 2019. The notional amount of the swap matches the outstanding principal balance over the remaining life of Epsilon's debt. This interest rate swap agreement is not designated as a hedge and changes in its fair market value are recorded in the consolidated statements of operations.
	Rockland Wind Farm, LLC ("Rockland") entered into interest rate swaps to manage interest rate risk exposure. These swaps effectively modify the project's exposure by converting the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap 100% of the expected interest payments from floating LIBOR to fixed rates structured in two tranches. The first tranche is for the notional amount due on the term loan commencing on December 30, 2011 and ending December 31, 2026 and fixes the interest rate at 4.2% plus an applicable margin of 2.3% - 2.8%. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2026 and ends on December 31, 2031, fixing the interest rate at 7.8%. The interest rate swap agreements are not designated as a hedge and changes in their fair market value are recorded in the consolidated statements of operations.
	The Meadow Creek project ("Meadow Creek") has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements effectively converted 75% of the floating rate debt to a fixed interest rate of 2.3% plus an applicable margin of 2.8% - 3.3% from December 31, 2012 to December 31, 2024. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2024 and ends on December 31, 2030, fixing the interest rate at 7.2%. The interest rate swaps were both executed on September 17, 2012 and expire on December 31, 2024 and December 31, 2030, respectively. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
	Foreign currency forward contracts
	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 but we pay dividends to shareholders, if and when declared by the board of directors, and interest on corporate level long-term debt and convertible debentures, predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on future payments of dividends to shareholders, if and when declared by the board of directors. We have executed this strategy utilizing cash flows from our projects that generate Canadian dollars and by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge an average of approximately 71% of any dividend and expected long-term debt and convertible debenture interest payments through 2015. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. At September 30, 2013, the forward contracts consist of contracts assumed in our acquisition of the Partnership with various expiration dates through December 2015 to purchase a total of Cdn$34.9 million at an average exchange rate of Cdn$1.108 per U.S. dollar. It is our intention to periodically consider extending or terminating these forward contracts.
	In April 2013, we terminated various foreign currency forward contracts with expiration dates through June 2015 assumed in our acquisition of the Partnership resulting in proceeds and a realized gain of $9.4 million.
	Volume of forecasted transactions
	We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption as of September 30, 2013 and December 31, 2012:
		Units		September 30,			December 31,
				2013			2012
	Natural gas swaps	Natural Gas (Mmbtu)			5.6			10.6
	Gas purchase agreements	Natural Gas (GJ)			43.9			49.8
	Interest rate swaps	Interest (US$)			164.4			172
	Foreign currency forwards	Cdn$			34.9			176.6
	Fair value of derivative instruments
	The fair value of our derivative assets and liabilities under counterparty master netting agreement are disclosed net on the consolidated balance sheets at September 30, 2013 and December 31, 2012. In the following table, 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:
		September 30, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			3.2
	Total derivative instruments designated as cash flow hedges		—			4.5
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.5
	Interest rate swaps long-term		7.9			12.6
	Foreign currency forward contracts current		0.6			0.3
	Foreign currency forward contracts long-term		1.6			—
	Natural gas swaps current		—			1.2
	Natural gas swaps long-term		—			3.9
	Gas purchase agreements current		—			22.8
	Gas purchase agreements long-term		—			67.4
	Total derivative instruments not designated as cash flow hedges		10.1			115.7
	Total derivative instruments	$	10.1		$	120.2
		December 31, 2012
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			5.2
	Total derivative instruments designated as cash flow hedges		—			6.5
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		0.1			27.7
	Foreign currency forward contracts current		9.5			—
	Foreign currency forward contracts long-term		11			—
	Natural gas swaps current		—			—
	Natural gas swaps long-term		0.1			3.9
	Gas purchase agreements current		0.1			24.5
	Gas purchase agreements long-term		—			81.4
Total derivative instruments not designated as cash flow hedges		20.8			144.8
Total derivative instruments	$	20.8		$	151.3
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:
(in millions)	Interest Rate			Natural Gas			Total
Three months ended September 30, 2013	Swaps			Swaps
Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
Change in fair value of cash flow hedges		(0.1	)		—			(0.1	)
Realized from OCI during the period		0.2			—			0.2
Accumulated OCI balance at September 30, 2013	$	(0.3	)	$	—		$	(0.3	)
(in millions)	Interest Rate			Natural Gas			Total
Three months ended September 30, 2012	Swaps			Swaps
Accumulated OCI balance at June 30, 2012	$	(1.7	)	$	0.2		$	(1.5	)
Change in fair value of cash flow hedges		(0.3	)		—			(0.3	)
Realized from OCI during the period		0.2			(0.1	)		0.1
Accumulated OCI balance at September 30, 2012	$	(1.8	)	$	0.1		$	(1.7	)
(in millions)	Interest Rate			Natural Gas			Total
Nine months ended September 30, 2013	Swaps			Swaps
Accumulated OCI balance at December 31, 2012	$	(1.5	)	$	0.1		$	(1.4	)
Change in fair value of cash flow hedges		0.5			—			0.5
Realized from OCI during the period		0.7			(0.1	)		0.6
Accumulated OCI balance at September 30, 2013	$	(0.3	)	$	—		$	(0.3	)
(in millions)	Interest Rate			Natural Gas			Total
Nine months ended September 30, 2012	Swaps			Swaps
Accumulated OCI balance at December 31, 2011	$	(1.7	)	$	0.3		$	(1.4	)
Change in fair value of cash flow hedges		(0.8	)		—			(0.8	)
Realized from OCI during the period		0.7			(0.2	)		0.5
Accumulated OCI balance at September 30, 2012	$	(1.8	)	$	0.1		$	(1.7	)
Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:
			Three months
			ended
	Classification of (gain) loss		September 30,
	recognized in income		2013			2012
Gas purchase agreements	Fuel		$	7.6		$	13.3
Foreign currency forwards	Foreign exchange gain			(1.1	)		(2.1	)
Interest rate swaps	Interest, net			2.7			1.2
			Nine months
			ended
	Classification of (gain) loss		September 30,
	recognized in income		2013			2012
Gas purchase agreements	Fuel		$	38		$	29.3
Foreign currency forwards	Foreign exchange gain			(14.4	)		(17.3	)
Interest rate swaps	Interest, net			9.4			3.4
The following table summarizes the unrealized gains and losses resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
			Three months ended
	Classification of (gain) loss		September 30,
	recognized in income		2013			2012
Natural gas swaps	Change in fair value of derivatives		$	0.6		$	(1.0	)
Gas purchase agreements	Change in fair value of derivatives			3.6			(10.0	)
Interest rate swaps	Change in fair value of derivatives			(0.7	)		0.3
Total change in fair value of derivative instruments			$	3.5		$	(10.7	)
Foreign currency forwards	Foreign exchange loss (gain)		$	(0.2	)	$	(4.7	)
			Nine months ended
	Classification of (gain) loss		September 30,
	recognized in income		2013			2012
Natural gas swaps	Change in fair value of derivatives		$	1.4		$	(0.2	)
Gas purchase agreements	Change in fair value of derivatives			(12.0	)		(49.3	)
Interest rate swaps	Change in fair value of derivatives			(22.8	)		(1.8	)
Total change in fair value of derivative instruments			$	(33.4	)	$	(51.3	)
Foreign currency forwards	Foreign exchange loss (gain)		$	18.5		$	8.2

Income_taxes

Income taxes	9 Months Ended
	Sep. 30, 2013
Income taxes	'
Income taxes	'
	8. Income taxes
	Income tax benefit from continuing operations for the nine months ended September 30, 2013 was $1.9 million. The difference between the actual tax benefit of $1.9 million and the expected income tax benefit of $7.0 million, based on the Canadian enacted statutory rate of 25%, is primarily due to a goodwill impairment of $13.7 million, a $4.5 million increase in the valuation allowance, $6.2 million in dividend withholding and preferred share taxes, and $5.2 million of changes in estimates at joint venture projects. This is partially offset by $19.4 million related to 1603 Treasury grant proceeds, $3.9 million of foreign exchange, and $1.0 million of other permanent differences.
		Three months ended					Nine months ended
		September 30,					September 30,
		2013			2012		2013			2012
	Current income tax expense	$	5.4		$	1.9	$	10.8		$	6.1
	Deferred tax (benefit) expense		(5.4	)		1.2		(12.7	)		(25.2	)
	Total income tax (benefit) expense	$	—		$	3.1	$	(1.9	)	$	(19.1	)
	As of September 30, 2013, we have recorded a valuation allowance of $122.0 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.

Employee_incentive_programs

Employee incentive programs	9 Months Ended
	Sep. 30, 2013
Employee incentive programs	'
Employee incentive programs	'
	9. Employee incentive programs
	Long-Term Incentive Program
	The following table summarizes the changes in LTIP notional units during the nine months ended September 30, 2013:
	(Units in thousands)	Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2012		492,535		$	13.88
	Granted		597,031			4.91
	Reinvested		45,344			9.12
	Forfeited		(138,473	)		8.88
	Vested		(202,696	)		13.48
	Outstanding at September 30, 2013		793,741		$	7.76
	Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies and, in some cases, Project Adjusted EBITDA per common share compared to budget. Compensation expense for notional units granted in 2013 is recorded net of estimated forfeitures. See Note 14 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2012 for further details. Cash payments made for vested notional units for the nine months ended September 30, 2013 was $0.9 million. Compensation expense for LTIP was $0.4 million and $1.7 million for the three and nine months end September 30, 2013, respectively.
	The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the following assumptions as of September 30, 2013 and December 31, 2012:
		September 30, 2013		December 31, 2012
	Weighted average risk free rate of return	0.0 – 0.5%		0.1 – 0.3%
	Dividend yield	9.00%		10.10%
	Expected volatility—Atlantic Power	42.20%		22.50%
	Expected volatility—peer companies	10.6 – 96.3%		11.9 – 97.1%
	Weighted average remaining measurement period	2.1 years		1.4 years

Basic_and_diluted_earnings_los

Basic and diluted earnings (loss) per share	9 Months Ended
	Sep. 30, 2013
Basic and diluted earnings (loss) per share	'
Basic and diluted earnings (loss) per share	'
	10. Basic and diluted earnings (loss) per share
	Basic earnings (loss) per share are calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share are computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2013. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine months ended September 30, 2013 and 2012:
		Three months ended						Nine months ended
		September 30,						September 30,
		2013			2012			2013			2012
	Numerator:
	Loss from continuing operations attributable to Atlantic Power Corporation	$	(40.9	)	$	(26.5	)	$	(31.8	)	$	(103.7	)
	Income (loss) from discontinued operations, net of tax		(0.4	)		19			(6.1	)		48.8
	Net loss attributable to Atlantic Power Corporation	$	(41.3	)	$	(7.5	)	$	(37.9	)	$	(54.9	)
	Denominator:
	Weighted average basic shares outstanding		120			119			119.8			115.4
	Dilutive potential shares:
	Convertible debentures		27.7			20.5			27.7			15.7
	LTIP notional units		0.8			0.5			0.7			0.5
	Potentially dilutive shares		148.5			140			148.2			131.6
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.34	)	$	(0.22	)	$	(0.27	)	$	(0.90	)
	Diluted earnings (loss) per share from discontinued operations		(0.00	)		0.16			(0.05	)		0.42
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.34	)	$	(0.06	)	$	(0.32	)	$	(0.48	)
	Potentially dilutive shares from convertible debentures and LTIP notional units have been excluded from fully diluted shares for the three and nine months ended September 30, 2013 and 2012 because their impact would be anti-dilutive.

Assets_held_for_sale_and_disco

Assets held for sale and discontinued operations	9 Months Ended
	Sep. 30, 2013
Assets held for sale and discontinued operations	'
Assets held for sale and discontinued operations	'
	11. Assets held for sale and discontinued operations
	During the three months ended September 30, 2013, we initiated and approved a plan to sell our 60% interest in Rollcast. Rollcast is classified as held for sale and its net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the three and nine months ended September 30, 2013 and 2012. Rollcast's loss from discontinued operations includes a $3.5 million impairment of goodwill charge and a $1.4 million impairment of intangible asset charge recorded in the three months ended June 30, 2013.
	The Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly, the projects' net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012.
	The following tables summarize the revenue, income (loss) from operations, and income tax expense of Rollcast, Path 15 and the Florida Projects for the three and nine months ended September 30, 2013 and 2012:
		Three months ended					Nine months ended
		September 30,					September 30,
	(in millions)	2013			2012		2013			2012
	Revenue	$	—		$	55.2	$	71.6		$	158.2
	Income (loss) from operations of discontinued businesses		(0.4	)		19.5		(5.3	)		49.7
	Income tax expense		—			0.5		0.8			0.9
	Income (loss) from operations of discontinued businesses, net of tax	$	(0.4	)	$	19	$	(6.1	)	$	48.8
	Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for Rollcast, the Florida Projects and Path 15 were $0.0 and $0.16 for the three month periods ended September 30, 2013 and 2012, respectively, and $(0.05) and $0.42 for the nine month periods ended September 30, 2013 and 2012, respectively.
	The assets and liabilities of these projects classified as assets held for sale in the accompanying consolidated balance sheets as of September 30, 2013 and December 31, 2012 consisted of the following:
	(in millions)	September 30, 2013			December 31, 2012
	Current assets:
	Cash and cash equivalents	$	0.3		$	6.5
	Restricted cash		—			12.6
	Accounts receivable		0.1			21.9
	Other current assets		—			6.3
			0.4			47.3
	Non-current assets:
	Plant, Property & Equipment		0.1			111.9
	Transmission system rights		—			172.4
	Goodwill		—			8.9
	Other assets		—			10.9
	Assets from discontinued operations		0.5			351.4
	Current liabilities:
	Accounts payable and other accrued liabilities	$	0.1		$	16.5
	Current portion of long-term debt		—			14.3
	Current portion of derivative instruments liability		—			20
	Other liabilities		—			0.5
			0.1			51.3
	Long-term liabilities
	Long-term debt		—			137.7
	Other long-term liabilities		—			—
	Liabilities from discontinued operations		0.1			189

Equity

Equity	9 Months Ended
	Sep. 30, 2013
Equity	'
Equity	'
	12. Equity
	The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the nine months ended September 30, 2013 and 2012:
		Nine months ended September 30, 2013
	(in millions)	Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	729.7		$	221.3		$	235.4		$	1,186.40
	Net income (loss)		(37.9	)		9.5			(3.3	)		(31.7	)
	Realized and unrealized loss on hedging activities, net of tax		1.1			—			—			1.1
	Foreign currency translation adjustment, net of tax		(19.3	)		—			—			(19.3	)
	Common shares issued for LTIP		1.2			—			—			1.2
	Contribution by and sale of noncontrolling interst		—			—			44.6			44.6
	Costs associated with tax equity raise		(0.9	)		—			—			(0.9	)
	Dividends paid to noncontrolling interest		—			—			(4.4	)		(4.4	)
	Dividends declared on common shares		(46.5	)		—			—			(46.5	)
	Dividends declared on preferred shares of a subsidiary company		—			(9.5	)		—			(9.5	)
	Balance at September 30	$	627.4		$	221.3		$	272.3		$	1,121.00
		Nine months ended September 30, 2012
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	891.5		$	221.3		$	3		$	1,115.80
	Net income (loss)		(54.9	)		9.8			(0.7	)		(45.8	)
	Realized and unrealized loss on hedging activities, net of tax		(0.3	)		—			—			(0.3	)
	Foreign currency translation adjustment, net of tax		22.6			—			—			22.6
	Common shares issuance, net of costs		67.8			—			—			67.8
	Common shares issued for LTIP		1.5			—			—			1.5
	Dividends declared on common shares		(99.0	)		—			—			(99.0	)
	Dividends declared on preferred shares of a subsidiary company		—			(9.8	)		—			(9.8	)
	Balance at September 30	$	829.2		$	221.3		$	2.3		$	1,052.80

Segment_and_geographic_informa

Segment and geographic information	9 Months Ended
	Sep. 30, 2013
Segment and geographic information	'
Segment and geographic information	'
	13. Segment and geographic information
	Our operating segments are Northeast, Northwest, Southeast, Southwest and Un-allocated Corporate. The segment classified as Un-allocated Corporate includes activities that support the executive offices, capital structure and costs of being a public registrant in the United States and Canada. Un-allocated Corporate also includes Rollcast, a 60% owned company, which develops, owns and operates renewable power plants that use wood or biomass fuel, and for which we initiated and approved a plan to sell, and Ridgeline, which develops and operates wind and solar power projects. These costs are not allocated to the operating segments when determining segment profit or loss.
	We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income 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. Rollcast, a component of the Un-allocated Corporate segment, Path 15, a component of the Southwest segment, and the Florida projects, which are components of the Southeast segment, are included in the income from discontinued operations line item in the table below. We have adjusted prior periods to reflect this reclassification. A reconciliation of project income to Project Adjusted EBITDA is included in the tables below.
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Three months ended September 30, 2013
	Project revenues	$	47.3		$	10.6		$	23.5		$	61		$	(0.6	)	$	141.8
	Segment assets		1,134.80			177.4			1,113.30			913.9			157.3			3,496.70
	Project Adjusted EBITDA	$	24.9		$	5.9		$	19.4		$	29.5		$	(3.5	)		76.2
	Change in fair value of derivative instruments		3.5			0.5			(0.5	)		—			—			3.5
	Depreciation and amortization		17.8			3.4			15.1			14.9			0.2			51.4
	Interest, net		4.1			1.4			4.8			0.4			(0.1	)		10.6
	Other project (income) expense		31.4			—			—			(26.3	)		0.8			5.9
	Project income (loss)		(31.9	)		0.6			(0.0	)		40.5			(4.4	)		4.8
	Administration		—			—			—			—			8.4			8.4
	Interest, net		—			—			—			—			27.5			27.5
	Foreign exchange gain		—			—			—			—			9.1			9.1
	Other expense, net		—			—			—			—			—			—
	Income (loss) from continuing operations before income taxes		(31.9	)		0.6			(0.0	)		40.5			(49.4	)		(40.2	)
	Income tax expense		—			—			—			—			—			—
	Net income (loss) from continuing operations		(31.9	)		0.6			(0.0	)		40.5			(49.4	)		(40.2	)
	Income (loss) from discontinued operations		—			—			—			—			(0.4	)		(0.4	)
	Net income (loss)	$	(31.9	)	$	0.6		$	(0.0	)	$	40.5		$	(49.8	)	$	(40.6	)
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Three months ended September 30, 2012
	Project revenues	$	43.8		$	—		$	15		$	47.7		$	(0.2	)	$	106.3
	Segment assets		1,157.90			446.3			852			1,162.60			25.2			3,644.00
	Project Adjusted EBITDA	$	20.3		$	2.3		$	12.6		$	23.4		$	(1.2	)		57.4
	Change in fair value of derivative instruments		(10.2	)		(0.6	)		—			—			—			(10.8	)
	Depreciation and amortization		20.4			1.4			10.7			9.3			—			41.8
	Interest, net		4.5			—			1.2			0.1			—			5.8
	Other project (income) expense		0.3			—			—			0.2			0.4			0.9
	Project income (loss)		5.3			1.5			0.7			13.8			(1.6	)		19.7
	Administration		—			—			—			—			6.3			6.3
	Interest, net		—			—			—			—			25.8			25.8
	Foreign exchange loss		—			—			—			—			7.7			7.7
	Other expense, net		—			—			—			—			0.3			0.3
	Income (loss) from continuing operations before income taxes		5.3			1.5			0.7			13.8			(41.7	)		(20.4	)
	Income tax expense		—			—			—			—			3.1			3.1
	Net income (loss) from continuing operations		5.3			1.5			0.7			13.8			(44.8	)		(23.5	)
	Income (loss) from discontinued operations		—			19.3			—			0.8			(1.1	)		19
	Net income (loss)	$	5.3		$	20.8		$	0.7		$	14.6		$	(45.9	)	$	(4.5	)
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Nine months ended September 30, 2013
	Project revenues	$	167.9		$	16.8		$	69.5		$	167.7		$	(0.9	)	$	421
	Segment assets		1,134.80			177.4			1,113.30			913.9			157.3			3,496.70
	Project Adjusted EBITDA	$	96.8		$	10.4		$	53		$	64.5		$	(11.4	)		213.3
	Change in fair value of derivative instruments		(12.9	)		(3.1	)		(18.8	)		—			—			(34.8	)
	Depreciation and amortization		55.7			7.9			45.7			44.7			0.5			154.5
	Interest, net		12.8			2.6			14.2			0.9			—			30.5
	Other project (income) expense		32.3			0.1			—			(26.6	)		—			5.8
	Project income (loss)		8.9			2.9			11.9			45.5			(11.9	)		57.3
	Administration		—			—			—			—			28.5			28.5
	Interest, net		—			—			—			—			78.7			78.7
	Foreign exchange gain		—			—			—			—			(12.9	)		(12.9	)
	Other expense, net		—			—			—			—			(9.5	)		(9.5	)
	Income (loss) from continuing operations before income taxes		8.9			2.9			11.9			45.5			(96.7	)		(27.5	)
	Income tax benefit		—			—			—			—			(1.9	)		(1.9	)
	Net income (loss) from continuing operations		8.9			2.9			11.9			45.5			(94.8	)		(25.6	)
	Income (loss) from discontinued operations		—			(1.1	)		—			1.3			(6.3	)		(6.1	)
	Net income (loss)	$	8.9		$	1.8		$	11.9		$	46.8		$	(101.1	)	$	(31.7	)
	Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
													Corporate
Nine months ended September 30, 2012
Project revenues	$	156.6		$	—		$	46.9		$	121.7		$	1.2		$	326.4
Segment assets		1,157.90			446.3			852			1,162.60			25.2			3,644.00
Project Adjusted EBITDA	$	85.2		$	6.5		$	38.5		$	48		$	(7.5	)		170.7
Change in fair value of derivative instruments		46.3			2.6			—			—			—			48.9
Depreciation and amortization		58			4.3			31.7			28.9			0.1			123
Interest, net		13.9			—			3.8			0.4			—			18.1
Other project (income) expense		0.8			—			—			2.9			0.7			4.4
Project income (loss)		(33.8	)		(0.4	)		3			15.8			(8.3	)		(23.7	)
Administration		—			—			—			—			22			22
Interest, net		—			—			—			—			69.3			69.3
Foreign exchange loss		—			—			—			—			4.4			4.4
Other expense, net		—			—			—			—			(5.7	)		(5.7	)
Income (loss) from continuing operations before income taxes		(33.8	)		(0.4	)		3			15.8			(98.3	)		(113.7	)
Income tax expense		—			—			—			—			(19.1	)		(19.1	)
Net income (loss) from continuing operations		(33.8	)		(0.4	)		3			15.8			(79.2	)		(94.6	)
Income (loss) from discontinued operations		—			49.5			—			1.5			(2.2	)		48.8
Net income (loss)	$	(33.8	)	$	49.1		$	3		$	17.3		$	(81.4	)	$	(45.8	)
The tables below provide information, by country, about our consolidated operations. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
													Property, Plant and
													Equipment, net of
	Project Revenue						Project Revenue						accumulated depreciation
	Three months ended						Nine months ended
	September 30,						September 30,						September 30,			December 31,
	2013			2012			2013			2012			2013			2012
United States	$	98		$	61		$	264.7		$	171.9		$	1,368.00		$	1,504.80
Canada		43.8			45.3			156.3			154.5			505.9			550.7
Total	$	141.8		$	106.3		$	421		$	326.4		$	1,873.90		$	2,055.50
The Ontario Electricity Financial Corp ("OEFC"), British Columbia Hydro and Power Authority ("BC Hydro"), San Diego Gas & Electric ("SD G&E") provided for approximately 20.7%, 10.2%, and 13.1% respectively, of total consolidated revenues for the three months ended September 30, 2013 and 26.3%, 10.8%, and 10.2% respectively, of total consolidated revenues for the nine months ended September 30, 2013. OEFC and BC Hydro provided for approximately 18.7% and 9.2%, respectively, of total consolidated revenues for the three months ended September 30, 2012 and 22.1% and 9.7% respectively, of total consolidated revenues for the nine months ended September 30, 2012. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the Northeast segment, BC Hydro purchases electricity from the Mamquam, Moresby Lake and Williams Lake projects in the Northwest segment, and SD G&E purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the Southwest segment.

Commitments_and_contingencies

Commitments and contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and contingencies.	'
Commitments and contingencies	'
	14. Commitments and contingencies
	We are party to numerous legal proceedings, including securities class actions, from time to time. In particular, we and/or certain of our current and former officers have been named as defendants in various class action lawsuits. Due to the nature of these proceedings, the lack of precise damage claims and the type of claims we are subject to, we are unable to determine the ultimate or maximum amount of monetary liability or financial impact, if any, to us in these legal matters, which unless otherwise specified, seek damages from the defendants of material or indeterminate amounts.
	Shareholder class action lawsuits
	Massachusetts District Court Actions
	On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our President and Chief Executive Officer and a Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Individual Defendants," and together with Atlantic Power, the "Defendants") (the "U.S. Actions").
	The District Court complaints differ in terms of the identities of the Individual Defendants they name, as noted above, the named plaintiffs, and the purported class period they allege (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 alleges, 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 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 Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.
	The parties to each District Court action have 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 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 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, which the Court will consider (along with the motion papers discussed above) in deciding who will serve as lead plaintiff and lead counsel.
	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 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 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. This claim names the Company, Barry Welch and Terrence Ronan as defendants (the "Defendants"). The Plaintiffs seeks leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserts common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased and held securities through a proposed class period of November 5, 2012 to February 28, 2013.
	On October 4, 2013 the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the statutory and common claims as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.
	A schedule for the Plaintiffs' motions and the action will be set on November 12, 2013.
	The Petitioner in the proposed Quebec class action has served and filed a motion to suspend those proceedings until a decision is made on certification of the Ontario action as a class proceeding. This motion will not be contested.
	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 each of the actions.
	Other
	Other than as described above, there were no material changes to legal proceedings disclosed in "Item 3. Legal Proceedings" of our Annual Report on Form 10-K for the year ended December 31, 2012.
	In addition to the 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. With respect to such other matters arising in the normal course of business, 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 September 30, 2013.

Guarantees_and_condensed_conso

Guarantees and condensed consolidating financial information	9 Months Ended
	Sep. 30, 2013
Guarantees and condensed consolidating financial information	'
Guarantees and condensed consolidating financial information	'
	15. Guarantees and condensed consolidating financial information
	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.
	We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for certain tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.
	As of September 30, 2013 and December 31, 2012, we had $460.0 million of Senior Notes. These notes are guaranteed by certain of our wholly owned subsidiaries, or guarantor subsidiaries. These guarantees are joint and several.
	Unless otherwise noted below, each of the following 100% owned guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2013:
	Atlantic Power Limited Partnership, Atlantic Power GP Inc., Atlantic Power (US) GP, Atlantic Oklahoma Wind LLC, Atlantic Power Corporation, Atlantic Power Generation, Inc., Atlantic Power Transmission, Inc., Atlantic Power Holdings, Inc.,. Atlantic Power Services Canada GP Inc., Atlantic Power Services Canada LP, Atlantic Power Services, LLC, Atlantic Rockland Holdings, LLC, Teton Power Funding, LLC, Harbor Capital Holdings, LLC, Epsilon Power Funding, LLC, Atlantic Cadillac Holdings, LLC, Atlantic Idaho Wind Holdings, LLC, Atlantic Idaho Wind C, LLC, Baker Lake Hydro, LLC, Olympia Hydro, LLC, Teton East Coast Generation, LLC, Atlantic Renewables Holdings, LLC, Orlando Power Generation I, LLC, Orlando Power Generation II, LLC, Atlantic Piedmont Holdings LLC, Teton Selkirk, LLC, Teton Operating Services, LLC, Atlantic Ridgeline Holdings, LLC, Ridgeline Energy Holdings, Inc., Ridgeline Energy LLC, Pah Rah Holding Company LLC, Lewis Ranch Wind Project LLC, Hurricane Wind LLC, Ridgeline Power Services LLC, Ridgeline Eastern Energy LLC, Ridgeline Alternative Energy LLC, Frontier Solar LLC, Ridgeline Energy Solar LLC, Pah Rah Project Company LLC, Monticello Hills Wind LLC, Dry Lots Wind LLC, Smokey Avenue Wind LLC, Saunders Bros. Transportation Corporation, Bruce Hill Wind LLC, South Mountain Wind LLC, Great Basin Solar Ranch LLC, Goshen Wind Holdings LLC, Meadow Creek Holdings LLC, Ridgeline Holdings Junior Inc., Rockland Wind Ridgeline Holdings LLC and Meadow Creek Intermediate Holdings LLC.
	The following condensed consolidating financial information presents the financial information of Atlantic Power, the guarantor subsidiaries, and Curtis Palmer, LLC ("Curtis Palmer") (our non-guarantor subsidiary) in accordance with Rule 3-10 under the SEC's Regulation S-X. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or Curtis Palmer operated as independent entities.
	In this presentation, Atlantic Power consists of parent company operations. Guarantor subsidiaries of Atlantic Power are reported on a combined basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING BALANCE SHEET
	September 30, 2013
	(in millions of U.S. dollars)
	(Unaudited)
		Guarantor			Curtis			Atlantic			Eliminations			Consolidated
		Subsidiaries			Palmer			Power						Balance
	Assets
	Current assets:
	Cash and cash equivalents	$	163.5		$	—		$	7.2		$	—		$	170.7
	Restricted cash		119.8			—			—			—			119.8
	Accounts receivable		165.9			10.9			2.8			(116.3	)		63.3
	Prepayments, supplies, and other current assets		32.2			2.3			0.8			(1.0	)		34.3
	Total current assets		481.4			13.2			10.8			(117.3	)		388.1
	Property, plant, and equipment, net		1,702.70			172.5			—			(1.3	)		1,873.90
	Equity investments in unconsolidated affiliates		3,753.90			—			963.7			(4,313.1	)		404.5
	Other intangible assets, net		321.5			149.6			—			—			471.1
	Goodwill		238.1			58.2			—			—			296.3
	Other assets		473.7			—			434.3			(845.2	)		62.8
	Total assets	$	6,971.30		$	393.5		$	1,408.80		$	(5,276.9	)	$	3,496.70
	Liabilities
	Current liabilities:
	Accounts payable and accrued liabilities	$	118.6		$	3.9		$	83.9		$	(116.3	)	$	90.1
	Revolving credit facility		—			—			—			—			—
	Current portion of long-term debt		16.7			190			—			—			206.7
	Other current liabilities		40			—			3.9			(1.0	)		42.9
	Total current liabilities		175.3			193.9			87.8			(117.3	)		339.7
	Long-term debt		814.1			—			460			—			1,274.10
	Convertible debentures		—			—			414.1			—			414.1
	Other non-current liabilities		1,184.00			8.5			0.5			(845.2	)		347.8
	Total liabilities		2,173.40			202.4			962.4			(962.5	)		2,375.70
	Equity
	Preferred shares issued by a subsidiary company		232.1			—			—			(10.8	)		221.3
	Common shares		4,323.50			191.1			1,285.80			(4,514.7	)		1,285.70
	Accumulated other comprehensive loss		(8.7	)		—			—			—			(8.7	)
	Retained deficit		(21.3	)		—			(839.4	)		211.1			(649.6	)
	Total Atlantic Power Corporation shareholders' equity		4,525.60			191.1			446.4			(4,314.4	)		848.7
	Noncontrolling interest		272.3			—			—			—			272.3
	Total equity		4,797.90			191.1			446.4			(4,314.4	)		1,121.00
	Total liabilities and equity	$	6,971.30		$	393.5		$	1,408.80		$	(5,276.9	)	$	3,496.70
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	Three months ended September 30, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
		Subsidiaries						Power						Balance
	Project revenue:
	Total project revenue	$	134.2		$	7.8		$	—		$	(0.2	)	$	141.8
	Project expenses:
	Fuel		47.2			—			—			—			47.2
	Project operations and maintenance		36.8			1.3			—			(0.1	)		38
	Development		1.4			—			—			—			1.4
	Depreciation and amortization		38.4			3.8			—			—			42.2
			123.8			5.1			—			(0.1	)		128.8
	Project other income (expense):
Change in fair value of derivative instruments		(3.5	)		—			—			—			(3.5	)
Equity in earnings of unconsolidated affiliates		39.1			—			—			—			39.1
Interest expense, net		(6.3	)		(2.7	)		—			—			(9.0	)
Other		(34.8	)		—			—			—			(34.8	)
		(5.5	)		(2.7	)		—			—			(8.2	)
Project income		4.9			—			—			(0.1	)		4.8
Administrative and other expenses (income):
Administration expense		4.9			—			3.5			—			8.4
Interest, net		18.9			—			8.6			—			27.5
Foreign exchange loss		4.1			—			5			—			9.1
Other income		—			—			—			—			—
		27.9			—			17.1			—			45
Loss from continuing operations before income taxes		(23.0	)		—			(17.1	)		(0.1	)		(40.2	)
Income tax benefit		—			—			—			—			—
Net loss from continuing operations		(23.0	)		—			(17.1	)		(0.1	)		(40.2	)
Net loss from discontinued operations		(0.4	)		—			—			—			(0.4	)
Net loss		(23.4	)		—			(17.1	)		(0.1	)		(40.6	)
Net income (loss) attributable to noncontrolling interest		(2.5	)		—			—			3.2			0.7
Net loss attributable to Atlantic Power Corporation	$	(20.9	)	$	—		$	(17.1	)	$	(3.3	)	$	(41.3	)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Nine months ended September 30, 2013
(in millions of U.S. dollars)
	Guarantor			Curtis			Atlantic			Eliminations			Consolidated
	Subsidiaries			Palmer			Power						Balance
Project revenue:
Total project revenue	$	394.1		$	27.4		$	—		$	(0.5	)	$	421
Project expenses:
Fuel		148.8			—			—			—			148.8
Project operations and maintenance		110			2.2			0.5			(0.4	)		112.3
Development		4.9			—			—			—			4.9
Depreciation and amortization		114.2			11.5			—			—			125.7
		377.9			13.7			0.5			(0.4	)		391.7
Project other income (expense):
Change in fair value of derivative instruments		33.4			—			—			—			33.4
Equity in earnings of unconsolidated affiliates		55			—			—			—			55
Interest expense, net		(17.4	)		(8.3	)		—			—			(25.7	)
Other		(35.0	)		—			0.3			—			(34.7	)
		36			(8.3	)		0.3			—			28
Project income		52.2			5.4			(0.2	)		(0.1	)		57.3
Administrative and other expenses (income):
Administration expense		15.3			—			13.2			—			28.5
Interest, net		57.1			—			21.6			—			78.7
Foreign exchange loss		(3.9	)		—			(9.0	)		—			(12.9	)
Other income		(9.5	)		—			—						(9.5	)
		59			—			25.8			—			84.8
Income (loss) from continuing operations before income taxes		(6.8	)		5.4			(26.0	)		(0.1	)		(27.5	)
Income tax benefit		(1.9	)		—			—			—			(1.9	)
Net income (loss) from continuing operations		(4.9	)		5.4			(26.0	)		(0.1	)		(25.6	)
Net loss from discontinued operations		(6.1	)		—			—			—			(6.1	)
Net income (loss)		(11.0	)		5.4			(26.0	)		(0.1	)		(31.7	)
Net income (loss) attributable to noncontrolling interest		(3.3	)		—			—			9.5			6.2
Net income (loss) attributable to Atlantic Power Corporation	$	(7.7	)	$	5.4		$	(26.0	)	$	(9.6	)	$	(37.9	)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME
Three and nine months ended September 30, 2013
(in millions of U.S. dollars)
	Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
	Subsidiaries						Power						Balance
Net loss	$	(23.4	)	$	—		$	(17.1	)	$	(0.1	)	$	(40.6	)
Other comprehensive income (loss):
Unrealized gain on hedging activities		(0.1	)		—			—			—			(0.1	)
Net amount reclassified to earnings		0.2			—			—			—			0.2
Net unrealized losses on derivatives		0.1			—			—			—			0.1
Foreign currency translation adjustments		10.7			—			—			—			10.7
Other comprehensive income, net of tax		10.8			—			—			—			10.8
Comprehensive loss		(12.6	)		—			(17.1	)		(0.1	)		(29.8	)
Less: Comprehensive income attributable to noncontrolling interest		0.7			—			—			—			0.7
Comprehensive loss attributable to Atlantic Power Corporation	$	(13.3	)	$	—		$	(17.1	)	$	(0.1	)	$	(30.5	)
	Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
	Subsidiaries						Power						Balance
Net income (loss)	$	(11.0	)	$	5.4		$	(26.0	)	$	(0.1	)	$	(31.7	)
Other comprehensive income (loss):
Unrealized gain on hedging activities		0.5			—			—			—			0.5
Net amount reclassified to earnings		0.6			—			—			—			0.6
Net unrealized losses on derivatives		1.1			—			—			—			1.1
Foreign currency translation adjustments		(19.3	)		—			—			—			(19.3	)
Other comprehensive income, net of tax		(18.2	)		—			—			—			(18.2	)
Comprehensive income (loss)		(29.2	)		5.4			(26.0	)		(0.1	)		(49.9	)
Less: Comprehensive income attributable to noncontrolling interest		6.2			—			—			—			6.2
Comprehensive income (loss) attributable to Atlantic Power Corporation	$	(35.4	)	$	5.4		$	(26.0	)	$	(0.1	)	$	(56.1	)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Nine months ended September 30, 2013
(in millions of U.S. dollars)
	Guarantor			Curtis			Atlantic			Eliminations			Consolidated
	Subsidiaries			Palmer			Power						Balance
Net cash provided by operating activities	$	69.8		$	2.4		$	71.1		$	—		$	143.3
Cash flows provided by (used in) investing activities:
Proceeds from treasury grant		103.2			—			—			—			103.2
Proceeds for sale of assets		183			—			—			—			183
Cash (paid) received for equity investments		8.5			—			(8.5	)		—			—
Change in restricted cash		(99.1	)		—			—			—			(99.1	)
Biomass development costs		(0.1	)		—			—			—			(0.1	)
Construction in progress		(32.2	)		—			—			—			(32.2	)
Purchase of property, plant and equipment		(4.8	)		(2.4	)		—			—			(7.2	)
Net cash provided by (used in) investing activities		158.5			(2.4	)		(8.5	)		—			147.6
Cash flows provided by (used in) financing activities:
Offering costs related to tax equity		(1.0	)		—			—			—			(1.0	)
Repayment of project-level debt		(115.3	)		—			—			—			(115.3	)
Proceeds from project-level debt		20.8			—			—			—			20.8
Payments for revolving credit facility borrowings		(47.0	)		—			(20.0	)		—			(67.0	)
Equity investment from noncontrolling interest		42.6			—			1.9			—			44.5
Deferred financing costs		(0.5	)		—			—			—			(0.5	)
Dividends paid		(13.9	)		—			(54.2	)		—			(68.1	)
Net cash used in financing activities		(114.3	)		—			(72.3	)		—			(186.6	)
Net increase (decrease) in cash and cash equivalents		114			—			(9.7	)		—			104.3
Cash and cash equivalents at beginning of period		49.5			—			16.9			—			66.4
Cash and cash equivalents at end of period	$	163.5		$	—		$	7.2		$	—		$	170.7

Basis_of_presentation_and_summ1

Basis of presentation and summary of significant accounting policies (Policies)	9 Months Ended
	Sep. 30, 2013
Basis of presentation and summary of significant accounting policies	'
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, 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 valuation of shares associated with our Long-Term Incentive Plan ("LTIP") and the fair value of financial instruments and derivatives. 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, 2012. 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.
Recently issued accounting standards	'
	Recently issued accounting standards
	Adopted
	In July 2012, the Financial Accounting Standards Board ("FASB") issued changes to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. These changes became effective for us for any indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes did not impact the consolidated financial statements.
	On January 1, 2012, we adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between U.S. generally accepted accounting principles ("GAAP") and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. The adoption of these changes had no impact on the consolidated financial statements.
	In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The enhanced disclosures will enable users of an entity's financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity's financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the adoption of these changes did not impact the consolidated financial statements.
	On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income. These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income. Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.
	The changes in accumulated other comprehensive loss by component were as follows:
		Three months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	(17.4	)	$	(0.1	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)	$	10.7			19.3
	Balance at end of period	$	(6.7	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(0.4	)	$	(1.5	)
	Other comprehensive income (loss):
	Net change from periodic revaluations		(0.2	)		(0.5	)
	Tax benefit		0.1			0.2
	Total Other comprehensive loss before reclassifications, net of tax		(0.1	)		(0.3	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		0.3			0.4
	Fuel commodity swaps(3)		—			(0.3	)
	Sub-total		0.3			0.1
	Tax expense(4)		(0.1	)		—
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.2			0.1
	Total Other comprehensive income (loss)		0.1			(0.2	)
	Balance at end of period		(0.3	)		(1.7	)
		Nine months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	12.7		$	(3.4	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)		(19.3	)		22.6
	Balance at end of period	$	(6.6	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(1.4	)	$	(1.4	)
	Other comprehensive loss:
	Net change from periodic revaluations		0.9			(1.4	)
	Tax (expense) benefit		(0.4	)		0.6
	Total Other comprehensive income (loss) before reclassifications, net of tax		0.5			(0.8	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		1.2			1.2
	Fuel commodity swaps(3)		(0.2	)		(0.4	)
	Sub-total		1			0.8
	Tax expense(4)		(0.4	)		(0.3	)
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.6			0.5
	Total Other comprehensive income (loss)		1.1			(0.3	)
	Balance at end of period		(0.3	)		(1.7	)
	-1
	In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings.
	-2
	This amount was included in Interest, net on the accompanying Statement of Consolidated Operations.
	-3
	These amounts were included in Fuel on the accompanying Statement of Consolidated Operations.
	-4
	These amounts were included in Income tax expense (benefit) on the accompanying Statement of Consolidated Operations.
	-5
	A positive amount indicates a corresponding charge to earnings and a negative amount indicates a corresponding benefit to earnings. These amounts were reflected on the accompanying Statement of Consolidated Operations in the line items indicated in footnotes 1 through 4.
	Issued
	In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes become effective for us on January 1, 2014. Management has determined that the adoption of these changes will not have a material impact on the consolidated financial statements.
In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.
In March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income into net income in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

Basis_of_presentation_and_summ2

Basis of presentation and summary of significant accounting policies (Tables)	9 Months Ended
	Sep. 30, 2013
Basis of presentation and summary of significant accounting policies	'
Schedule of changes in accumulated other comprehensive loss by component	'
		Three months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	(17.4	)	$	(0.1	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)	$	10.7			19.3
	Balance at end of period	$	(6.7	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(0.4	)	$	(1.5	)
	Other comprehensive income (loss):
	Net change from periodic revaluations		(0.2	)		(0.5	)
	Tax benefit		0.1			0.2
	Total Other comprehensive loss before reclassifications, net of tax		(0.1	)		(0.3	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		0.3			0.4
	Fuel commodity swaps(3)		—			(0.3	)
	Sub-total		0.3			0.1
	Tax expense(4)		(0.1	)		—
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.2			0.1
	Total Other comprehensive income (loss)		0.1			(0.2	)
	Balance at end of period		(0.3	)		(1.7	)
		Nine months ended
		September 30,
		2013			2012
	Foreign currency translation
	Balance at beginning of period	$	12.7		$	(3.4	)
	Other comprehensive loss:
	Foreign currency translation adjustments(1)		(19.3	)		22.6
	Balance at end of period	$	(6.6	)	$	19.2
	Cash flow hedges
	Balance at beginning of period	$	(1.4	)	$	(1.4	)
	Other comprehensive loss:
	Net change from periodic revaluations		0.9			(1.4	)
	Tax (expense) benefit		(0.4	)		0.6
	Total Other comprehensive income (loss) before reclassifications, net of tax		0.5			(0.8	)
	Net amount reclassified to earnings:
	Interest rate swaps(2)		1.2			1.2
	Fuel commodity swaps(3)		(0.2	)		(0.4	)
	Sub-total		1			0.8
	Tax expense(4)		(0.4	)		(0.3	)
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		0.6			0.5
	Total Other comprehensive income (loss)		1.1			(0.3	)
	Balance at end of period		(0.3	)		(1.7	)
	-1
	In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings.
	-2
	This amount was included in Interest, net on the accompanying Statement of Consolidated Operations.
	-3
	These amounts were included in Fuel on the accompanying Statement of Consolidated Operations.
	-4
	These amounts were included in Income tax expense (benefit) on the accompanying Statement of Consolidated Operations.
	-5
	A positive amount indicates a corresponding charge to earnings and a negative amount indicates a corresponding benefit to earnings. These amounts were reflected on the accompanying Statement of Consolidated Operations in the line items indicated in footnotes 1 through 4.

Equity_method_investments_Tabl

Equity method investments (Tables)	9 Months Ended
	Sep. 30, 2013
Equity method investments	'
Summarized operating results information	'
		Three months					Nine months
		ended					ended
		September 30,					September 30,
	(in millions)	2013			2012		2013			2012
	Project revenue
	Chambers	$	13.4		$	12.2	$	40		$	40.1
	Other		37.2			39.4		117.7			118.4
			50.6			51.6		157.7			158.5
	Project expenses
	Chambers		10.1			9.6		30.8			28.1
	Other		29.3			38.5		97.5			110.8
			39.4			48.1		128.3			138.9
	Project other income (expense)
	Chambers		(0.7	)		0.2		(1.8	)		(1.4	)
	Other		28.6			0.3		27.4			(5.8	)
			27.9			0.5		25.6			(7.2	)
	Project income
	Chambers		2.6			2.8		7.4			10.6
	Other		36.5			1.2		47.6			1.8
			39.1			4		55			12.4

Goodwill_Tables

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2013
Goodwill	'
Schedule of goodwill	'
	(in millions)	Northeast			Northwest		Southwest			Un-allocated			Total
										corporate
	Balance at December 31, 2012	$	135.3		$	138.3	$	57.6		$	3.5		$	334.7
	Impairment of goodwill		(30.8	)		—		(4.1	)		(3.5	)		(38.4	)
	Balance at September 30, 2013	$	104.5		$	138.3	$	53.5		$	—		$	296.3

Longterm_debt_Tables

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2013
Long-term debt	'
Schedule of long-term debt	'
	(in millions)	September 30,			December 31,			Interest Rate
		2013			2012
	Recourse Debt:
	Senior unsecured notes, due 2018	$	460		$	460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		203.8			211.1		6.00%
	Senior unsecured notes, due July 2014		190			190		5.90%
	Series A senior unsecured notes, due August 2015		150			150		5.90%
	Series B senior unsecured notes, due August 2017		75			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		31.2			33.5		7.40%
	Cadillac term loan, due 2025		36			37.8		6.0% – 8.0%
	Piedmont construction loan, due 2013		76.6	-1		127.4		Libor plus 3.5%
	Meadow Creek term loan, due 2024		171.4	-2		208.7		2.9% – 5.1%
	Rockland term loan, due 2027		85.8			86.5		6.40%
	Other long-term debt		1			0.3		5.5% – 6.7%
	Less: current maturities		(206.7	)		(121.2	)
	Total long-term debt	$	1,274.10		$	1,459.10
Schedule of current maturities	'
		September 30, 2013			December 31, 2012			Interest Rate
	Current Maturities:
	Senior unsecured notes, due July 2014	$	190			—		5.90%
	Epsilon Power Partners term facility, due 2019		4.5			3		7.40%
	Cadillac term loan, due 2025		2.1			2.4		6.0% – 8.0%
	Piedmont construction loan, due 2013		4.4	-1		55.1		Libor plus 3.5%
	Meadow Creek term loan, due 2024		4.1	-2		59.5		2.9% – 5.1%
	Rockland term loan, due 2027		1.4			1.2		6.40%
	Other short-term debt		0.2			—		5.5 – 6.7%
	Total current maturities	$	206.7		$	121.2
	-1
	The terms of the Piedmont project-level debt financing include a $51.0 million bridge loan and an $82.0 million construction loan ($76.6 million at September 30, 2013) that is expected to convert to a term loan in the fourth quarter of 2013. On April 19, 2013, Piedmont achieved commercial operations and submitted an application under the 1603 federal grant program to recover approximately 30% of its capital cost. The grant application was approved and we received a $49.5 million grant from the U.S. Treasury in July 2013. Upon receipt of the grant, we repaid in full the $51.0 million bridge loan with the proceeds of the grant and a $1.5 million contribution from us to cover the shortfall resulting from the federal sequester on spending. We expect to commence the repayment of the term loan in the fourth quarter of 2013.
	-2
	Meadow Creek debt consists of $171.4 million term loan and a $56.5 million cash grant loan. The cash grant loan was repaid in April 2013 with $49.0 million of proceeds from the 1603 grant with the U.S. Treasury, $4.7 million from the former owners to cover the shortfall resulting from the federal sequester on spending and a $2.8 million contribution from us to cover the shortfall from lower grant-eligible costs than anticipated, primarily as a result of a lower project cost versus budget.

Fair_value_of_financial_instru1

Fair value of financial instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Fair value of financial instruments	'
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	'
		September 30, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	170.7	$	—	$	—	$	170.7
	Restricted cash		119.8		—		—		119.8
	Derivative instruments asset		—		9.8		—		9.8
	Total	$	290.5	$	9.8	$	—	$	300.3
	Liabilities:
	Derivative instruments liability	$	—	$	119.9	$	—	$	119.9
	Total	$	—	$	119.9	$	—	$	119.9
		December 31, 2012
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	60.2	$	—	$	—	$	60.2
	Restricted cash		28.6		—		—		28.6
	Derivative instruments asset		—		20.6		—		20.6
	Total	$	88.8	$	20.6	$	—	$	109.4
	Liabilities:
	Derivative instruments liability	$	—	$	151.1	$	—	$	151.1
	Total	$	—	$	151.1	$	—	$	151.1

Derivative_instruments_and_hed1

Derivative instruments and hedging activities (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative instruments and hedging activities	'
Schedule of notional volumes of forecasted transactions	'
		Units		September 30,			December 31,
				2013			2012
	Natural gas swaps	Natural Gas (Mmbtu)			5.6			10.6
	Gas purchase agreements	Natural Gas (GJ)			43.9			49.8
	Interest rate swaps	Interest (US$)			164.4			172
	Foreign currency forwards	Cdn$			34.9			176.6
Schedule of fair value of derivative instruments	'
		September 30, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			3.2
	Total derivative instruments designated as cash flow hedges		—			4.5
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.5
	Interest rate swaps long-term		7.9			12.6
	Foreign currency forward contracts current		0.6			0.3
	Foreign currency forward contracts long-term		1.6			—
	Natural gas swaps current		—			1.2
	Natural gas swaps long-term		—			3.9
	Gas purchase agreements current		—			22.8
	Gas purchase agreements long-term		—			67.4
	Total derivative instruments not designated as cash flow hedges		10.1			115.7
	Total derivative instruments	$	10.1		$	120.2
		December 31, 2012
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			5.2
	Total derivative instruments designated as cash flow hedges		—			6.5
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		0.1			27.7
	Foreign currency forward contracts current		9.5			—
	Foreign currency forward contracts long-term		11			—
	Natural gas swaps current		—			—
	Natural gas swaps long-term		0.1			3.9
	Gas purchase agreements current		0.1			24.5
	Gas purchase agreements long-term		—			81.4
	Total derivative instruments not designated as cash flow hedges		20.8			144.8
	Total derivative instruments	$	20.8		$	151.3
Schedule of changes in OCI attributable to derivative financial instruments	'
	(in millions)	Interest Rate			Natural Gas			Total
	Three months ended September 30, 2013	Swaps			Swaps
	Accumulated OCI balance at June 30, 2013	$	(0.4	)	$	—		$	(0.4	)
	Change in fair value of cash flow hedges		(0.1	)		—			(0.1	)
	Realized from OCI during the period		0.2			—			0.2
	Accumulated OCI balance at September 30, 2013	$	(0.3	)	$	—		$	(0.3	)
	(in millions)	Interest Rate			Natural Gas			Total
	Three months ended September 30, 2012	Swaps			Swaps
	Accumulated OCI balance at June 30, 2012	$	(1.7	)	$	0.2		$	(1.5	)
	Change in fair value of cash flow hedges		(0.3	)		—			(0.3	)
	Realized from OCI during the period		0.2			(0.1	)		0.1
	Accumulated OCI balance at September 30, 2012	$	(1.8	)	$	0.1		$	(1.7	)
	(in millions)	Interest Rate			Natural Gas			Total
	Nine months ended September 30, 2013	Swaps			Swaps
	Accumulated OCI balance at December 31, 2012	$	(1.5	)	$	0.1		$	(1.4	)
	Change in fair value of cash flow hedges		0.5			—			0.5
	Realized from OCI during the period		0.7			(0.1	)		0.6
	Accumulated OCI balance at September 30, 2013	$	(0.3	)	$	—		$	(0.3	)
	(in millions)	Interest Rate			Natural Gas			Total
	Nine months ended September 30, 2012	Swaps			Swaps
	Accumulated OCI balance at December 31, 2011	$	(1.7	)	$	0.3		$	(1.4	)
	Change in fair value of cash flow hedges		(0.8	)		—			(0.8	)
	Realized from OCI during the period		0.7			(0.2	)		0.5
	Accumulated OCI balance at September 30, 2012	$	(1.8	)	$	0.1		$	(1.7	)
Summary of realized (gains) and losses for derivative instruments not designated as cash flow hedges	'
				Three months
				ended
		Classification of (gain) loss		September 30,
		recognized in income		2013			2012
	Gas purchase agreements	Fuel		$	7.6		$	13.3
	Foreign currency forwards	Foreign exchange gain			(1.1	)		(2.1	)
	Interest rate swaps	Interest, net			2.7			1.2
				Nine months
				ended
		Classification of (gain) loss		September 30,
		recognized in income		2013			2012
	Gas purchase agreements	Fuel		$	38		$	29.3
	Foreign currency forwards	Foreign exchange gain			(14.4	)		(17.3	)
	Interest rate swaps	Interest, net			9.4			3.4
Summary of the unrealized gains and losses resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges	'
				Three months ended
		Classification of (gain) loss		September 30,
		recognized in income		2013			2012
	Natural gas swaps	Change in fair value of derivatives		$	0.6		$	(1.0	)
	Gas purchase agreements	Change in fair value of derivatives			3.6			(10.0	)
	Interest rate swaps	Change in fair value of derivatives			(0.7	)		0.3
	Total change in fair value of derivative instruments			$	3.5		$	(10.7	)
	Foreign currency forwards	Foreign exchange loss (gain)		$	(0.2	)	$	(4.7	)
				Nine months ended
		Classification of (gain) loss		September 30,
		recognized in income		2013			2012
	Natural gas swaps	Change in fair value of derivatives		$	1.4		$	(0.2	)
	Gas purchase agreements	Change in fair value of derivatives			(12.0	)		(49.3	)
	Interest rate swaps	Change in fair value of derivatives			(22.8	)		(1.8	)
	Total change in fair value of derivative instruments			$	(33.4	)	$	(51.3	)
	Foreign currency forwards	Foreign exchange loss (gain)		$	18.5		$	8.2

Income_taxes_Tables

Income taxes (Tables)	9 Months Ended
	Sep. 30, 2013
Income taxes	'
Schedule of components of income tax expenses (benefit)	'
		Three months ended					Nine months ended
		September 30,					September 30,
		2013			2012		2013			2012
	Current income tax expense	$	5.4		$	1.9	$	10.8		$	6.1
	Deferred tax (benefit) expense		(5.4	)		1.2		(12.7	)		(25.2	)
	Total income tax (benefit) expense	$	—		$	3.1	$	(1.9	)	$	(19.1	)

Employee_incentive_programs_Ta

Employee incentive programs (Tables)	9 Months Ended
	Sep. 30, 2013
Employee incentive programs	'
Schedule of changes in LTIP notional shares	'
	(Units in thousands)	Units			Grant Date
					Weighted-Average
					Price per Unit
	Outstanding at December 31, 2012		492,535		$	13.88
	Granted		597,031			4.91
	Reinvested		45,344			9.12
	Forfeited		(138,473	)		8.88
	Vested		(202,696	)		13.48
	Outstanding at September 30, 2013		793,741		$	7.76
Schedule of assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'
		September 30, 2013		December 31, 2012
	Weighted average risk free rate of return	0.0 – 0.5%		0.1 – 0.3%
	Dividend yield	9.00%		10.10%
	Expected volatility—Atlantic Power	42.20%		22.50%
	Expected volatility—peer companies	10.6 – 96.3%		11.9 – 97.1%
	Weighted average remaining measurement period	2.1 years		1.4 years

Basic_and_diluted_earnings_los1

Basic and diluted earnings (loss) per share (Tables)	9 Months Ended
	Sep. 30, 2013
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						Nine months ended
		September 30,						September 30,
		2013			2012			2013			2012
	Numerator:
	Loss from continuing operations attributable to Atlantic Power Corporation	$	(40.9	)	$	(26.5	)	$	(31.8	)	$	(103.7	)
	Income (loss) from discontinued operations, net of tax		(0.4	)		19			(6.1	)		48.8
	Net loss attributable to Atlantic Power Corporation	$	(41.3	)	$	(7.5	)	$	(37.9	)	$	(54.9	)
	Denominator:
	Weighted average basic shares outstanding		120			119			119.8			115.4
	Dilutive potential shares:
	Convertible debentures		27.7			20.5			27.7			15.7
	LTIP notional units		0.8			0.5			0.7			0.5
	Potentially dilutive shares		148.5			140			148.2			131.6
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.34	)	$	(0.22	)	$	(0.27	)	$	(0.90	)
	Diluted earnings (loss) per share from discontinued operations		(0.00	)		0.16			(0.05	)		0.42
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.34	)	$	(0.06	)	$	(0.32	)	$	(0.48	)

Assets_held_for_sale_and_disco1

Assets held for sale and discontinued operations (Tables) (Path 15)	9 Months Ended
	Sep. 30, 2013
Path 15	'
Held for Sale Business	'
Summary of income (loss) from discontinued operations	'
		Three months ended					Nine months ended
		September 30,					September 30,
	(in millions)	2013			2012		2013			2012
	Revenue	$	—		$	55.2	$	71.6		$	158.2
	Income (loss) from operations of discontinued businesses		(0.4	)		19.5		(5.3	)		49.7
	Income tax expense		—			0.5		0.8			0.9
	Income (loss) from operations of discontinued businesses, net of tax	$	(0.4	)	$	19	$	(6.1	)	$	48.8
Summary of assets and liabilities classified as assets held for sale	'
	(in millions)	September 30, 2013			December 31, 2012
	Current assets:
	Cash and cash equivalents	$	0.3		$	6.5
	Restricted cash		—			12.6
	Accounts receivable		0.1			21.9
	Other current assets		—			6.3
			0.4			47.3
	Non-current assets:
	Plant, Property & Equipment		0.1			111.9
	Transmission system rights		—			172.4
	Goodwill		—			8.9
	Other assets		—			10.9
	Assets from discontinued operations		0.5			351.4
	Current liabilities:
	Accounts payable and other accrued liabilities	$	0.1		$	16.5
	Current portion of long-term debt		—			14.3
	Current portion of derivative instruments liability		—			20
	Other liabilities		—			0.5
			0.1			51.3
	Long-term liabilities
	Long-term debt		—			137.7
	Other long-term liabilities		—			—
	Liabilities from discontinued operations		0.1			189

Equity_Tables

Equity (Tables)	9 Months Ended
	Sep. 30, 2013
Equity	'
Schedule of reconciliation of equity	'
		Nine months ended September 30, 2013
	(in millions)	Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	729.7		$	221.3		$	235.4		$	1,186.40
	Net income (loss)		(37.9	)		9.5			(3.3	)		(31.7	)
	Realized and unrealized loss on hedging activities, net of tax		1.1			—			—			1.1
	Foreign currency translation adjustment, net of tax		(19.3	)		—			—			(19.3	)
	Common shares issued for LTIP		1.2			—			—			1.2
	Contribution by and sale of noncontrolling interst		—			—			44.6			44.6
	Costs associated with tax equity raise		(0.9	)		—			—			(0.9	)
	Dividends paid to noncontrolling interest		—			—			(4.4	)		(4.4	)
	Dividends declared on common shares		(46.5	)		—			—			(46.5	)
	Dividends declared on preferred shares of a subsidiary company		—			(9.5	)		—			(9.5	)
	Balance at September 30	$	627.4		$	221.3		$	272.3		$	1,121.00
		Nine months ended September 30, 2012
		Total Atlantic Power			Preferred shares			Noncontrolling			Total Equity
		Corporation			issued by a subsidiary			Interests
		Shareholders' Equity			company
	Balance at January 1	$	891.5		$	221.3		$	3		$	1,115.80
	Net income (loss)		(54.9	)		9.8			(0.7	)		(45.8	)
	Realized and unrealized loss on hedging activities, net of tax		(0.3	)		—			—			(0.3	)
	Foreign currency translation adjustment, net of tax		22.6			—			—			22.6
	Common shares issuance, net of costs		67.8			—			—			67.8
	Common shares issued for LTIP		1.5			—			—			1.5
	Dividends declared on common shares		(99.0	)		—			—			(99.0	)
	Dividends declared on preferred shares of a subsidiary company		—			(9.8	)		—			(9.8	)
	Balance at September 30	$	829.2		$	221.3		$	2.3		$	1,052.80

Segment_and_geographic_informa1

Segment and geographic information (Tables)	9 Months Ended
	Sep. 30, 2013
Segment and geographic information	'
Schedule of a reconciliation of project income to Project Adjusted EBITDA	'
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Three months ended September 30, 2013
	Project revenues	$	47.3		$	10.6		$	23.5		$	61		$	(0.6	)	$	141.8
	Segment assets		1,134.80			177.4			1,113.30			913.9			157.3			3,496.70
	Project Adjusted EBITDA	$	24.9		$	5.9		$	19.4		$	29.5		$	(3.5	)		76.2
	Change in fair value of derivative instruments		3.5			0.5			(0.5	)		—			—			3.5
	Depreciation and amortization		17.8			3.4			15.1			14.9			0.2			51.4
	Interest, net		4.1			1.4			4.8			0.4			(0.1	)		10.6
	Other project (income) expense		31.4			—			—			(26.3	)		0.8			5.9
	Project income (loss)		(31.9	)		0.6			(0.0	)		40.5			(4.4	)		4.8
	Administration		—			—			—			—			8.4			8.4
	Interest, net		—			—			—			—			27.5			27.5
	Foreign exchange gain		—			—			—			—			9.1			9.1
	Other expense, net		—			—			—			—			—			—
	Income (loss) from continuing operations before income taxes		(31.9	)		0.6			(0.0	)		40.5			(49.4	)		(40.2	)
	Income tax expense		—			—			—			—			—			—
	Net income (loss) from continuing operations		(31.9	)		0.6			(0.0	)		40.5			(49.4	)		(40.2	)
	Income (loss) from discontinued operations		—			—			—			—			(0.4	)		(0.4	)
	Net income (loss)	$	(31.9	)	$	0.6		$	(0.0	)	$	40.5		$	(49.8	)	$	(40.6	)
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Three months ended September 30, 2012
	Project revenues	$	43.8		$	—		$	15		$	47.7		$	(0.2	)	$	106.3
	Segment assets		1,157.90			446.3			852			1,162.60			25.2			3,644.00
	Project Adjusted EBITDA	$	20.3		$	2.3		$	12.6		$	23.4		$	(1.2	)		57.4
	Change in fair value of derivative instruments		(10.2	)		(0.6	)		—			—			—			(10.8	)
	Depreciation and amortization		20.4			1.4			10.7			9.3			—			41.8
	Interest, net		4.5			—			1.2			0.1			—			5.8
	Other project (income) expense		0.3			—			—			0.2			0.4			0.9
	Project income (loss)		5.3			1.5			0.7			13.8			(1.6	)		19.7
	Administration		—			—			—			—			6.3			6.3
	Interest, net		—			—			—			—			25.8			25.8
	Foreign exchange loss		—			—			—			—			7.7			7.7
	Other expense, net		—			—			—			—			0.3			0.3
	Income (loss) from continuing operations before income taxes		5.3			1.5			0.7			13.8			(41.7	)		(20.4	)
	Income tax expense		—			—			—			—			3.1			3.1
	Net income (loss) from continuing operations		5.3			1.5			0.7			13.8			(44.8	)		(23.5	)
	Income (loss) from discontinued operations		—			19.3			—			0.8			(1.1	)		19
	Net income (loss)	$	5.3		$	20.8		$	0.7		$	14.6		$	(45.9	)	$	(4.5	)
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Nine months ended September 30, 2013
	Project revenues	$	167.9		$	16.8		$	69.5		$	167.7		$	(0.9	)	$	421
	Segment assets		1,134.80			177.4			1,113.30			913.9			157.3			3,496.70
	Project Adjusted EBITDA	$	96.8		$	10.4		$	53		$	64.5		$	(11.4	)		213.3
	Change in fair value of derivative instruments		(12.9	)		(3.1	)		(18.8	)		—			—			(34.8	)
	Depreciation and amortization		55.7			7.9			45.7			44.7			0.5			154.5
	Interest, net		12.8			2.6			14.2			0.9			—			30.5
	Other project (income) expense		32.3			0.1			—			(26.6	)		—			5.8
	Project income (loss)		8.9			2.9			11.9			45.5			(11.9	)		57.3
	Administration		—			—			—			—			28.5			28.5
	Interest, net		—			—			—			—			78.7			78.7
	Foreign exchange gain		—			—			—			—			(12.9	)		(12.9	)
	Other expense, net		—			—			—			—			(9.5	)		(9.5	)
	Income (loss) from continuing operations before income taxes		8.9			2.9			11.9			45.5			(96.7	)		(27.5	)
	Income tax benefit		—			—			—			—			(1.9	)		(1.9	)
	Net income (loss) from continuing operations		8.9			2.9			11.9			45.5			(94.8	)		(25.6	)
	Income (loss) from discontinued operations		—			(1.1	)		—			1.3			(6.3	)		(6.1	)
	Net income (loss)	$	8.9		$	1.8		$	11.9		$	46.8		$	(101.1	)	$	(31.7	)
		Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
														Corporate
	Nine months ended September 30, 2012
Project revenues	$	156.6		$	—		$	46.9		$	121.7		$	1.2		$	326.4
Segment assets		1,157.90			446.3			852			1,162.60			25.2			3,644.00
Project Adjusted EBITDA	$	85.2		$	6.5		$	38.5		$	48		$	(7.5	)		170.7
Change in fair value of derivative instruments		46.3			2.6			—			—			—			48.9
Depreciation and amortization		58			4.3			31.7			28.9			0.1			123
Interest, net		13.9			—			3.8			0.4			—			18.1
Other project (income) expense		0.8			—			—			2.9			0.7			4.4
Project income (loss)		(33.8	)		(0.4	)		3			15.8			(8.3	)		(23.7	)
Administration		—			—			—			—			22			22
Interest, net		—			—			—			—			69.3			69.3
Foreign exchange loss		—			—			—			—			4.4			4.4
Other expense, net		—			—			—			—			(5.7	)		(5.7	)
Income (loss) from continuing operations before income taxes		(33.8	)		(0.4	)		3			15.8			(98.3	)		(113.7	)
Income tax expense		—			—			—			—			(19.1	)		(19.1	)
Net income (loss) from continuing operations		(33.8	)		(0.4	)		3			15.8			(79.2	)		(94.6	)
Income (loss) from discontinued operations		—			49.5			—			1.5			(2.2	)		48.8
Net income (loss)	$	(33.8	)	$	49.1		$	3		$	17.3		$	(81.4	)	$	(45.8	)
Schedule of revenue and assets by country	'
														Property, Plant and
														Equipment, net of
		Project Revenue						Project Revenue						accumulated depreciation
		Three months ended						Nine months ended
		September 30,						September 30,						September 30,			December 31,
		2013			2012			2013			2012			2013			2012
	United States	$	98		$	61		$	264.7		$	171.9		$	1,368.00		$	1,504.80
	Canada		43.8			45.3			156.3			154.5			505.9			550.7
	Total	$	141.8		$	106.3		$	421		$	326.4		$	1,873.90		$	2,055.50

Guarantees_and_condensed_conso1

Guarantees and condensed consolidating financial information (Tables)	9 Months Ended
	Sep. 30, 2013
Guarantees and condensed consolidating financial information	'
Schedule of consolidating balance sheet	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING BALANCE SHEET
	September 30, 2013
	(in millions of U.S. dollars)
	(Unaudited)
		Guarantor			Curtis			Atlantic			Eliminations			Consolidated
		Subsidiaries			Palmer			Power						Balance
	Assets
	Current assets:
	Cash and cash equivalents	$	163.5		$	—		$	7.2		$	—		$	170.7
	Restricted cash		119.8			—			—			—			119.8
	Accounts receivable		165.9			10.9			2.8			(116.3	)		63.3
	Prepayments, supplies, and other current assets		32.2			2.3			0.8			(1.0	)		34.3
	Total current assets		481.4			13.2			10.8			(117.3	)		388.1
	Property, plant, and equipment, net		1,702.70			172.5			—			(1.3	)		1,873.90
	Equity investments in unconsolidated affiliates		3,753.90			—			963.7			(4,313.1	)		404.5
	Other intangible assets, net		321.5			149.6			—			—			471.1
	Goodwill		238.1			58.2			—			—			296.3
	Other assets		473.7			—			434.3			(845.2	)		62.8
	Total assets	$	6,971.30		$	393.5		$	1,408.80		$	(5,276.9	)	$	3,496.70
	Liabilities
	Current liabilities:
	Accounts payable and accrued liabilities	$	118.6		$	3.9		$	83.9		$	(116.3	)	$	90.1
	Revolving credit facility		—			—			—			—			—
	Current portion of long-term debt		16.7			190			—			—			206.7
	Other current liabilities		40			—			3.9			(1.0	)		42.9
	Total current liabilities		175.3			193.9			87.8			(117.3	)		339.7
	Long-term debt		814.1			—			460			—			1,274.10
	Convertible debentures		—			—			414.1			—			414.1
	Other non-current liabilities		1,184.00			8.5			0.5			(845.2	)		347.8
	Total liabilities		2,173.40			202.4			962.4			(962.5	)		2,375.70
	Equity
	Preferred shares issued by a subsidiary company		232.1			—			—			(10.8	)		221.3
	Common shares		4,323.50			191.1			1,285.80			(4,514.7	)		1,285.70
	Accumulated other comprehensive loss		(8.7	)		—			—			—			(8.7	)
	Retained deficit		(21.3	)		—			(839.4	)		211.1			(649.6	)
	Total Atlantic Power Corporation shareholders' equity		4,525.60			191.1			446.4			(4,314.4	)		848.7
	Noncontrolling interest		272.3			—			—			—			272.3
	Total equity		4,797.90			191.1			446.4			(4,314.4	)		1,121.00
	Total liabilities and equity	$	6,971.30		$	393.5		$	1,408.80		$	(5,276.9	)	$	3,496.70
Consolidating statement of operations	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	Three months ended September 30, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
		Subsidiaries						Power						Balance
	Project revenue:
	Total project revenue	$	134.2		$	7.8		$	—		$	(0.2	)	$	141.8
	Project expenses:
	Fuel		47.2			—			—			—			47.2
	Project operations and maintenance		36.8			1.3			—			(0.1	)		38
	Development		1.4			—			—			—			1.4
	Depreciation and amortization		38.4			3.8			—			—			42.2
			123.8			5.1			—			(0.1	)		128.8
	Project other income (expense):
	Change in fair value of derivative instruments		(3.5	)		—			—			—			(3.5	)
	Equity in earnings of unconsolidated affiliates		39.1			—			—			—			39.1
	Interest expense, net		(6.3	)		(2.7	)		—			—			(9.0	)
	Other		(34.8	)		—			—			—			(34.8	)
			(5.5	)		(2.7	)		—			—			(8.2	)
	Project income		4.9			—			—			(0.1	)		4.8
	Administrative and other expenses (income):
	Administration expense		4.9			—			3.5			—			8.4
	Interest, net		18.9			—			8.6			—			27.5
	Foreign exchange loss		4.1			—			5			—			9.1
	Other income		—			—			—			—			—
			27.9			—			17.1			—			45
	Loss from continuing operations before income taxes		(23.0	)		—			(17.1	)		(0.1	)		(40.2	)
	Income tax benefit		—			—			—			—			—
	Net loss from continuing operations		(23.0	)		—			(17.1	)		(0.1	)		(40.2	)
	Net loss from discontinued operations		(0.4	)		—			—			—			(0.4	)
	Net loss		(23.4	)		—			(17.1	)		(0.1	)		(40.6	)
	Net income (loss) attributable to noncontrolling interest		(2.5	)		—			—			3.2			0.7
	Net loss attributable to Atlantic Power Corporation	$	(20.9	)	$	—		$	(17.1	)	$	(3.3	)	$	(41.3	)
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	Nine months ended September 30, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis			Atlantic			Eliminations			Consolidated
		Subsidiaries			Palmer			Power						Balance
	Project revenue:
	Total project revenue	$	394.1		$	27.4		$	—		$	(0.5	)	$	421
	Project expenses:
	Fuel		148.8			—			—			—			148.8
	Project operations and maintenance		110			2.2			0.5			(0.4	)		112.3
	Development		4.9			—			—			—			4.9
	Depreciation and amortization		114.2			11.5			—			—			125.7
			377.9			13.7			0.5			(0.4	)		391.7
	Project other income (expense):
	Change in fair value of derivative instruments		33.4			—			—			—			33.4
	Equity in earnings of unconsolidated affiliates		55			—			—			—			55
	Interest expense, net		(17.4	)		(8.3	)		—			—			(25.7	)
	Other		(35.0	)		—			0.3			—			(34.7	)
			36			(8.3	)		0.3			—			28
	Project income		52.2			5.4			(0.2	)		(0.1	)		57.3
	Administrative and other expenses (income):
	Administration expense		15.3			—			13.2			—			28.5
	Interest, net		57.1			—			21.6			—			78.7
	Foreign exchange loss		(3.9	)		—			(9.0	)		—			(12.9	)
	Other income		(9.5	)		—			—						(9.5	)
			59			—			25.8			—			84.8
	Income (loss) from continuing operations before income taxes		(6.8	)		5.4			(26.0	)		(0.1	)		(27.5	)
	Income tax benefit		(1.9	)		—			—			—			(1.9	)
Net income (loss) from continuing operations		(4.9	)		5.4			(26.0	)		(0.1	)		(25.6	)
Net loss from discontinued operations		(6.1	)		—			—			—			(6.1	)
Net income (loss)		(11.0	)		5.4			(26.0	)		(0.1	)		(31.7	)
Net income (loss) attributable to noncontrolling interest		(3.3	)		—			—			9.5			6.2
Net income (loss) attributable to Atlantic Power Corporation	$	(7.7	)	$	5.4		$	(26.0	)	$	(9.6	)	$	(37.9	)
Consolidating statement of comprehensive income	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME
	Three and nine months ended September 30, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
		Subsidiaries						Power						Balance
	Net loss	$	(23.4	)	$	—		$	(17.1	)	$	(0.1	)	$	(40.6	)
	Other comprehensive income (loss):
	Unrealized gain on hedging activities		(0.1	)		—			—			—			(0.1	)
	Net amount reclassified to earnings		0.2			—			—			—			0.2
	Net unrealized losses on derivatives		0.1			—			—			—			0.1
	Foreign currency translation adjustments		10.7			—			—			—			10.7
	Other comprehensive income, net of tax		10.8			—			—			—			10.8
	Comprehensive loss		(12.6	)		—			(17.1	)		(0.1	)		(29.8	)
	Less: Comprehensive income attributable to noncontrolling interest		0.7			—			—			—			0.7
	Comprehensive loss attributable to Atlantic Power Corporation	$	(13.3	)	$	—		$	(17.1	)	$	(0.1	)	$	(30.5	)
		Guarantor			Curtis Palmer			Atlantic			Eliminations			Consolidated
		Subsidiaries						Power						Balance
	Net income (loss)	$	(11.0	)	$	5.4		$	(26.0	)	$	(0.1	)	$	(31.7	)
	Other comprehensive income (loss):
	Unrealized gain on hedging activities		0.5			—			—			—			0.5
	Net amount reclassified to earnings		0.6			—			—			—			0.6
	Net unrealized losses on derivatives		1.1			—			—			—			1.1
	Foreign currency translation adjustments		(19.3	)		—			—			—			(19.3	)
	Other comprehensive income, net of tax		(18.2	)		—			—			—			(18.2	)
	Comprehensive income (loss)		(29.2	)		5.4			(26.0	)		(0.1	)		(49.9	)
	Less: Comprehensive income attributable to noncontrolling interest		6.2			—			—			—			6.2
	Comprehensive income (loss) attributable to Atlantic Power Corporation	$	(35.4	)	$	5.4		$	(26.0	)	$	(0.1	)	$	(56.1	)
Consolidating statement of cash flows	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	Nine months ended September 30, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis			Atlantic			Eliminations			Consolidated
		Subsidiaries			Palmer			Power						Balance
	Net cash provided by operating activities	$	69.8		$	2.4		$	71.1		$	—		$	143.3
	Cash flows provided by (used in) investing activities:
	Proceeds from treasury grant		103.2			—			—			—			103.2
	Proceeds for sale of assets		183			—			—			—			183
	Cash (paid) received for equity investments		8.5			—			(8.5	)		—			—
	Change in restricted cash		(99.1	)		—			—			—			(99.1	)
	Biomass development costs		(0.1	)		—			—			—			(0.1	)
	Construction in progress		(32.2	)		—			—			—			(32.2	)
	Purchase of property, plant and equipment		(4.8	)		(2.4	)		—			—			(7.2	)
	Net cash provided by (used in) investing activities		158.5			(2.4	)		(8.5	)		—			147.6
	Cash flows provided by (used in) financing activities:
	Offering costs related to tax equity		(1.0	)		—			—			—			(1.0	)
	Repayment of project-level debt		(115.3	)		—			—			—			(115.3	)
	Proceeds from project-level debt		20.8			—			—			—			20.8
	Payments for revolving credit facility borrowings		(47.0	)		—			(20.0	)		—			(67.0	)
	Equity investment from noncontrolling interest		42.6			—			1.9			—			44.5
	Deferred financing costs		(0.5	)		—			—			—			(0.5	)
	Dividends paid		(13.9	)		—			(54.2	)		—			(68.1	)
	Net cash used in financing activities		(114.3	)		—			(72.3	)		—			(186.6	)
	Net increase (decrease) in cash and cash equivalents		114			—			(9.7	)		—			104.3
	Cash and cash equivalents at beginning of period		49.5			—			16.9			—			66.4
	Cash and cash equivalents at end of period	$	163.5		$	—		$	7.2		$	—		$	170.7

Basis_of_presentation_and_summ3

Basis of presentation and summary of significant accounting policies (Details)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
	MW	Delta-Person
	state
	province
	project
Basis of presentation and summary of significant accounting policies	'	'
Percentage of ownership interest	'	40.00%
Gross generating capacity of project (in MW)	3,018	'
Ownership interest in operational power generation projects (in MW)	2,098	'
Number of operational power generation projects	29	'
Number of states in which power generation projects operate	11	'
Number of provinces in which power generation projects operate	2	'
Number of projects Which are wholly owned subsidiaries	23	'

Basis_of_presentation_and_summ4

Basis of presentation and summary of significant accounting policies (Details 2) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in accumulated other comprehensive loss by component	'	'	'	'
Balance at beginning of period	'	'	$9.40	'
Other comprehensive income (loss):	'	'	'	'
Foreign currency translation adjustments	10.7	19.3	-19.3	22.6
Tax expense	'	3.1	-1.9	-19.1
Total Other comprehensive income (loss)	10.8	19.1	-18.2	22.3
Balance at end of period	-8.7	'	-8.7	'
Foreign currency translation	'	'	'	'
Changes in accumulated other comprehensive loss by component	'	'	'	'
Balance at beginning of period	-17.4	-0.1	12.7	-3.4
Other comprehensive income (loss):	'	'	'	'
Foreign currency translation adjustments	10.7	19.3	-19.3	22.6
Balance at end of period	-6.7	19.2	-6.7	19.2
Cash flow hedges	'	'	'	'
Changes in accumulated other comprehensive loss by component	'	'	'	'
Balance at beginning of period	-0.4	-1.5	-1.4	-1.4
Other comprehensive income (loss):	'	'	'	'
Net change from periodic revaluations	-0.2	-0.5	0.9	-1.4
Tax benefit	0.1	0.2	-0.4	0.6
Total Other comprehensive loss before reclassifications, net of tax	-0.1	-0.3	0.5	-0.8
Tax expense	-0.1	'	-0.4	-0.3
Total amount reclassified from Accumulated other comprehensive loss, net of tax	0.2	0.1	0.6	0.5
Total Other comprehensive income (loss)	0.1	-0.2	1.1	-0.3
Balance at end of period	-0.3	-1.7	-0.3	-1.7
Cash flow hedges | Amount reclassified from accumulated other comprehensive income	'	'	'	'
Other comprehensive income (loss):	'	'	'	'
Net amount reclassified to earnings:	0.3	0.1	1	0.8
Cash flow hedges | Amount reclassified from accumulated other comprehensive income | Interest rate swaps	'	'	'	'
Other comprehensive income (loss):	'	'	'	'
Net amount reclassified to earnings:	0.3	0.4	1.2	1.2
Cash flow hedges | Amount reclassified from accumulated other comprehensive income | Fuel commodity swaps	'	'	'	'
Other comprehensive income (loss):	'	'	'	'
Net amount reclassified to earnings:	'	($0.30)	($0.20)	($0.40)

Acquisitions_and_divestments_D

Acquisitions and divestments (Details) (USD $)

9 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

1 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2012

2-May-13

Jul. 31, 2012

Mar. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Jan. 31, 2012

Apr. 12, 2013

Jan. 30, 2013

Apr. 30, 2013

Apr. 30, 2013

Sep. 30, 2013

31-May-12

Feb. 29, 2012

Feb. 16, 2012

Apr. 02, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 04, 2012

Jun. 30, 2012

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Path 15

Path 15

Primary Energy Recycling Corporation

Primary Energy Recycling Corporation

Primary Energy Recycling Corporation

Gregory

Gregory

Gregory

Badger Creek

Badger Creek

item

MW

Acquisition and divestments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage acquired in entity

'

'

'

48.00%

'

'

51.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Wind power project capacity (in MW)

'

'

'

'

'

'

300

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

'

99.00%

'

'

'

'

'

'

'

'

'

'

14.30%

'

'

'

50.00%

'

Percentage of retained interest

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Project-level construction financing facility

'

'

'

$310

'

'

'

'

'

'

'

$137.20

'

'

'

'

'

'

'

'

Construction loan

'

'

'

290

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letter of credit facility

'

'

'

20

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letter of credit facility, term

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment in equity

'

'

190

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax equity investments received

'

'

'

'

225

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of institutional tax equity investors by whom tax equity investments received

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Own tax equity investment

'

44

'

'

44

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest sold (as a percent)

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax equity interests

'

269

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term debt

'

'

'

'

265

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of remaining tax equity ownership

'

42.1

'

'

'

'

'

92

'

25

'

'

'

'

'

'

'

'

'

'

Total price

'

'

'

'

'

'

'

'

140

'

56

'

'

30.2

'

274.2

'

'

'

'

Expected proceeds from sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

34.6

'

'

'

'

Proceeds from sale to be held in escrow account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

Term Of Escrow Account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

Net cash proceeds from sale

27.9

'

'

'

'

'

'

117

'

'

52

'

'

'

'

'

'

'

3.7

'

Management termination fee

'

'

'

'

'

'

'

'

'

'

4

'

'

6

'

'

'

'

'

'

Outstanding balance of senior credit facility

'

'

'

'

'

'

'

64.1

'

'

'

'

'

'

'

'

'

'

'

'

Impairment charge on pending sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

Price of entity's common membership interest in equity method investee

'

'

'

'

'

'

'

'

'

'

'

'

'

24.2

'

'

'

'

'

'

Gain on sale of equity method investment

'

'

'

'

'

'

'

'

'

'

'

'

$0.60

'

'

'

$30.40

$30.40

'

'

Entity's common membership interest to be purchased in equity method investee (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

7,462,830

'

'

'

'

'

'

Equity_method_investments_Deta

Equity method investments (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating results	'	'	'	'
Project revenue	$50.60	$51.60	$157.70	$158.50
Project expenses	39.4	48.1	128.3	138.9
Project other income (expense)	27.9	0.5	25.6	-7.2
Project income	39.1	4	55	12.4
Chambers	'	'	'	'
Operating results	'	'	'	'
Project revenue	13.4	12.2	40	40.1
Project expenses	10.1	9.6	30.8	28.1
Project other income (expense)	-0.7	0.2	-1.8	-1.4
Project income	2.6	2.8	7.4	10.6
Other	'	'	'	'
Operating results	'	'	'	'
Project revenue	37.2	39.4	117.7	118.4
Project expenses	29.3	38.5	97.5	110.8
Project other income (expense)	28.6	0.3	27.4	-5.8
Project income	$36.50	$1.20	$47.60	$1.80

Goodwill_Details

Goodwill (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended	1 Months Ended	9 Months Ended			9 Months Ended	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2011	Mar. 31, 2010	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Jun. 30, 2013	Sep. 30, 2013
	item	item	Partnership	Rollcast	Northeast	Northwest	Northwest	Southwest	Un-allocated Corporate	Un-allocated Corporate
Goodwill	'	'	'	'	'	'	'	'	'	'
Capitalized development costs at Rollcast related to the Greenway development project written-off	'	$1.40	'	'	'	'	'	'	'	'
Number of lease and steam projects	2	2	'	'	'	'	'	'	'	'
Goodwill	'	'	'	'	'	'	'	'	'	'
Goodwill recorded in connection with the acquisition	'	'	331.1	3.5	'	'	'	'	'	'
Goodwill	'	'	'	'	'	'	'	'	'	'
Balance at the beginning of the period	'	334.7	'	'	135.3	138.3	138.3	57.6	'	3.5
Impairment of goodwill	34.9	34.9	'	'	-30.8	'	'	-4.1	3.5	-3.5
Impairment of goodwill	'	38.4	'	'	'	'	'	'	'	'
Balance at the end of the period	$296.30	$296.30	'	'	$104.50	$138.30	$138.30	$53.50	'	'

Longterm_debt_Details

Long-term debt (Details)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Apr. 19, 2013

Jul. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Aug. 02, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Apr. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Aug. 02, 2013

Jul. 31, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

In Millions, unless otherwise specified

USD ($)

USD ($)

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due July 2014

Senior unsecured notes, due July 2014

Series A senior unsecured notes, due August 2015

Series A senior unsecured notes, due August 2015

Series B senior unsecured notes, due August 2017

Series B senior unsecured notes, due August 2017

Epsilon Power Partners term facility, due 2019

Epsilon Power Partners term facility, due 2019

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Piedmont bridge loan, due 2013

Piedmont bridge loan, due 2013

Piedmont bridge loan, due 2013

Piedmont bridge loan, due 2013

Senior credit facility

Senior credit facility

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Construction loan

Cash grant loan

Cash grant loan

Rockland term loan, due 2027

Rockland term loan, due 2027

Other long-term debt

Other long-term debt

Other long-term debt

Other long-term debt

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

Amended senior credit facility

USD ($)

USD ($)

USD ($)

CAD

USD ($)

CAD

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

US Prime Rate

Eurocurrency LIBOR Rate

Cdn. Prime Rate

Minimum

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

Maximum

USD ($)

US Prime Rate

Eurocurrency LIBOR Rate

Cdn. Prime Rate

US Prime Rate

Eurocurrency LIBOR Rate

Cdn. Prime Rate

Long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt

'

'

$460

$460

$203.80

210

$211.10

210

$190

$190

$150

$150

$75

$75

$31.20

$33.50

$36

$37.80

'

'

'

'

$76.60

$127.40

'

'

$171.40

$208.70

'

'

$171.40

'

$56.50

$85.80

$86.50

$1

$0.30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less current maturities

-206.7

-121.2

'

'

'

'

'

'

190

'

'

'

'

'

4.5

3

2.1

2.4

'

'

'

'

4.4

55.1

'

'

4.1

59.5

'

'

'

'

'

1.4

1.2

0.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt

1,274.10

1,459.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate (as a percent)

'

'

9.00%

'

6.00%

6.00%

'

'

5.90%

'

5.90%

'

6.00%

'

7.40%

'

'

'

6.00%

8.00%

'

'

'

'

'

'

'

'

2.90%

5.10%

'

'

'

6.40%

'

'

'

5.50%

6.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable interest rate basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Libor

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'US Prime Rate

'Eurocurrency LIBOR Rate

'Cdn. Prime Rate

'

'

'

'

'

'

'

'

Amount drawn on the senior credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit issued but not drawn

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

91.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

'

'

4.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.75%

2.75%

2.75%

'

4.75%

4.75%

4.75%

Bridge loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery as a percentage of capital cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount received under the 1603 federal grant program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment of debt from proceeds from 1603 grant with U.S. Treasury

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51

'

'

'

'

'

'

'

'

'

49

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150

'

'

'

'

'

'

'

'

'

'

'

'

'

150

300

'

'

'

'

'

'

'

'

'

'

'

Maximum capacity to be utilized for letter of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200

'

'

'

'

'

'

'

'

'

'

'

'

Contribution to cover shortfall resulting from the federal sequester on spending

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.5

'

'

'

'

'

'

'

'

'

4.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate amount of sublimit available for borrowings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

Cash collateralized required if letters of credit and borrowings outstanding under the amended credit facility exceeds $125 million

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125

'

'

'

'

'

'

'

Threshold limit of amended credit facility for required cash collateralized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125

'

'

'

'

'

'

'

Unrestricted cash and cash equivalents

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75

'

'

'

'

'

'

'

Consolidated Total Net Debt to Consolidated EBITDA

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.75

'

'

'

Consolidated EBITDA to Consolidated Interest Expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.6

'

'

'

'

'

'

'

Commitment fee (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

'

'

'

1.75%

'

'

'

Consolidated Total Net Debt to Consolidated EBITDA Over Time

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period preceding the maturity of debt for voluntarily prepayment or repurchase of any outstanding debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

Contribution to cover shortfall resulting from lower grant-eligible costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2.80

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_value_of_financial_instru2

Fair value of financial instruments (Details) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Credit valuation adjustments

Credit valuation adjustments

Credit valuation adjustments

Recurring

Recurring

Recurring

Recurring

Recurring

Recurring

Foreign currency forward contracts

Level 1

Level 1

Level 2

Level 2

Total

Total

Assets:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash and cash equivalents

'

'

'

'

'

'

'

'

$170.70

$60.20

'

'

$170.70

$60.20

Restricted cash

119.8

'

119.8

'

28.6

'

'

'

119.8

28.6

'

'

119.8

28.6

Derivative instruments asset

'

'

'

'

'

'

'

'

'

'

9.8

20.6

9.8

20.6

Total

'

'

'

'

'

'

'

'

290.5

88.8

9.8

20.6

300.3

109.4

Liabilities:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instruments liability

'

'

'

'

'

'

'

'

'

'

119.9

151.1

119.9

151.1

Total

'

'

'

'

'

'

'

'

'

'

119.9

151.1

119.9

151.1

Net increase in fair value

'

'

'

'

'

13

18.4

'

'

'

'

'

'

'

Pre-tax increase in other comprehensive income

'

'

'

'

'

0.6

1

'

'

'

'

'

'

'

Increase in change in fair value of derivatives

'

'

'

'

'

12.4

13.8

'

'

'

'

'

'

'

Foreign exchange gain (loss)

$9.10

$7.70

($12.90)

$4.40

'

'

'

$3.60

'

'

'

'

'

'

Derivative_instruments_and_hed2

Derivative instruments and hedging activities (Details)

9 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Apr. 30, 2013

Sep. 30, 2013

Swaption interest rate from December 31, 2012 to December 31, 2024

Swaption interest rate from December 2024 to December 2030

Natural gas swaps

Natural gas swaps

Natural gas swaps during 2014 and 2015

Natural gas swaps during 2016 and 2017

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Foreign currency forward contracts

Foreign currency forward contracts

MMBTU

MMBTU

Orlando project

Orlando project

Epsilon

Rockland Wind Farm

Swaption interest rate until February 15, 2015

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

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

Swaption interest rate after February 15, 2023

Swaption interest rate until February 29, 2016

Swaption interest rate from February, 2016 to November, 2017

Swaption interest rate from November, 2017 to November, 2030

Swaption interest rate from December 30, 2011 to December 31, 2026

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

USD ($)

CAD

MMBTU

MMBTU

item

Piedmont

Piedmont

Piedmont

Rockland Wind Farm

Rockland Wind Farm

Derivative instruments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount (in Mmbtu)

'

'

5,600,000

10,600,000

3,200,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

74.00%

38.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Swaption interest rate (as a percent)

'

'

'

'

'

'

7.40%

'

6.00%

6.10%

6.30%

6.40%

1.70%

4.50%

4.50%

'

'

'

'

Swap percentage

2.30%

7.20%

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

4.20%

7.80%

'

'

Number of tranches

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

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

2.80%

'

'

'

'

'

'

'

'

'

'

'

3.50%

'

'

2.30%

'

'

'

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

3.30%

'

'

'

'

'

'

'

'

'

'

'

3.80%

'

'

2.80%

'

'

'

Percentage of floating rate debt converted to a fixed interest rate

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

8.50%

'

'

'

'

'

Percentage of expected dividend, long-term debt and convertible debenture interest payments hedge

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

71.00%

Notional amount through December 2015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

34.9

Exchange rate through December 2015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.108

Proceeds from termination of various foreign currency forward contracts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$9.40

'

Derivative_instruments_and_hed3

Derivative instruments and hedging activities (Details 2)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Natural gas swaps	Natural gas swaps	Gas purchase agreements	Gas purchase agreements	Interest rate swaps	Interest rate swaps	Foreign currency forwards	Foreign currency forwards
	MMBTU	MMBTU	gigajoule	gigajoule	USD ($)	USD ($)	CAD	CAD
Derivative instruments	'	'	'	'	'	'	'	'
Volume of forecasted transactions	5,600,000	10,600,000	43,900,000	49,800,000	'	'	'	'
Volume of forecasted transactions, (in dollars)	'	'	'	'	$164.40	$172	34.9	176.6

Derivative_instruments_and_hed4

Derivative instruments and hedging activities (Details 3) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair value of derivative instruments	'	'
Derivative Assets	$10.10	$20.80
Derivative Liabilities	120.2	151.3
Derivative instruments designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	4.5	6.5
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	1.3	1.3
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	3.2	5.2
Derivative instruments not designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Assets	10.1	20.8
Derivative Liabilities	115.7	144.8
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	7.5	7.3
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	7.9	0.1
Derivative Liabilities	12.6	27.7
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	0.6	9.5
Derivative Liabilities	0.3	'
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	1.6	11
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	1.2	'
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	'	0.1
Derivative Liabilities	3.9	3.9
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	'	0.1
Derivative Liabilities	22.8	24.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	$67.40	$81.40

Derivative_instruments_and_hed5

Derivative instruments and hedging activities (Details 4) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	($0.40)	($1.50)	($1.40)	($1.40)
Change in fair value of cash flow hedges	-0.1	-0.3	0.5	-0.8
Realized from OCI during the period	0.2	0.1	0.6	0.5
Accumulated OCI balance at end of period	-0.3	-1.7	-0.3	-1.7
Interest Rate Swaps	'	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	-0.4	-1.7	-1.5	-1.7
Change in fair value of cash flow hedges	-0.1	-0.3	0.5	-0.8
Realized from OCI during the period	0.2	0.2	0.7	0.7
Accumulated OCI balance at end of period	-0.3	-1.8	-0.3	-1.8
Natural Gas Swaps	'	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'	'
Accumulated OCI balance at beginning of period	'	0.2	0.1	0.3
Realized from OCI during the period	'	-0.1	-0.1	-0.2
Accumulated OCI balance at end of period	'	$0.10	'	$0.10

Derivative_instruments_and_hed6

Derivative instruments and hedging activities (Details 5) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Impact of derivative instruments on the consolidated statements of operations	'	'	'	'
Change in fair value of derivative instruments	($3.50)	$10.70	$33.40	($51.30)
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	3.5	10.7	-33.4	-51.3
Derivative instruments not designated as cash flow hedges | Natural gas swaps	'	'	'	'
Impact of derivative instruments on the consolidated statements of operations	'	'	'	'
Change in fair value of derivative instruments	0.6	-1	1.4	-0.2
Derivative instruments not designated as cash flow hedges | Gas purchase agreements	'	'	'	'
Impact of derivative instruments on the consolidated statements of operations	'	'	'	'
Realized (gains) and losses of derivative instruments	7.6	13.3	38	29.3
Change in fair value of derivative instruments	3.6	-10	-12	-49.3
Derivative instruments not designated as cash flow hedges | Interest rate swaps	'	'	'	'
Impact of derivative instruments on the consolidated statements of operations	'	'	'	'
Realized (gains) and losses of derivative instruments	2.7	1.2	9.4	3.4
Change in fair value of derivative instruments	-0.7	0.3	-22.8	-1.8
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts	'	'	'	'
Impact of derivative instruments on the consolidated statements of operations	'	'	'	'
Realized (gains) and losses of derivative instruments	-1.1	-2.1	-14.4	-17.3
Change in fair value of derivative instruments	($0.20)	($4.70)	$18.50	$8.20

Income_taxes_Details

Income taxes (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income taxes	'	'	'	'
Expected income tax benefit	'	'	$7,000,000	'
Permanent differences benefits generated from U.S. treasury grant proceeds, production tax credits and foreign exchange differences	'	'	1,900,000	'
Canadian enacted statutory rate (as a percent)	'	'	25.00%	'
Goodwill impairment	'	'	13,700,000	'
Increase in the valuation allowance	'	'	4,500,000	'
Dividend withholding and preferred share taxes	'	'	6,200,000	'
Changes in estimates at joint venture projects	'	'	5,200,000	'
Offset related to treasury grant proceeds	'	'	19,400,000	'
Treasury grant proceeds	'	'	1,603	'
Foreign exchange	'	'	3,900,000	'
Other permanent differences	'	'	1,000,000	'
Components of income tax expenses (benefit)	'	'	'	'
Current income tax expense	5,400,000	1,900,000	10,800,000	6,100,000
Deferred tax (benefit) expense	-5,400,000	1,200,000	-12,700,000	-25,200,000
Total income tax (benefit) expense	'	3,100,000	-1,900,000	-19,100,000
Deferred tax assets:	'	'	'	'
Valuations allowance	$122,000,000	'	$122,000,000	'

Employee_incentive_programs_De

Employee incentive programs (Details) (Long-term incentive plan, USD $)	3 Months Ended	9 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012
Units	'	'	'
Outstanding at the beginning of the period (in shares)	'	492,535	'
Granted (in shares)	'	597,031	'
Reinvested (in shares)	'	45,344	'
Forfeited (in shares)	'	-138,473	'
Vested (in shares)	'	-202,696	'
Outstanding at the end of the period (in shares)	793,741	793,741	492,535
Grant Date Weighted Average Fair Value per Unit	'	'	'
Outstanding at the beginning of the period (in dollars per share)	'	$13.88	'
Granted (in dollars per share)	'	$4.91	'
Reinvested (in dollars per share)	'	$9.12	'
Forfeited (in dollars per share)	'	$8.88	'
Vested (in dollars per share)	'	$13.48	'
Outstanding at the end of the period (in dollars per share)	$7.76	$7.76	$13.88
Cash payments made for vested notional units	'	$0.90	'
Compensation expense	$0.40	$1.70	'
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Weighted average risk free rate of return, minimum (as a percent)	'	0.00%	0.10%
Weighted average risk free rate of return, maximum (as a percent)	'	0.50%	0.30%
Dividend yield (as a percent)	'	9.00%	10.10%
Expected volatility Atlantic Power (as a percent)	'	42.20%	22.50%
Weighted average remaining measurement period	'	'2 years 1 month 6 days	'1 year 4 months 24 days
Minimum	'	'	'
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Expected volatility of peer companies (as a percent)	'	10.60%	11.90%
Maximum	'	'	'
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Expected volatility of peer companies (as a percent)	'	96.30%	97.10%

Basic_and_diluted_earnings_los2

Basic and diluted earnings (loss) per share (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Numerator:	'	'	'	'
Loss from continuing operations attributable to Atlantic Power Corporation	($40.90)	($26.50)	($31.80)	($103.70)
Income (loss) from discontinued operations, net of tax	-0.4	19	-6.1	48.8
Net loss attributable to Atlantic Power Corporation	($41.30)	($7.50)	($37.90)	($54.90)
Denominator:	'	'	'	'
Weighted average basic shares outstanding	120	119	119.8	115.4
Dilutive potential shares:	'	'	'	'
Convertible debentures (in shares)	27.7	20.5	27.7	15.7
LTIP notional units (in shares)	0.8	0.5	0.7	0.5
Potentially dilutive shares	148.5	140	148.2	131.6
Diluted loss per share from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.22)	($0.27)	($0.90)
Diluted earnings (loss) per share from discontinued operations (in dollars per share)	$0	$0.16	($0.05)	$0.42
Net loss attributable to Atlantic Power Corporation (in dollars per share)	($0.34)	($0.06)	($0.32)	($0.48)

Assets_held_for_sale_and_disco2

Assets held for sale and discontinued operations (Details) (USD $)	3 Months Ended		9 Months Ended			3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Jun. 30, 2013	Sep. 30, 2013
						Rollcast	Rollcast
Assets held for sale and discontinued operations	'	'	'	'	'	'	'
Ownership interest sold (as a percent)	'	'	'	'	'	'	60.00%
Impairment of goodwill charge	'	'	'	'	'	$3.50	'
Impairment of intangible asset	'	'	'	'	'	1.4	'
Revenue	'	55.2	71.6	158.2	'	'	'
Income (loss) from operations of discontinued businesses	-0.4	19.5	-5.3	49.7	'	'	'
Income tax expense	'	0.5	0.8	0.9	'	'	'
Income (loss) from operations of discontinued businesses, net of tax	-0.4	19	-6.1	48.8	'	'	'
Basic and diluted earnings (loss) per share from income (loss) discontinued operations	$0	$0.16	($0.05)	$0.42	'	'	'
Current assets:	'	'	'	'	'	'	'
Cash and cash equivalents	0.3	'	0.3	'	6.5	'	'
Restricted cash	'	'	'	'	12.6	'	'
Accounts receivable	0.1	'	0.1	'	21.9	'	'
Other current assets	'	'	'	'	6.3	'	'
Total current assets	0.4	'	0.4	'	47.3	'	'
Non-current assets:	'	'	'	'	'	'	'
Plant, Property & Equipment	0.1	'	0.1	'	111.9	'	'
Transmission system rights	'	'	'	'	172.4	'	'
Goodwill	'	'	'	'	8.9	'	'
Other assets	'	'	'	'	10.9	'	'
Assets from discontinued operations	0.5	'	0.5	'	351.4	'	'
Current liabilities:	'	'	'	'	'	'	'
Accounts payable and other accrued liabilities	0.1	'	0.1	'	16.5	'	'
Current portion of long-term debt	'	'	'	'	14.3	'	'
Current portion of derivative instruments liability	'	'	'	'	20	'	'
Other liabilities	'	'	'	'	0.5	'	'
Assets from discontinued operations	0.1	'	0.1	'	189	'	'
Long-term liabilities	'	'	'	'	'	'	'
Long-term debt	'	'	'	'	137.7	'	'
Liabilities from discontinued operations	$0.10	'	$0.10	'	$189	'	'

Equity_Details

Equity (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Increase (decrease) in shareholders' equity	'	'	'	'
Balance	'	'	$1,186.40	$1,115.80
Net income (loss)	-40.6	-4.5	-31.7	-45.8
Realized and unrealized loss on hedging activities, net of tax	0.1	-0.2	1.1	-0.3
Foreign currency translation adjustment, net of tax	10.7	19.3	-19.3	22.6
Common shares issuance, net of costs	'	'	'	67.8
Common shares issued for LTIP	'	'	1.2	1.5
Contribution by and sale of noncontrolling interest	'	'	44.6	'
Costs associated with tax equity raise	'	'	-0.9	'
Dividends paid to noncontrolling interest	'	'	-4.4	'
Dividends declared on common shares	'	'	-46.5	-99
Dividends declared on preferred shares of a subsidiary company	'	'	-9.5	-9.8
Balance	1,121	1,052.80	1,121	1,052.80
Total Atlantic Power Corporation Shareholders' Equity	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance	'	'	729.7	891.5
Net income (loss)	'	'	-37.9	-54.9
Realized and unrealized loss on hedging activities, net of tax	'	'	1.1	-0.3
Foreign currency translation adjustment, net of tax	'	'	-19.3	22.6
Common shares issuance, net of costs	'	'	'	67.8
Common shares issued for LTIP	'	'	1.2	1.5
Costs associated with tax equity raise	'	'	-0.9	'
Dividends declared on common shares	'	'	-46.5	-99
Balance	627.4	829.2	627.4	829.2
Preferred shares issued by a subsidiary company	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance	'	'	221.3	221.3
Net income (loss)	'	'	9.5	9.8
Dividends declared on preferred shares of a subsidiary company	'	'	-9.5	-9.8
Balance	221.3	221.3	221.3	221.3
Noncontrolling Interests	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'
Balance	'	'	235.4	3
Net income (loss)	'	'	-3.3	-0.7
Contribution by and sale of noncontrolling interest	'	'	44.6	'
Dividends paid to noncontrolling interest	'	'	-4.4	'
Balance	$272.30	$2.30	$272.30	$2.30

Segment_and_geographic_informa2

Segment and geographic information (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment and geographic information	'	'	'	'	'
Project revenues	$141.80	$106.30	$421	$326.40	'
Segment assets	3,496.70	3,644	3,496.70	3,644	4,002.70
Project Adjusted EBITDA	76.2	57.4	213.3	170.7	'
Change in fair value of derivative instruments	3.5	-10.8	-34.8	48.9	'
Depreciation and amortization	51.4	41.8	154.5	123	'
Interest, net	10.6	5.8	30.5	18.1	'
Other project (income) expense	5.9	0.9	5.8	4.4	'
Project income (loss)	4.8	19.7	57.3	-23.7	'
Administration	8.4	6.3	28.5	22	'
Interest, net	27.5	25.8	78.7	69.3	'
Foreign exchange gain (loss)	9.1	7.7	-12.9	4.4	'
Other expense, net	'	0.3	-9.5	-5.7	'
Loss from continuing operations before income taxes	-40.2	-20.4	-27.5	-113.7	'
Income tax benefit	'	3.1	-1.9	-19.1	'
Net income (loss) from continuing operations	-40.2	-23.5	-25.6	-94.6	'
Income (loss) from discontinued operations	-0.4	19	-6.1	48.8	'
Net income (loss)	-40.6	-4.5	-31.7	-45.8	'
Rollcast	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Ownership interest (as a percent)	'	'	60.00%	'	'
Operating Segments | Northeast	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	47.3	43.8	167.9	156.6	'
Segment assets	1,134.80	1,157.90	1,134.80	1,157.90	'
Project Adjusted EBITDA	24.9	20.3	96.8	85.2	'
Change in fair value of derivative instruments	3.5	-10.2	-12.9	46.3	'
Depreciation and amortization	17.8	20.4	55.7	58	'
Interest, net	4.1	4.5	12.8	13.9	'
Other project (income) expense	31.4	0.3	32.3	0.8	'
Project income (loss)	-31.9	5.3	8.9	-33.8	'
Loss from continuing operations before income taxes	-31.9	5.3	8.9	-33.8	'
Net income (loss) from continuing operations	-31.9	5.3	8.9	-33.8	'
Net income (loss)	-31.9	5.3	8.9	-33.8	'
Operating Segments | Southeast	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	10.6	'	16.8	'	'
Segment assets	177.4	446.3	177.4	446.3	'
Project Adjusted EBITDA	5.9	2.3	10.4	6.5	'
Change in fair value of derivative instruments	0.5	-0.6	-3.1	2.6	'
Depreciation and amortization	3.4	1.4	7.9	4.3	'
Interest, net	1.4	'	2.6	'	'
Other project (income) expense	'	'	0.1	'	'
Project income (loss)	0.6	1.5	2.9	-0.4	'
Loss from continuing operations before income taxes	0.6	1.5	2.9	-0.4	'
Net income (loss) from continuing operations	0.6	1.5	2.9	-0.4	'
Income (loss) from discontinued operations	'	19.3	-1.1	49.5	'
Net income (loss)	0.6	20.8	1.8	49.1	'
Operating Segments | Northwest	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	23.5	15	69.5	46.9	'
Segment assets	1,113.30	852	1,113.30	852	'
Project Adjusted EBITDA	19.4	12.6	53	38.5	'
Change in fair value of derivative instruments	-0.5	'	-18.8	'	'
Depreciation and amortization	15.1	10.7	45.7	31.7	'
Interest, net	4.8	1.2	14.2	3.8	'
Project income (loss)	0	0.7	11.9	3	'
Loss from continuing operations before income taxes	0	0.7	11.9	3	'
Net income (loss) from continuing operations	0	0.7	11.9	3	'
Net income (loss)	0	0.7	11.9	3	'
Operating Segments | Southwest	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	61	47.7	167.7	121.7	'
Segment assets	913.9	1,162.60	913.9	1,162.60	'
Project Adjusted EBITDA	29.5	23.4	64.5	48	'
Depreciation and amortization	14.9	9.3	44.7	28.9	'
Interest, net	0.4	0.1	0.9	0.4	'
Other project (income) expense	-26.3	0.2	-26.6	2.9	'
Project income (loss)	40.5	13.8	45.5	15.8	'
Loss from continuing operations before income taxes	40.5	13.8	45.5	15.8	'
Net income (loss) from continuing operations	40.5	13.8	45.5	15.8	'
Income (loss) from discontinued operations	'	0.8	1.3	1.5	'
Net income (loss)	40.5	14.6	46.8	17.3	'
Un-allocated Corporate	'	'	'	'	'
Segment and geographic information	'	'	'	'	'
Project revenues	-0.6	-0.2	-0.9	1.2	'
Segment assets	157.3	25.2	157.3	25.2	'
Project Adjusted EBITDA	-3.5	-1.2	-11.4	-7.5	'
Depreciation and amortization	0.2	'	0.5	0.1	'
Interest, net	-0.1	'	'	'	'
Other project (income) expense	0.8	0.4	'	0.7	'
Project income (loss)	-4.4	-1.6	-11.9	-8.3	'
Administration	8.4	6.3	28.5	22	'
Interest, net	27.5	25.8	78.7	69.3	'
Foreign exchange gain (loss)	9.1	7.7	-12.9	4.4	'
Other expense, net	'	0.3	-9.5	-5.7	'
Loss from continuing operations before income taxes	-49.4	-41.7	-96.7	-98.3	'
Income tax benefit	-4.1	3.1	-1.9	-19.1	'
Net income (loss) from continuing operations	-45.3	-44.8	-94.8	-79.2	'
Income (loss) from discontinued operations	-0.4	-1.1	-6.3	-2.2	'
Net income (loss)	($45.70)	($45.90)	($101.10)	($81.40)	'

Segment_and_geographic_informa3

Segment and geographic information (Details 2) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Revenue and Assets	'	'	'	'	'
Project Revenue	$141.80	$106.30	$421	$326.40	'
Property, plant, and equipment, net	1,873.90	'	1,873.90	'	2,055.50
United States	'	'	'	'	'
Revenue and Assets	'	'	'	'	'
Project Revenue	98	61	264.7	171.9	'
Property, plant, and equipment, net	1,368	'	1,368	'	1,504.80
Canada	'	'	'	'	'
Revenue and Assets	'	'	'	'	'
Project Revenue	43.8	45.3	156.3	154.5	'
Property, plant, and equipment, net	$505.90	'	$505.90	'	$550.70

Segment_and_geographic_informa4

Segment and geographic information (Details 3) (Revenues, net, Consolidated revenue)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Ontario Electricity Financial Corp (OEFC)	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	20.70%	18.70%	26.30%	22.10%
BC Hydro	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	10.20%	9.20%	10.80%	9.70%
San Diego Gas & Electric (SD G&E)	'	'	'	'
Consolidated revenue concentration	'	'	'	'
Percentage of consolidated revenue	13.10%	'	10.20%	'

Commitments_and_contingencies_

Commitments and contingencies (Details) (USD $)	0 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 09, 2013	Aug. 19, 2013	7-May-13	Sep. 30, 2013	Oct. 04, 2013
	item	item	item	item
Commitments and contingencies	'	'	'	'	'
Number of District Court actions alleged from July 23, 2010 to March 4, 2013	'	'	'	3	'
Number of District Court actions alleged from August 8, 2012 to February 28, 2013	'	'	'	2	'
Number of actions were succeeded by specific action with an amended claim	'	'	'	3	'
Number of actions by which specific Ontario actions were succeeded	'	'	'	1	'
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	'	'	'
Number of plaintiff applicants directed to file supplemental submissions	2	'	'	'	'
Number of notices of actions relating to Canadian securities class action claims	'	'	'	3	'
Estimate damages claimed for statutory misrepresentation	'	'	'	'	$197.40
Number of District Court actions in which discoveries are stayed	'	'	'	5	'
Number of District Court actions alleged in specific period	'	'	'	5	'
Number of investors filed motion	'	'	6	'	'

Guarantees_and_condensed_conso2

Guarantees and condensed consolidating financial information (Details) (Senior Notes, USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Senior Notes	'	'
Long-term debt	'	'
Total debt	$460	$460
Percentage of ownership in subsidiary (as a percent)	100.00%	'

Guarantees_and_condensed_conso3

Guarantees and condensed consolidating financial information (Details 2) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Current assets:	'	'	'	'
Cash and cash equivalents	$170.70	$60.20	$42.90	$60.70
Restricted cash	119.8	28.6	'	'
Accounts receivable	63.3	58.5	'	'
Prepayments, supplies, and other current assets	34.3	'	'	'
Total current assets	388.1	561.7	'	'
Property, plant, and equipment, net	1,873.90	2,055.50	'	'
Equity investments in unconsolidated affiliates	404.5	428.7	'	'
Other intangible assets, net	471.1	524.9	'	'
Goodwill	296.3	334.7	'	'
Other assets	62.8	'	'	'
Total assets	3,496.70	4,002.70	3,644	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	90.1	'	'	'
Revolving credit facility	'	67	'	'
Current portion of long-term debt	206.7	121.2	'	'
Other current liabilities	42.9	'	'	'
Total current liabilities	339.7	535.5	'	'
Long-term debt	1,274.10	1,459.10	'	'
Convertible debentures	414.1	424.2	'	'
Other non-current liabilities	347.8	'	'	'
Total liabilities	2,375.70	2,816.30	'	'
Equity	'	'	'	'
Preferred shares issued by a subsidiary company	221.3	221.3	'	'
Common shares	1,285.70	1,285.50	'	'
Accumulated other comprehensive income (loss)	-8.7	9.4	'	'
Retained deficit	-649.6	-565.2	'	'
Total Atlantic Power Corporation shareholders' equity	848.7	951	'	'
Noncontrolling interest	272.3	235.4	'	'
Total equity	1,121	1,186.40	1,052.80	1,115.80
Total liabilities and equity	3,496.70	4,002.70	'	'
Eliminations	'	'	'	'
Current assets:	'	'	'	'
Accounts receivable	-116.3	'	'	'
Prepayments, supplies, and other current assets	-1	'	'	'
Total current assets	-117.3	'	'	'
Property, plant, and equipment, net	-1.3	'	'	'
Equity investments in unconsolidated affiliates	-4,313.10	'	'	'
Other assets	-845.2	'	'	'
Total assets	-5,276.90	'	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	-116.3	'	'	'
Other current liabilities	-1	'	'	'
Total current liabilities	-117.3	'	'	'
Other non-current liabilities	-845.2	'	'	'
Total liabilities	-962.5	'	'	'
Equity	'	'	'	'
Preferred shares issued by a subsidiary company	-10.8	'	'	'
Common shares	-4,514.70	'	'	'
Retained deficit	211.1	'	'	'
Total Atlantic Power Corporation shareholders' equity	-4,314.40	'	'	'
Total equity	-4,314.40	'	'	'
Total liabilities and equity	-5,276.90	'	'	'
Guarantor Subsidiaries | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Cash and cash equivalents	163.5	49.5	'	'
Restricted cash	119.8	'	'	'
Accounts receivable	165.9	'	'	'
Prepayments, supplies, and other current assets	32.2	'	'	'
Total current assets	481.4	'	'	'
Property, plant, and equipment, net	1,702.70	'	'	'
Equity investments in unconsolidated affiliates	3,753.90	'	'	'
Other intangible assets, net	321.5	'	'	'
Goodwill	238.1	'	'	'
Other assets	473.7	'	'	'
Total assets	6,971.30	'	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	118.6	'	'	'
Current portion of long-term debt	16.7	'	'	'
Other current liabilities	40	'	'	'
Total current liabilities	175.3	'	'	'
Long-term debt	814.1	'	'	'
Other non-current liabilities	1,184	'	'	'
Total liabilities	2,173.40	'	'	'
Equity	'	'	'	'
Preferred shares issued by a subsidiary company	232.1	'	'	'
Common shares	4,323.50	'	'	'
Accumulated other comprehensive income (loss)	-8.7	'	'	'
Retained deficit	-21.3	'	'	'
Total Atlantic Power Corporation shareholders' equity	4,525.60	'	'	'
Noncontrolling interest	272.3	'	'	'
Total equity	4,797.90	'	'	'
Total liabilities and equity	6,971.30	'	'	'
Curtis Palmer | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Accounts receivable	10.9	'	'	'
Prepayments, supplies, and other current assets	2.3	'	'	'
Total current assets	13.2	'	'	'
Property, plant, and equipment, net	172.5	'	'	'
Other intangible assets, net	149.6	'	'	'
Goodwill	58.2	'	'	'
Total assets	393.5	'	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	3.9	'	'	'
Current portion of long-term debt	190	'	'	'
Total current liabilities	193.9	'	'	'
Other non-current liabilities	8.5	'	'	'
Total liabilities	202.4	'	'	'
Equity	'	'	'	'
Common shares	191.1	'	'	'
Total Atlantic Power Corporation shareholders' equity	191.1	'	'	'
Total equity	191.1	'	'	'
Total liabilities and equity	393.5	'	'	'
Atlantic Power | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Cash and cash equivalents	7.2	16.9	'	'
Accounts receivable	2.8	'	'	'
Prepayments, supplies, and other current assets	0.8	'	'	'
Total current assets	10.8	'	'	'
Equity investments in unconsolidated affiliates	963.7	'	'	'
Other assets	434.3	'	'	'
Total assets	1,408.80	'	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	83.9	'	'	'
Other current liabilities	3.9	'	'	'
Total current liabilities	87.8	'	'	'
Long-term debt	460	'	'	'
Convertible debentures	414.1	'	'	'
Other non-current liabilities	0.5	'	'	'
Total liabilities	962.4	'	'	'
Equity	'	'	'	'
Common shares	1,285.80	'	'	'
Retained deficit	-839.4	'	'	'
Total Atlantic Power Corporation shareholders' equity	446.4	'	'	'
Total equity	446.4	'	'	'
Total liabilities and equity	$1,408.80	'	'	'

Guarantees_and_condensed_conso4

Guarantees and condensed consolidating financial information (Details 3) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Project revenue:	'	'	'	'
Total project revenue	$141,800,000	$106,300,000	$421,000,000	$326,400,000
Project expenses:	'	'	'	'
Fuel	47,200,000	40,100,000	148,800,000	123,600,000
Project operations and maintenance	38,000,000	26,500,000	112,300,000	88,000,000
Development	1,400,000	'	4,900,000	'
Depreciation and amortization	42,200,000	30,600,000	125,700,000	87,300,000
Total project expenses	128,800,000	97,200,000	391,700,000	298,900,000
Project other income (expense):	'	'	'	'
Change in fair value of derivative instruments	-3,500,000	10,700,000	33,400,000	-51,300,000
Equity in earnings of unconsolidated affiliates	39,100,000	4,000,000	55,000,000	12,400,000
Interest expense, net	-9,000,000	-4,100,000	-25,700,000	-12,300,000
Other	-34,800,000	'	-34,700,000	'
Total project other income (expense)	-8,200,000	10,600,000	28,000,000	-51,200,000
Project income	4,800,000	19,700,000	57,300,000	-23,700,000
Administrative and other expenses (income):	'	'	'	'
Administration expense	8,400,000	6,300,000	28,500,000	22,000,000
Interest, net	27,500,000	25,800,000	78,700,000	69,300,000
Foreign exchange gain (loss)	9,100,000	7,700,000	-12,900,000	4,400,000
Other income	'	300,000	-9,500,000	-5,700,000
Total administrative and other expenses (income)	45,000,000	40,100,000	84,800,000	90,000,000
Loss from continuing operations before income taxes	-40,200,000	-20,400,000	-27,500,000	-113,700,000
Income tax benefit	'	3,100,000	-1,900,000	-19,100,000
Net loss from continuing operations	-40,200,000	-23,500,000	-25,600,000	-94,600,000
Net loss from discontinued operations	-400,000	19,000,000	-6,100,000	48,800,000
Net loss	-40,600,000	-4,500,000	-31,700,000	-45,800,000
Net income (loss) attributable to noncontrolling interest	-2,500,000	-400,000	-3,300,000	-700,000
Net loss attributable to Atlantic Power Corporation	-41,300,000	-7,500,000	-37,900,000	-54,900,000
Eliminations	'	'	'	'
Project revenue:	'	'	'	'
Total project revenue	-200,000	'	-500,000	'
Project expenses:	'	'	'	'
Project operations and maintenance	-100,000	'	-400,000	'
Total project expenses	-100,000	'	-400,000	'
Project other income (expense):	'	'	'	'
Project income	-100,000	'	-100,000	'
Administrative and other expenses (income):	'	'	'	'
Loss from continuing operations before income taxes	-100,000	'	-100,000	'
Net loss from continuing operations	-100,000	'	-100,000	'
Net loss	-100,000	'	-100,000	'
Net income (loss) attributable to noncontrolling interest	3,200,000	'	9,500,000	'
Net loss attributable to Atlantic Power Corporation	-3,300,000	'	-9,600,000	'
Guarantor Subsidiaries | Reportable legal entities	'	'	'	'
Project revenue:	'	'	'	'
Total project revenue	134,200,000	'	394,100,000	'
Project expenses:	'	'	'	'
Fuel	47,200,000	'	148,800,000	'
Project operations and maintenance	36,800,000	'	110,000,000	'
Development	1,400,000	'	4,900,000	'
Depreciation and amortization	38,400,000	'	114,200,000	'
Total project expenses	123,800,000	'	377,900,000	'
Project other income (expense):	'	'	'	'
Change in fair value of derivative instruments	-3,500,000	'	33,400,000	'
Equity in earnings of unconsolidated affiliates	39,100,000	'	55,000,000	'
Interest expense, net	-6,300,000	'	-17,400,000	'
Other	-34,800,000	'	-35,000,000	'
Total project other income (expense)	-5,500,000	'	36,000,000	'
Project income	4,900,000	'	52,200,000	'
Administrative and other expenses (income):	'	'	'	'
Administration expense	4,900,000	'	15,300,000	'
Interest, net	18,900,000	'	57,100,000	'
Foreign exchange gain (loss)	4,100,000	'	-3,900,000	'
Other income	'	'	-9,500,000	'
Total administrative and other expenses (income)	27,900,000	'	59,000,000	'
Loss from continuing operations before income taxes	-23,000,000	'	-6,800,000	'
Income tax benefit	'	'	-1,900,000	'
Net loss from continuing operations	-23,000,000	'	-4,900,000	'
Net loss from discontinued operations	-400,000	'	-6,100,000	'
Net loss	-23,400,000	'	-11,000,000	'
Net income (loss) attributable to noncontrolling interest	-2,500,000	'	-3,300,000	'
Net loss attributable to Atlantic Power Corporation	-20,900,000	'	-7,700,000	'
Curtis Palmer | Reportable legal entities	'	'	'	'
Project revenue:	'	'	'	'
Total project revenue	7,800,000	'	27,400,000	'
Project expenses:	'	'	'	'
Project operations and maintenance	1,300,000	'	2,200,000	'
Depreciation and amortization	3,800,000	'	11,500,000	'
Total project expenses	5,100,000	'	13,700,000	'
Project other income (expense):	'	'	'	'
Interest expense, net	-2,700,000	'	-8,300,000	'
Total project other income (expense)	-2,700,000	'	-8,300,000	'
Project income	'	'	5,400,000	'
Administrative and other expenses (income):	'	'	'	'
Loss from continuing operations before income taxes	'	'	5,400,000	'
Net loss from continuing operations	'	'	5,400,000	'
Net loss	'	'	5,400,000	'
Net loss attributable to Atlantic Power Corporation	'	'	5,400,000	'
Atlantic Power | Reportable legal entities	'	'	'	'
Project expenses:	'	'	'	'
Project operations and maintenance	'	'	500,000	'
Total project expenses	'	'	500,000	'
Project other income (expense):	'	'	'	'
Other	'	'	300,000	'
Total project other income (expense)	'	'	300,000	'
Project income	'	'	-200,000	'
Administrative and other expenses (income):	'	'	'	'
Administration expense	3,500,000	'	13,200,000	'
Interest, net	8,600,000	'	21,600,000	'
Foreign exchange gain (loss)	5,000,000	'	-9,000,000	'
Total administrative and other expenses (income)	17,100,000	'	25,800,000	'
Loss from continuing operations before income taxes	-17,100,000	'	-26,000,000	'
Net loss from continuing operations	-17,100,000	'	-26,000,000	'
Net loss	-17,100,000	'	-26,000,000	'
Net loss attributable to Atlantic Power Corporation	($17,100,000)	'	($26,000,000)	'

Guarantees_and_condensed_conso5

Guarantees and condensed consolidating financial information (Details 4) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Condensed consolidating statement of operations and comprehensive income	'	'	'	'
Net income (loss)	($40.60)	($4.50)	($31.70)	($45.80)
Other comprehensive income (loss):	'	'	'	'
Unrealized gain on hedging activities	-0.1	-0.3	0.5	-0.8
Net amount reclassified to earnings	0.2	0.1	0.6	0.5
Net unrealized gain (loss) on derivatives	0.1	-0.2	1.1	-0.3
Foreign currency translation adjustments	10.7	19.3	-19.3	22.6
Other comprehensive income (loss), net of tax	10.8	19.1	-18.2	22.3
Comprehensive income (loss)	-29.8	14.6	-49.9	-23.5
Less: Comprehensive income attributable to noncontrolling interest	0.7	3	6.2	9.1
Comprehensive income (loss) attributable to Atlantic Power Corporation	-30.5	11.6	-56.1	-32.6
Eliminations	'	'	'	'
Condensed consolidating statement of operations and comprehensive income	'	'	'	'
Net income (loss)	-0.1	'	-0.1	'
Other comprehensive income (loss):	'	'	'	'
Comprehensive income (loss)	-0.1	'	-0.1	'
Comprehensive income (loss) attributable to Atlantic Power Corporation	-0.1	'	-0.1	'
Guarantor Subsidiaries | Reportable legal entities	'	'	'	'
Condensed consolidating statement of operations and comprehensive income	'	'	'	'
Net income (loss)	-23.4	'	-11	'
Other comprehensive income (loss):	'	'	'	'
Unrealized gain on hedging activities	-0.1	'	0.5	'
Net amount reclassified to earnings	0.2	'	0.6	'
Net unrealized gain (loss) on derivatives	0.1	'	1.1	'
Foreign currency translation adjustments	10.7	'	-19.3	'
Other comprehensive income (loss), net of tax	10.8	'	-18.2	'
Comprehensive income (loss)	-12.6	'	-29.2	'
Less: Comprehensive income attributable to noncontrolling interest	0.7	'	6.2	'
Comprehensive income (loss) attributable to Atlantic Power Corporation	-13.3	'	-35.4	'
Curtis Palmer | Reportable legal entities	'	'	'	'
Condensed consolidating statement of operations and comprehensive income	'	'	'	'
Net income (loss)	'	'	5.4	'
Other comprehensive income (loss):	'	'	'	'
Comprehensive income (loss)	'	'	5.4	'
Comprehensive income (loss) attributable to Atlantic Power Corporation	'	'	5.4	'
Atlantic Power | Reportable legal entities	'	'	'	'
Condensed consolidating statement of operations and comprehensive income	'	'	'	'
Net income (loss)	-17.1	'	-26	'
Other comprehensive income (loss):	'	'	'	'
Comprehensive income (loss)	-17.1	'	-26	'
Comprehensive income (loss) attributable to Atlantic Power Corporation	($17.10)	'	($26)	'

Guarantees_and_condensed_conso6

Guarantees and condensed consolidating financial information (Details 5) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Condensed consolidating statement of cash flows	'	'
Net cash provided by operating activities	$143.30	$124.10
Cash flows provided by (used in) investing activities:	'	'
Proceeds from treasury grant	103.2	'
Proceeds for sale of assets	183	'
Change in restricted cash	-99.1	-105.5
Biomass development costs	-0.1	-0.4
Construction in progress	-32.2	-336
Purchase of property, plant and equipment	-7.2	-1.2
Cash provided by (used in) investing activities	147.6	-415.5
Cash flows provided by (used in) financing activities:	'	'
Offering costs related to tax equity	-1	'
Repayment of project-level debt	-115.4	-12.1
Proceeds from project-level debt	20.8	261.3
Payments for revolving credit facility borrowings	-67	-60.8
Equity investment from noncontrolling interest	44.6	'
Deferred financing costs	-0.5	-25.3
Dividends paid	-68.1	-108.2
Cash (used in) provided by financing activities	-186.6	275.4
Net increase (decrease) in cash and cash equivalents	104.3	'
Cash and cash equivalents at beginning of period	60.2	60.7
Cash and cash equivalents at end of period	170.7	42.9
Guarantor Subsidiaries | Reportable legal entities	'	'
Condensed consolidating statement of cash flows	'	'
Net cash provided by operating activities	69.8	'
Cash flows provided by (used in) investing activities:	'	'
Proceeds from treasury grant	103.2	'
Proceeds for sale of assets	183	'
Cash (paid) received for equity investments	8.5	'
Change in restricted cash	-99.1	'
Biomass development costs	-0.1	'
Construction in progress	-32.2	'
Purchase of property, plant and equipment	-4.8	'
Cash provided by (used in) investing activities	158.5	'
Cash flows provided by (used in) financing activities:	'	'
Offering costs related to tax equity	-1	'
Repayment of project-level debt	-115.3	'
Proceeds from project-level debt	20.8	'
Payments for revolving credit facility borrowings	-47	'
Equity investment from noncontrolling interest	42.6	'
Deferred financing costs	-0.5	'
Dividends paid	-13.9	'
Cash (used in) provided by financing activities	-114.3	'
Net increase (decrease) in cash and cash equivalents	114	'
Cash and cash equivalents at beginning of period	49.5	'
Cash and cash equivalents at end of period	163.5	'
Curtis Palmer | Reportable legal entities	'	'
Condensed consolidating statement of cash flows	'	'
Net cash provided by operating activities	2.4	'
Cash flows provided by (used in) investing activities:	'	'
Purchase of property, plant and equipment	-2.4	'
Cash provided by (used in) investing activities	-2.4	'
Atlantic Power | Reportable legal entities	'	'
Condensed consolidating statement of cash flows	'	'
Net cash provided by operating activities	71.1	'
Cash flows provided by (used in) investing activities:	'	'
Cash (paid) received for equity investments	-8.5	'
Cash provided by (used in) investing activities	-8.5	'
Cash flows provided by (used in) financing activities:	'	'
Payments for revolving credit facility borrowings	-20	'
Equity investment from noncontrolling interest	1.9	'
Dividends paid	-54.2	'
Cash (used in) provided by financing activities	-72.3	'
Net increase (decrease) in cash and cash equivalents	-9.7	'
Cash and cash equivalents at beginning of period	16.9	'
Cash and cash equivalents at end of period	$7.20	'