Atlantic Power 10-Q 5 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 02, 2015
Document and Entity Information
Entity Registrant Name	ATLANTIC POWER CORP
Entity Central Index Key	1,419,242
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		122,130,947
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 76.4	$ 106
Restricted cash	14.5	22.5
Accounts receivable	41.6	46.2
Inventory	17.6	19.3
Prepayments and other current assets	12.8	13.9
Assets held for sale (Note 3)		792.1
Refundable income taxes		0.2
Total current assets	162.9	1,000.2
Property, plant, and equipment, net of accumulated depreciation of $226.5 million and $195.9 million at September 30, 2015 and December 31, 2014, respectively	875.7	962.9
Equity investments in unconsolidated affiliates (Note 4)	296.5	305.2
Other intangible assets, net of accumulated amortization of $228.3 million and $200.3 million at September 30, 2015 and December 31, 2014, respectively	324.4	377.1
Goodwill	197.2	197.2
Derivative instruments asset (Notes 7 and 8)		1.1
Deferred financing costs	44.8	62.8
Other assets	8.7	10.1
Total assets	1,910.2	2,916.6
Current liabilities:
Accounts payable	7.1	9.4
Income taxes payable	0.6
Accrued interest	6.6	5.3
Other accrued liabilities	35.5	30.7
Current portion of long-term debt (Note 5)	16.8	20
Current portion of derivative instruments liability (Notes 7 and 8)	35.1	36.1
Liabilities held for sale (Note 3)		271.8
Other current liabilities	5.5	6.8
Total current liabilities	107.2	380.1
Long-term debt (Note 5)	738.3	1,145.9
Convertible debentures (Note 6)	291.9	340.6
Derivative instruments liability (Notes 7 and 8)	30.9	47.5
Deferred income taxes (Note 9)	112.8	92.4
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $13.3 million and $11.4 million at September 30, 2015 and December 31, 2014, respectively	28.4	33.4
Other non-current liabilities	$ 56.4	$ 60.2
Commitments and contingencies (Note 15)
Total liabilities	$ 1,365.9	$ 2,100.1
Equity
Common shares, no par value, unlimited authorized shares; 122,118,147 and 121,323,614 issued and outstanding at September 30, 2015 and December 31, 2014, respectively (Note 12)	1,290.4	1,288.4
Accumulated other comprehensive loss	(121.1)	(68.3)
Retained deficit	(846.3)	(863.9)
Total Atlantic Power Corporation shareholders' equity	323	356.2
Preferred shares issued by a subsidiary company (Note 12)	221.3	221.3
Noncontrolling interests held for sale (Notes 3 and 12)		239
Total equity	544.3	816.5
Total liabilities and equity	$ 1,910.2	$ 2,916.6

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
CONSOLIDATED BALANCE SHEETS
Property, plant, and equipment, net of accumulated depreciation	$ 226.5	$ 195.9
Other intangible assets, net of accumulated amortization	228.3	200.3
Power purchase and fuel supply agreement liabilities, net of accumulated amortization	$ 13.3	$ 11.4
Common shares, no par value (in dollars per share)	$ 0	$ 0
Common shares, issued shares (in shares)	122,118,147	121,323,614
Common shares, outstanding shares (in shares)	122,118,147	121,323,614

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Project revenue:
Energy sales	$ 43.4	$ 53	$ 144.9	$ 177.6
Energy capacity revenue	45.9	49.1	117.4	124
Other	18.2	19.5	59.5	68.4
Total project revenue	107.5	121.6	321.8	370
Project expenses:
Fuel	41.1	49.3	125.3	159.5
Operations and maintenance	24.8	28.9	81.6	85.5
Development		1	1.1	2.7
Depreciation and amortization	27.8	30.7	83.8	92.1
Total project expenses	93.7	109.9	291.8	339.8
Project other income (expense):
Change in fair value of derivative instruments (Notes 7 and 8)	3.6	1.7	8.7	23.3
Equity in earnings of unconsolidated affiliates (Note 4)	8.9	15.6	28.3	27.8
Interest expense, net	(2.1)	(2.3)	(6.2)	(15.7)
Impairment		(91.8)		(106.6)
Other income (expense), net (Note 3)			2.2
Total project other income (expense)	10.4	(76.8)	33	(71.2)
Project income (loss)	24.2	(65.1)	63	(41)
Administrative and other expenses (income):
Administration	6.9	9.2	23	26.7
Interest, net	41	26.7	91.3	120.8
Foreign exchange gain (Note 8)	(21.7)	(19)	(49.1)	(20.4)
Other income, net (Note 6)			(3.1)
Total administrative and other expenses (income)	26.2	16.9	62.1	127.1
(Loss) income from continuing operations before income taxes	(2)	(82)	0.9	(168.1)
Income tax expense (benefit) (Note 9)	1.4	1.4	(0.3)	(20)
(Loss) income from continuing operations	(3.4)	(83.4)	1.2	(148.1)
Net (loss) income from discontinued operations, net of tax (Note 13)	(0.5)	(7.7)	20.6	(21.8)
Net (loss) income	(3.9)	(91.1)	21.8	(169.9)
Net loss attributable to noncontrolling interests of discontinued operations		(5.1)	(11)	(11.8)
Net income attributable to preferred shares of a subsidiary company	2.1	2.9	6.7	8.8
Net (loss) income attributable to Atlantic Power Corporation	$ (6)	$ (88.9)	$ 26.1	$ (166.9)
Basic and diluted earnings per share: (Note 11)
Loss from continuing operations attributable to Atlantic Power Corporation	$ (0.05)	$ (0.72)	$ (0.05)	$ (1.30)
(Loss) income from discontinued operations, net of tax		(0.02)	0.26	(0.08)
Net (loss) income attributable to Atlantic Power Corporation	$ (0.05)	$ (0.74)	$ 0.21	$ (1.38)
Weighted average number of common shares outstanding: (Note 11)
Basic (in shares)	122.1	120.7	121.8	120.6
Diluted (in shares)	122.2	120.7	121.9	120.6
Dividend paid per common share (in dollars per share)	$ 0.02	$ 0.06	$ 0.07	$ 0.23

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
Net (loss) income	$ (3.9)	$ (91.1)	$ 21.8	$ (169.9)
Other comprehensive income (loss), net of tax
Unrealized income (loss) on hedging activities	(0.4)	0.1	(0.8)	(0.6)
Net amount reclassified to earnings	0.2	0.2	0.6	0.6
Net unrealized (loss) gain on derivatives	(0.2)	0.3	(0.2)	0.1
Foreign currency translation adjustments	(22.1)	(23.1)	(52.6)	(24.5)
Other comprehensive loss, net of tax	(22.3)	(22.8)	(52.8)	(24.5)
Comprehensive loss	(26.2)	(113.9)	(31)	(194.4)
Less: Comprehensive income (loss) attributable to noncontrolling interests	2.1	(2.2)	(4.3)	(3)
Comprehensive loss attributable to Atlantic Power Corporation	$ (28.3)	$ (111.7)	$ (26.7)	$ (191.4)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Cash flows from operating activities:
Net income (loss)	$ 21.8	$ (169.9)
Adjustments to reconcile to net cash provided by operating activities:
Depreciation and amortization	94.1	122.3
Gain on sale of discontinued operations	(47.2)	(2.1)
Gain on sale of development project and other assets	2.3
Gain on sale of equity investment		(8.6)
Gain on purchase and cancellation of convertible debentures	3.1
Stock-based compensation expense	2	1.8
Impairment charges		106.6
Equity in earnings from unconsolidated affiliates	(28.3)	(18.8)
Distributions from unconsolidated affiliates	40	52.8
Unrealized foreign exchange gain	(49.3)	(21)
Change in fair value of derivative instruments	(8)	(12.3)
Change in deferred income taxes	23.6	(11.1)
Change in other operating balances
Accounts receivable	4.3	(0.3)
Inventory	1.7	(4.3)
Prepayments, refundable income taxes and other assets	20.2	18.2
Accounts payable	(6)	(4.8)
Accruals and other liabilities	4.2	(2.6)
Cash provided by operating activities	67.7	45.9
Cash flows provided by investing activities:
Change in restricted cash	8	78.2
Proceeds from sale of assets, net of cash sold	326.3	0.9
Contribution to unconsolidated affiliate	(0.5)	8.6
Capitalized development costs	(0.8)
Purchase of property, plant and equipment	(9.4)	(11.3)
Cash provided by investing activities	323.6	76.4
Cash flows used in financing activities:
Proceeds from senior secured term loan facility		600
Repayment of corporate and project-level debt	(387.1)	(621.9)
Repayments of convertible debenture	(18.7)
Deferred financing costs		(39)
Dividends paid to common shareholders	(8.5)	(32)
Dividends paid to noncontrolling interests	(10.5)	(20.4)
Cash used in financing activities	(424.8)	(113.3)
Net (decrease) increase in cash and cash equivalents	(33.5)	9
Cash and cash equivalents at beginning of period at discontinued operations	3.9
Cash and cash equivalents at beginning of period	106	158.6
Cash and cash equivalents at end of period	76.4	167.6
Supplemental cash flow information
Interest paid	75.5	124.4
Income taxes paid, net	4.1	1
Accruals for construction in progress	$ 1.2	$ 8.2

Nature of business

Nature of business	9 Months Ended
	Sep. 30, 2015
Nature of business
Nature of business	1. Nature of business General Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of September 30, 2015, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,141 megawatts ("MW") in which our aggregate ownership interest is approximately 1,504 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada. Eighteen of our projects are majority-owned subsidiaries. These totals exclude an aggregate of 521 MWs from our previous 100% ownership interest in Meadow Creek Project Company, LLC ("Meadow Creek"), 99% ownership in Canadian Hills Wind, LLC ("Canadian Hills"), 50% ownership interest in Rockland Wind Farm, LLC ("Rockland"), 27.6% ownership interest in Idaho Wind Partners 1, LLC ("Idaho Wind") and 12.5% ownership interest in Goshen Phase II, LLC ("Goshen") (collectively, the "Wind Projects"), which we sold on June 26, 2015, and which are designated as discontinued operations for the three and nine months ended September 30, 2015 and 2014. Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." Our registered office is located at 215-10451 Shellbridge Way, Richmond, British Columbia V6X 2W8 Canada and our headquarters is located at 3 Allied Drive, Suite 220, Dedham, Massachusetts 02026, USA. Our telephone number in Dedham is (617) 977-2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power's website or that can be accessed through its website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website. We make available on our website, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission ("SEC"). Additionally, we make available on our website our Canadian securities filings, which are not incorporated by reference into our Exchange Act filings. Basis of presentation The interim consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014. Interim results are not necessarily indicative of results for the full year. In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of September 30, 2015, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2015 and 2014, and our cash flows for the nine months ended September 30, 2015 and 2014 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included. Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Annual Report on Form 10-K for the year ended December 31, 2014. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount. Revision to the presentation of preferred shares issued by a subsidiary company The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic Power Corporation shareholder's equity on the Consolidated Balance Sheets at December 31, 2014 to a separate line item in the noncontrolling interests section of equity. The revision does not impact total equity in either period presented. The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the consolidated balance sheet. The revision is not considered material to any previously issued financial statements. Recently issued accounting standards Adopted In April 2014, the Financial Accounting Standards Board ("FASB") issued changes to reporting discontinued operations and disclosures of disposals of components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity's financial statements. The threshold is defined as a strategic shift that has, or will have, a major effect on an entity's operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes became effective on January 1, 2015 and were implemented when designating the Wind Projects as assets held for sale and discontinued operations on March 31, 2015. See Note 3, Discontinued operations . Issued In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements and which implementation approach to select. In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity's income statement, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become effective for us on January 1, 2016. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements. In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes become effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements. In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are required to be presented as a noncurrent asset in an entity's balance sheet and amortized into interest expense over the term of the related debt instrument. The changes require that debt issuance costs be presented in an entity's balance sheet as a direct deduction from the carrying value of the related debt liability. The amortization of debt issuance costs remains unchanged. These changes become effective for us on January 1, 2016. Management has determined that the adoption of these changes will result in a decrease of approximately $44.8 million based on the outstanding amount at September 30, 2015 to both deferred financing costs located in noncurrent assets and long-term debt on the accompanying consolidated balance sheets. In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The changes require that inventory be measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on January 1, 2017. Management has determined that the adoption of these changes will not have an impact on the consolidated financial statements. In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for us beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. We will apply this new guidance to any future business combinations.

Changes in accumulated other co

Changes in accumulated other comprehensive loss by component	9 Months Ended
	Sep. 30, 2015
Equity
Changes in accumulated other comprehensive loss by component	2. Changes in accumulated other comprehensive loss by component The changes in accumulated other comprehensive loss by component were as follows: Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Foreign currency translation Balance at beginning of period $ ) $ ) $ ) $ ) Other comprehensive income (loss): Foreign currency translation adjustments (1) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Pension Balance at beginning of period $ ) $ ) $ ) $ ) Other comprehensive loss: Amortization of net actuarial gain — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash flow hedges Balance at beginning of period $ $ ) $ $ Other comprehensive (loss) income: Net change from periodic revaluations ) ) ) Tax expense (benefit) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Other comprehensive income (loss) before reclassifications, net of tax ) ) ) Net amount reclassified to earnings (loss): Interest rate swaps (2) Tax expense ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total amount reclassified from Accumulated other comprehensive loss, net of tax Total Other comprehensive income ) ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). (2) This amount was included in Interest expense, net on the accompanying consolidated statements of operations.

Discontinued operations and oth

Discontinued operations and other divestitures	9 Months Ended
	Sep. 30, 2015
Discontinued operations and other divestitures
Discontinued operations and other divestitures	3. Discontinued operations and other divestitures Wind Projects On March 31, 2015, Atlantic Power Transmission, Inc. ("APT"), our wholly-owned, direct subsidiary, entered into a definitive agreement (the "Purchase Agreement") with TerraForm AP Acquisition Holdings, LLC ("TerraForm"), an affiliate of SunEdison, Inc. (an affiliate of TerraForm Power, Inc.), to sell our Wind Projects. On June 26, 2015, the sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded a $47.2 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2015. Terraform acquired from APT, 100% of APT's direct membership interests in a holding company formed to facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50% economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian Hills. The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind Projects as discontinued operations was based on the impact the sale will have on our operations and financial results and because the Wind Projects made up the entirety of our Wind reportable Segment. We stopped depreciating the property, plant and equipment of the Wind Projects on the designation date. Greeley In March 2014, we closed a transaction with Initium Power Partners, LLC. ("Initium"), whereby Initium agreed to purchase all of the issued and outstanding membership interests in Greeley for approximately $1.0 million. We recorded a $2.1 million non-cash gain on the sale resulting from the write-off of asset retirement obligations in the consolidated statement of operations as of March 31, 2014. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2014. The following table summarizes the revenue and income (loss) from operations of the Wind Projects and Greeley for the three and nine months ended September 30, 2015 and 2014: Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Revenue $ — $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project expenses: Operations and maintenance — Depreciation and amortization — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ — Project other income (expense): Change in fair value of derivatives ) ) ) Equity in earnings of unconsolidated affiliates — ) ) ) Interest expense, net — ) ) ) Gain (loss) on sale of asset ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses ) ) ) Income tax expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses, net of tax ) ) ) Net loss attributable to noncontrolling interests of discontinued businesses — ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses, net of noncontrolling interests $ ) $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for the Wind Projects and Greeley was $0.00 and $(0.02) for the three months ended September 30, 2015 and 2014, respectively and $0.26 and $(0.08) for the nine months ended September 30, 2015 and 2014, respectively. The following table summarizes the operating and investing cash flows of the Wind Projects for the nine months ended September 30, 2015 and 2014: Nine months ended September 30, 2015 2014 Cash provided by operating activities $ $ Cash (used in) provided by investing activities ) The following table summarizes the December 31, 2014 financial position of the Wind Projects that were classified as assets held for sale: December 31, 2014 Current assets: Cash and cash equivalents $ Accounts receivable Other current assets ​ ​ ​ ​ ​ Non-current assets: Property, Plant & Equipment Equity investments in unconsolidated affiliates Other intangible assets, net Restricted cash Other assets ​ ​ ​ ​ ​ Assets held for sale Current liabilities: Accounts payable and other accrued liabilities $ Current portion of long-term debt Current portion of derivative instruments liability ​ ​ ​ ​ ​ Long term liabilities Long-term debt Derivative instruments liability Other long-term liabilities ​ ​ ​ ​ ​ Liabilities held for sale Noncontrolling interests held for sale Frontier On April 22, 2015, our indirect wholly-owned subsidiary, Ridgeline Energy LLC ("Ridgeline"), closed a transaction with CRE-Frontier Solar California LLC ("CRE"), a subsidiary of Centaurus Renewable Energy LLC, whereby CRE agreed to purchase 100% of Ridgeline's equity interests in Frontier Solar, LLC ("Frontier"), which is developing an approximately 20 MW solar electric generating facility in California, for net cash proceeds of $4.3 million. If Frontier achieves commercial operations and meets certain operating performance metrics, we could receive additional cash proceeds. We recorded a $2.3 million gain on sale related to the transaction in other income in the consolidated statements of operations for the nine months ended September 30, 2015. Frontier is not accounted for as a component of discontinued operations. Delta-Person In December 2012, we and the other owners of Delta-Person, entered into a purchase and sale agreement with BHB Power, LLC and Public Service Company of New Mexico to sell the project for approximately $37.2 million including working capital adjustments. The sale of Delta-Person closed in July 2014, resulting in a gain on sale of approximately $8.6 million that was recorded as a component of equity in earnings of unconsolidated affiliates in the consolidated statement of operations for the three and nine months ended September 30, 2014. We received net cash proceeds in July 2014 for our ownership interest of approximately $7.2 million in the aggregate. We received an additional $1.4 million of cash proceeds that were held in escrow in October 2015. Delta-Person is not accounted for as a component of discontinued operations.

Equity method investments in un

Equity method investments in unconsolidated affiliates	9 Months Ended
	Sep. 30, 2015
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	4. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three and nine months ended September 30, 2015 and 2014, respectively, for earnings in our equity method investments: Three months ended September 30, Nine months ended September 30, Operating results 2015 2014 2015 2014 Revenue Chambers $ $ $ $ Orlando $ Other (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project expenses Chambers Orlando Other (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project other expense Chambers ) ) ) ) Orlando — — — — Other (1) — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ) ) Project income Chambers $ $ $ $ Orlando Other (1)(2) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes. (2) Includes an $8.6 million gain on the sale of Delta-Person in the third quarter of 2014.

Long-term debt

Long-term debt	9 Months Ended
	Sep. 30, 2015
Long-term debt
Long-term debt	5. Long-term debt Long-term debt consists of the following: September 30, 2015 December 31, 2014 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus 3.8% Senior unsecured notes, due 2018 — Senior unsecured notes, due June 2036 (Cdn$210.0) Non-Recourse Debt: (2) Epsilon Power Partners term facility, due 2019 LIBOR plus 3.1% Cadillac term loan, due 2025 Piedmont term loan, due 2018 Other long-term debt 5.5% – 6.7% Less: current maturities ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ Total long-term debt $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current maturities consist of the following: September 30, 2015 December 31, 2014 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus 3.8% Epsilon Power Partners term facility, due 2019 LIBOR plus 3.1% Cadillac term loan, due 2025 Piedmont term loan, due 2018 Other short-term debt 5.5 – 6.7% ​ ​ ​ ​ ​ ​ ​ ​ ​ Total current maturities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) LIBOR cannot be less than 1.00%. On May 5, 2014, we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $157.7 million amount of the $484.9 million outstanding aggregate borrowings under our senior secured term loan facility. See Note 8, Accounting for derivative instruments and hedging activities for further details. (2) The table does not include non-recourse debt at the Wind Projects, which have been sold and are classified as discontinued operations at December 31, 2014. Notes of Atlantic Power Corporation On July 26, 2015, we redeemed all of our outstanding $310.9 million aggregate principal amount of 9.0% Senior Unsecured Notes due November 2018 (the "Notes") with the cash proceeds received from the sale of the Wind Projects. The Notes were redeemed at a price equal to 104.5 percent of the principal amount of the 9.0% notes, plus accrued and unpaid interest to the redemption date. We paid $330.4 million to fund the full redemption of the Notes, which includes $14.0 million in make-whole premiums and $5.5 million in accrued interest. The make-whole premiums, accrued interest and the $9.0 million of deferred financing costs related to the Notes are included in interest expense for the three and nine months ended September 30, 2015. Non-Recourse Debt Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue generating contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available cash to Atlantic Power. At September 30, 2015, all of our projects with the exception of Piedmont and Selkirk were in compliance with the covenants contained in project-level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but are not callable or subject to acceleration under the terms of their debt agreements. We do not expect our Piedmont project to meet its debt service coverage ratio covenants before 2017 at the earliest, due to continued operational issues that have resulted in higher forecasted maintenance and fuel expenses than initially expected. We expect Selkirk to meet its debt service coverage ratio in the next twelve months.

Convertible debentures

Convertible debentures	9 Months Ended
	Sep. 30, 2015
Convertible debentures
Convertible debentures	6. Convertible debentures The following table provides details related to outstanding convertible debentures: 6.25% Debentures due March 2017 5.6% Debentures due June 2017 5.75% Debentures due June 2019 6.00% Debentures due December 2019 Total Balance at December 31, 2014 $ $ $ $ $ Repayment of convertible debentures — ) ) ) ) Foreign exchange gain ) ) — ) ) Gain on repurchase of convertible debentures — — ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at March 31, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repayment of convertible debentures $ — $ ) $ ) $ ) $ ) Foreign exchange gain — Gain on repurchase of convertible debentures — ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at June 30, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repayment of convertible debentures $ — $ ) $ — $ — $ ) Foreign exchange gain ) ) — ) ) Gain on repurchase of convertible debentures — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ During the fourth quarter of 2014, we announced a Normal Course Issuer Bid ("NCIB") for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures. The NCIB commenced on November 11, 2014 and will expire on November 10, 2015 or such earlier date as we complete our purchases pursuant to the NCIB. The actual amount of convertible debentures that may be purchased under the NCIB cannot exceed approximately $31.0 million and is further limited based on the outstanding principal of the individual outstanding tranches. Since inception of the NCIB in the fourth quarter of 2014 and through September 30, 2015, we have repurchased and cancelled $24.6 million aggregate principal amount of convertible debentures. We have recorded a gain of $3.0 million in the consolidated statement of operations for the nine months ended September 30, 2015 representing the difference between the aggregate principal amount cancelled and the cash paid adjusted for the impact of foreign exchange rates.

Fair value of financial instrum

Fair value of financial instruments	9 Months Ended
	Sep. 30, 2015
Fair value of financial instruments
Fair value of financial instruments	7. Fair value of financial instruments The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2015 and December 31, 2014. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. September 30, 2015 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ $ — $ — $ Restricted cash — — Derivative instruments asset — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ — $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Derivative instruments liability $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ $ — $ — $ Restricted cash — — Derivative instruments asset — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Derivative instruments liability $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 2015, the credit valuation adjustments resulted in a $4.4 million net increase in fair value, which consists of a $0.4 million pre-tax gain in other comprehensive income and a $4.0 million gain in change in fair value of derivative instruments. As of December 31, 2014, the credit valuation adjustments resulted in an $8.3 million net increase in fair value, which consists of a $0.7 million pre-tax gain in other comprehensive income and a $7.6 million gain in change in fair value of derivative instruments. The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.

Accounting for derivative instr

Accounting for derivative instruments and hedging activities	9 Months Ended
	Sep. 30, 2015
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	8. Accounting for derivative instruments and hedging activities We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts. Gas purchase agreements Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales ("NPNS") exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration in the fourth quarter of 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. In June 2014, Atlantic Power Limited Partnership (the "Partnership") entered into contracts for the purchase of 2.9 million Gigajoules ("Gj") of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 100% of our expected uncontracted gas requirements for 2015 and 35% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations. Natural gas swaps Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. We have entered into various natural gas swaps to effectively fix the price of 6.3 million MMbtu of future natural gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas purchases at the project through 2016 or approximately 96% and 64% of our share of the expected base load natural gas purchases for the remainder of 2015 and 2016, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2015. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations. On February 20, 2014, we paid $4.0 million to terminate certain of the natural gas contracts for our Orlando project in connection with the termination of our prior revolving credit facility. We recorded fuel expense related to the settlement of these contracts in the consolidated statement of operations for the nine months ended September 30, 2014. Interest rate swaps On May 5, 2014, the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ($157.7 million at September 30, 2015) of the $600 million aggregate principal amount of borrowings ($484.9 million of borrowings at September 30, 2015) under the Term Loan Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual Adjusted Eurodollar Rate and 1.16%. The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations. The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% until November 2030. Prior to conversion of the Piedmont construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont's construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations. The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive loss. Epsilon Power Partners, our wholly owned subsidiary, previously had an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July 2019. The notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon Power Partners' debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement of operations for the nine months ended September 30, 2014. Foreign currency forward contracts From time to time, we use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars. On February 20, 2014, we paid $0.4 million to terminate all of our remaining foreign currency forward contracts in connection with the termination of our prior revolving credit facility and recorded their settlement in foreign exchange gain in the consolidated statement of operations for the nine months ended September 30, 2014. Volume of forecasted transactions We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption at September 30, 2015 and December 31, 2014: Notional Units September 30, 2015 December 31, 2014 Natural gas swaps Natural Gas (Mmbtu) Gas purchase agreements Natural Gas (Gj) Interest rate swaps Aggregate Principal (US$) Fair value of derivative instruments We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities: September 30, 2015 Derivative Assets Derivative Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ Interest rate swaps long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments not designated as cash flow hedges: Interest rate swaps current — Interest rate swaps long-term Natural gas swaps current — Natural gas swaps long-term — Gas purchase agreements current — Gas purchase agreements long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments not designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Derivative Assets Derivative Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ Interest rate swaps long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments not designated as cash flow hedges: Interest rate swaps current — Interest rate swaps long-term Natural gas swaps current — Natural gas swaps long-term — Gas purchase agreements current — Gas purchase agreements long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments not designated as cash flow hedges ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accumulated other comprehensive income The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax: For the three months ended September 30, 2015 Interest Rate Swaps Accumulated OCI balance at June 30, 2015 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2015 $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the three months ended September 30, 2014 Interest Rate Swaps Accumulated OCI balance at June 30, 2014 $ ) Change in fair value of cash flow hedges Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2014 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the nine months ended September 30, 2015 Interest Rate Swaps Accumulated OCI balance at January 1, 2015 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2015 $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the nine months ended September 30, 2014 Interest Rate Swaps Accumulated OCI balance at January 1, 2014 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2014 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Impact of derivative instruments on the consolidated statements of operations The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges: Three months ended September 30, Nine months ended September 30, Classification of (gain) loss recognized in income 2015 2014 2015 2014 Natural gas swaps Fuel $ $ $ $ Gas purchase agreements Fuel Interest rate swaps Interest, net ) Foreign currency forwards Foreign exchange loss — — The following table summarizes the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges: Three months ended September 30, Nine months ended September 30, Classification of (gain) loss recognized in income 2015 2014 2015 2014 Natural gas swaps Change in fair value of derivatives $ $ $ ) $ ) Gas purchase agreements Change in fair value of derivatives ) ) ) ) Interest rate swaps Change in fair value of derivatives ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total change in fair value of derivative instruments $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign currency forwards Foreign exchange loss $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Income taxes

Income taxes	9 Months Ended
	Sep. 30, 2015
Income taxes
Income taxes	9. Income taxes Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Current income tax (benefit) expense $ ) $ $ $ Deferred tax expense (benefit) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total income tax expense (benefit), net $ $ $ ) $ ) For the three months ended September 30, 2015 and 2014 Income tax expense for the three months ended September 30, 2015 was $1.4 million. The expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $0.5 million. The primary items impacting the tax rate for the three months ended September 30, 2015 were $4.0 million relating to a change in valuation allowance, and $2.8 million related to a capital gain on repatriation of wind sale proceeds. These items were partially offset by $2.6 million of dividend withholding and other taxes, $2.2 million related to foreign exchange and $0.1 million of other permanent differences. Income tax expense for the three months ended September 30, 2014 was $1.4 million. The expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $21.4 million. The primary items impacting the tax rate for the three months ended September 30, 2014 were $33.7 million relating to goodwill impairment, $5.1 million relating to a change in the valuation allowance and $0.6 million of other permanent differences. These items were partially offset by $8.3 million relating to operating in higher tax rate jurisdictions, $4.8 million of intra-period allocations from the wind projects, $3.5 million relating to foreign exchange and $2.6 million of minority interest adjustments. For the nine months ended September 30, 2015 and 2014 Income tax benefit for the nine months ended September 30, 2015 was $0.3 million. The expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $0.3 million. The primary items impacting the tax rate for the nine months ended September 30, 2015 were $6.3 million relating to foreign exchange, $4.0 million relating to operating in higher tax rate jurisdictions, $3.6 million related to tax credits and $0.6 million of other permanent differences. These items were partially offset by $10.1 million relating to a change in the valuation allowance, $2.8 million related to a capital gain on repatriation of wind sale proceeds and $1.0 million relating to dividend withholding and other taxes. Income tax benefit for the nine months ended September 30, 2014 was $20.0 million. The expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $43.2 million. The primary items impacting the tax rate for the nine months ended September 30, 2014 were $34.4 million relating to a change in the valuation allowance, $33.7 million relating to goodwill impairment, and $0.2 million of other permanent differences. These items were partially offset by $17.9 million relating to operating in higher tax rate jurisdictions, $11.9 million of intraperiod allocations from the wind projects, $10.6 million of capital losses recognized on tax restructuring and $4.7 million relating to foreign exchange. Valuation allowance As of September 30, 2015, we have recorded a valuation allowance of $178.7 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

Equity compensation plans

Equity compensation plans	9 Months Ended
	Sep. 30, 2015
Equity compensation plans
Equity compensation plans	10. Equity compensation plans Long-term incentive plan ("LTIP") The following table summarizes the changes in outstanding LTIP notional units during the nine months ended September 30, 2015: Units Grant Date Weighted-Average Price per Unit Outstanding at December 31, 2014 $ Granted Reinvested Forfeited ) Vested ) ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at September 30, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Certain awards have a market condition based on our total shareholder return during the performance period as compared to a group of peer companies and, in some cases, Project Adjusted EBITDA per common share compared to budget. Compensation expense for notional units granted is recorded net of estimated forfeitures. See Note 16 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014 for further details. Cash payments made for vested notional units for the nine months ended September 30, 2015 and 2014 were $1.0 million and $0.2 million, respectively. Compensation expense for LTIP was $1.0 million and $2.0 million for the three and nine months ended September 30, 2015, respectively, and $0.9 million and $1.8 million for the three and nine months ended September 30, 2014, respectively. Transition Equity Participation Agreement We also have 542,606 transition notional shares outstanding at September 30, 2015 under the Transition Equity Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted with respect to fiscal year 2015 will vest upon the four-year anniversary of the date of grant and the remaining portion will vest on or any time after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares on the TSX for at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015 ($2.58) by at least 50%.

Basic and diluted earnings (los

Basic and diluted earnings (loss) per share	9 Months Ended
	Sep. 30, 2015
Basic and diluted earnings (loss) per share
Basic and diluted earnings (loss) per share	11. Basic and diluted earnings (loss) per share Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. Because we reported a loss for the three months ended September 30, 2015 and the three and nine months ended September 30, 2014, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive. The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine months ended September 30, 2015 and 2014: Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Numerator: Loss from continuing operations attributable to Atlantic Power Corporation $ ) $ ) $ ) $ ) (Loss) income from discontinued operations, net of tax ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) attributable to Atlantic Power Corporation $ ) $ ) $ $ ) Denominator: Weighted average basic shares outstanding Dilutive potential shares: Convertible debentures LTIP notional units ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Potentially dilutive shares ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted loss per share from continuing operations attributable to Atlantic Power Corporation $ ) $ ) $ ) $ ) Diluted (loss) income per share from discontinued operations — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted (loss) income per share attributable to Atlantic Power Corporation $ ) $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Potentially dilutive shares from convertible debentures of 22.4 million and 22.8 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2015, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from convertible debentures of 27.7 million and 27.7 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2014, respectively, because their impact would be anti-dilutive.

Equity

Equity	9 Months Ended
	Sep. 30, 2015
Equity
Equity	12. Equity The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the nine months ended September 30, 2015 and 2014: Nine months ended September 30, 2015 Total Atlantic Power Corporation Shareholders' Equity Preferred shares issued by a subsidiary company Noncontrolling Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) ) Realized an unrealized loss on hedging activities, net of tax ) — — ) Foreign currency translation adjustment ) — — ) Stock-based compensation — — Dividends paid to noncontrolling interests — — ) ) Dividends declared on common shares ) — — ) Dividends declared on preferred shares of a subsidiary company — ) — ) Derecognition of noncontrolling interests upon sale of subsidiaries — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30 $ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine months ended September 30, 2014 Total Atlantic Power Corporation Shareholders' Equity Preferred shares issued by a subsidiary company Noncontrolling Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) ) ) ) Realized and unrealized gain on hedging activities, net of tax — — Foreign currency translation adjustment ) — — ) Stock-based compensation — — Dividends paid to noncontrolling interest — — ) ) Dividends declared on common shares ) — — ) Dividends declared on preferred shares of a subsidiary company — ) — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Segment and geographic informat

Segment and geographic information	9 Months Ended
	Sep. 30, 2015
Segment and geographic information
Segment and geographic information	13. Segment and geographic information We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We revised our reportable business segments in the second quarter of 2015 as the result of recent significant asset sales and in order to align with changes in management's structure, resource allocation and performance assessment in making decisions regarding our operations. The Wind Projects, which made up the entirety of the former Wind segment, were sold in June 2015 and are designated as discontinued operations for the three and nine months ended September 30, 2014 and 2015. Our financial results for the three and nine months ended September 30, 2014 have been revised to reflect these changes in operating segments. We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented as proportionately consolidated based on our ownership percentage in the reconciliation of Project Adjusted EBITDA to project income (loss). A reconciliation of Project Adjusted EBITDA to project income (loss) for the three and nine months ended September 30, 2014 and 2015 reflecting our revised reportable business segments is included in the table below: East U.S. West U.S. Canada Un-allocated Corporate Consolidated Three months ended September 30, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) Depreciation and amortization Interest, net — — Other project expense (income) — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) ) Income tax expense — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ $ $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Three months ended September 30, 2014 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) ) Depreciation and amortization Interest, net — — Other project expense (income) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project loss ) ) ) ) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Loss from continuing operations before income taxes ) ) ) ) ) Income tax expense — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net loss from continuing operations $ ) $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Nine months ended September 30, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) Depreciation and amortization Interest, net — — Other project expense (income) — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) Other income, net — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) Income tax benefit — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Nine months ended September 30, 2014 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments ) — ) ) Depreciation and amortization Interest, net — — — Other project expense (income) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) ) ) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) ) ) ) Income tax benefit — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The table below provides information, by country, about our consolidated operations for each of the three and nine months ended September 30, 2015 and 2014 and Property, Plant & Equipment as of September 30, 2015 and December 31, 2014, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located. Property, Plant and Equipment, net of accumulated depreciation Project Revenue Three months ended September 30, Project Revenue Nine months ended September 30, September 30, 2015 December 31, 2014 2015 2014 2015 2014 United States $ $ $ $ $ $ Canada ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ $ We will perform our annual goodwill impairment analysis as of November 30, 2015. We performed an event-driven goodwill impairment analysis in the third quarter of 2014 and recorded a $91.8 million impairment. We also performed our annual goodwill impairment analysis as of November 30, 2014 and recorded no additional impairment. All cash flow forecasts in our models utilized for our impairment tests include estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. Changes to these assumptions and inputs, especially those impacted by the current and forward prices of oil and natural gas, could negatively impact future cash flow forecasts for our 2015 analysis and result in further goodwill impairment. Independent Electricity System Operator ("IESO"), San Diego Gas & Electric, Georgia Power and BC Hydro provided 22.9%, 16.7%, 10.2% and 9.1%, respectively, of total consolidated revenues for the three months ended September 30, 2015. For the nine months ended September 30, 2015, IESO, San Diego Gas & Electric, BC Hydro and Georgia Power provided 27.7%, 12.6%, 10.4% and 7.7% of total consolidated revenue. IESO, San Diego Gas & Electric and BC Hydro provided 21.3%, 18.7% and 9.8%, respectively, of total consolidated revenues for the three months ended September 30, 2014 and 23.8%, 16.2% and 9.0%, respectively, of total consolidated revenues for the nine months ended September 30, 2014. IESO purchases electricity from the Calstock, Kapuskasing, Nipigon and North Bay projects in the Canada segment, San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West U.S. segment, BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment and Georgia Power purchases electricity from the Piedmont project in the East U.S. segment.

Guarantees

Guarantees	9 Months Ended
	Sep. 30, 2015
Guarantees
Guarantees	14. Guarantees We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, including the Purchase Agreement to sell the Wind Projects, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In connection with the Purchase Agreement for the sale of the Wind Projects, on March 31, 2015, we entered into a guaranty agreement (the "Guaranty Agreement"), under which we agreed to guarantee the full and prompt payment of all payment obligations of APT under the Purchase Agreement as and when they shall become due. APT and TerraForm have agreed to utilize the representation and warranty insurance for coverage of certain indemnification obligations, subject to a cap and certain exclusions.

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2015
Contingencies
Contingencies	15. Contingencies Shareholder class action lawsuits Massachusetts District Court Actions On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our former President and Chief Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Proposed Individual Defendants," and together with Atlantic Power, the "Proposed Defendants") (the "U.S. Actions"). The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleged, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. The parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking: (i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013. On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff's selection of counsel. The Court also granted the parties' joint motion regarding initial case scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this requested schedule. On June 6, 2014, Lead Plaintiff filed the amended complaint (the "Amended Complaint"). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the "Individual Defendants") and Atlantic Power (together with the Individual Defendants, the "Defendants") and alleges a class period of June 20, 2011 to March 4, 2013 (the "Class Period"). The Amended Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend, which artificially inflated the price of Atlantic Power's common shares during the class period. The Amended Complaint continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated (the "Motion to Dismiss") U.S. Action on August 5, 2014. On September 30, 2014, citing Atlantic Power's September 16, 2014 announcement of changes to its dividend and its President and CEO transition, Lead Plaintiff filed a motion (the "Extension Motion") requesting a thirty-day extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending Lead Plaintiff's deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014, Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the Motion to Dismiss (the "Opposition") and also filed a motion for leave to amend the Amended Complaint, attaching a proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff's motion for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and Extension Motion. On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to Defendants' motion to dismiss (the "Motion for Leave"). The Court denied the Motion for Leave in an order entered on February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015. On March 13, 2015, the District Court entered an order granting Defendants' motion to dismiss and denying Lead Plaintiff's motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order dismissing the Amended Complaint with prejudice. On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First Circuit (the "First Circuit"). On August 19, 2015, Lead Plaintiff filed with the First Circuit its brief appealing the dismissal of its securities fraud claims. On September 4, 2015, while appellate proceedings were still on-going, Lead Plaintiff filed with the District Court a Rule 60(b)(2) motion to vacate the judgment based on evidence cited in the Ontario Superior Court's decision dismissing the Canadian action (for more information on that litigation, see below under "Canadian Actions"). On September 17, 2015, Atlantic Power opposed Lead Plaintiff's motion. On September 18, 2015, Lead Plaintiff requested a stay of the appellate proceedings in the First Circuit pending resolution of the District Court's decision on its Rule 60(b)(2) motion. On September 21, 2015, Atlantic Power opposed Lead Plaintiff's request for a stay and tendered to the First Circuit its opposition brief to Lead Plaintiff's appeal. On October 5, 2015, the First Circuit granted Lead Plaintiff's request for a stay in the appellate proceeding pending the District Court's decision on the Rule 60(b)(2) motion. On October 21, 2015, the District Court entered an order denying Lead Plaintiff's Rule 60(b)(2) motion to vacate the judgment. Thereafter, Lead Plaintiff informed Atlantic Power that it no longer wished to prosecute the appeal. On October 29, 2015, pursuant to Federal Rule of Appellate Procedure 42(b), the parties jointly stipulated to the voluntary dismissal of the appeal with prejudice. Canadian Actions On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the "Canadian Actions"). On April 17, May 22, and June 7, 2013, statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario. On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim names the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs seek leave to commence an action for statutory misrepresentation under the Ontario Securities Act and assert common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs sought 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. On March 26, 2015, the Plaintiffs amended their claim to add Scott Fife as a proposed representative plaintiff. On April 24, 2015, the Plaintiffs amended their claim to remove Ms. Lowry, who claimed to hold Atlantic Power convertible debentures, as a proposed representative plaintiff. The Plaintiffs' motions for leave and certification were heard on May 20-21, 2015. On July 24, 2015, the Ontario Superiour Court of Justice issued a decision denying the Plaintiffs' motion for leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial indemnity costs of responding to the Plaintiffs' motion. Plaintiffs have appealed the July 24 decision on leave and certification to the Ontario Court of Appeal. The Company will oppose that appeal. A date for the appeal has not yet been set. The proposed class action in Quebec is stayed until September 16, 2016. Pursuant to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S. Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously against each of the actions. Other In addition to the other matters listed, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of September 30, 2015.

Nature of business (Policies)

Nature of business (Policies)	9 Months Ended
	Sep. 30, 2015
Nature of business
Basis of presentation	Basis of presentation The interim consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014. Interim results are not necessarily indicative of results for the full year. In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of September 30, 2015, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2015 and 2014, and our cash flows for the nine months ended September 30, 2015 and 2014 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
Use of estimates	Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Annual Report on Form 10-K for the year ended December 31, 2014. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Revision to the presentation of preferred shares issued by a subsidiary company	Revision to the presentation of preferred shares issued by a subsidiary company The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic Power Corporation shareholder's equity on the Consolidated Balance Sheets at December 31, 2014 to a separate line item in the noncontrolling interests section of equity. The revision does not impact total equity in either period presented. The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the consolidated balance sheet. The revision is not considered material to any previously issued financial statements.
Recently issued accounting standards	Recently issued accounting standards Adopted In April 2014, the Financial Accounting Standards Board ("FASB") issued changes to reporting discontinued operations and disclosures of disposals of components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity's financial statements. The threshold is defined as a strategic shift that has, or will have, a major effect on an entity's operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes became effective on January 1, 2015 and were implemented when designating the Wind Projects as assets held for sale and discontinued operations on March 31, 2015. See Note 3, Discontinued operations . Issued In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements and which implementation approach to select. In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity's income statement, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become effective for us on January 1, 2016. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements. In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes become effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements. In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are required to be presented as a noncurrent asset in an entity's balance sheet and amortized into interest expense over the term of the related debt instrument. The changes require that debt issuance costs be presented in an entity's balance sheet as a direct deduction from the carrying value of the related debt liability. The amortization of debt issuance costs remains unchanged. These changes become effective for us on January 1, 2016. Management has determined that the adoption of these changes will result in a decrease of approximately $44.8 million based on the outstanding amount at September 30, 2015 to both deferred financing costs located in noncurrent assets and long-term debt on the accompanying consolidated balance sheets. In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The changes require that inventory be measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on January 1, 2017. Management has determined that the adoption of these changes will not have an impact on the consolidated financial statements. In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for us beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. We will apply this new guidance to any future business combinations.

Changes in accumulated other 23

Changes in accumulated other comprehensive loss by component (Tables)	9 Months Ended
	Sep. 30, 2015
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax
Schedule of changes in accumulated other comprehensive loss by component	Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Foreign currency translation Balance at beginning of period $ ) $ ) $ ) $ ) Other comprehensive income (loss): Foreign currency translation adjustments (1) ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Pension Balance at beginning of period $ ) $ ) $ ) $ ) Other comprehensive loss: Amortization of net actuarial gain — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash flow hedges Balance at beginning of period $ $ ) $ $ Other comprehensive (loss) income: Net change from periodic revaluations ) ) ) Tax expense (benefit) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Other comprehensive income (loss) before reclassifications, net of tax ) ) ) Net amount reclassified to earnings (loss): Interest rate swaps (2) Tax expense ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total amount reclassified from Accumulated other comprehensive loss, net of tax Total Other comprehensive income ) ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at end of period $ ) $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). (2) This amount was included in Interest expense, net on the accompanying consolidated statements of operations.

Discontinued operations and o24

Discontinued operations and other divestitures (Tables)	9 Months Ended
	Sep. 30, 2015
Discontinued operations and other divestitures
Summary of the revenue, income (loss) from operations, cash flows and financial position of Wind Projects and Greelay	The following table summarizes the revenue and income (loss) from operations of the Wind Projects and Greeley for the three and nine months ended September 30, 2015 and 2014: Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Revenue $ — $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project expenses: Operations and maintenance — Depreciation and amortization — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ — Project other income (expense): Change in fair value of derivatives ) ) ) Equity in earnings of unconsolidated affiliates — ) ) ) Interest expense, net — ) ) ) Gain (loss) on sale of asset ) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses ) ) ) Income tax expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses, net of tax ) ) ) Net loss attributable to noncontrolling interests of discontinued businesses — ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (Loss) income from operations of discontinued businesses, net of noncontrolling interests $ ) $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table summarizes the operating and investing cash flows of the Wind Projects for the nine months ended September 30, 2015 and 2014: Nine months ended September 30, 2015 2014 Cash provided by operating activities $ $ Cash (used in) provided by investing activities ) The following table summarizes the December 31, 2014 financial position of the Wind Projects that were classified as assets held for sale: December 31, 2014 Current assets: Cash and cash equivalents $ Accounts receivable Other current assets ​ ​ ​ ​ ​ Non-current assets: Property, Plant & Equipment Equity investments in unconsolidated affiliates Other intangible assets, net Restricted cash Other assets ​ ​ ​ ​ ​ Assets held for sale Current liabilities: Accounts payable and other accrued liabilities $ Current portion of long-term debt Current portion of derivative instruments liability ​ ​ ​ ​ ​ Long term liabilities Long-term debt Derivative instruments liability Other long-term liabilities ​ ​ ​ ​ ​ Liabilities held for sale Noncontrolling interests held for sale

Equity method investments in 25

Equity method investments in unconsolidated affiliates (Tables)	9 Months Ended
	Sep. 30, 2015
Equity method investments in unconsolidated affiliates
Summary of operating results	Three months ended September 30, Nine months ended September 30, Operating results 2015 2014 2015 2014 Revenue Chambers $ $ $ $ Orlando $ Other (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project expenses Chambers Orlando Other (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project other expense Chambers ) ) ) ) Orlando — — — — Other (1) — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ) ) Project income Chambers $ $ $ $ Orlando Other (1)(2) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes. (2) Includes an $8.6 million gain on the sale of Delta-Person in the third quarter of 2014.

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2015
Long-term debt
Schedule of long-term debt	September 30, 2015 December 31, 2014 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus 3.8% Senior unsecured notes, due 2018 — Senior unsecured notes, due June 2036 (Cdn$210.0) Non-Recourse Debt: (2) Epsilon Power Partners term facility, due 2019 LIBOR plus 3.1% Cadillac term loan, due 2025 Piedmont term loan, due 2018 Other long-term debt 5.5% – 6.7% Less: current maturities ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ Total long-term debt $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of current maturities	September 30, 2015 December 31, 2014 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus 3.8% Epsilon Power Partners term facility, due 2019 LIBOR plus 3.1% Cadillac term loan, due 2025 Piedmont term loan, due 2018 Other short-term debt 5.5 – 6.7% ​ ​ ​ ​ ​ ​ ​ ​ ​ Total current maturities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) LIBOR cannot be less than 1.00%. On May 5, 2014, we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $157.7 million amount of the $484.9 million outstanding aggregate borrowings under our senior secured term loan facility. See Note 8, Accounting for derivative instruments and hedging activities for further details. (2) The table does not include non-recourse debt at the Wind Projects, which have been sold and are classified as discontinued operations at December 31, 2014.

Convertible debentures (Tables)

Convertible debentures (Tables)	9 Months Ended
	Sep. 30, 2015
Convertible debentures
Schedule of outstanding convertible debentures	6.25% Debentures due March 2017 5.6% Debentures due June 2017 5.75% Debentures due June 2019 6.00% Debentures due December 2019 Total Balance at December 31, 2014 $ $ $ $ $ Repayment of convertible debentures — ) ) ) ) Foreign exchange gain ) ) — ) ) Gain on repurchase of convertible debentures — — ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at March 31, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repayment of convertible debentures $ — $ ) $ ) $ ) $ ) Foreign exchange gain — Gain on repurchase of convertible debentures — ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at June 30, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repayment of convertible debentures $ — $ ) $ — $ — $ ) Foreign exchange gain ) ) — ) ) Gain on repurchase of convertible debentures — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30, 2015 $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Fair value of financial instr28

Fair value of financial instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	September 30, 2015 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ $ — $ — $ Restricted cash — — Derivative instruments asset — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ — $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Derivative instruments liability $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ $ — $ — $ Restricted cash — — Derivative instruments asset — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Derivative instruments liability $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Accounting for derivative ins29

Accounting for derivative instruments and hedging activities (Tables)	9 Months Ended
	Sep. 30, 2015
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	Notional Units September 30, 2015 December 31, 2014 Natural gas swaps Natural Gas (Mmbtu) Gas purchase agreements Natural Gas (Gj) Interest rate swaps Aggregate Principal (US$)
Schedule of fair value of derivative instruments	September 30, 2015 Derivative Assets Derivative Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ Interest rate swaps long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments not designated as cash flow hedges: Interest rate swaps current — Interest rate swaps long-term Natural gas swaps current — Natural gas swaps long-term — Gas purchase agreements current — Gas purchase agreements long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments not designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Derivative Assets Derivative Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ Interest rate swaps long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments designated as cash flow hedges — ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments not designated as cash flow hedges: Interest rate swaps current — Interest rate swaps long-term Natural gas swaps current — Natural gas swaps long-term — Gas purchase agreements current — Gas purchase agreements long-term — ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments not designated as cash flow hedges ​ ​ ​ ​ ​ ​ ​ ​ Total derivative instruments $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of changes in OCI attributable to derivative financial instruments	For the three months ended September 30, 2015 Interest Rate Swaps Accumulated OCI balance at June 30, 2015 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2015 $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the three months ended September 30, 2014 Interest Rate Swaps Accumulated OCI balance at June 30, 2014 $ ) Change in fair value of cash flow hedges Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2014 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the nine months ended September 30, 2015 Interest Rate Swaps Accumulated OCI balance at January 1, 2015 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2015 $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the nine months ended September 30, 2014 Interest Rate Swaps Accumulated OCI balance at January 1, 2014 $ Change in fair value of cash flow hedges ) Realized from OCI during the period ​ ​ ​ ​ ​ Accumulated OCI balance at September 30, 2014 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges	Three months ended September 30, Nine months ended September 30, Classification of (gain) loss recognized in income 2015 2014 2015 2014 Natural gas swaps Fuel $ $ $ $ Gas purchase agreements Fuel Interest rate swaps Interest, net ) Foreign currency forwards Foreign exchange loss — —
Summary of the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges	Three months ended September 30, Nine months ended September 30, Classification of (gain) loss recognized in income 2015 2014 2015 2014 Natural gas swaps Change in fair value of derivatives $ $ $ ) $ ) Gas purchase agreements Change in fair value of derivatives ) ) ) ) Interest rate swaps Change in fair value of derivatives ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total change in fair value of derivative instruments $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign currency forwards Foreign exchange loss $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
	Sep. 30, 2015
Income taxes
Schedule of components of income tax expense (benefit)	Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Current income tax (benefit) expense $ ) $ $ $ Deferred tax expense (benefit) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total income tax expense (benefit), net $ $ $ ) $ )

Equity compensation plans (Tabl

Equity compensation plans (Tables)	9 Months Ended
	Sep. 30, 2015
Equity compensation plans
Schedule of changes in outstanding LTIP notional units	Units Grant Date Weighted-Average Price per Unit Outstanding at December 31, 2014 $ Granted Reinvested Forfeited ) Vested ) ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at September 30, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Basic and diluted earnings (l32

Basic and diluted earnings (loss) per share (Tables)	9 Months Ended
	Sep. 30, 2015
Basic and diluted earnings (loss) per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	Three months ended September 30, Nine months ended September 30, 2015 2014 2015 2014 Numerator: Loss from continuing operations attributable to Atlantic Power Corporation $ ) $ ) $ ) $ ) (Loss) income from discontinued operations, net of tax ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) attributable to Atlantic Power Corporation $ ) $ ) $ $ ) Denominator: Weighted average basic shares outstanding Dilutive potential shares: Convertible debentures LTIP notional units ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Potentially dilutive shares ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted loss per share from continuing operations attributable to Atlantic Power Corporation $ ) $ ) $ ) $ ) Diluted (loss) income per share from discontinued operations — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted (loss) income per share attributable to Atlantic Power Corporation $ ) $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2015
Equity
Schedule of reconciliation of equity	Nine months ended September 30, 2015 Total Atlantic Power Corporation Shareholders' Equity Preferred shares issued by a subsidiary company Noncontrolling Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) ) Realized an unrealized loss on hedging activities, net of tax ) — — ) Foreign currency translation adjustment ) — — ) Stock-based compensation — — Dividends paid to noncontrolling interests — — ) ) Dividends declared on common shares ) — — ) Dividends declared on preferred shares of a subsidiary company — ) — ) Derecognition of noncontrolling interests upon sale of subsidiaries — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30 $ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine months ended September 30, 2014 Total Atlantic Power Corporation Shareholders' Equity Preferred shares issued by a subsidiary company Noncontrolling Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) ) ) ) Realized and unrealized gain on hedging activities, net of tax — — Foreign currency translation adjustment ) — — ) Stock-based compensation — — Dividends paid to noncontrolling interest — — ) ) Dividends declared on common shares ) — — ) Dividends declared on preferred shares of a subsidiary company — ) — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at September 30 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Segment and geographic inform34

Segment and geographic information (Tables)	9 Months Ended
	Sep. 30, 2015
Segment and geographic information
Schedule of a reconciliation of Project Adjusted EBITDA to project income (loss)	East U.S. West U.S. Canada Un-allocated Corporate Consolidated Three months ended September 30, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) Depreciation and amortization Interest, net — — Other project expense (income) — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) ) Income tax expense — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ $ $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Three months ended September 30, 2014 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) ) Depreciation and amortization Interest, net — — Other project expense (income) — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project loss ) ) ) ) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Loss from continuing operations before income taxes ) ) ) ) ) Income tax expense — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net loss from continuing operations $ ) $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Nine months ended September 30, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments — ) ) Depreciation and amortization Interest, net — — Other project expense (income) — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) Other income, net — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) Income tax benefit — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ East U.S. West U.S. Canada Un-allocated Corporate Consolidated Nine months ended September 30, 2014 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ ) $ Change in fair value of derivative instruments ) — ) ) Depreciation and amortization Interest, net — — — Other project expense (income) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Project income (loss) ) ) ) ) Administration — — — Interest, net — — — Foreign exchange gain — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income (loss) from continuing operations before income taxes ) ) ) ) Income tax benefit — — — ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) from continuing operations $ $ ) $ ) $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of revenue and property, plant and equipment by country	Property, Plant and Equipment, net of accumulated depreciation Project Revenue Three months ended September 30, Project Revenue Nine months ended September 30, September 30, 2015 December 31, 2014 2015 2014 2015 2014 United States $ $ $ $ $ $ Canada ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ $

Nature of business (Details)

Nature of business (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)stateprojectitemMW	Dec. 31, 2014USD ($)
Nature of business
Gross generating capacity of project (in MW)	2,141
Ownership interest in operational power generation projects (in MW)	1,504
Number of operational power generation projects | project	23
Number of states in which power generation projects operate | state	9
Number of provinces in which power generation projects operate | item	2
Number of projects Which are wholly owned subsidiaries | project	18
Deferred financing costs | $	$ 44.8	$ 62.8
Wind Projects | Discontinued Operations, Disposed of by Sale
Nature of business
Wind power project capacity of disposed projects (in MW)	521
Meadow Creek | Discontinued Operations, Disposed of by Sale
Nature of business
Discontinued Operation Ownership Interest Sold	100.00%
Canadian Hills | Discontinued Operations, Disposed of by Sale
Nature of business
Discontinued Operation Ownership Interest Sold	99.00%
Rockland Wind Farm | Discontinued Operations, Disposed of by Sale
Nature of business
Discontinued Operation Ownership Interest Sold	50.00%
Idaho Wind | Discontinued Operations, Disposed of by Sale
Nature of business
Discontinued Operation Ownership Interest Sold	27.60%
Goshen | Discontinued Operations, Disposed of by Sale
Nature of business
Discontinued Operation Ownership Interest Sold	12.50%

Changes in accumulated other 36

Changes in accumulated other comprehensive loss by component (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Changes in accumulated other comprehensive loss by component
Beginning Balance			$ 356.2
Other comprehensive income (loss):
Foreign currency translation adjustments	$ (22.1)	$ (23.1)	(52.6)	$ (24.5)
Tax expense	1.4	1.4	(0.3)	(20)
Total Other comprehensive income	(22.3)	(22.8)	(52.8)	(24.5)
Ending Balance	323		323		$ 356.2
Foreign currency translation
Changes in accumulated other comprehensive loss by component
Beginning Balance	(96.9)	(23.6)	(66.3)	(22.2)	(22.2)
Other comprehensive income (loss):
Foreign currency translation adjustments	(22.1)	(23.1)	(52.6)	(24.5)
Ending Balance	(118.9)	(46.7)	(118.9)	(46.7)	(66.3)
Cash flow hedges
Changes in accumulated other comprehensive loss by component
Beginning Balance	0.1	(0.1)	0.1	0.2	0.2
Other comprehensive income (loss):
Net change from periodic revaluations	(0.7)	0.2	(1.3)	(1)
Tax (expense) benefit	0.3	(0.1)	0.5	0.4
Total Other comprehensive income (loss) before reclassifications, net of tax	(0.4)	0.1	(0.8)	(0.6)
Tax expense	(0.1)	(0.1)	(0.4)	(0.4)
Total amount reclassified from Accumulated other comprehensive loss, net of tax	0.2	0.2	0.6	0.6
Total Other comprehensive income	(0.2)	0.3	(0.2)
Ending Balance	(0.1)	0.2	(0.1)	0.2	0.1
Cash flow hedges | Amount reclassified from accumulated other comprehensive income | Interest rate swaps
Other comprehensive income (loss):
Net amount reclassified to earnings (loss):	0.3	0.3	1	1
Pension
Changes in accumulated other comprehensive loss by component
Beginning Balance	(2.1)	(0.4)	(2.1)	(0.4)	(0.4)
Other comprehensive income (loss):
Ending Balance	$ (2.1)	$ (0.4)	$ (2.1)	$ (0.4)	$ (2.1)

Discontinued operations and o37

Discontinued operations and other divestitures (Details) $ / shares in Units, $ in Millions	Jun. 26, 2015USD ($)itemMW	Mar. 31, 2014USD ($)	Sep. 30, 2015USD ($)$ / shares	Sep. 30, 2014USD ($)$ / shares	Sep. 30, 2015USD ($)$ / sharesMW	Sep. 30, 2014USD ($)$ / shares	Dec. 31, 2014USD ($)
Discontinued operations and other divestitures
Gain on sale of discontinued operations					$ 47.2	$ 2.1
Project other income (expense):
(Loss) income from operations of discontinued businesses, net of tax			$ (0.5)	$ (7.7)	20.6	(21.8)
Net loss attributable to noncontrolling interests of discontinued businesses				(5.1)	(11)	(11.8)
(Loss) income from operations of discontinued businesses, net of noncontrolling interests			$ (0.5)	$ (2.6)	$ 31.6	$ (10)
Current assets:
Total current assets							$ 792.1
Long-term liabilities
Liabilities held for sale							271.8
Discontinued Operations, Held-for-sale or Disposed of by Sale
Discontinued operations and other divestitures
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares					$ 0.26	$ (0.08)
Summary of revenue and loss from discontinued operations
Revenue					$ 34.8	$ 56.8
Project expenses:
Operations and maintenance					10.8	15.7
Depreciation and amortization					10.3	30.2
Total Project expenses					21.1	45.9
Project other income (expense):
Change in fair value of derivatives					(0.7)	(11)
Equity in earnings of unconsolidated affiliates					(37.8)	(0.5)
Interest expense, net					(6.7)	(10.7)
Gain (loss) on sale of asset					84.7	2.1
Total Project other income (expense)					39.5	(20.1)
(Loss) income from operations of discontinued businesses					53.2	(9.2)
Income tax expense					32.6	12.6
(Loss) income from operations of discontinued businesses, net of tax					20.6	(21.8)
Net loss attributable to noncontrolling interests of discontinued businesses					(11)	(11.8)
(Loss) income from operations of discontinued businesses, net of noncontrolling interests					31.6	(10)
Discontinued Operations, Held-for-sale or Disposed of by Sale | APT | Wind (Discontinued Operations) | Wind Projects
Operating and investing cash flows:
Cash provided by operating activities					21.9
Cash (used in) provided by investing activities					$ (12.8)
Discontinued Operations, Disposed of by Sale
Discontinued operations and other divestitures
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares			$ 0
Project other income (expense):
Gain (loss) on sale of asset			$ (0.2)
Total Project other income (expense)			(0.2)
(Loss) income from operations of discontinued businesses			(0.2)
Income tax expense			0.3
(Loss) income from operations of discontinued businesses, net of tax			(0.5)
(Loss) income from operations of discontinued businesses, net of noncontrolling interests			$ (0.5)
Discontinued Operations, Disposed of by Sale | Greeley
Discontinued operations and other divestitures
Gain on sale of discontinued operations		$ 2.1
Proceeds from sale of our outstanding membership interest		$ 1
Discontinued Operations, Disposed of by Sale | Wind Projects
Discontinued operations and other divestitures
Wind power project capacity of disposed projects (in MW) | MW					521
Discontinued Operations, Disposed of by Sale | Goshen
Discontinued operations and other divestitures
Ownership interest sold (as a percent)			12.50%		12.50%
Discontinued Operations, Disposed of by Sale | Idaho Wind
Discontinued operations and other divestitures
Ownership interest sold (as a percent)			27.60%		27.60%
Discontinued Operations, Disposed of by Sale | Meadow Creek
Discontinued operations and other divestitures
Ownership interest sold (as a percent)			100.00%		100.00%
Discontinued Operations, Disposed of by Sale | Rockland Wind Farm
Discontinued operations and other divestitures
Ownership interest sold (as a percent)			50.00%		50.00%
Discontinued Operations, Disposed of by Sale | Canadian Hills
Discontinued operations and other divestitures
Ownership interest sold (as a percent)			99.00%		99.00%
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Wind Projects
Discontinued operations and other divestitures
Consideration received on disposal interests	$ 335
Gain on sale of discontinued operations					$ 47.2
Ownership interest sold (as a percent)	100.00%
Number of operating wind projects sold | item	5
Wind power project capacity of disposed projects (in MW) | MW	521
Project debt deconsolidated	$ 249
Project debt deconsolidated, including adjustment for entities with proportional ownership interest	274
Non-controlling interests deconsolidated	$ 224
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Goshen
Discontinued operations and other divestitures
Ownership interest sold (as a percent)	12.50%
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Idaho Wind
Discontinued operations and other divestitures
Ownership interest sold (as a percent)	27.60%
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Meadow Creek
Discontinued operations and other divestitures
Ownership interest sold (as a percent)	100.00%
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Rockland Wind Farm
Discontinued operations and other divestitures
Ownership interest sold (as a percent)	50.00%
Consolidated ownership interest sold (as a percent)	100.00%
Discontinued Operations, Disposed of by Sale | APT | Wind (Discontinued Operations) | Canadian Hills
Discontinued operations and other divestitures
Consolidated ownership interest sold (as a percent)	99.00%
Discontinued Operations, Held-for-sale
Discontinued operations and other divestitures
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares				$ (0.02)
Summary of revenue and loss from discontinued operations
Revenue				$ 16.7
Project expenses:
Operations and maintenance				5.1
Depreciation and amortization				10.1
Total Project expenses				15.2
Project other income (expense):
Change in fair value of derivatives				(1.3)
Equity in earnings of unconsolidated affiliates				(0.2)
Interest expense, net				(3.5)
Total Project other income (expense)				(5)
(Loss) income from operations of discontinued businesses				(3.5)
Income tax expense				4.2
(Loss) income from operations of discontinued businesses, net of tax				(7.7)
Net loss attributable to noncontrolling interests of discontinued businesses				(5.1)
(Loss) income from operations of discontinued businesses, net of noncontrolling interests				$ (2.6)
Discontinued Operations, Held-for-sale | APT | Wind (Discontinued Operations) | Wind Projects
Discontinued operations and other divestitures
Non-controlling interests deconsolidated							239
Operating and investing cash flows:
Cash provided by operating activities						36.9
Cash (used in) provided by investing activities						$ 6.9
Current assets:
Cash and cash equivalents							3.9
Accounts receivable							11.2
Other current assets							2.4
Total current assets							17.5
Non-current assets:
Plant, property & equipment							710.5
Equity investments in unconsolidated affiliates							38.7
Other intangible assets, net							4.3
Restricted cash							19.1
Other assets							2
Assets held for sale							792.1
Current liabilities:
Accounts payable and other accrued liabilities							5.9
Current portion of long-term debt							6.4
Current portion of derivative instruments liability							3.1
Total current liabilities							15.4
Long-term liabilities
Long-term debt							242.4
Derivative instruments liability							10
Other long-term liabilities							4
Liabilities held for sale							$ 271.8

Discontinued operations and o38

Discontinued operations and other divestitures (Details 2) - Disposal Group, Disposed of by Sale, Not Discontinued Operations $ in Millions	Apr. 22, 2015USD ($)MW	Oct. 31, 2015USD ($)	Jul. 31, 2014USD ($)	Dec. 31, 2012USD ($)	Sep. 30, 2014USD ($)
Delta-Person, LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total price			$ 7.2	$ 37.2
Gain on sale of equity method investment			$ 8.6		$ 8.6
Delta-Person, LP | Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale to be held in escrow account		$ 1.4
Frontier
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest sold (as a percent)	100.00%
Potential solar projects capacity under development (in MW) | MW	20
Consideration received on disposal interests	$ 4.3
Gain on sale of equity method investment	$ 2.3

Equity method investments in 39

Equity method investments in unconsolidated affiliates (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 31, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating results
Revenue		$ 34	$ 41.5	$ 104.9	$ 137.8
Project expenses		24.6	34.1	75.2	115.8
Project other expense		(0.5)	8.2	(1.4)	5.8
Project income		8.9	15.6	28.3	27.8
Delta-Person, LP | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Operating results
Gain on sale of equity method investment	$ 8.6		8.6
Chambers
Operating results
Revenue		11	12	37.3	42.6
Project expenses		9.2	9.9	30.2	35
Project other expense		(0.5)	(0.4)	(1.4)	(2.6)
Project income		1.3	1.7	5.7	5
Orlando
Operating results
Revenue		13.9	13.4	40.9	37.5
Project expenses		7.3	8.1	20.6	24.3
Project income		6.6	5.3	20.3	13.2
Other
Operating results
Revenue		9.1	16.1	26.7	57.7
Project expenses		8.1	16.1	24.4	56.5
Project other expense			8.6		8.4
Project income		$ 1	$ 8.6	$ 2.3	$ 9.6
Other | Maximum
Operating results
Percentage of ownership interest		10.00%		10.00%

Long-term debt (Details)

Long-term debt (Details) - USD ($) $ in Millions	Jul. 26, 2015	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	May. 05, 2014
Long-term debt
Less: current maturities		$ (16.8)	$ (16.8)	$ (20)
Total long-term debt		738.3	738.3	1,145.9
Interest rate swaps
Long-term debt
Notional amount		256.2	256.2	277.4
Senior secured term loan, due 2021
Long-term debt
Total debt		484.9	484.9	541.5
Less: current maturities		$ (4.9)	$ (4.9)	(5.4)
Interest rate (as a percent)		(1.00%)	(1.00%)
Senior secured term loan, due 2021 | London Interbank Offered Rate (LIBOR)
Long-term debt
Minimum percentage of variable rate base			1.00%
Applicable margin (as a percent)			3.80%
Senior secured term loan, due 2021 | London Interbank Offered Rate (LIBOR) | Interest rate swaps
Long-term debt
Notional amount					$ 157.7
Senior secured term loan, due 2018
Long-term debt
Total debt				319.9
Interest rate (as a percent)	9.00%	9.00%	9.00%
Aggregate principal amount of debt repurchased	$ 310.9
Debt Instrument, Redemption Price, Percentage	104.50%
Debt Instrument, Repurchase Amount	$ 330.4
Senior Notes
Long-term debt
Accrued interest and make-whole premiums			$ 14
Applicable redemption make whole premium			5.5
Write off of deferred financing cost related to repurchase		$ 9	9
Senior unsecured notes, due June 2036
Long-term debt
Total debt		$ 157.6	$ 157.6	181
Interest rate (as a percent)		6.00%	6.00%
Epsilon Power Partners term facility, due 2019
Long-term debt
Total debt		$ 21	$ 21	25.5
Less: current maturities		(6)	$ (6)	(6.1)
Epsilon Power Partners term facility, due 2019 | Epsilon Power Partners
Long-term debt
Variable interest rate basis			LIBOR
Epsilon Power Partners term facility, due 2019 | London Interbank Offered Rate (LIBOR)
Long-term debt
Applicable margin (as a percent)			3.10%
Cadillac term loan, due 2025
Long-term debt
Total debt		30.1	$ 30.1	33.4
Less: current maturities		$ (2.5)	$ (2.5)	(3.9)
Interest rate (as a percent)		6.20%	6.20%
Piedmont term loan, due 2018
Long-term debt
Total debt		$ 61.2	$ 61.2	64
Less: current maturities		$ (3.2)	$ (3.2)	(4.5)
Interest rate (as a percent)		5.20%	5.20%
Other long-term debt
Long-term debt
Total debt		$ 0.3	$ 0.3	0.6
Less: current maturities		$ (0.2)	$ (0.2)	$ (0.1)
Other long-term debt | Minimum
Long-term debt
Interest rate (as a percent)		5.50%	5.50%
Other long-term debt | Maximum
Long-term debt
Interest rate (as a percent)		6.70%	6.70%

Convertible debentures (Details

Convertible debentures (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Movement in convertible debentures
Balance at the beginning of the period	$ 304.6	$ 315.7	$ 340.6		$ 340.6
Repayment of convertible debentures	(0.7)	(12.5)	(5.7)
Foreign exchange gain	21.7	3.1	(17.9)	$ 19	49.1	$ 20.4
Gain on repurchase of convertible debentures		(1.7)	(1.3)
Balance at the end of the period	291.9	304.6	315.7		291.9		$ 340.6
NCIB
Movement in convertible debentures
Repayment of convertible debentures							(24.6)
Gain on repurchase of convertible debentures					(3)
NCIB | Maximum
Movement in convertible debentures
Aggregate principal amount of debt repurchased	31				31
6.25% Debentures due March 2017
Movement in convertible debentures
Balance at the beginning of the period	53.9	53.1	58		58
Foreign exchange gain	(3.5)	0.8	(4.9)
Balance at the end of the period	50.4	53.9	53.1		50.4		58
5.6% Debentures due June 2017
Movement in convertible debentures
Balance at the beginning of the period	61.7	62.7	68.6		68.6
Repayment of convertible debentures	(0.7)	(2)	(0.1)
Foreign exchange gain	(3.9)	1.1	(5.8)
Gain on repurchase of convertible debentures		(0.1)
Balance at the end of the period	57.1	61.7	62.7		57.1		68.6
5.75% Debentures due June 2019
Movement in convertible debentures
Balance at the beginning of the period	117	124	128.4		128.4
Repayment of convertible debentures		(6)	(3.6)
Gain on repurchase of convertible debentures		(1.2)	(0.8)
Balance at the end of the period	117	117	124		117		128.4
6.00% Debenture due December 2019
Movement in convertible debentures
Balance at the beginning of the period	72	75.9	85.6		85.6
Repayment of convertible debentures		(4.5)	(2)
Foreign exchange gain	(4.6)	1.2	(7.2)
Gain on repurchase of convertible debentures		(0.6)	(0.5)
Balance at the end of the period	$ 67.4	$ 72	$ 75.9		$ 67.4		$ 85.6

Fair value of financial instr42

Fair value of financial instruments (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Assets:
Restricted cash	$ 14.5	$ 22.5
Recurring | Fair Value
Assets:
Cash and cash equivalents	76.4	106
Restricted cash	14.5	22.5
Derivative instruments asset		1.1
Total	90.9	129.6
Liabilities:
Derivative instruments liability	66	83.6
Total	66	83.6
Recurring | Level 1
Assets:
Cash and cash equivalents	76.4	106
Restricted cash	14.5	22.5
Total	90.9	128.5
Recurring | Level 2
Assets:
Derivative instruments asset		1.1
Total		1.1
Liabilities:
Derivative instruments liability	66	83.6
Total	$ 66	$ 83.6

Fair value of financial instr43

Fair value of financial instruments (Details 2) - Credit valuation adjustments - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Recurring measurements of fair value hierarchy of financial assets and liabilities
Net increase in fair value	$ 4.4	$ 8.3
Pre-tax gain in other comprehensive income	0.4	0.7
Gain in change in fair value of derivatives	$ 4	$ 7.6

Accounting for derivative ins44

Accounting for derivative instruments and hedging activities (Details) $ in Millions	May. 05, 2014USD ($)	Feb. 20, 2014USD ($)	Jun. 30, 2014MMBTU	Sep. 30, 2015USD ($)MMBTUitem	Dec. 31, 2014USD ($)MMBTU	Feb. 14, 2014USD ($)
Accounting for derivative instruments and hedging activities
Derivative Number of Contracts Designated as Cash Flow Hedges | item				1
New term loan facility | Adjusted Eurodollar Rate
Derivative instruments
Applicable margin (as a percent)	3.75%
Minimum percentage of variable rate base	1.00%
Gas purchase agreements | Ontario project
Derivative instruments
Notional amount (in Mmbtu) | MMBTU			2,900,000
Expected uncontracted gas requirements for 2015 | Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements				100.00%
Expected uncontracted gas requirements for 2016 | Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements				35.00%
Expected uncontracted gas requirements for 2017 | Ontario project
Derivative instruments
Percentage of the entity's expected uncontracted gas requirements				30.00%
Natural gas swaps
Derivative instruments
Notional amount (in Mmbtu) | MMBTU				3.6	6.3
Natural gas swaps | Ontario project
Derivative instruments
Amount paid for termination of contracts		$ 4
Natural gas swaps | Orlando project
Derivative instruments
Notional amount (in Mmbtu) | MMBTU				6,300,000
Interest rate swaps
Derivative instruments
Notional amount				$ 256.2	$ 277.4
Interest rate swaps | New term loan facility
Derivative instruments
Minimum fixed interest rate (as a percent)	4.75%
Maximum fixed interest rate (as a percent)	4.91%
Interest rate swaps | New term loan facility | Adjusted Eurodollar Rate
Derivative instruments
Notional amount	$ 199			157.7
Aggregate principal amount of debt	$ 600			$ 484.9
Interest rate swaps | New term loan facility | Adjusted Eurodollar Rate | Derivative instruments not designated as cash flow hedges
Derivative instruments
Swaption interest rate (as a percent)	1.16%
Interest rate swaps | Epsilon Power Partners
Derivative instruments
Amount paid for termination of contracts		2.6
Swaption interest rate (as a percent)				7.37%
Interest rate swaps | Piedmont | Piedmont construction loan, due 2014
Derivative instruments
Total debt						$ 68.5
Interest rate swaps | Swaption interest rate until February 15, 2015 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)				6.00%
Interest rate swaps | Swaption interest rate from February 16, 2015 to February 15, 2019 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)				6.10%
Interest rate swaps | Swaption interest rate from February 16, 2019 to February 15, 2023 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)				6.30%
Interest rate swaps | Swaption interest rate after February 15, 2023 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)				6.40%
Interest rate swaps | Swaption interest rate until February 29, 2016 | Piedmont
Derivative instruments
Swaption interest rate (as a percent)				1.70%
Applicable margin, low end of range (as a percent)				3.50%
Applicable margin, high end of range (as a percent)				3.80%
Interest rate swaps | Swaption interest rate from February, 2016 to November, 2017 | Piedmont
Derivative instruments
Swaption interest rate (as a percent)				4.47%
Applicable margin of derivative (as a percent)				4.00%
Swaption interest rate after addition of applicable margin (as a percent)				8.50%
Interest rate swaps | Swaption interest rate from November, 2017 to November, 2030 | Piedmont
Derivative instruments
Swaption interest rate (as a percent)				4.47%
Foreign currency forward contracts
Derivative instruments
Amount paid for termination of contracts		$ 0.4
Natural gas swaps during remainder of 2014 | Orlando project
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge				100.00%
Natural gas swaps during 2015 | Orlando project
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge				96.00%
Natural gas swaps during 2016 | Orlando project
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge				64.00%

Accounting for derivative ins45

Accounting for derivative instruments and hedging activities (Details 2) kJ in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015USD ($)MMBTUkJ	Dec. 31, 2014USD ($)MMBTUkJ
Natural gas swaps
Derivative instruments
Volume of forecasted transactions	3.6	6.3
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions | kJ	27.2	33.9
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $	$ 256.2	$ 277.4

Accounting for derivative ins46

Accounting for derivative instruments and hedging activities (Details 3) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Fair value of derivative instruments
Derivative Assets		$ 1.1
Derivative Liabilities	$ 66	83.6
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	4.2	4
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	1.1	1.1
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	3.1	2.9
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets		1.1
Derivative Liabilities	61.8	79.6
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	2.4	2
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Assets		1.1
Derivative Liabilities	9	6.9
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current
Fair value of derivative instruments
Derivative Liabilities	4.4	4.4
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	1.1	2.2
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current
Fair value of derivative instruments
Derivative Liabilities	27.2	28.6
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term
Fair value of derivative instruments
Derivative Liabilities	$ 17.7	$ 35.5

Accounting for derivative ins47

Accounting for derivative instruments and hedging activities (Details 4) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges	$ (0.4)	$ 0.1	$ (0.8)	$ (0.6)
Realized from OCI during the period	0.2	0.2	0.6	0.6
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	0.1	(0.1)	0.1	0.2
Change in fair value of cash flow hedges	(0.4)	0.1	(0.8)	(0.6)
Realized from OCI during the period	0.2	0.2	0.6	0.6
Accumulated OCI balance at end of period	$ (0.1)	$ 0.2	$ (0.1)	$ 0.2

Accounting for derivative ins48

Accounting for derivative instruments and hedging activities (Details 5) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ 3.6	$ 1.7	$ 8.7	$ 23.3
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	(3.6)	(1.7)	(8.7)	(23.3)
Derivative instruments not designated as cash flow hedges | Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	1.5	0.3	4.3	4
Change in fair value of derivative instruments	0.1	1.5	(0.7)	(2)
Derivative instruments not designated as cash flow hedges | Gas purchase agreements
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	11.8	13.3	36.1	42.6
Change in fair value of derivative instruments	(6.1)	(2.1)	(11.6)	(20.7)
Derivative instruments not designated as cash flow hedges | Interest rate swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments	0.5	(0.2)	1.7	4.4
Change in fair value of derivative instruments	$ 2.4	(1.1)	$ 3.6	(0.6)
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) of derivative instruments		0.6		0.5
Change in fair value of derivative instruments		$ 1.4		$ 1.1

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Components of income tax expenses (benefit)
Current income tax (benefit) expense	$ (1.6)	$ 1.1	$ 5.7	$ 3.7
Deferred tax expense (benefit)	3	0.3	(6)	(23.7)
Total income tax expense (benefit), net	$ 1.4	$ 1.4	$ (0.3)	$ (20)
Canadian enacted statutory rate (as a percent)	26.00%	26.00%	26.00%	26.00%
Computed income taxes at Canadian statutory rate	$ 0.5	$ 21.4	$ 0.3	$ 43.2
Foreign exchange	2.2	3.5	6.3	4.7
Operating in higher tax rates jurisdictions	0.1	4.8	4	17.9
Tax credits			3.6
Other permanent differences		0.6	0.6	0.2
Change in valuation allowance	4	5.1	10.1	34.4
Capital gain on repatriation of wind sale proceeds	2.8		2.8
Dividend withholding and other state taxes	2.6		1
Intraperiod allocation		8.3		11.9
Minority interest adjustments		2.6
Goodwill impairment		$ 33.7		33.7
Capital losses on tax restructuring				$ 10.6
Valuation allowance	$ 178.7		$ 178.7

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	Jan. 22, 2015$ / shares	Sep. 30, 2015USD ($)$ / sharesshares	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)item$ / sharesshares	Sep. 30, 2014USD ($)
Transition equity participation agreement
Units
Granted (in shares)				542,606
Transition equity participation agreement
Granted (in shares)				542,606
Vesting percentage				50.00%
Vesting period				4 years
Period after which remaining portions vests				2 years
Market price (in dollars per share) | $ / shares	$ 2.58
Minimum percentage by which weighted average Canadian dollar price exceeds market price	50.00%
Minimum | Transition equity participation agreement
Transition equity participation agreement
Number of consecutive months, weighted average Canadian dollar price exceeds market price of share by 50% | item				3
Long-term incentive plan
Units
Outstanding at the beginning of the period (in shares)				1,443,254
Granted (in shares)				1,007,726
Reinvested (in shares)				43,440
Forfeited (in shares)				(131,934)
Vested (in shares)				(1,022,181)
Outstanding at the end of the period (in shares)		1,340,305		1,340,305
Weighted-Average Price per Unit
Outstanding at the beginning of the period (in dollars per share) | $ / shares				$ 3.28
Granted (in dollars per share) | $ / shares				2.75
Reinvested (in dollars per share) | $ / shares				2.86
Forfeited (in dollars per share) | $ / shares				3.70
Vested (in dollars per share) | $ / shares				3.23
Outstanding at the end of the period (in dollars per share) | $ / shares		$ 2.88		$ 2.88
Cash payments made for vested notional units | $				$ 1	$ 0.2
Compensation expense related to LTIP | $		$ 1	$ 0.9	$ 2	$ 1.8
Transition equity participation agreement
Granted (in shares)				1,007,726

Basic and diluted earnings (l51

Basic and diluted earnings (loss) per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Numerator:
Loss from continuing operations attributable to Atlantic Power Corporation	$ (5.5)	$ (86.3)	$ (5.5)	$ (156.9)
(Loss) income from discontinued operations, net of tax	(0.5)	(2.6)	31.6	(10)
Net (loss) income attributable to Atlantic Power Corporation	$ (6)	$ (88.9)	$ 26.1	$ (166.9)
Denominator:
Weighted average basic shares outstanding	122.1	120.7	121.8	120.6
Dilutive potential shares:
Convertible debentures (in shares)	22.4	27.7	22.8	27.7
LTIP notional units (in shares)	0.1	0.6	0.1	0.2
Potentially dilutive shares	144.6	149	144.7	148.5
Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$ 0.05	$ (0.72)	$ (0.05)	$ (1.30)
Diluted (loss) income per share from discontinued operations		(0.02)	0.26	(0.08)
Diluted (loss) income per share attributable to Atlantic Power Corporation	$ 0.05	$ (0.74)	$ 0.21	$ (1.38)
Potentially dilutive convertible debenture excluded from calculation of EPS	22.4	27.7	22.8	27.7

Equity (Details)

Equity (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Increase (decrease) in shareholders' equity
Balance at the beginning of the period			$ 816.5	$ 1,096
Net income (loss)			21.8	(169.9)
Realized and unrealized gain on hedging activities, net of tax	$ (0.2)	$ 0.3	(0.2)	0.1
Foreign currency translation adjustments	(22.1)	(23.1)	(52.6)	(24.5)
Stock-based compensation			2	0.8
Dividends paid to noncontrolling interests			(3.7)	(8.8)
Dividends declared on common shares			(8.5)	(28.1)
Dividends declared on preferred shares			(6.7)	(8.8)
Derecognition of noncontrolling interests upon sale of subsidiaries			(224.3)
Balance at the end of the period	544.3	856.8	544.3	856.8
Total Atlantic Power Corporation Shareholder's Equity
Increase (decrease) in shareholders' equity
Balance at the beginning of the period			356.2	608.3
Net income (loss)			26.1	(166.9)
Realized and unrealized gain on hedging activities, net of tax			(0.2)	0.1
Foreign currency translation adjustments			(52.6)	(24.5)
Stock-based compensation			2	0.8
Dividends declared on common shares			(8.5)	(28.1)
Balance at the end of the period	323	389.7	323	389.7
Preferred shares issued by a subsidiary company
Increase (decrease) in shareholders' equity
Balance at the beginning of the period			221.3	221.3
Net income (loss)			6.7	8.8
Dividends declared on preferred shares			(6.7)	(8.8)
Balance at the end of the period	$ 221.3	221.3	221.3	221.3
Noncontrolling Interests
Increase (decrease) in shareholders' equity
Balance at the beginning of the period			239	266.4
Net income (loss)			(11)	(11.8)
Dividends paid to noncontrolling interests			(3.7)	(8.8)
Derecognition of noncontrolling interests upon sale of subsidiaries			$ (224.3)
Balance at the end of the period		$ 245.8		$ 245.8

Segment and geographic inform53

Segment and geographic information (Details) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)item	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Segment and geographic information
Number of Reportable Segments | item					4
Segment and geographic information
Project revenues	$ 107.5			$ 121.6	$ 321.8	$ 370
Segment assets	1,910.2			2,178.1	1,910.2	2,178.1	$ 2,916.6
Project Adjusted EBITDA	56			58.1	158.5	172.6
Change in fair value of derivative instruments	(3.6)			(1.8)	(8.7)	(23.1)
Depreciation and amortization	32.8			38.9	98.9	120.6
Interest, net	2.5			3	7.7	18.1
Impairment				(91.8)		(106.6)
Other project expense (income)	0.1			83.1	(2.2)	(106.6)
Project income (loss)	24.2			(65.1)	63	(41)
Administration	6.9			9.2	23	26.7
Interest, net	41			26.7	91.3	120.8
Foreign exchange gain	(21.7)	$ (3.1)	$ 17.9	(19)	(49.1)	(20.4)
Other income, net					(3.1)
Income (loss) from continuing operations before income taxes	(2)			(82)	0.9	(168.1)
Income tax benefit	1.4			1.4	(0.3)	(20)
(Loss) income from continuing operations	(3.4)			(83.4)	1.2	(148.1)
Operating Segments | East U.S.
Segment and geographic information
Project revenues	38.4			39.5	114.8	130.1
Segment assets	849.7			963.9	849.7	963.9
Project Adjusted EBITDA	27.4			27.3	81	82.4
Change in fair value of derivative instruments	1.9			1.1	1.6	(2.8)
Depreciation and amortization	10.7			13.8	31.8	44.3
Interest, net	2.4			2.7	7.6	18.1
Other project expense (income)				17.9		18
Project income (loss)	12.4			(8.2)	40	4.8
Income (loss) from continuing operations before income taxes	12.4			(8.2)	40	4.8
(Loss) income from continuing operations	12.4			(8.2)	40	4.8
Operating Segments | West U.S.
Segment and geographic information
Project revenues	34.5			39	83.9	99.1
Segment assets	368.7			418.2	368.7	418.2
Project Adjusted EBITDA	21.4			21.3	37.1	44.8
Depreciation and amortization	9.9			9.8	29.7	30.3
Other project expense (income)				41.4	0.1	41.6
Project income (loss)	11.5			(29.9)	7.3	(27.1)
Income (loss) from continuing operations before income taxes	11.5			(29.9)	7.3	(27.1)
(Loss) income from continuing operations	11.5			(29.9)	7.3	(27.1)
Operating Segments | Canada
Segment and geographic information
Project revenues	34.4			42.9	122.6	140.2
Segment assets	569.7			714.9	569.7	714.9
Project Adjusted EBITDA	7.6			12.3	43	51.6
Change in fair value of derivative instruments	(6.1)			(2.1)	(11.6)	(20.7)
Depreciation and amortization	11.7			15.1	36.5	45.5
Interest, net	0.1				0.1
Other project expense (income)				23.8	0.1	38.6
Project income (loss)	1.9			(24.5)	17.9	(11.8)
Income (loss) from continuing operations before income taxes	1.9			(24.5)	17.9	(11.8)
(Loss) income from continuing operations	1.9			(24.5)	17.9	(11.8)
Un-Allocated Corporate
Segment and geographic information
Project revenues	0.2			0.2	0.5	0.6
Segment assets	122.1			81.1	122.1	81.1
Project Adjusted EBITDA	(0.4)			(2.8)	(2.6)	(6.2)
Change in fair value of derivative instruments	0.6			(0.8)	1.3	0.4
Depreciation and amortization	0.5			0.2	0.9	0.5
Interest, net				0.3
Other project expense (income)	0.1				(2.6)	(0.2)
Project income (loss)	(1.6)			(2.5)	(2.2)	(6.9)
Administration	6.9			9.2	23	26.7
Interest, net	41			26.7	91.3	120.8
Foreign exchange gain	(21.7)			(19)	(49.1)	(20.4)
Other income, net					(3.1)
Income (loss) from continuing operations before income taxes	(27.8)			(19.4)	(64.3)	(134)
Income tax benefit	1.4			1.4	(0.3)	(20)
(Loss) income from continuing operations	$ (29.2)			$ (20.8)	$ (64)	$ (114)

Segment and geographic inform54

Segment and geographic information (Details 2) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Revenue and Assets
Project revenue	$ 107.5	$ 121.6	$ 321.8	$ 370
Property, Plant and Equipment, net of accumulated depreciation	875.7		875.7		$ 962.9
Impairement of goodwill		91.8
United States
Revenue and Assets
Project revenue	73.1	78.7	199.2	229.8
Property, Plant and Equipment, net of accumulated depreciation	537.2		537.2		553.5
Canada
Revenue and Assets
Project revenue	34.4	$ 42.9	122.6	$ 140.2
Property, Plant and Equipment, net of accumulated depreciation	$ 338.5		$ 338.5		$ 409.4

Segment and geographic inform55

Segment and geographic information (Details 3) - Revenues, net - Consolidated revenue	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	22.90%	21.30%	27.70%	23.80%
San Diego Gas & Electric
Consolidated revenue concentration
Percentage of consolidated revenue	16.70%	18.70%	12.60%	16.20%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	10.20%	9.80%	10.40%	9.00%
Georgia Power
Consolidated revenue concentration
Percentage of consolidated revenue	9.10%		7.70%

Contingencies (Details)

Contingencies (Details) $ in Millions	Mar. 31, 2014item	Sep. 09, 2013item	Aug. 19, 2013item	May. 07, 2013item	Sep. 30, 2015item	Oct. 04, 2013USD ($)
Commitments and contingencies
Number of District Court actions alleged from July 23, 2010 to March 4, 2013					3
Number of District Court actions alleged from August 8, 2012 to February 28, 2013					2
Number of actions were succeeded by specific action with an amended claim					3
Number of actions by which specific Ontario actions were succeeded					1
Shareholder class action lawsuits
Commitments and contingencies
Number of purported securities fraud class action complaints filed					5
Number of action complaints filed ordered to consolidate			5		5
Number of plaintiff applicants directed to file supplemental submissions		2
Extension term					30 days
Number of notices of actions relating to Canadian securities class action claims					3
Estimate damages claimed for statutory misrepresentation | $						$ 197.4
Number of District Court actions in which discoveries are stayed					5
Number of investors filed motion				6
Number of pending matters having material adverse impact on financial position or results of operations or have been reserved					0
Number of District Court actions alleged in specific period	5
Number of plaintiff applicants directed resubmit a proposed schedule that contains specific dates	1