Atlantic Power 10-Q 7 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 04, 2016
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, 2016
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		115,635,212
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 93.8	$ 72.4
Restricted cash	12.6	15.2
Accounts receivable	39.5	39.6
Current portion of derivative instruments asset (Notes 8 and 9)	1.6
Inventory	15.9	16.9
Prepayments	10.1	8.3
Other current assets	2.5	4.5
Total current assets	176	156.9
Property, plant, and equipment, net of accumulated depreciation of $279.2 million and $236.3 million at September 30, 2016 and December 31, 2015, respectively	749.8	777.7
Equity investments in unconsolidated affiliates (Note 5)	277.6	286.2
Power purchase agreements and intangible assets, net of accumulated amortization of $282.5 million and $238.0 million at September 30, 2016 and December 31, 2015, respectively	273	308.9
Goodwill (Note 3)	37.6	134.5
Derivative instruments asset (Notes 8 and 9)	1.3	0.3
Deferred income taxes	1
Other assets	5.6	6.7
Total assets	1,521.9	1,671.2
Current liabilities:
Accounts payable	3.7	6.9
Accrued interest	10.9	1.6
Other accrued liabilities	24.3	25.4
Current portion of long-term debt (Note 6)	101.4	15.8
Current portion of derivative instruments liability (Notes 8 and 9)	15.2	36.7
Other current liabilities	4.1	2.5
Total current liabilities	159.6	88.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 6)	778.9	682.7
Convertible debentures, net of unamortized deferred financing costs (Note 7)	101.4	277.7
Derivative instruments liability (Notes 8 and 9)	27.3	20.8
Deferred income taxes	69.8	85.7
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $15.9 million and $14.0 million at September 30, 2016 and December 31, 2015, respectively	26.2	27
Other long-term liabilities	54.9	53.2
Total liabilities	1,218.1	1,236
Equity
Common shares, no par value, unlimited authorized shares; 117,029,308 and 122,153,082 issued and outstanding at September 30, 2016 and December 31, 2015, respectively (Note 13)	1,278.1	1,290.6
Accumulated other comprehensive loss (Note 2)	(142)	(139.3)
Retained deficit (Note 13)	(1,053.6)	(937.4)
Total Atlantic Power Corporation shareholders' equity	82.5	213.9
Preferred shares issued by a subsidiary company (Note 13)	221.3	221.3
Total equity	303.8	435.2
Total liabilities and equity	$ 1,521.9	$ 1,671.2

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
CONSOLIDATED BALANCE SHEETS
Accumulated Depreciation on Property, Plant, and Equipment	$ 279.2	$ 236.3
Accumulated amortization on power purchase agreements and other intangible assets	282.5	238
Accumulated amortization on power purchase and fuel supply agreement liabilities	$ 15.9	$ 14
Common shares, no par value (in dollars per share)	$ 0	$ 0
Common Stock, Shares Authorized, Unlimited	Unlimited	Unlimited
Common shares, issued shares (in shares)	117,029,308	122,153,082
Common shares, outstanding shares (in shares)	117,029,308	122,153,082

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Project revenue:
Energy sales	$ 40.7	$ 43.4	$ 138.4	$ 144.9
Energy capacity revenue	44	45.9	113.2	117.4
Other	16.5	18.2	54.2	59.5
Total project revenue	101.2	107.5	305.8	321.8
Project expenses:
Fuel	36.8	41.1	110.8	125.3
Operations and maintenance	28.2	24.8	79.4	81.6
Development				1.1
Depreciation and amortization	25.3	27.8	75.6	83.8
Total project expenses	90.3	93.7	265.8	291.8
Project other income (loss):
Change in fair value of derivative instruments (Notes 8 and 9)	9	3.6	20	8.7
Equity in earnings of unconsolidated affiliates (Note 5)	9.6	8.9	27.9	28.3
Interest, net	(2.4)	(2.1)	(6.9)	(6.2)
Impairment (Note 3)	(84.7)		(84.7)
Other income, net	0.5		0.4	2.2
Total project other income (expense)	(68)	10.4	(43.3)	33
Project (loss) income	(57.1)	24.2	(3.3)	63
Administrative and other expenses (income):
Administration	5.7	6.9	17.6	23
Interest, net	20	41	87.9	91.3
Foreign exchange (gain) loss	(3.4)	(21.7)	19.1	(49.1)
Other income, net (Note 7)	(1.7)		(3.9)	(3.1)
Total administrative and other expenses (income)	20.6	26.2	120.7	62.1
(Loss) income from continuing operations before income taxes	(77.7)	(2)	(124)	0.9
Income tax (benefit) expense (Note 10)	2.6	1.4	(14.2)	(0.3)
(Loss) income from continuing operations	(80.3)	(3.4)	(109.8)	1.2
Net (loss) income from discontinued operations, net of tax (Note 4)		(0.5)		20.6
Net (loss) income	(80.3)	(3.9)	(109.8)	21.8
Net loss attributable to noncontrolling interests				(11)
Net income attributable to preferred shares dividends of a subsidiary company	2.1	2.1	6.4	6.7
Net (loss) income attributable to Atlantic Power Corporation	$ (82.4)	$ (6)	$ (116.2)	$ 26.1
Basic and diluted (loss) income per share: (Note 12)
Loss from continuing operations attributable to Atlantic Power Corporation	$ (0.69)	$ (0.05)	$ (0.96)	$ (0.05)
Income from discontinued operations, net of tax				0.26
Net (loss) income attributable to Atlantic Power Corporation	$ (0.69)	$ (0.05)	$ (0.96)	$ 0.21
Weighted average number of common shares outstanding: (Note 12)
Basic (in shares)	119.3	122.1	120.9	121.8
Diluted (in shares)	119.3	122.2	120.9	121.9
Dividends per common share (in dollars per share)		$ 0.02		$ 0.07

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Net (loss) income	$ (80.3)	$ (3.9)	$ (109.8)	$ 21.8
Other comprehensive (loss) income, net of tax
Unrealized (loss) gain on hedging activities		(0.4)	(0.6)	(0.8)
Net amount reclassified to earnings	0.2	0.2	0.5	0.6
Net unrealized gain (loss) on derivatives	0.2	(0.2)	(0.1)	(0.2)
Foreign currency translation adjustments	(22)	(22.1)	(2.6)	(52.7)
Other comprehensive loss, net of tax	(21.8)	(22.3)	(2.7)	(52.9)
Comprehensive loss	(102.1)	(26.2)	(112.5)	(31.1)
Less: Comprehensive income (loss) attributable to noncontrolling interests	2.1	2.1	6.4	(4.3)
Comprehensive loss attributable to Atlantic Power Corporation	$ (104.2)	$ (28.3)	$ (118.9)	$ (26.8)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash provided by operating activities:
Net (loss) income	$ (109.8)	$ 21.8
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	75.6	94.1
Gain from discontinued operations		(47.2)
Gain on sale of development project and other assets		(2.3)
Gain on purchase and cancellation of convertible debentures	(4.7)	(3.1)
Loss on disposal of fixed assets	0.2
Stock-based compensation expense	1.4	2.1
Long-lived asset and goodwill impairment	84.7
Equity in earnings from unconsolidated affiliates	(27.9)	(28.3)
Distributions from unconsolidated affiliates	36.5	40
Unrealized foreign exchange loss (gain)	19.1	(49.3)
Change in fair value of derivative instruments	(20)	(8)
Change in deferred income taxes	(16.8)	23.6
Change in other operating balances
Accounts receivable		4.3
Inventory	1.1	1.7
Prepayments and other assets	42.1	20.2
Accounts payable	0.3	(6.1)
Accruals and other liabilities	10.1	4.2
Cash provided by operating activities	91.9	67.7
Cash provided by investing activities:
Change in restricted cash	2.6	8
Proceeds from sale of assets and equity investments, net		326.3
Contribution to unconsolidated affiliate		(0.5)
Capitalized development costs		(0.8)
Reimbursement of costs for third-party construction project	4.7
Purchase of property, plant and equipment	(6.5)	(9.4)
Cash provided by investing activities	0.8	323.6
Cash used in financing activities:
Proceeds from senior secured term loan facility, net of discount	679
Common share repurchases	(13.9)
Repayment of corporate and project-level debt	(526.4)	(387.1)
Repayment of convertible debentures	(187.4)	(18.7)
Deferred financing costs	(16.2)
Dividends paid to common shareholders		(8.5)
Dividends paid to noncontrolling interests		(3.8)
Dividends paid to preferred shareholders	(6.4)	(6.7)
Cash used in financing activities	(71.3)	(424.8)
Increase (decrease) in cash and cash equivalents	21.4	(33.5)
Less cash at discontinued operations		3.9
Cash and cash equivalents at beginning of period	72.4	106
Cash and cash equivalents at end of period	93.8	76.4
Supplemental cash flow information
Interest paid	43.3	75.5
Income taxes paid, net	2.8	4.1
Accruals for construction in progress	$ 0.4	$ 1.2

Nature of business

Nature of business	9 Months Ended
	Sep. 30, 2016
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, 2016, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 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. Atlantic Power is a corporation established under the laws of the Province of Ontario 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, 2015. 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, 2016, the results of operations and comprehensive loss for the three and nine months ended September 30, 2016 and 2015, and our cash flows for the nine months ended September 30, 2016 and 2015 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 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, 2015. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount. Recently issued accounting standards Adopted In January 2015, the Financial Accounting Standards Board (“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 statement of operations, 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 became effective for us on January 1, 2016. The adoption of these changes did 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 became effective for us on January 1, 2016. The adoption of these changes did not have an impact 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 became effective for us on January 1, 2016. As a result, we have presented $19.5 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended September 30, 2016 and December 31, 2015, respectively. 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 statement of operations 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 became effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations. 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 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 a material impact on the consolidated financial statements. In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after December 15, 2016 and is not expected to have a material impact on the consolidated financial statements. In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a right-of-use asset and a lease liability, measured on a discounted basis, at the commencement date for all leases with terms greater than twelve months. Additionally, this guidance will require disclosures to help investors and other financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The guidance should be applied under a modified retrospective transition approach for leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. This guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance. In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance. In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements.

Changes in accumulated other co

Changes in accumulated other comprehensive loss by component	9 Months Ended
	Sep. 30, 2016
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, 2016 2015 2016 2015 Foreign currency translation Balance at beginning of period $ $ $ $ Other comprehensive income (loss): Foreign currency translation adjustments (1) Balance at end of period $ $ $ $ Cash flow hedges Balance at beginning of period $ $ $ $ Other comprehensive income (loss): Net change from periodic revaluations Tax (expense) benefit Total Other comprehensive income before reclassifications, net of tax — Net amount reclassified to earnings: 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.

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2016
Goodwill
Goodwill	3. Goodwill Our goodwill balance was $37.6 million and $134.5 million as of September 30, 2016 and December 31, 2015, respectively. We apply an accounting standard under which goodwill has an indefinite life and is not amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which discrete financial information is available. In the third quarter of 2016, we performed an event-driven goodwill impairment test. While declining power prices have been observed over the past two years, we identified a significant decrease in the long-term outlook for power prices in the regions where our reporting units operate in the third quarter of 2016. Because the estimated future cash flows of our reporting units are sensitive to fluctuations in forward power prices and these prices are the most impactful input in calculating a reporting unit’s fair value, we determined that it was appropriate to perform an event-driven impairment test. For two of our reporting units (Morris and Nipigon) we performed a qualitative assessment and concluded that it was likely that the fair values significantly exceed the carrying values. These reporting units have aggregate goodwill of $6.9 million and have PPAs with significant remaining time before their expiration and are not significantly impacted by the decrease in the long-term outlook for power prices. The other five of the reporting units tested (Curtis Palmer, Mamquam, North Bay, Kapuskasing and Moresby Lake) failed step 1 of our quantitative two‑step test. Because five reporting units failed step 1 of the two-step goodwill impairment test, we identified a triggering event and initiated a test of the recoverability of their long-lived assets. The asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the five asset groups tested, the North Bay and Kapuskasing asset groups (Canada segment) failed the recoverability test and we recorded property, plant and equipment impairment charges aggregating $5.9 million for the periods ended September 30, 2016. For these asset groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These assumptions include estimated cash flows under the remaining period of their respective PPAs. Subsequent to recording long-lived asset impairments, we performed the step 2 goodwill impairment test and recorded a $50.2 million full impairment at the Mamquam reporting unit, a $15.4 million partial impairment at the Curtis Palmer reporting unit, a $6.5 million full impairment at the North Bay reporting unit, a $6.7 million full impairment at the Kapuskasing reporting unit and no impairment at the Moresby Lake reporting unit for a total goodwill impairment charge of $78.8 million for the periods ended September 30, 2016. At the time of their acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Mamquam and Curtis Palmer reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the respective markets in which those plants operate, have declined from 2011 and from the dates of our previous impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices resulting from an abundance of shale gas. Our forecasts for discounted cash flows also reflect a higher level of uncertainty for re‑contracting at prices than were previously forecasted in 2011. The decline in forward power prices for British Columbia since our last goodwill impairment performed as of November 30, 2015, in particular, had a significant impact on the estimated discounted cash flows of our Mamquam reporting unit and was the primary driver for its recorded goodwill impairment. British Columbia’s peak demand outlook has declined primarily attributable to a reduction in forecasted liquefaction build and need in the region and the associated loss of power demand. The resulting drop in the peak demand reduces the amount of needed capacity and therefore the capacity prices also were reduced. Furthermore, the PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill impairment test, we anticipate the PPA expiring two years before December 2027. As a result, the discounted cash flow model for Curtis Palmer utilizes forward power prices for that two-year period that are substantially lower than the prices under the current PPA. The long-lived asset and goodwill impairment charges were recorded in the third quarter of 2016 and not earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment assessment. While declining power prices have been observed over the past two years, the significant decrease in the long-term outlook for power prices in the regions where our reporting units operate identified in the third quarter of 2016 had the most significant impact to the key inputs to our long-term forecasted cash flow models. Additionally, the PPAs at our North Bay and Kapuskasing reporting units expire on December 31, 2017. As these projects approach the expiration date, the remaining estimated contracted future cash flows decrease. We determine the fair value of our reporting units using an income approach with discounted cash flow (“DCF”) models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long‑lived asset recovery and step 1 and 2 goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long‑term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third-party sources. We utilized the assistance of valuation experts to perform step 1 and step 2 of the quantitative impairment test for several of our reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill. The valuation of long-lived assets and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts. The following table is a rollforward of goodwill for the nine months ended September 30, 2016: December 31, Translation September 30, Reporting unit Segment 2015 Impairment adjustment 2016 Curtis Palmer East U.S. $ $ $ — $ Morris East U.S. — — Kapuskasing Canada — Mamquam Canada — Moresby Lake Canada — — Nipigon Canada — — North Bay Canada — $ $ $ $

Discontinued operations

Discontinued operations	9 Months Ended
	Sep. 30, 2016
Discontinued operations
Discontinued operations	4. Discontinued operations On June 26, 2015, Atlantic Power Transmission, Inc. (“APT”), our wholly-owned, direct subsidiary, sold our Wind Projects under a definitive agreement (the “Purchase Agreement”) with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc. (an affiliate of TerraForm Power, Inc.). The sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded an approximate $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 would 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. The following table summarizes the revenue and income from operations of the Wind Projects for the three and nine months ended September 30, 2015: Three months Nine months ended ended September 30, September 30, 2015 2015 Revenue $ — $ Project expenses: Operations and maintenance — Depreciation and amortization — — Project other expense: Change in fair value of derivatives — Equity in earnings of unconsolidated affiliates — Interest expense, net — Gain (loss) on sale of asset Income (loss) from operations of discontinued businesses Income tax expense Income (loss) from operations of discontinued businesses, net of tax Net loss attributable to noncontrolling interests of discontinued businesses — Income (loss) from operations of discontinued businesses, net of noncontrolling interests $ $ Basic and diluted earnings per share related to income (loss) from discontinued operations for the Wind Projects was $0.00 and $0.26 for the three and nine months ended September 30, 2015, respectively. The following table summarizes the operating and investing cash flows of the Wind Projects for the nine months ended September 30, 2015: Nine months ended September 30, 2015 Cash provided by operating activities $ Cash used in investing activities

Equity method investments in un

Equity method investments in unconsolidated affiliates	9 Months Ended
	Sep. 30, 2016
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	5. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three and nine months ended September 30, 2016 and 2015, respectively, for our equity method investments: Three Months Ended September 30, Nine Months Ended September 30, Operating results 2016 2015 2016 2015 Revenue Chambers $ $ $ $ Frederickson Orlando Other (1) Project expenses Chambers Frederickson Orlando Other (1) Project other expense Chambers Frederickson — — — — Orlando — — — — Other (1) — — — — Project income (loss) Chambers $ $ $ $ Frederickson Orlando Other (1) (1) Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

Long-term debt

Long-term debt	9 Months Ended
	Sep. 30, 2016
Long-term debt excluding debentures
Long-term debt	6. Long‑term debt Long‑term debt consists of the following: September 30, December 31, 2016 2015 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ — $ LIBOR (1) plus % Senior secured term loan facility, due 2023 — LIBOR (1) plus % Senior unsecured notes, due June 2036 (Cdn$210.0) % Non-Recourse Debt: Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 % Other long-term debt % - % Less: unamortized discount — Less: unamortized deferred financing costs Less: current maturities Total long-term debt $ $ Current maturities consist of the following: September 30, December 31, 2016 2015 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ — $ LIBOR (1) plus % Senior secured term loan facility, due 2023 (2) — LIBOR (1) plus % Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 % Other short-term debt % - % Total current maturities $ $ (1) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $434.7 million of the $654.9 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2016. See Note 9, Accounting for derivative instruments and hedging activities for further details. (2) On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the credit agreement and disclosed below. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. New Credit Facilities On April 13, 2016, APLP Holdings Limited Partnership (“APLP Holdings”), our wholly-owned subsidiary, entered into new senior secured credit facilities, comprising $700 million in aggregate principal amount of senior secured term loan facilities (the “New Term Loans”) and $200 million in aggregate principal amount of senior secured revolving credit facilities (the “New Revolver” and together with the New Term Loans, the “New Credit Facilities”). On the same date, $700 million was drawn under the New Term Loan, bearing interest at the Adjusted Eurodollar Rate plus the applicable margin of 5.00%, and letters of credit in an aggregate face amount of $105.8 million were issued (but not drawn) pursuant to the revolving commitments under the New Revolver and used (i) to fund a debt service reserve in an amount equivalent to six months of debt service (approximately $25.3 million), and (ii) to support contractual credit support obligations of APLP Holdings and its subsidiaries and of certain other affiliates of the Company. The New Revolver matures in April 2021 and the New Term Loans mature in April 2023. We received $679.0 million in proceeds after an original issue discount of 3% ($21.0 million). We have used the $679.0 million proceeds from the New Term Loans to:  redeem in whole, at a price equal to par plus accrued interest, Atlantic Power Limited Partnership’s (“APLP”) existing senior secured term loan, maturing in February 2021, in an aggregate principal amount outstanding of $447.9 million (see “Senior Secured Credit Facilities” below);  redeem in whole, at a price equal to par plus accrued interest (i) our outstanding Cdn$67.2 million 6.25% Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017 (the “Series A Debentures”) and (ii) our outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated Debentures, Series B, maturing in June 2017 (the “Series B Debentures”) (total US$ equivalent of $110.7 million);  redeem, at a price equal to $965 per $1,000 principal amount plus accrued interest, $62.7 million of our 5.75% Convertible Unsecured Subordinated Debentures, Series C, maturing on June 30, 2019; and  pay transaction costs and expenses of approximately $14.4 million. We may use the remaining proceeds for any corporate purpose including common share repruchases. We accounted for the redemption of the Senior Secured Credit Facilities as an extinguishment of debt and wrote off $30.2 million of deferred financing costs to interest expense in the nine months ended September 30, 2016. Borrowings under the New Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate, the Base Rate or the Canadian Prime Rate as applicable, plus an applicable margin between 4.00% and 5.00% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The New Term Loans include a 3% original issue discount, and matures on April 12, 2023. The revolving commitments under the New Revolver terminate on April 12, 2021. Letters of credit are available to be issued under the New Revolver until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. In addition to paying interest on outstanding principal under the New Credit Facilities, APLP Holdings is required to pay a commitment fee of 0.75% times the unused commitments under the New Revolver. The New Credit Facilities are secured by a pledge of the equity interests in APLP Holdings and certain of its subsidiaries, guaranties from certain of the subsidiaries of APLP Holdings (the “Subsidiary Guarantors”), a downstream guarantee from the Company, a limited recourse guaranty from Atlantic Power GP II, Inc., the entity that holds all of the equity interest in APLP Holdings, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of APLP Holdings and its subsidiaries (subject to certain exceptions), and certain other assets. The New Credit Facilities also have the benefit of a debt service reserve account, which is required to be maintained at the debt service reserve requirement, equal to six months of debt service. The reserve requirement is maintained utilizing a letter of credit. APLP, a wholly-owned, indirect subsidiary of the Company, is a party to an existing indenture governing its Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due June 23, 2036 (the “MTNs”) that prohibits APLP (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, APLP Holdings has granted an equal and ratable security interest in the collateral package securing the New Credit Facilities in favor of the trustee under the indenture governing the MTNs for the benefit of the holders of the MTNs. The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The negative covenants include a requirement that APLP Holdings and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 6.00:1.00 in 2016 to 4.25:1.00 from June 30, 2020, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 2.75:1.00 in 2016 to 4.00:1.00 from June 30, 2022. In addition, the Credit Agreement includes customary restrictions and limitations on APLP Holdings’ and its subsidiaries’ ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to certain exceptions and other customary carve-outs and various thresholds. Specifically, APLP Holdings may be restricted from making dividend payments or other distributions to Atlantic Power Corporation, and APLP and its subsidiaries may be prohibited from making dividends or distributions to Atlantic Power Preferred Equity Limited shareholders in the event of a covenant default or if APLP Holdings fails to achieve a target principal amount on the new term loan that declines quarterly based on a predetermined specified schedule. Under the Credit Agreement, if a Change of Control (as defined in the Credit Agreement) occurs, unless APLP Holdings elects to make a voluntary prepayment of the term loans under the New Credit Facilities, it will be required to offer each electing lender a prepayment of such lender’s term loans under the New Credit Facilities at a price equal to 101% of par. In addition, in the event that APLP Holdings elects to repay, prepay, refinance or replace all or any portion of the term loan facilities within one year from the initial funding date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid, refinanced or replaced. The Credit Agreement also contains a mandatory amortization feature and other mandatory prepayment provisions, including prepayments:  from the proceeds of asset sales (except from the sale proceeds of certain excluded projects), insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and  in respect of excess cash flow, to be determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the New Credit Facilities and the MTNs, funding of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Credit Agreement, and payment on the preferred equity issued by Atlantic Power Preferred Equity Ltd., a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Failure to achieve the specified target principal amount for any quarter does not constitute a default by APLP Holdings. Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect, non-payment or acceleration of other material debt of APLP Holdings and its subsidiaries, bankruptcy, material judgments rendered against APLP Holdings or certain of its subsidiaries, certain ERISA or regulatory events, a Change of Control of APLP Holdings (solely with respect to the New Revolver), or defaults under certain guaranties and collateral documents securing the New Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods. Senior Secured Credit Facilities As noted above in “New Credit Facilities”, our Senior Secured Credit Facilities were repaid on April 13, 2016. The redemption and extinguishment was recorded in the three months ended June 30, 2016. 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 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 were recorded in interest expense in 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, 2016, all of our projects with the exception of Piedmont 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 the debt is 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 or to make distributions before the project’s debt maturity in 2018 at the earliest.

Convertible debentures

Convertible debentures	9 Months Ended
	Sep. 30, 2016
Convertible Debentures
Long-term debt	7. Convertible debentures Convertible debentures consist of the following: September 30, December 31, 2016 2015 6.25% Debentures due March 2017 $ — $ 5.60% Debentures due June 2017 — 5.75% Debentures due June 2019 6.00% Debentures due December 2019 (Cdn$81.0 million) Less: Unamortized deferred financing costs Total convertible debentures $ $ On November 11, 2014, we commenced a normal course issuer bid (“NCIB”) for our convertible debentures. Under the NCIB, which expired on November 10, 2015, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures. As of December 31, 2015, we had repurchased and cancelled $24.8 million of convertible debentures and recorded a gain of $3.1 million in the consolidated statements of operations related to these transactions. On December 29, 2015, we commenced a new NCIB, which will expire on December 28, 2016. The actual amount of convertible debentures that may be purchased under the NCIB is approximately $28.5 million and is further limited to 10% of the public float of our convertible debentures. Since inception of the NCIB in the fourth quarter of 2015 and through September 30, 2016, we repurchased and canceled $18.8 million of convertible debentures and recorded a gain of $2.5 million in the consolidated statement of operations for the nine months ended September 30, 2016. On April 13, 2016, we deposited a portion of the proceeds from the issuance of the New Credit Facilities, for the redemption in whole on May 13, 2016 at a price equal to par plus accrued interest (i) the outstanding Cdn$67.2 million 6.25% Debentures due March 2017 and (ii) the outstanding Cdn$75.8 million 5.60% Debentures due June 2017 (total US$ equivalent of $110.7 million as of April 13, 2016). Deferred financing costs related to the debentures of $1.3 million were written off and recorded to interest expense in April 2016. On June 17, 2016, we commenced a substantial issuer bid to purchase for cancellation up to $65.0 million aggregate principal amount of our issued and outstanding 5.75% Series C Convertible Unsecured Subordinated Debentures maturing June 30, 2019. The offer expired on July 22, 2016. An aggregate of $62.7 million principal amount of the debentures were purchased and cancelled under the offer. As of September 30, 2016, there were approximately $42.6 million principal amount of Series C debentures outstanding and a gain of $1.7 million was recorded related to the repurchase in the consolidated statements of operations for the three and nine months ended September 30, 2016. Deferred financing costs related to the debentures of $1.4 million were written off and recorded to interest expense in July 2016.

Fair value of financial instrum

Fair value of financial instruments	9 Months Ended
	Sep. 30, 2016
Fair value of financial instruments
Fair value of financial instruments	8. 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, 2016 and December 31, 2015. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. September 30, 2016 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, 2015 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, 2016, the credit valuation adjustments resulted in a $5.2 million net increase in fair value, which consists of a $0.5 million pre‑tax gain in other comprehensive income and a $4.7 million gain in change in fair value of derivative instruments. As of December 31, 2015, the credit valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.4 million pre‑tax gain in other comprehensive income and a $3.4 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, 2016
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	9. Accounting for derivative instruments and hedging activities We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts. Gas purchase agreements Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration on December 31, 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. In June 2014, APLP 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. We have entered into various natural gas sales and purchase agreements for approximately 1.3 million Mmbtu to effectively mitigate seasonal fluctuation of future natural gas price at Morris through March 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2016. 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 5.7 million Mmbtu of future natural gas purchases at Orlando, which is approximately 95% of our share of the expected natural gas purchases at the project through December 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2016. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations. Interest rate swaps On May 5, 2014, APLP entered into several interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ($124.7 million at September 30, 2016) of the $600 million aggregate principal amount of borrowings under the Term Loan Facility, which had entered on February 24, 2014 and redeemed in whole on May 2016. 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. These interest rate swap agreements were novated to APLP Holdings. APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in interest at the Adjusted Eurodollar Rate for $310.0 million notional amount ($124.7 million at September 30, 2016) of the $700.0 million aggregate principal amount ($654.9 million at September 30, 2016) of borrowings under the New Term Loans. Interest rate swap agreements with $160.0 million remaining notional terminate on September 30, 2019 and interest swap agreements with $150.0 million remaining notional terminate on March 31, 2020. Borrowings under the $700.0 million New Term Loans bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 5.00%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 6.00% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $509.0 million of the New Term Loans cannot be less than 6.00%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. 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 $68.5 million principal of the term loan. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations. The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac’s debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive loss. Volume of forecasted transactions We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption at September 30, 2016 and December 31, 2015: September 30, December 31, Units 2016 2015 Natural gas swaps Natural Gas (Mmbtu) Gas purchase agreements Natural Gas (Gigajoules) Interest rate swaps Interest (US$) 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, 2016 Derivative Derivative Assets 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, 2015 Derivative Derivative Assets 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: Interest Rate Three Months Ended September 30, 2016 Swaps Accumulated OCI balance at June 30, 2016 $ Change in fair value of cash flow hedges Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ Interest Rate Three Months Ended September 30, 2015 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 $ Interest Rate Nine Months Ended September 30, 2016 Swaps Accumulated OCI balance at January 1, 2016 $ Change in fair value of cash flow hedges Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ Interest Rate Nine Months Ended September 30, 2015 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 $ 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: Classification of loss (gain) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2016 2015 2016 2015 Gas purchase agreements Fuel $ $ $ Natural gas swaps Fuel Interest rate swaps Interest, net 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: Classification of gain (loss) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2016 2015 2016 2015 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 $ $ $ $

Income taxes

Income taxes	9 Months Ended
	Sep. 30, 2016
Income taxes
Income taxes	10. Income taxes Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Current income tax expense (benefit) $ $ $ $ Deferred tax expense (benefit) Total income tax expense (benefit), net $ $ $ $ For the three and nine months ended September 30, 2016 and 2015 Income tax expense for the three months ended September 30, 2016 was $2.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $20.2 million. The primary item increasing the tax rate for the three months ended September 30, 2016 was $22.5 million related to goodwill impairment. In addition, the rate was further impacted by a net increase to our valuation allowances of $8.6 million, consisting primarily of increases of $9.3 million in Canada related to losses and a decrease of $0.7 million in the United States due to additional earnings. These items were offset by $7.2 million related to capital loss on intercompany notes, $1.9 million relating to operating in higher tax rate jurisdictions and $0.8 million of other permanent differences. Income tax expense for the three months ended September 30, 2015 was $1.4 million. 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 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 benefit for the nine months ended September 30, 2016 was $14.2 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $32.2 million. The primary items increasing the tax rate for the nine months ended September 30, 2016 were $22.5 million relating to goodwill impairment, $5.5 million relating to foreign exchange and $1.1 million of other permanent differences. In addition, the rate was further impacted by a net increase to the Company’s valuation allowances of $13.2 million, consisting primarily of increases of $31.6 million in Canada related to losses and a decrease of $18.4 million in the United States due to tax restructurings and additional earnings. These items were offset by $18.5 million Canadian capital losses recognized on tax restructurings, $3.0 million related to capital loss on intercompany notes and $2.8 million relating to operating in higher tax rate jurisdictions. Income tax benefit for the nine months ended September 30, 2015 was $0.3 million. 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. As of September 30, 2016, we have recorded a valuation allowance of $188.5 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, 2016
Equity compensation plans
Equity compensation plans	11. 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, 2016: Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2015 $ Granted Vested and redeemed Forfeitures Outstanding at September 30, 2016 $ Cash payments made for vested notional units for the nine months ended September 30, 2016 and 2015 were $0.4 million and $1.0 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $0.5 million and $1.4 million for the three and nine months ended September 30, 2016, respectively, and $1.0 million and $2.1 million for the three and nine months ended September 30, 2015, respectively. Transition Equity Participation Agreement We also have 539,904 transition notional shares outstanding at September 30, 2016 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 (Cdn$3.18) by at least 50% (Cdn$4.77).

Basic and diluted (loss) earnin

Basic and diluted (loss) earnings per share	9 Months Ended
	Sep. 30, 2016
Basic and diluted (loss) earnings per share
Basic and diluted (loss) earnings per share	12. Basic and diluted (loss) earnings per share Basic (loss) earnings 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 and nine months ended September 30, 2016, 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, 2016 and 2015: Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Numerator: Loss from continuing operations attributable to Atlantic Power Corporation $ $ $ $ (Loss) income from discontinued operations, net of tax — — Net (loss) income 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 earnings per share from discontinued operations — — — Diluted (loss) earnings per share attributable to Atlantic Power Corporation $ $ $ $ The dilutive effect of our convertible debentures is calculated using the “if-converted method.” Under the if-converted method, the debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted EPS calculation for the entire period being presented. Interest expense, net of any income tax effects, would be added back to the numerator for purposes of the if-converted calculation. Potentially dilutive shares from convertible debentures of $8.1 million and $14.9 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2016, respectively, because their impact would be anti-dilutive. 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.

Equity

Equity	9 Months Ended
	Sep. 30, 2016
Equity
Equity	13. Equity The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the nine months ended September 30, 2016 and 2015: Nine months ended September 30, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2016 $ $ $ Net (loss) income Realized and unrealized loss on hedging activities, net of tax — Foreign currency translation adjustment — Common share repurchases — Stock-based compensation — Dividends declared on preferred shares of a subsidiary company — Balance at September 30, 2016 $ $ $ Nine months ended September 30, 2015 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Noncontrolling Shareholders’ Equity company Interests Total Equity Balance at January 1, 2015 $ $ $ $ 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 — — Derecognition of noncontrolling interests upon sale of subsidiaries — — Balance at September 30, 2015 $ $ $ — $ Stock Repurchase Program In December 2015, our Board of Directors approved an NCIB for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd (“APPEL”), our wholly-owned subsidiary. The Board authorization permits the Company to repurchase stock through open market repurchases. The NCIB will expire on December 28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. For the nine months ended September 30, 2016, we repurchased a cumulative 5,678,736 common shares at a total cost of $13.9 million. Repurchases and retirement of common shares are recorded to common shares on the consolidated balance sheets. Subsequent to September 30, 2016, we repurchased an additional 1,394,096 common shares.

Segment and geographic informat

Segment and geographic information	9 Months Ended
	Sep. 30, 2016
Segment and geographic information
Segment and geographic information	14. 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 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, 2015. 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. We use Project Adjusted EBITDA to provide comparative information about segment 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 net (loss) income from continuing operations to Project Adjusted EBITDA for the three and nine months ended September 30, 2016 and 2015 is included in the table below: Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2016 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Impairment — — Other project income — — — Project (loss) income Administration — — — Interest, net — — — Foreign exchange gain — — — Other income, net — — — (Loss) income from continuing operations before income taxes Income tax expense — — — Net income (loss) from continuing operations $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada 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 — — — 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 $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2016 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Impairment — — Other project income — — — Project income (loss) Administration — — — Interest, net — — — Foreign exchange loss — — — Other income, net — — — Income (loss) from continuing operations before income taxes Income tax benefit — — — Net income (loss) from continuing operations $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada 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 loss — — — Other income, net — — — 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, 2016 and 2015 and Property, Plant & Equipment as of September 30, 2016 and December 31, 2015, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located. Project Revenue Three Months Ended September 30, Project Revenue Nine Months Ended September 30, Property, Plant and 2016 2015 2016 2015 September 30, 2016 December 31, 2015 United States $ $ $ $ $ $ Canada Total $ $ $ $ $ $ Independent Electricity System Operator (“IESO”), San Diego Gas & Electric, Georgia Power Company and BC Hydro provided 24.5%, 16.1%, 10.9%, and 10.6%, respectively, of total consolidated revenues for the three months ended September 30, 2016. IESO, BC Hydro and San Diego Gas & Electric provided 28.0%, 11.6% and 11.5% respectively, of total consolidated revenues for the nine months ended September 30, 2016. 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 and 27.7%, 12.6%, 10.4% and 7.7%, respectively, of total consolidated revenues for the nine months ended September 30, 2015. 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, Georgia Power purchases electricity from the Piedmont project in the East U.S. segment and BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment.

Guarantees

Guarantees	9 Months Ended
	Sep. 30, 2016
Guarantees
Guarantees	15. Guarantees We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2016
Contingencies
Contingencies	16. Contingencies 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, 2016.

Summary of significant accounti

Summary of significant accounting policies (Policies)	9 Months Ended
	Sep. 30, 2016
Nature of business
Basis of Presentation and Significant Accounting Policies [Text Block]	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, 2015. 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, 2016, the results of operations and comprehensive loss for the three and nine months ended September 30, 2016 and 2015, and our cash flows for the nine months ended September 30, 2016 and 2015 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 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, 2015. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Recently adopted and issued accounting standards	Recently issued accounting standards Adopted In January 2015, the Financial Accounting Standards Board (“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 statement of operations, 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 became effective for us on January 1, 2016. The adoption of these changes did 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 became effective for us on January 1, 2016. The adoption of these changes did not have an impact 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 became effective for us on January 1, 2016. As a result, we have presented $19.5 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended September 30, 2016 and December 31, 2015, respectively. 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 statement of operations 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 became effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations. 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 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 a material impact on the consolidated financial statements. In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after December 15, 2016 and is not expected to have a material impact on the consolidated financial statements. In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a right-of-use asset and a lease liability, measured on a discounted basis, at the commencement date for all leases with terms greater than twelve months. Additionally, this guidance will require disclosures to help investors and other financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The guidance should be applied under a modified retrospective transition approach for leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. This guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance. In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance. In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements.

Goodwill (Tables)

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2016
Goodwill
Schedule of changes in the carrying amount of goodwill	December 31, Translation September 30, Reporting unit Segment 2015 Impairment adjustment 2016 Curtis Palmer East U.S. $ $ $ — $ Morris East U.S. — — Kapuskasing Canada — Mamquam Canada — Moresby Lake Canada — — Nipigon Canada — — North Bay Canada — $ $ $ $

Discontinued operations (Tables

Discontinued operations (Tables)	9 Months Ended
	Sep. 30, 2016
Discontinued operations
Summary of income (loss) from discontinued operations	The following table summarizes the revenue and income from operations of the Wind Projects for the three and nine months ended September 30, 2015: Three months Nine months ended ended September 30, September 30, 2015 2015 Revenue $ — $ Project expenses: Operations and maintenance — Depreciation and amortization — — Project other expense: Change in fair value of derivatives — Equity in earnings of unconsolidated affiliates — Interest expense, net — Gain (loss) on sale of asset Income (loss) from operations of discontinued businesses Income tax expense Income (loss) from operations of discontinued businesses, net of tax Net loss attributable to noncontrolling interests of discontinued businesses — Income (loss) from operations of discontinued businesses, net of noncontrolling interests $ $
Summary of operating and investing cash flows	The following table summarizes the operating and investing cash flows of the Wind Projects for the nine months ended September 30, 2015: Nine months ended September 30, 2015 Cash provided by operating activities $ Cash used in investing activities

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2016
Schedule of current maturities	September 30, December 31, 2016 2015 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ — $ LIBOR (1) plus % Senior secured term loan facility, due 2023 (2) — LIBOR (1) plus % Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 % Other short-term debt % - % Total current maturities $ $ (1) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $434.7 million of the $654.9 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2016. See Note 9, Accounting for derivative instruments and hedging activities for further details. (2) On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the credit agreement and disclosed below. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule.
Long-term debt excluding debentures
Schedule of long-term debt	September 30, December 31, 2016 2015 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ — $ LIBOR (1) plus % Senior secured term loan facility, due 2023 — LIBOR (1) plus % Senior unsecured notes, due June 2036 (Cdn$210.0) % Non-Recourse Debt: Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 % Other long-term debt % - % Less: unamortized discount — Less: unamortized deferred financing costs Less: current maturities Total long-term debt $ $

Convertible debentures (Tables)

Convertible debentures (Tables)	9 Months Ended
	Sep. 30, 2016
Convertible Debentures
Schedule of long-term debt	September 30, December 31, 2016 2015 6.25% Debentures due March 2017 $ — $ 5.60% Debentures due June 2017 — 5.75% Debentures due June 2019 6.00% Debentures due December 2019 (Cdn$81.0 million) Less: Unamortized deferred financing costs Total convertible debentures $ $

Fair value of financial instr28

Fair value of financial instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	September 30, 2016 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, 2015 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, 2016
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	September 30, December 31, Units 2016 2015 Natural gas swaps Natural Gas (Mmbtu) Gas purchase agreements Natural Gas (Gigajoules) Interest rate swaps Interest (US$)
Schedule of fair value of derivative instruments	September 30, 2016 Derivative Derivative Assets 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, 2015 Derivative Derivative Assets 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	Interest Rate Three Months Ended September 30, 2016 Swaps Accumulated OCI balance at June 30, 2016 $ Change in fair value of cash flow hedges Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ Interest Rate Three Months Ended September 30, 2015 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 $ Interest Rate Nine Months Ended September 30, 2016 Swaps Accumulated OCI balance at January 1, 2016 $ Change in fair value of cash flow hedges Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ Interest Rate Nine Months Ended September 30, 2015 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 $
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges	Classification of loss (gain) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2016 2015 2016 2015 Gas purchase agreements Fuel $ $ $ Natural gas swaps Fuel Interest rate swaps Interest, net
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	Classification of gain (loss) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2016 2015 2016 2015 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 $ $ $ $

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
	Sep. 30, 2016
Income taxes
Schedule of components of income tax expense (benefit)	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Current income tax expense (benefit) $ $ $ $ Deferred tax expense (benefit) Total income tax expense (benefit), net $ $ $ $

Equity compensation plans (Tabl

Equity compensation plans (Tables)	9 Months Ended
	Sep. 30, 2016
Equity compensation plans
Schedule of changes in outstanding LTIP notional units	Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2015 $ Granted Vested and redeemed Forfeitures Outstanding at September 30, 2016 $

Basic and diluted earnings (los

Basic and diluted earnings (loss) per share (Tables)	9 Months Ended
	Sep. 30, 2016
Basic and diluted (loss) earnings 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, 2016 2015 2016 2015 Numerator: Loss from continuing operations attributable to Atlantic Power Corporation $ $ $ $ (Loss) income from discontinued operations, net of tax — — Net (loss) income 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 earnings per share from discontinued operations — — — Diluted (loss) earnings per share attributable to Atlantic Power Corporation $ $ $ $

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2016
Equity
Schedule of reconciliation of equity	Nine months ended September 30, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2016 $ $ $ Net (loss) income Realized and unrealized loss on hedging activities, net of tax — Foreign currency translation adjustment — Common share repurchases — Stock-based compensation — Dividends declared on preferred shares of a subsidiary company — Balance at September 30, 2016 $ $ $ Nine months ended September 30, 2015 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Noncontrolling Shareholders’ Equity company Interests Total Equity Balance at January 1, 2015 $ $ $ $ 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 — — Derecognition of noncontrolling interests upon sale of subsidiaries — — Balance at September 30, 2015 $ $ $ — $

Segment and geographic inform34

Segment and geographic information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment and geographic information
Schedule of a reconciliation of Project Adjusted EBITDA to project (loss) income	Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2016 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Impairment — — Other project income — — — Project (loss) income Administration — — — Interest, net — — — Foreign exchange gain — — — Other income, net — — — (Loss) income from continuing operations before income taxes Income tax expense — — — Net income (loss) from continuing operations $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada 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 — — — 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 $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2016 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Impairment — — Other project income — — — Project income (loss) Administration — — — Interest, net — — — Foreign exchange loss — — — Other income, net — — — Income (loss) from continuing operations before income taxes Income tax benefit — — — Net income (loss) from continuing operations $ $ $ $ $ Un-Allocated East U.S. West U.S. Canada 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 loss — — — Other income, net — — — 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	Project Revenue Three Months Ended September 30, Project Revenue Nine Months Ended September 30, Property, Plant and 2016 2015 2016 2015 September 30, 2016 December 31, 2015 United States $ $ $ $ $ $ Canada Total $ $ $ $ $ $

Nature of business (Details)

Nature of business (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)stateprojectitemMW	Dec. 31, 2015USD ($)
Nature of business
Gross generating capacity of project (in MW) | MW	2,138
Ownership interest in operational power generation projects (in MW) | MW	1,500
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 majority owned | project	18
Recent accounting pronouncements adopted
Long term debt and convertible debentures | $	$ 778.9	$ 682.7
Accounting Standards Update 2015-03 | Restatement Adjustment
Recent accounting pronouncements adopted
Long term debt and convertible debentures | $	$ 19.5	$ 42.5

Changes in accumulated other 36

Changes in accumulated other comprehensive loss by component (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
AOCI Attributable to Parent, Net of Tax
Beginning Balance			$ 213.9
Ending Balance	$ 82.5		82.5
Cash flow hedges
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(0.1)	$ 0.1	0.2	$ 0.1
Ending Balance	0.1	(0.1)	0.1	(0.1)
Other comprehensive income (loss)
Net change from periodic revaluations	0.1	(0.7)	(1)	(1.3)
Tax (expense) benefit	(0.1)	0.3	0.4	0.5
Total Other comprehensive (loss) income before reclassifications, net of tax		(0.4)	(0.6)	(0.8)
Amount reclassified
Total Other comprehensive income	0.2	(0.2)	(0.1)	(0.2)
Foreign currency translation
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(119.7)	(96.9)	(139.1)	(66.3)
Ending Balance	(141.7)	(119)	(141.7)	(119)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	0	0	0	0
Other comprehensive income (loss)
Foreign currency translation adjustments	(22)	(22.1)	(2.6)	(52.7)
Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
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	0.5	0.6
Amount reclassified from accumulated other comprehensive income | Foreign currency translation
AOCI Attributable to Parent, Net of Tax
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	0	0
Interest rate swaps | Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
Amount reclassified from AOCI	$ 0.3	$ 0.3	$ 0.9	$ 1

Goodwill (Details)

Goodwill (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016USD ($)item	Sep. 30, 2016USD ($)GWh
Goodwill
Period of declining power prices	2 years
Goodwill	$ 37.6	$ 134.5
Number of asset groups tested under step one | item	5
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		134.5
Impairment of goodwill		(78.8)
Translation Adjustments		(18.1)
Goodwill, Ending Balance	$ 37.6	37.6
Morris And Nipigon
Goodwill
Number of reporting units not significantly impacted by declining power prices | item	2
Goodwill	$ 6.9	6.9
Changes in the carrying amount of goodwill
Goodwill, Ending Balance	6.9	$ 6.9
Curtis Palmer
Goodwill
Quantity triggering agreement expiration | GWh		10,000
Expected period of expiration before specified date (in years)		2 years
Moresby Lake
Changes in the carrying amount of goodwill
Impairment of goodwill		$ 0
East U.S.
Goodwill
Goodwill	3.3	3.3
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		3.3
Goodwill, Ending Balance	3.3	3.3
East U.S. | Curtis Palmer
Goodwill
Goodwill	29.1	44.5
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		44.5
Impairment of goodwill		(15.4)
Goodwill, Ending Balance	29.1	29.1
Canada | Nipigon
Goodwill
Goodwill	3.6	3.6
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		3.6
Goodwill, Ending Balance	3.6	3.6
Canada | North Bay And Kapuskasing
Goodwill
Long lived asset impairment charge	5.9	5.9
Canada | North Bay
Goodwill
Goodwill		8.3
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		8.3
Impairment of goodwill		(6.5)
Translation Adjustments		(1.8)
Canada | Kapuskasing
Goodwill
Goodwill		8.8
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		8.8
Impairment of goodwill		(6.7)
Translation Adjustments		(2.1)
Canada | Mamquam
Goodwill
Goodwill		64.4
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		64.4
Impairment of goodwill		(50.2)
Translation Adjustments		(14.2)
Canada | Moresby Lake
Goodwill
Goodwill	1.6	1.6
Changes in the carrying amount of goodwill
Goodwill, Beginning Balance		1.6
Goodwill, Ending Balance	$ 1.6	$ 1.6

Discontinued operations (Detail

Discontinued operations (Details) $ / shares in Units, $ in Millions	Jun. 26, 2015USD ($)itemMW	Sep. 30, 2015USD ($)$ / shares	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)$ / shares
Discontinued operations
Gain on the disposal				$ (47.2)
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Income (loss) from operations of discontinued businesses, net of tax		$ (0.5)		20.6
Income (loss) from operations of discontinued businesses, net of noncontrolling interests		(0.5)		$ 31.6
Basic and diluted earnings per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares				$ 0.26
Wind Projects | Discontinued Operations, Held-for-sale or Disposed of by Sale
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue				$ 34.8
Operations and maintenance				10.8
Depreciation and amortization				10.3
Total Project expenses				21.1
Change in fair value of derivatives				(0.7)
Equity in earnings of unconsolidated affiliates				(0.3)
Interest expense, net				(6.7)
Gain (loss) on sale of asset		(0.2)		47.2
Total Project other income (expense)		(0.2)		39.5
Income (loss) from operations of discontinued businesses		(0.2)		53.2
Income tax expense		0.3		32.6
Income (loss) from operations of discontinued businesses, net of tax		(0.5)		20.6
Net loss attributable to noncontrolling interests of discontinued businesses				(11)
Income (loss) from operations of discontinued businesses, net of noncontrolling interests		$ (0.5)		$ 31.6
Basic and diluted earnings per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares		$ 0		$ 0.26
Wind Projects | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Consideration received on disposal interests	$ 335
Wind Projects | Wind (Discontinued Operations) | Discontinued Operations, Held-for-sale or Disposed of by Sale
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Cash provided by operating activities				$ 21.9
Cash used in investing activities				$ (12.8)
Wind Projects | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
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
Goshen North | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Ownership interest sold (as a percent)	12.50%
Idaho Wind | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Ownership interest sold (as a percent)	27.60%
Meadow Creek | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Ownership interest sold (as a percent)	100.00%
Rockland Wind Farm | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Ownership interest sold (as a percent)	50.00%
Consolidated ownership interest sold (as a percent)	100.00%
Canadian Hills | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Consolidated ownership interest sold (as a percent)	99.00%
Income from Discontinued Operations [Member] | Wind Projects | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Gain on the disposal			$ 47.2

Equity method investments in 39

Equity method investments in unconsolidated affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating results
Revenue	$ 34.1	$ 34.1	$ 97.8	$ 104.9
Project expenses	24.1	24.7	68.5	75.2
Project other expense	(0.4)	(0.5)	(1.4)	(1.4)
Project income (loss)	9.6	8.9	27.9	28.3
Chambers
Operating results
Revenue	11.2	11	34.3	37.3
Project expenses	9.3	9.2	27.8	30.2
Project other expense	(0.4)	(0.5)	(1.4)	(1.4)
Project income (loss)	1.5	1.3	5.1	5.7
Frederickson
Operating results
Revenue	5.8	5.8	15.7	15.9
Project expenses	4.9	5.1	14.3	14.1
Project income (loss)	0.9	0.7	1.4	1.8
Orlando
Operating results
Revenue	13.9	13.9	40.6	40.9
Project expenses	6.9	7.3	19.6	20.6
Project income (loss)	7	6.6	21	20.3
Other
Operating results
Revenue	3.2	3.4	7.2	10.8
Project expenses	3	3.1	6.8	10.3
Project income (loss)	$ 0.2	$ 0.3	$ 0.4	$ 0.5
Other | Maximum
Operating results
Percentage of ownership interest	10.00%		10.00%

Long-term debt (Details)

Long-term debt (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015	May 05, 2014
Long-term debt
Less: unamortized discount	$ (18.5)
Less: current maturities	(101.4)	$ (15.8)
Total long-term debt	778.9	682.7
Interest rate swaps
Long-term debt
Notional amount	520.4	302.3
London Interbank Offered Rate (LIBOR) | Interest rate swaps
Long-term debt
Aggregate principal amount of debt	654.9
Long-term debt excluding debentures
Long-term debt
Less: unamortized deferred financing costs	(16.6)	(34.8)
Less: current maturities	(101.4)	(15.8)
Total long-term debt	778.9	682.7
Long-term debt excluding debentures | Senior secured term loan facility, due 2021
Long-term debt
Long-term debt		473.2
Less: current maturities		(4.7)
Long-term debt excluding debentures | Senior secured term loan facility, due 2023
Long-term debt
Long-term debt	654.9
Less: current maturities	$ (90)
Applicable margin (as a percent)	5.00%
Long-term debt excluding debentures | Senior unsecured notes, due June 2036 (Cdn$210.0)
Long-term debt
Long-term debt	$ 160.1	151.7
Interest rate (as a percent)	5.95%
Long-term debt excluding debentures | Epsilon Power Partners term facility, due 2019
Long-term debt
Long-term debt	$ 15	19.5
Less: current maturities	(6.1)	(6)
Long-term debt excluding debentures | Cadillac term loan, due 2025
Long-term debt
Long-term debt	27.7	29.5
Less: current maturities	(2.9)	(2.5)
Long-term debt excluding debentures | Piedmont term loan, due 2018
Long-term debt
Long-term debt	57.5	59
Less: current maturities	$ (2.2)	(2.4)
Applicable margin (as a percent)	8.47%
Long-term debt excluding debentures | Other long-term debt
Long-term debt
Long-term debt	$ 0.2	0.4
Less: current maturities	$ (0.2)	$ (0.2)
Long-term debt excluding debentures | Minimum | Other long-term debt
Long-term debt
Interest rate (as a percent)	5.50%
Long-term debt excluding debentures | Maximum | Other long-term debt
Long-term debt
Interest rate (as a percent)	6.70%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2021
Long-term debt
Minimum percentage of variable rate base	1.00%
Applicable margin (as a percent)	3.75%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Epsilon Power Partners term facility, due 2019
Long-term debt
Applicable margin (as a percent)	3.125%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Cadillac term loan, due 2025
Long-term debt
Applicable margin (as a percent)	1.37%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Interest rate swaps | Senior secured term loan facility, due 2021
Long-term debt
Notional amount			$ 434.7

Long-term debt - New Credit Fac

Long-term debt - New Credit Facilities (Details) CAD in Millions, $ in Millions

Jul. 26, 2016USD ($)

Apr. 13, 2016USD ($)

Jul. 26, 2015USD ($)

Jul. 31, 2016USD ($)

Apr. 30, 2016USD ($)

Sep. 30, 2016USD ($)

Jun. 30, 2016CAD

Jun. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Jul. 22, 2016USD ($)

Jun. 17, 2016

Apr. 13, 2016CAD

Apr. 13, 2016USD ($)

Dec. 31, 2015USD ($)

Debt Instrument [Line Items]

Original issue discount amount

$ 18.5

$ 18.5

Long-term debt excluding debentures | Senior unsecured notes, due June 2036 (Cdn$210.0)

Debt Instrument [Line Items]

Interest rate (as a percent)

5.95%

5.95%

Long-term debt excluding debentures | Senior unsecured notes due 2018

Debt Instrument [Line Items]

Redemption price percentage of principal amount

104.50%

Debt Instrument, Repurchase Amount

$ 330.4

Interest rate (as a percent)

9.00%

Aggregate principal amount of debt repurchased

$ 310.9

Long-term debt excluding debentures | Senior unsecured notes due 2018 | Interest expense

Debt Instrument [Line Items]

Debt Instrument Redemption Applicable Make Whole Premium

14

Accrued interest paid in redemption of debt

$ 5.5

Debt Instrument Write Off of Deferred Financing Cost Related to Repurchase

$ 9

$ 9

Convertible Debentures

Debt Instrument [Line Items]

Aggregate principal amount of debt

$ 101.4

$ 101.4

$ 277.7

Convertible Debentures | 6.25% Debentures due March 2017

Debt Instrument [Line Items]

Interest rate (as a percent)

6.25%

6.25%

Convertible Debentures | 5.6% Debentures due June 2017

Debt Instrument [Line Items]

Interest rate (as a percent)

5.60%

5.60%

5.60%

5.60%

Convertible Debentures | 5.6% Debentures Due June 2017 And 6.25% Debentures Due March 2017 (Member) | Interest expense

Debt Instrument [Line Items]

Write-off of deferred financing costs

$ 1.3

Convertible Debentures | 5.75% Debentures due June 2019

Debt Instrument [Line Items]

Redemption price percentage of principal amount

965.00%

965.00%

Debt Instrument, Repurchase Amount

$ 62.7

$ 62.7

Interest rate (as a percent)

5.75%

5.75%

5.75%

5.75%

Convertible Debentures | 5.75% Debentures due June 2019 | Interest expense

Debt Instrument [Line Items]

Write-off of deferred financing costs

$ 1.4

APLP Holdings

Debt Instrument [Line Items]

Amount of cash flow of APLP Holdings and its subsidiaries remaining after application of funds according to the Credit Agreement to be applied under

50

50

APLP Holdings | Minimum

Debt Instrument [Line Items]

Leverage ratio as defined in Credit Agreement

4.25

4.25

Interest coverage ratio as defined in Credit Agreement

2.75

2.75

APLP Holdings | Maximum

Debt Instrument [Line Items]

Leverage ratio as defined in Credit Agreement

6

6

Interest coverage ratio as defined in Credit Agreement

4

4

Other percentage of cash flow required to reduce aggregate principal amount of new term loans outstanding to achieve target principal amount that declines

100

100

APLP Holdings | Interest expense

Debt Instrument [Line Items]

Write-off of deferred financing costs

$ 30.2

APLP Holdings | New Term Loans

Debt Instrument [Line Items]

Prepayment of term loans if change of control occurs, as a percentage of par

101

101

Period from initial funding date that APLP would be required to repay, prepay, refinance or replace at a price of 101 percent of the principal amount if they elect to do so for any portion or all of the term loan facilities

1 year

Percent of principal amount required to be repaid, prepaid, refinanced or replaced if APLP elects to do so within one year of initial funding date

101

101

APLP Holdings | New Credit Facilities | Minimum

Debt Instrument [Line Items]

Margin on variable interest rate

4.00%

APLP Holdings | New Credit Facilities | New Term Loans

Debt Instrument [Line Items]

Aggregate principal amount of debt

$ 700

Amount drawn under loan

700

Proceeds from debt, net of discount

$ 679

Original issue discount (as a percent)

3.00%

Original issue discount amount

$ 21

$ 21

Transaction costs and expenses

$ 14.4

APLP Holdings | New Credit Facilities | New Term Loans | Adjusted Eurodollar Rate

Debt Instrument [Line Items]

Margin on variable interest rate

5.00%

APLP Holdings | New Credit Facilities | New Revolver

Debt Instrument [Line Items]

Aggregate principal amount of debt

200

Number of days prior to the Letter of Credit Expiration Date that letters of credit are available to be issued

30 days

Commitment fee related to New Revolver, as a percent

0.75%

APLP Holdings | New Credit Facilities | Letters of credit

Debt Instrument [Line Items]

Aggregate principal amount of debt

$ 105.8

Period of debt service covered by debt service reserve fund

6 months

Amount of debt service reserve

$ 25.3

APLP Holdings | Convertible Debentures | 6.25% Debentures due March 2017

Debt Instrument [Line Items]

Redemption of convertible unsecured subordinated debentures | CAD

CAD 67.2

APLP Holdings | Convertible Debentures | 5.6% Debentures due June 2017

Debt Instrument [Line Items]

Redemption of convertible unsecured subordinated debentures | CAD

CAD 75.8

APLP Holdings | Convertible Debentures | 5.6% Debentures Due June 2017 And 6.25% Debentures Due March 2017 (Member)

Debt Instrument [Line Items]

Redemption of convertible unsecured subordinated debentures

110.7

APLP | New Credit Facilities | Maximum

Debt Instrument [Line Items]

Margin on variable interest rate

5.00%

APLP | Long-term debt excluding debentures | Senior secured term loan facility, due 2021

Debt Instrument [Line Items]

Redemption of senior secured term loan

$ 447.9

APLP | Long-term debt excluding debentures | Senior unsecured notes, due June 2036 (Cdn$210.0)

Debt Instrument [Line Items]

Aggregate principal amount of debt | CAD

CAD 210

Interest rate (as a percent)

5.95%

5.95%

APLP | Convertible Debentures | 6.25% Debentures due March 2017

Debt Instrument [Line Items]

Interest rate (as a percent)

6.25%

APLP | Convertible Debentures | 5.6% Debentures due June 2017

Debt Instrument [Line Items]

Interest rate (as a percent)

5.60%

Convertible debentures (Details

Convertible debentures (Details) CAD in Millions, $ in Millions	Apr. 13, 2016CAD	Apr. 13, 2016USD ($)	Dec. 29, 2015USD ($)	Jul. 31, 2016USD ($)	Apr. 30, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Jul. 22, 2016USD ($)	Jun. 30, 2016USD ($)	Jun. 17, 2016USD ($)
Convertible debentures
Convertible debentures						$ 101.4		$ 101.4		$ 101.4	$ 277.7
Foreign Currency Transaction Gain (Loss), before Tax						3.4	$ 21.7	(19.1)	$ 49.1
Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures		$ 110.7
Convertible Debentures
Convertible debentures
Aggregate principal amount of debt						101.4		101.4		101.4	277.7
Less: unamortized deferred financing costs						$ (2.9)		$ (2.9)		$ (2.9)	(7.7)
Gain on repurchase of convertible debentures											(3.1)
Convertible Debentures | 6.25% Debentures due March 2017
Convertible debentures
Convertible debentures											48.6
Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD	CAD 67.2
Convertible debentures stated interest rate percentage						6.25%		6.25%		6.25%
Convertible Debentures | 5.6% Debentures due June 2017
Convertible debentures
Convertible debentures											54.8
Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD	CAD 75.8
Convertible debentures stated interest rate percentage	5.60%	5.60%				5.60%		5.60%		5.60%
Convertible Debentures | 5.75% Debentures due June 2019
Convertible debentures
Convertible debentures						$ 42.6		$ 42.6		$ 42.6	117			$ 65
Gain on repurchase of convertible debentures						$ 1.7		$ 1.7
Convertible debentures stated interest rate percentage						5.75%		5.75%		5.75%			5.75%	5.75%
Debentures purchased												$ 62.7	$ 62.7
Debentures cancelled														$ 62.7
Convertible Debentures | 6.00% Debenture due December 2019
Convertible debentures
Convertible debentures						$ 61.7		$ 61.7		$ 61.7	65
Convertible debentures stated interest rate percentage						6.00%		6.00%		6.00%
Convertible Debentures | Maximum
Convertible debentures
Amount that may be purchased, as a percentage of public float			10.00%
Convertible Debentures | Interest expense | 5.75% Debentures due June 2019
Convertible debentures
Write-off of deferred financing costs				$ 1.4
Convertible Debentures | Interest expense | 5.6% Debentures Due June 2017 And 6.25% Debentures Due March 2017 (Member)
Convertible debentures
Write-off of deferred financing costs					$ 1.3
Convertible Debentures | NCIB
Convertible debentures
Amount that may be purchased under the NCIB			$ 28.5
Repayment of convertible debentures										$ 18.8	$ 24.8
Gain on repurchase of convertible debentures										$ (2.5)

Fair value of financial instr43

Fair value of financial instruments - recurring (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Assets:
Restricted cash	$ 12.6	$ 15.2
Recurring
Assets:
Cash and cash equivalents	93.8	72.4
Restricted cash	12.6	15.2
Derivative instruments asset	2.9	0.3
Total	109.3	87.9
Liabilities:
Derivative instruments liability	42.5	57.5
Total	42.5	57.5
Recurring | Credit valuation adjustments
Liabilities:
Net increase in fair value	5.2	3.8
Pre-tax gain in other comprehensive income	0.5	0.4
Gain in change in fair value of derivatives	4.7	3.4
Recurring | Level 1
Assets:
Cash and cash equivalents	93.8	72.4
Restricted cash	12.6	15.2
Total	106.4	87.6
Recurring | Level 2
Assets:
Derivative instruments asset	2.9	0.3
Total	2.9	0.3
Liabilities:
Derivative instruments liability	42.5	57.5
Total	$ 42.5	$ 57.5

Accounting for derivative ins44

Accounting for derivative instruments and hedging activities (Details) MMBTU in Millions, $ in Millions

Apr. 13, 2016USD ($)

May 05, 2014USD ($)

Jun. 30, 2014MMBTU

Sep. 30, 2016USD ($)item

Sep. 30, 2015USD ($)

Mar. 31, 2017MMBTU

Sep. 30, 2016USD ($)MMBTUitem

Sep. 30, 2015USD ($)

Dec. 31, 2015USD ($)MMBTU

Mar. 31, 2020USD ($)

Sep. 30, 2019USD ($)

Feb. 29, 2016

Mar. 31, 2015

Feb. 14, 2014USD ($)

Derivative instruments

Derivative Number of Contracts Designated as Cash Flow Hedges | item

1

1

Minimum fixed interest rate (as a percent)

6.00%

Convertible Debentures

Derivative instruments

Aggregate principal amount of debt

$ 101.4

$ 101.4

$ 277.7

Senior secured term loan facility, due 2021 | Long-term debt excluding debentures

Derivative instruments

Long-term debt

473.2

Piedmont term loan, due 2018 | Long-term debt excluding debentures

Derivative instruments

Long-term debt

57.5

$ 57.5

$ 59

Applicable margin (as a percent)

8.47%

London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2021 | Long-term debt excluding debentures

Derivative instruments

Minimum percentage of variable rate base

1.00%

Applicable margin (as a percent)

3.75%

Adjusted Eurodollar Rate

Derivative instruments

Minimum percentage of variable rate base

1.00%

Applicable margin (as a percent)

5.00%

Gas purchase agreements | Ontario project

Derivative instruments

Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU

2.9

Gas purchase agreements | Morris Project | Forecast

Derivative instruments

Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU

1.3

Expected uncontracted gas requirements for 2015 | Ontario project

Derivative instruments

Percentage of requirements whose price is fixed by derivative

100.00%

Expected uncontracted gas requirements for 2016 | Ontario project

Derivative instruments

Percentage of requirements whose price is fixed by derivative

35.00%

Expected uncontracted gas requirements for 2017 | Ontario project

Derivative instruments

Percentage of requirements whose price is fixed by derivative

30.00%

Natural gas swaps

Derivative instruments

Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU

4.7

2.8

Natural gas swaps | Derivative instruments not designated as cash flow hedges

Derivative instruments

Gain (Loss) on Sale of Derivatives

0.6

$ 1.5

$ 4

$ 4.3

Natural gas swaps during remainder of 2014 | Orlando project

Derivative instruments

Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU

5.7

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

95.00%

Interest rate swaps

Derivative instruments

Minimum fixed interest rate (as a percent)

6.00%

Notional amount

520.4

$ 520.4

$ 302.3

Interest rate swaps | Derivative instruments not designated as cash flow hedges

Derivative instruments

Gain (Loss) on Sale of Derivatives

1

$ 0.5

2.7

$ 1.7

Interest rate swaps | London Interbank Offered Rate (LIBOR)

Derivative instruments

Aggregate principal amount of debt

654.9

654.9

Interest rate swaps | London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2021 | Long-term debt excluding debentures

Derivative instruments

Notional amount

$ 434.7

Interest rate swaps | Adjusted Eurodollar Rate

Derivative instruments

Notional amount

199

124.7

124.7

Interest rate swaps | Adjusted Eurodollar Rate | Senior secured term loan facility, due 2021 | Long-term debt excluding debentures

Derivative instruments

Notional amount

$ 509

Aggregate principal amount of debt

$ 600

Interest rate swaps | Minimum | Adjusted Eurodollar Rate

Derivative instruments

Minimum percentage of variable rate base

1.00%

Interest rate swaps | APLP Holdings | Adjusted Eurodollar Rate | Senior secured term loan facility, due 2021

Derivative instruments

Notional amount

$ 310

124.7

124.7

Aggregate principal amount of debt

$ 700

$ 654.9

$ 654.9

Interest rate swaps | APLP Holdings | Forecast

Derivative instruments

Remaining notional amount to terminate

$ 150

$ 160

Interest rate swaps | Piedmont

Derivative instruments

Long-term 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%

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%

6.30%

Interest rate swaps | Swaption interest rate after February 15, 2023 | Cadillac Project

Derivative instruments

Swaption interest rate (as a percent)

6.40%

6.40%

Interest rate swaps | Swaption interest rate until February 29, 2016 | Piedmont

Derivative instruments

Swaption interest rate (as a percent)

1.70%

1.70%

Interest rate swaps | Swaption interest rate until February 29, 2016 | Piedmont | Minimum

Derivative instruments

Applicable margin of derivative (as a percent)

3.50%

Interest rate swaps | Swaption interest rate until February 29, 2016 | Piedmont | Maximum

Derivative instruments

Applicable margin of derivative (as a percent)

3.80%

Interest rate swaps | Swaption interest rate From February, 2016 to August, 2018 | Piedmont

Derivative instruments

Swaption interest rate (as a percent)

4.47%

4.47%

Applicable margin of derivative (as a percent)

4.00%

4.00%

Swaption all in one interest rate (as a percent)

8.50%

8.50%

Interest rate swaps | Swaption interest rate From August, 2018 to November, 2030 | Piedmont

Derivative instruments

Swaption interest rate (as a percent)

4.47%

4.47%

Accounting for derivative ins45

Accounting for derivative instruments - forecasted trans (Details) kJ in Millions, MMBTU in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)kJMMBTU	Dec. 31, 2015USD ($)kJMMBTU
Natural gas swaps
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | MMBTU	4.7	2.8
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | kJ	17.2	25
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $	$ 520.4	$ 302.3

Accounting for derivative ins46

Accounting for derivative instruments - FV by Bal Sht Loc (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair value of derivative instruments
Derivative Assets	$ 2.9	$ 0.3
Derivative Liabilities	42.5	57.5
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	3.8	3.7
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	0.9	1
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	2.9	2.7
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets	2.9	0.3
Derivative Liabilities	38.7	53.8
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	2.5	2
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Assets	0.8	0.3
Derivative Liabilities	10.7	7.8
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current
Fair value of derivative instruments
Derivative Assets	1.5
Derivative Liabilities	1	5
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term
Fair value of derivative instruments
Derivative Assets	0.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current
Fair value of derivative instruments
Derivative Assets	0.1
Derivative Liabilities	10.8	28.7
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term
Fair value of derivative instruments
Derivative Liabilities	$ 13.7	$ 10.3

Accounting for derivative ins47

Accounting for derivative instruments - AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges		$ (0.4)	$ (0.6)	$ (0.8)
Realized from OCI during the period	$ 0.2	0.2	0.5	0.6
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	(0.1)	0.1	0.2	0.1
Change in fair value of cash flow hedges	0	(0.4)	(0.6)	(0.8)
Realized from OCI during the period	0.2	0.2	0.5	0.6
Accumulated OCI balance at end of period	$ 0.1	$ (0.1)	$ 0.1	$ (0.1)

Accounting for derivative ins48

Accounting for derivative instruments - gain, loss - (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ 9	$ 3.6	$ 20	$ 8.7
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	9	3.6	20	8.7
Derivative instruments not designated as cash flow hedges | Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized (gains) and losses of derivative instruments	0.6	1.5	4	4.3
Change in fair value of derivative instruments	0.2	(0.1)	6	0.7
Derivative instruments not designated as cash flow hedges | Gas purchase agreements
Impact of derivative instruments on the consolidated statements of operations
Realized (gains) and losses of derivative instruments	12.4	11.8	36.4	36.1
Change in fair value of derivative instruments	5.6	6.1	16.8	11.6
Derivative instruments not designated as cash flow hedges | Interest rate swaps
Impact of derivative instruments on the consolidated statements of operations
Realized (gains) and losses of derivative instruments	1	0.5	2.7	1.7
Change in fair value of derivative instruments	$ 3.2	$ (2.4)	$ (2.8)	$ (3.6)

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Components of income tax expenses (benefit)
Current income tax expense	$ 0.8	$ (1.6)	$ 2.6	$ 5.7
Deferred tax benefit	1.8	3	(16.8)	(6)
Total income tax (benefit) expense, net	$ 2.6	$ 1.4	$ (14.2)	$ (0.3)
Reconciliation of income taxes
Canadian enacted statutory rate (as a percent)	26.00%	26.00%	26.00%	26.00%
Computed income taxes at Canadian statutory rate	$ 20.2	$ 0.5	$ 32.2	$ 0.3
Goodwill impairment	22.5		22.5
Impairment of goodwill			78.8
Capital loss on intercompany notes	7.2		3
Foreign exchange		2.2	5.5	6.3
Change in valuation allowance	8.6	4	13.2	10.1
Dividend withholding tax and other cash taxes		2.6		1
Other permanent differences	0.8	0.1	1.1	0.6
Tax credit		3.6		3.6
Operating in higher tax rate jurisdictions	1.9		2.8	4
Valuation allowance	188.5		188.5
Capital gain on repatriation of wind sale proceeds		$ 2.8		$ 2.8
United States
Reconciliation of income taxes
Change in valuation allowance	(0.7)		(18.4)
Canada
Reconciliation of income taxes
Change in valuation allowance	9.3		31.6
Capital losses on tax restructuring	$ 18.5		$ 18.5

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	Jan. 22, 2015CAD / shares	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)
Units
Outstanding at the beginning of the period (in shares)				1,298,401
Granted (in shares)				1,594,954
Vested and redeemed (in shares)				(771,437)
Forfeitures (in shares)				(7,431)
Outstanding at the end of the period (in shares)		2,114,487		2,114,487
Weighted-Average Fair Value per Unit
Outstanding at the beginning of the period (in dollars per share) | $ / shares				$ 2.88
Granted (in dollars per share) | $ / shares				1.81
Vested and redeemed (in dollars per share) | $ / shares				2.85
Forfeitures (in dollars per share) | $ / shares				2.71
Outstanding at the end of the period (in dollars per share) | $ / shares		$ 1.84		$ 1.84
Long-term incentive plan
Weighted-Average Fair Value per Unit
Cash payments made for vested notional units | $				$ 0.4	$ 1
Compensation expense related to LTIP | $		$ 0.5	$ 1	$ 1.4	$ 2.1
Transition equity participation agreement
Transition equity participation agreement
Number of transition notional shares outstanding				539,904
Vesting percentage				50.00%
Vesting period				4 years
Period after which remaining portions vests				2 years
Market price (in dollars per share) | CAD / shares	CAD 3.18
Minimum market price required for 3 consecutive months to vest remaining shares | CAD / shares	CAD 4.77
Transition equity participation agreement | Minimum
Transition equity participation agreement
Number of consecutive months, weighted average Canadian dollar price must exceed market price of share by 50% for vesting				3 months
Minimum percentage by which weighted average Canadian dollar price exceeds market price	50.00%

Basic and diluted (loss) earn51

Basic and diluted (loss) earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Numerator:
Loss from continuing operations attributable to Atlantic Power Corporation	$ (82.4)	$ (5.5)	$ (116.2)	$ (5.5)
(Loss) income from discontinued operations, net of tax		(0.5)		31.6
Net (loss) income attributable to Atlantic Power Corporation	$ (82.4)	$ (6)	$ (116.2)	$ 26.1
Denominator:
Weighted average basic shares outstanding	119.3	122.1	120.9	121.8
Dilutive potential shares:
Convertible debentures (in shares)	8.1	22.4	14.9	22.8
LTIP notional units (in shares)	0.1	0.1	0.1	0.1
Potentially dilutive shares	127.5	144.6	135.9	144.7
Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$ (0.69)	$ (0.05)	$ (0.96)	$ (0.05)
Diluted earnings per share from discontinued operations				0.26
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$ (0.69)	$ (0.05)	$ (0.96)	$ 0.21
Potentially dilutive shares from convertible debentures excluded from fully diluted shares	$ 8.1	$ 22.4	$ 14.9	$ 22.8

Equity (Details)

Equity (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				$ 435.2	$ 816.5
Net (loss) income				(109.8)	21.8
Realized and unrealized gain on hedging activities, net of tax		$ 0.2	$ (0.2)	(0.1)	(0.2)
Foreign currency translation adjustments		(22)	(22.1)	(2.6)	(52.7)
Common share repurchases				(13.9)
Stock-based compensation				1.4	2.1
Dividends paid to noncontrolling interests					(3.7)
Dividends declared on common shares					(8.5)
Dividends declared on preferred shares of a subsidiary company				(6.4)	(6.7)
Derecognition of noncontrolling interests upon sale of subsidiaries					(224.3)
Balance at the end of the period	$ 303.8	303.8	544.3	$ 303.8	544.3
Stock Repurchase Program
Total Number of Shares Purchased	1,394,096			5,678,736
Common stock repurchased, value				$ 13.9
Total Atlantic Power Corporation Shareholder's Equity
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				213.9	356.2
Net (loss) income				(116.2)	26.1
Realized and unrealized gain on hedging activities, net of tax				(0.1)	(0.2)
Foreign currency translation adjustments				(2.6)	(52.7)
Common share repurchases				(13.9)
Stock-based compensation				1.4	2.1
Dividends declared on common shares					(8.5)
Balance at the end of the period	$ 82.5	82.5	323	82.5	323
Preferred Shares of A Subsidiary Company
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				221.3	221.3
Net (loss) income				6.4	6.7
Dividends declared on preferred shares of a subsidiary company				(6.4)	(6.7)
Balance at the end of the period	$ 221.3	$ 221.3	$ 221.3	$ 221.3	221.3
Noncontrolling Interests
Increase (decrease) in shareholders' equity
Balance at the beginning of the period					239
Net (loss) income					(11)
Dividends paid to noncontrolling interests					(3.7)
Derecognition of noncontrolling interests upon sale of subsidiaries					$ (224.3)

Segment and geographic inform53

Segment and geographic information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)segment	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Segment and geographic information
Number of Reportable Segments | segment			4
Project revenues	$ 101.2	$ 107.5	$ 305.8	$ 321.8
Segment assets	1,521.9	1,910.2	1,521.9	1,910.2	$ 1,671.2
Project Adjusted EBITDA	51.3	56	159.9	158.5
Change in fair value of derivative instruments	(9)	(3.6)	(20.1)	(8.7)
Depreciation and amortization	30.4	32.8	90.8	98.9
Interest, net	(2.8)	(2.5)	(8.2)	7.7
Impairment charges	84.7		84.7
Other project (income) expense	(0.5)	0.1	(0.4)	(2.4)
Project (loss) income	(57.1)	24.2	(3.3)	63
Administration	5.7	6.9	17.6	23
Interest, net.	(20)	(41)	(87.9)	(91.3)
Foreign exchange (gain) loss	(3.4)	(21.7)	19.1	(49.1)
Other income, net	(1.7)		(3.9)	(3.1)
Income (loss) from continuing operations before income taxes	(77.7)	(2)	(124)	0.9
Income tax expense (benefit)	2.6	1.4	(14.2)	(0.3)
Net income (loss) from continuing operations	(80.3)	(3.4)	(109.8)	1.2
East U.S.
Segment and geographic information
Project revenues	31.3	38.4	104.3	114.8
Segment assets	764.9	849.7	764.9	849.7
Project Adjusted EBITDA	19.4	27.4	70.5	81
Change in fair value of derivative instruments	(1.2)	1.9	(3)	1.6
Depreciation and amortization	11	10.7	33	31.8
Interest, net	(2.8)	(2.4)	(8.2)	7.6
Impairment charges	15.4		15.4
Project (loss) income	(8.6)	12.4	16.9	40
Income (loss) from continuing operations before income taxes	(8.6)	12.4	16.9	40
Net income (loss) from continuing operations	(8.6)	12.4	16.9	40
West U.S.
Segment and geographic information
Project revenues	34.1	34.5	78.7	83.9
Segment assets	328.9	368.2	328.9	368.2
Project Adjusted EBITDA	21.3	21.4	43.4	37.1
Depreciation and amortization	9.9	9.9	29.6	29.7
Other project (income) expense				0.1
Project (loss) income	11.4	11.5	13.8	7.3
Income (loss) from continuing operations before income taxes	11.4	11.5	13.8	7.3
Net income (loss) from continuing operations	11.4	11.5	13.8	7.3
Canada
Segment and geographic information
Project revenues	35.6	34.4	122	122.6
Segment assets	325.3	569.5	325.3	569.5
Project Adjusted EBITDA	10.7	7.6	46.2	43
Change in fair value of derivative instruments	(5.6)	(6.1)	(17.7)	(11.6)
Depreciation and amortization	9.4	11.7	27.7	36.5
Interest, net		(0.1)		0.1
Impairment charges	69.3		69.3
Other project (income) expense				0.1
Project (loss) income	(62.4)	1.9	(33.1)	17.9
Income (loss) from continuing operations before income taxes	(62.4)	1.9	(33.1)	17.9
Net income (loss) from continuing operations	(62.4)	1.9	(33.1)	17.9
Un-Allocated Corporate
Segment and geographic information
Project revenues	0.2	0.2	0.8	0.5
Segment assets	102.8	122.8	102.8	122.8
Project Adjusted EBITDA	(0.1)	(0.4)	(0.2)	(2.6)
Change in fair value of derivative instruments	(2.2)	0.6	0.6	1.3
Depreciation and amortization	0.1	0.5	0.5	0.9
Other project (income) expense	(0.5)	0.1	(0.4)	(2.6)
Project (loss) income	2.5	(1.6)	(0.9)	(2.2)
Administration	5.7	6.9	17.6	23
Interest, net.	(20)	(41)	(87.9)	(91.3)
Foreign exchange (gain) loss	(3.4)	(21.7)	19.1	(49.1)
Other income, net	(1.7)		(3.9)	(3.1)
Income (loss) from continuing operations before income taxes	(18.1)	(27.8)	(121.6)	(64.3)
Income tax expense (benefit)	2.6	1.4	(14.2)	(0.3)
Net income (loss) from continuing operations	$ (20.7)	$ (29.2)	$ (107.4)	$ (64)

Segment and geographic inform54

Segment and geographic information - Geographic (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Revenue and Assets
Revenue	$ 101.2	$ 107.5	$ 305.8	$ 321.8
Property, Plant and Equipment, net of accumulated depreciation	749.8		749.8		$ 777.7
Impairment charges	84.7		84.7
United States
Revenue and Assets
Revenue	65.6	73.1	183.8	199.2
Property, Plant and Equipment, net of accumulated depreciation	506.1		506.1		529.6
Canada
Revenue and Assets
Revenue	35.6	$ 34.4	122	$ 122.6
Property, Plant and Equipment, net of accumulated depreciation	$ 243.7		$ 243.7		$ 248.1

Segment and geographic inform55

Segment and geographic information - Risk (Details) - Revenues, net - Consolidated revenue	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	24.50%	22.90%	28.00%	27.70%
San Diego Gas & Electric
Consolidated revenue concentration
Percentage of consolidated revenue	16.10%	16.70%	11.50%	12.60%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	10.60%	9.10%	11.60%	7.70%
Georgia Power
Consolidated revenue concentration
Percentage of consolidated revenue	10.90%	10.20%		10.40%

Contingencies (Details)

Contingencies (Details)	Sep. 30, 2016item
Shareholder class action lawsuits
Contingencies
Number of pending matters having material adverse impact on financial position or results of operations or have been reserved	0