Atlantic Power 10-Q 5 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 02, 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	Mar. 31, 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		122,083,528
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 64.3	$ 72.4
Restricted cash	10	15.2
Accounts receivable	40	39.6
Current portion of derivative instruments asset (Notes 7 and 8)	0.2
Inventory	14.1	16.9
Prepayments	8.7	8.3
Income taxes receivable	3.2	3.5
Other current assets	2.6	4.4
Total current assets	143.1	160.3
Property, plant, and equipment, net of accumulated depreciation of $255.6 million and $236.3 million at March 31, 2016 and December 31, 2015, respectively	777.8	777.7
Equity investments in unconsolidated affiliates (Note 4)	292.6	286.2
Power purchase agreements and intangible assets, net of accumulated amortization of $257.2 million and $238.0 million at March 31, 2016 and December 31, 2015, respectively	299.9	308.9
Goodwill	134.5	134.5
Derivative instruments asset (Notes 7 and 8)	0.4	0.3
Other assets	11.7	6.7
Total assets	1,660	1,674.6
Current liabilities:
Accounts payable	4.1	6.9
Accrued interest	6.8	1.6
Other accrued liabilities	25.3	28.8
Current portion of long-term debt (Note 5)	15.7	15.8
Current portion of derivative instruments liability (Note 7 and 8)	35.5	36.7
Other current liabilities	1.7	2.5
Total current liabilities	89.1	92.3
Long-term debt, net of unamortized deferred financing costs (Note 5)	666.9	682.7
Convertible debentures, net of unamortized deferred financing costs (Note 5 and 6)	271.4	277.7
Derivative instruments liability (Note 7 and 8)	26.5	20.8
Deferred income taxes (Note 9)	85.5	85.7
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $14.9 million and $14.0 million at March 31, 2016 and December 31, 2015, respectively	27.4	27
Other long-term liabilities	55	53.2
Total liabilities	1,221.8	1,239.4
Equity
Common shares, no par value, unlimited authorized shares; 122,083,528 and 122,153,082 issued and outstanding at March 31, 2016 and December 31, 2015	1,290.2	1,290.6
Accumulated other comprehensive loss (Note 2)	(121.2)	(139.3)
Retained deficit (Note 12)	(952.1)	(937.4)
Total Atlantic Power Corporation shareholders' equity	216.9	213.9
Preferred shares issued by a subsidiary company (Note 12)	221.3	221.3
Total equity	438.2	435.2
Total liabilities and equity	$ 1,660	$ 1,674.6

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CONSOLIDATED BALANCE SHEETS
Accumulated Depreciation on Property, Plant, and Equipment	$ 255.6	$ 236.3
Accumulated amortization on power purchase agreements and other intangible assets	257.2	238
Accumulated amortization on power purchase and fuel supply agreement liabilities	$ 14.9	$ 14
Common shares, no par value (in dollars per share)	$ 0	$ 0
Common shares, issued shares (in shares)	122,083,528	122,153,082
Common shares, outstanding shares (in shares)		122,153,082

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Project revenue:
Energy sales	$ 52.5	$ 54
Energy capacity revenue	31.9	33.5
Other	22	23.8
Total project revenue	106.4	111.3
Project expenses:
Fuel	38.9	46.2
Operations and maintenance	21.2	21.5
Development		1.1
Depreciation and amortization	24.8	28
Total project expenses	84.9	96.8
Project other income:
Change in fair value of derivative instruments (Notes 7 and 8)	(1.2)	(1.7)
Equity in earnings of unconsolidated affiliates (Note 4)	10.7	10.8
Interest expense, net	(2.1)	(2.1)
Other income, net	(0.2)
Total project other income (expense)	7.2	7
Project income	28.7	21.5
Administrative and other expenses (income):
Administration	6.1	9.4
Interest, net	16.6	25.7
Foreign exchange loss (gain)	19.8	(32.2)
Other income, net (Note 6)	(2.5)	(1.4)
Total administrative and other expenses (income)	40	1.5
(Loss) income from continuing operations before income taxes	(11.3)	20
Income tax expense (benefit) (Note 9)	1.6	(4.6)
Loss (income) from continuing operations	(12.9)	24.6
Net loss from discontinued operations, net of tax (Note 13)		(12.3)
Net (loss) income	(12.9)	12.3
Net loss attributable to noncontrolling interests		(7.5)
Net income attributable to preferred shares dividends of a subsidiary company	2	2.3
Net (loss) income attributable to Atlantic Power Corporation	$ (14.9)	$ 17.5
Basic and diluted (loss) income per share: (Note 11)
(Loss) income from continuing operations attributable to Atlantic Power Corporation	$ (0.12)	$ 0.17
Loss from discontinued operations, net of tax		(0.03)
Net (loss) income attributable to Atlantic Power Corporation	$ (0.12)	$ 0.14
Weighted average number of common shares outstanding: (Note 11)
Basic (in shares)	121.9	121.5
Diluted (in shares)	121.9	122.4
Dividends per common share (in dollars per share)	$ 0	$ 0.02

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
Net (loss) income	$ (12.9)	$ 12.3
Other comprehensive (loss) income, net of tax
Unrealized loss on hedging activities	(0.5)	(0.5)
Net amount reclassified to earnings	0.2	0.2
Net unrealized loss on derivatives	(0.3)	(0.3)
Foreign currency translation adjustments	18.5	(35.1)
Other comprehensive income (loss), net of tax	18.2	(35.4)
Comprehensive income (loss)	5.3	(23.1)
Less: Comprehensive income (loss) attributable to noncontrolling interests	2	(5.2)
Comprehensive income (loss) attributable to Atlantic Power Corporation	$ 3.3	$ (17.9)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash provided by operating activities:
Net (loss) income	$ (12.9)	$ 12.3
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	24.8	38.1
Gain on purchase and cancellation of convertible debentures	(2.5)	(1.4)
Loss on disposal of fixed assets	0.2
Stock-based compensation expense	0.6	0.4
Equity in earnings from unconsolidated affiliates	(10.7)	(9.9)
Distributions from unconsolidated affiliates	4.3	7.2
Unrealized foreign exchange loss (gain)	20.1	(32.8)
Change in fair value of derivative instruments	1.2	9
Change in deferred income taxes	0.1	(3.9)
Change in other operating balances
Accounts receivable	(0.5)	6
Inventory	2.8	3.6
Prepayments, refundable income taxes and other assets	(10.4)	4.3
Accounts payable	1.4	(5.5)
Accruals and other liabilities	10.9	7.7
Cash provided by operating activities	29.4	35.1
Cash provided by investing activities:
Change in restricted cash	5.2	9.7
Capitalized development costs		(0.8)
Reimbursement of costs for third-party construction project	4.7
Purchase of property, plant and equipment	(0.7)	(1.3)
Cash provided by investing activities	9.2	7.6
Cash used in financing activities:
Common share repurchases	(0.9)
Repayment of corporate and project-level debt	(27.5)	(32.8)
Repayment of convertible debentures	(16.3)	(5.7)
Dividends paid to common shareholders		(2.9)
Dividends paid to noncontrolling interests		(2.7)
Dividends paid to preferred shareholders	(2)	(2.3)
Cash used in financing activities	(46.7)	(46.4)
Net decrease in cash and cash equivalents	(8.1)	(3.7)
Less cash at discontinued operations		(6.2)
Cash and cash equivalents at beginning of period at discontinued operations		3.9
Cash and cash equivalents at beginning of period	72.4	106.1
Cash and cash equivalents at end of period	64.3	100.1
Supplemental cash flow information
Interest paid	8.9	11.7
Income taxes paid, net	0.9	$ 0.4
Accruals for construction in progress	$ 1

Nature of business

Nature of business	3 Months Ended
	Mar. 31, 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 March 31, 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 eleven 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 March 31, 2016, the results of operations and comprehensive income (loss) for the three months ended March 31, 2016 and 2015, and our cash flows for the three months ended March 31, 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 fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity based compensation. In addition, estimates are used to test long lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates ” in our Annual Report on Form 10 K for the year ended December 31, 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 $39.5 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended March 31, 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.

Changes in accumulated other co

Changes in accumulated other comprehensive loss by component	3 Months Ended
	Mar. 31, 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 March 31, 2016 2015 Foreign currency translation Balance at beginning of period $ $ Other comprehensive income (loss): Foreign currency translation adjustments (1) Balance at end of period $ $ Pension Balance at beginning of period $ $ Other comprehensive income (loss): Unrecognized net actuarial gain (loss) — — Tax benefit (expense) — — Total Other comprehensive (loss) income before reclassifications, net of tax — — Amortization of net actuarial loss — — Tax benefit — — Total amount reclassified from Accumulated other comprehensive loss, net of tax — — Total Other comprehensive (loss) income — — Balance at end of period $ $ Cash flow hedges Balance at beginning of period $ $ Other comprehensive income (loss): Net change from periodic revaluations Tax benefit Total Other comprehensive income before reclassifications, net of tax Net amount reclassified to earnings: Interest rate swaps (2) Sub-total Tax benefit 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.

Assets held for sale and discon

Assets held for sale and discontinued operations	3 Months Ended
	Mar. 31, 2016
Assets held for sale and discontinued operations
Assets held for sale and discontinued operations	3. Assets held for sale and 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 a $46.8 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the year ended December 31, 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 (loss) from operations of the Wind Projects for the three months ended March 31, 2015: Three months ended March 31, 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 — Loss from operations of discontinued businesses Income tax expense Loss from operations of discontinued businesses, net of tax Net loss attributable to noncontrolling interests of discontinued businesses Loss from operations of discontinued businesses, net of noncontrolling interests $ Basic and diluted loss per share related to loss from discontinued operations for the Wind Projects was $(0.03) for the three months ended March 31, 2015. The following table summarizes the operating and investing cash flows of the Wind Projects for the three months ended March 31, 2015: Three months ended March 31, 2015 Cash provided by operating activities $ Cash provided by investing activities The following table summarizes the March 31, 2015 financial position of the Wind Projects that were classified as assets held for sale : March 31, 2015 Current assets: Cash and cash equivalents $ Accounts receivable Other current assets Non-current assets: Property, Plant & Equipment Equity investments in unconsolidated affiliates Other intangible assets, net Restricted cash Other assets Assets held for sale $ Current liabilities: Accounts payable and other accrued liabilities $ Current portion of long-term debt Current portion of derivative instruments liability Long term liabilities Long-term debt Derivative instruments liability Other long-term liabilities Liabilities held for sale $ Noncontrolling interests held for sale

Equity method investments in un

Equity method investments in unconsolidated affiliates	3 Months Ended
	Mar. 31, 2016
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	4. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three months ended March 31, 2016 and 2015, respectively, for our equity method investments: Three Months Ended March 31, Operating results 2016 2015 Revenue Chambers $ $ Frederickson Orlando Other (1) Project expenses Chambers Frederickson Orlando Other (1) Project other income (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	3 Months Ended
	Mar. 31, 2016
Long-term debt excluding debentures
Long-term debt	5. Long ‑term debt Long ‑term debt consists of the following: March 31, December 31, 2016 2015 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ $ 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 LIBOR plus % Other long-term debt % - % Less: unamortized deferred financing costs Less: current maturities Total long-term debt $ $ Current maturities consist of the following: March 31, December 31, 2016 2015 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus % Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 LIBOR plus % Other short-term debt % - % Total current maturities $ $ (1) LIBOR cannot be less than 1.00% . On May 5, 2014, we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount ( $ 1 40.4 million at March 31, 2016) of the $600.0 million ( $447.9 million at March 31, 2016) outstanding aggregate borrowings under our senior secured term loan facility . See Note 8, Accounting for derivative instruments and hedging activities for further details. 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). As of May 2, 2016, we have used the proceeds from the New Term Loans to:  redeem in whole, at a price equal to par plus accrued interest, APLP’s 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);  deposit proceeds with the trustee for the redemption in whole on May 13, 2016, 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 $111.8 million); and  pay transaction costs and expenses of approximately $14.4 million. We may use the remaining proceeds of approximately $105.0 million for any corporate purpose, which may include, at our discretion, taking into account available funds, market conditions and other relevant factors, repurchase of all or a portion of our $105.3 million of 5.75% Convertible Unsecured Subordinated Debentures, Series C, due June 2019, all or a portion of our Cdn$81.0 million of 6.00% Convertible Unsecured Subordinated Debentures, Series D, due December 2019 and a portion of our preferred and common equity or other potential initiatives to reshape our capital structure. We accounted for the redemption of the Senior Secured Credit Facilities as an extinguishment of debt and wrote off $30.0 million of deferred financing costs to interest expense in April 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 with respect to the revolving commitments under the New Revolver that is equal to 0.75% times the average of the daily difference between (A) the revolving commitments and (B) drawings, if any and all outstanding reimbursement obligations with respect to drawn letters of credit. 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 APLP Holdings equity, 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 funded and maintained at the debt service reserve requirement, equal to six months of debt service. Atlantic Power Limited Partnership (“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. 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 to prepay 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, solely with respect to the New Revolver, a Change of Control of APLP Holdings, 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 redeemed on April 13, 2016. The redemption and extinguishment was recorded in April 2016 and will be presented in the Quarterly Report on Form 10-Q for the three and six 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 9.0% notes, plus accrued and unpaid interest to the redemption date. We paid $330.4 million to fund the full redemption of the Notes, which includes $14.0 million in make-whole premiums and $5.5 million in accrued interest. The make whole premiums, accrued interest and the $9.0 million of deferred financing costs related to the Notes 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 March 31, 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	3 Months Ended
	Mar. 31, 2016
Convertible Debentures
Long-term debt	6. Convertible debentures Convertible debentures consist of the following: March 31, December 31, 2016 2015 6.25% Debentures due March 2017 ( Cdn$67.2 million) $ $ 5.60% Debentures due June 2017 ( Cdn$75.8 million) 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, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures which expired on November 10, 2015. 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 statement 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 March 31, 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 three months ended March 31, 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 $ 111.8 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.

Fair value of financial instrum

Fair value of financial instruments	3 Months Ended
	Mar. 31, 2016
Fair value of financial instruments
Fair value of financial instruments	7. Fair value of financial instruments The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of March 31, 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. March 31, 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 March 31, 2016, the credit valuation adjustments resulted in a $5.1 million net increase in fair value, which consists of a $0.5 million pre ‑tax gain in other comprehensive income and a $4.6 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	3 Months Ended
	Mar. 31, 2016
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	8. Accounting for derivative instruments and hedging activities We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts. Gas purchase agreements Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration in the fourth quarter of 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. In June 2014, Atlantic Power Limited Partnership (the “Partnership”) entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 100% of our expected uncontracted gas requirements for 2015 and 35% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations. We have entered into various natural gas sales and purchase agreements for approximately 450,000 MMBtu to effectively mitigate seasonal fluctuation of future natural gas price at Morris from April 2016 through February 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at March 31, 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 7.7 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 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at March 31, 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, the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ( $140.4 million at March 31, 2016) of the $600 million aggregate principal amount of borrowings ( $447.9 million of borrowings at March 31, 2016) under the Term Loan Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.75% . Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00% . If the Adjusted Eurodollar Rate is below 1.00% , we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual Adjusted Eurodollar Rate and 1.16% . The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations. The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable ‑rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable margin is 4.0% , resulting in an all ‑in rate of 8.5% . The swap continues at the fixed rate of 4.47% until November 2030. Prior to conversion of the Piedmont construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations. The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac’s debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive loss. Volume of forecasted transactions We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption at March 31, 2016 and December 31, 2015: March 31, December 31, Units 2016 2015 Natural gas swaps Natural Gas (Mmbtu) Gas purchase agreements Natural Gas (Gigajoules) Interest rate swaps Interest (US$) 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 : March 31, 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 March 31, 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 March 31, 2016 $ Interest Rate Three Months Ended March 31, 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 March 31, 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 March 31, recognized in income 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 March 31, recognized in income 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	3 Months Ended
	Mar. 31, 2016
Income taxes
Income taxes	9. Income taxes Three Months Ended March 31, 2016 2015 Current income tax expense $ $ Deferred tax expense (benefit) Total income tax expense (benefit), net $ $ For the three months ended March 31, 2016 and 2015 Income tax expense for the three months ended March 31, 2016 was $1.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26% was $3.0 million. The primary items impacting the tax rate for the three months ended March 31, 2016 were $2.8 million relating to a change in the valuation allowance, $2.5 million related to foreign exchange, $0.6 million relating to dividend withholding and other taxes and $0.2 million of other permanent differences. These items were partially offset by $1.1 million relating to operating in higher tax rate jurisdictions and $0.4 million related to capital loss on intercompany notes. Income tax benefit for the three months ended March 31, 2015 was $4.6 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26% was $5.2 million. The primary items impacting the tax rate for the three months ended March 31, 2015 were $2.9 million relating to a change in the valuation allowance, $2.4 million relating to operating in higher tax rate jurisdictions, $1.8 million relating to foreign exchange and $2.7 million of other permanent differences. As of March 31, 2016, we have recorded a valuation allowance of $178.1 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

Equity compensation plans

Equity compensation plans	3 Months Ended
	Mar. 31, 2016
Equity compensation plans
Equity compensation plans	10. Equity compensation plans Long ‑term incentive plan (“LTIP”) The following table summarizes the changes in outstanding LTIP notional units during the three months ended March 31, 2016: Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2015 $ Granted Vested and redeemed Forfeitures Outstanding at March 31, 2016 $ Certain awards have a market condition based on our total shareholder return during the performance period as compared to a group of peer companies and, in some cases, Project Adjusted EBITDA per common share compared to budget. Compensation expense for notional units granted is recorded net of estimated forfeitures. See Note 16 to the consolidated financial statements in our Annual Report on Form 10 ‑K for the year ended December 31, 2015 for further details. Cash payments made for vested notional units for the three months ended March 31, 2016 and 2015 were $0. 1 million and $0.2 million, respectively. Compensation expense for LTIP was $0.2 million and $0.4 million for the three months ended March 31, 2016 and 2015, respectively. Transition Equity Participation Agreement We also have 539,904 transition notional shares outstanding at March 31, 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 ( $2.58 ) by at least 50% .

Basic and diluted earnings (los

Basic and diluted earnings (loss) per share	3 Months Ended
	Mar. 31, 2016
Basic and diluted earnings (loss) per share
Basic and diluted earnings (loss) per share	11. Basic and diluted earnings (loss) per share Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. Because we reported a loss for the three months ended March 31, 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 months ended March 31, 2016 and 2015: 2016 2015 Numerator: (Loss) gain from continuing operations attributable to Atlantic Power Corporation $ $ Loss 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) earnings per share from continuing operations attributable to Atlantic Power Corporation $ $ Diluted (loss) 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, is added back to the numerator for purposes of the if-converted calculation. Potentially dilutive shares from convertible debentures of 21.6 million and 23.5 million have been excluded from fully diluted shares in the three months ended March 31, 2016 and 2015, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from convertible debentures are anti-dilutive for the three months ended March 31, 2016 because we recorded a net loss. For the three months ended March 31, 2015, adding back the related interest expense, net of tax, under the if-converted method results in potentially dilutive shares from convertible debentures being anti-dilutive. Potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the three months ended March 31, 2016 because we recorded a net loss.

Stockholders Equity

Stockholders Equity	3 Months Ended
	Mar. 31, 2016
Equity
Stockholders' Equity Note Disclosure [Text Block]	12. Equity The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the three months ended March 31, 2016 and 2015: Three months ended March 31, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1 $ $ $ Net income (loss) 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 March 31 $ $ $ Three months ended March 31, 2015 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Noncontrolling Shareholders’ Equity company Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) Realized and unrealized gain on hedging activities, net of tax — — Foreign currency translation adjustment — — Stock-based compensation — — Dividends paid to noncontrolling interest — — Dividends declared on common shares — — Dividends declared on preferred shares of a subsidiary company — — Balance at March 31 $ $ $ $

Segment and geographic informat

Segment and geographic information	3 Months Ended
	Mar. 31, 2016
Segment and geographic information
Segment and geographic information	13. Segment and geographic information We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We revised our reportable business segments in the second quarter of 2015 as the result of 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 months ended March 31, 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. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented as proportionately consolidated based on our ownership percentage in the reconciliation of Project Adjusted EBITDA to project income (loss). A reconciliation of Project Adjusted EBITDA to project income (loss) for the three months ended March 31, 2016 and 2015 reflecting our revised reportable business segments is included in the table below: Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended March 31, 2016 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 loss — — — Other income, net — — — Income (loss) 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 March 31, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Other project expense (income) — — — — — Project income (loss) Administration — — — Interest, net — — — Foreign exchange gain — — — Other income, net — — — Income (loss) from continuing operations before income taxes Income tax benefit — — — Net income (loss) from continuing operations $ $ $ $ $ The table below provides information, by country, about our consolidated operations for each of the three months ended March 31, 2016 and 2015 and Property, Plant & Equipment as of March 31, 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 March 31, Property, Plant and Equipment, net of accumulated depreciation 2016 2015 March 31, 2016 December 31, 2015 United States $ $ $ $ Canada Total $ $ $ $ Independent Electricity System Operator (“IESO”), BC Hydro and Niagara Mohawk provided 38.1% , 14.2% , and 9.9% , respectively, of total consolidated revenues for the three months ended March 31, 2016. IESO, San Diego Gas & Electric and BC Hydro provided 33.7% , 14.4% and 11.7% , respectively, of total consolidated revenues for the three months ended March 31, 2015. IESO purchases electricity from the Calstock, Kapuskasing, Nipigon and North Bay projects in the Canada segment, San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West U.S. segment, BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment and Niagara Mohawk purchases electricity from the Curtis Palmer project in the East U.S. segment.

Guarantees

Guarantees	3 Months Ended
	Mar. 31, 2016
Guarantees
Guarantees	14. Guarantees We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, including the Purchase Agreement to sell the Wind Projects, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In connection with the Purchase Agreement for the sale of the Wind Projects, on March 31, 2015, we entered into a guaranty agreement (the “Guaranty Agreement”), under which we agreed to guarantee the full and prompt payment of all payment obligations of APT under the Purchase Agreement as and when they shall become due. APT and TerraForm have agreed to utilize the representation and warranty insurance for coverage of certain indemnification obligations, subject to a cap and certain exclusions.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2016
Contingencies
Contingencies	15. Contingencies Shareholder class action lawsuits On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the “Canadian Actions”). On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. This claim named the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation. The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015. On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial indemnity costs of responding to the Plaintiffs’ motion. The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal. The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs. The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the motions for leave and certification of the Ontario action as a class proceeding. On April 19, 2016, the Superior Court of Quebec authorized the discontinuance of the action. Other In addition to the matters listed above, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of March 31, 2016.

Nature of business (Policies)

Nature of business (Policies)	3 Months Ended
	Mar. 31, 2016
Nature of business
Basis of presentation	Basis of presentation The interim consolidated financial statements included in this Quarterly Report on Form 10 ‑Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10 ‑Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10 ‑K for the year ended December 31, 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 March 31, 2016, the results of operations and comprehensive income (loss) for the three months ended March 31, 2016 and 2015, and our cash flows for the three months ended March 31, 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 fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity based compensation. In addition, estimates are used to test long lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates ” in our Annual Report on Form 10 K for the year ended December 31, 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 $39.5 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended March 31, 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.

Changes in accumulated other 23

Changes in accumulated other comprehensive loss by component (Tables)	3 Months Ended
	Mar. 31, 2016
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax
Schedule of changes in accumulated other comprehensive loss by component	Three Months Ended March 31, 2016 2015 Foreign currency translation Balance at beginning of period $ $ Other comprehensive income (loss): Foreign currency translation adjustments (1) Balance at end of period $ $ Pension Balance at beginning of period $ $ Other comprehensive income (loss): Unrecognized net actuarial gain (loss) — — Tax benefit (expense) — — Total Other comprehensive (loss) income before reclassifications, net of tax — — Amortization of net actuarial loss — — Tax benefit — — Total amount reclassified from Accumulated other comprehensive loss, net of tax — — Total Other comprehensive (loss) income — — Balance at end of period $ $ Cash flow hedges Balance at beginning of period $ $ Other comprehensive income (loss): Net change from periodic revaluations Tax benefit Total Other comprehensive income before reclassifications, net of tax Net amount reclassified to earnings: Interest rate swaps (2) Sub-total Tax benefit Total amount reclassified from Accumulated other comprehensive loss, net of tax Total Other comprehensive income Balance at end of period $ $ (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). (2) This amount was included in Interest expense, net on the accompanying consolidated statements of operations.

Discontinued Operations (Tables

Discontinued Operations (Tables)	3 Months Ended
	Mar. 31, 2016
Assets held for sale and discontinued operations
Summary of income (loss) from discontinued operations	The following table summarizes the revenue and income (loss) from operations of the Wind Projects for the three months ended March 31, 2015: Three months ended March 31, 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 — Loss from operations of discontinued businesses Income tax expense Loss from operations of discontinued businesses, net of tax Net loss attributable to noncontrolling interests of discontinued businesses 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 three months ended March 31, 2015: Three months ended March 31, 2015 Cash provided by operating activities $ Cash provided by investing activities
Schedule of assets and liabilities held for sale	The following table summarizes the March 31, 2015 financial position of the Wind Projects that were classified as assets held for sale : March 31, 2015 Current assets: Cash and cash equivalents $ Accounts receivable Other current assets Non-current assets: Property, Plant & Equipment Equity investments in unconsolidated affiliates Other intangible assets, net Restricted cash Other assets Assets held for sale $ Current liabilities: Accounts payable and other accrued liabilities $ Current portion of long-term debt Current portion of derivative instruments liability Long term liabilities Long-term debt Derivative instruments liability Other long-term liabilities Liabilities held for sale $ Noncontrolling interests held for sale

Equity method investments in 25

Equity method investments in unconsolidated affiliates (Tables)	3 Months Ended
	Mar. 31, 2016
Equity method investments in unconsolidated affiliates
Summary of operating results	Three Months Ended March 31, Operating results 2016 2015 Revenue Chambers $ $ Frederickson Orlando Other (1) Project expenses Chambers Frederickson Orlando Other (1) Project other income (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 (Tables)

Long-term debt (Tables)	3 Months Ended
	Mar. 31, 2016
Schedule of current maturities	March 31, December 31, 2016 2015 Interest Rate Current Maturities: Senior secured term loan facility, due 2021 $ $ LIBOR (1) plus % Epsilon Power Partners term facility, due 2019 LIBOR plus % Cadillac term loan, due 2025 LIBOR plus % Piedmont term loan, due 2018 LIBOR plus % Other short-term debt % - % Total current maturities $ $ (1) LIBOR cannot be less than 1.00% . On May 5, 2014, we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount ( $ 1 40.4 million at March 31, 2016) of the $600.0 million ( $447.9 million at March 31, 2016) outstanding aggregate borrowings under our senior secured term loan facility . See Note 8, Accounting for derivative instruments and hedging activities for further details.
Long-term debt excluding debentures
Schedule of long-term debt	March 31, December 31, 2016 2015 Interest Rate Recourse Debt: Senior secured term loan facility, due 2021 $ $ 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 LIBOR plus % Other long-term debt % - % Less: unamortized deferred financing costs Less: current maturities Total long-term debt $ $

Convertible debentures (Tables)

Convertible debentures (Tables)	3 Months Ended
	Mar. 31, 2016
Convertible Debentures
Schedule of long-term debt	March 31, December 31, 2016 2015 6.25% Debentures due March 2017 ( Cdn$67.2 million) $ $ 5.60% Debentures due June 2017 ( Cdn$75.8 million) 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)	3 Months Ended
	Mar. 31, 2016
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	March 31, 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)	3 Months Ended
	Mar. 31, 2016
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	March 31, 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	March 31, 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 March 31, 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 March 31, 2016 $ Interest Rate Three Months Ended March 31, 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 March 31, 2015 $
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges	Classification of loss (gain) Three Months Ended March 31, recognized in income 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 March 31, recognized in income 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)	3 Months Ended
	Mar. 31, 2016
Income taxes
Schedule of components of income tax expense (benefit)	Three Months Ended March 31, 2016 2015 Current income tax expense $ $ Deferred tax expense (benefit) Total income tax expense (benefit), net $ $

Equity compensation plans (Tabl

Equity compensation plans (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016 $

Basic and diluted earnings (l32

Basic and diluted earnings (loss) per share (Tables)	3 Months Ended
	Mar. 31, 2016
Basic and diluted earnings (loss) per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	2016 2015 Numerator: (Loss) gain from continuing operations attributable to Atlantic Power Corporation $ $ Loss 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) earnings per share from continuing operations attributable to Atlantic Power Corporation $ $ Diluted (loss) per share from discontinued operations — Diluted (loss) earnings per share attributable to Atlantic Power Corporation $ $

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2016
Equity
Schedule of reconciliation of equity	Three months ended March 31, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1 $ $ $ Net income (loss) 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 March 31 $ $ $ Three months ended March 31, 2015 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Noncontrolling Shareholders’ Equity company Interests Total Equity Balance at January 1 $ $ $ $ Net income (loss) Realized and unrealized gain on hedging activities, net of tax — — Foreign currency translation adjustment — — Stock-based compensation — — Dividends paid to noncontrolling interest — — Dividends declared on common shares — — Dividends declared on preferred shares of a subsidiary company — — Balance at March 31 $ $ $ $

Segment and geographic inform34

Segment and geographic information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment and geographic information
Schedule of a reconciliation of Project Adjusted EBITDA to project income (loss)	Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended March 31, 2016 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 loss — — — Other income, net — — — Income (loss) 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 March 31, 2015 Project revenues $ $ $ $ $ Segment assets Project Adjusted EBITDA $ $ $ $ $ Change in fair value of derivative instruments — Depreciation and amortization Interest, net — — — Other project expense (income) — — — — — Project income (loss) Administration — — — Interest, net — — — Foreign exchange gain — — — Other income, net — — — Income (loss) from continuing operations before income taxes Income tax benefit — — — Net income (loss) from continuing operations $ $ $ $ $
Schedule of revenue and property, plant and equipment by country	Project Revenue Three Months Ended March 31, Property, Plant and Equipment, net of accumulated depreciation 2016 2015 March 31, 2016 December 31, 2015 United States $ $ $ $ Canada Total $ $ $ $

Nature of business (Details)

Nature of business (Details) $ in Millions	3 Months Ended
	Mar. 31, 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	11
Number of provinces in which power generation projects operate | item	2
Number of projects which are wholly owned | project	18
Recent accounting pronouncements adopted
Deferred financing costs | $	$ 39.5	$ 42.5

Changes in accumulated other 36

Changes in accumulated other comprehensive loss by component (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Changes in accumulated other comprehensive loss by component
Balance at beginning of period	$ (139.3)
Other comprehensive income (loss):
Foreign currency translation adjustments	18.5	$ (35.1)
Tax benefit	1.6	(4.6)
Total Other comprehensive income (loss)	18.2	(35.4)
Balance at end of period	(121.2)		$ (139.3)
Foreign currency translation
Changes in accumulated other comprehensive loss by component
Balance at beginning of period	(139.1)	(66.3)	(66.3)
Other comprehensive income (loss):
Foreign currency translation adjustments	18.4	(35.1)
Balance at end of period	(120.7)	(101.4)	(139.1)
Pension
Changes in accumulated other comprehensive loss by component
Balance at beginning of period	(0.4)	(2.1)	(2.1)
Other comprehensive income (loss):
Balance at end of period	(0.4)	(2.1)	(0.4)
Cash flow hedges
Changes in accumulated other comprehensive loss by component
Balance at beginning of period	0.2	0.1	0.1
Other comprehensive income (loss):
Tax benefit (expense)	0.3	0.4
Total Other comprehensive income (loss) before reclassifications, net of tax	(0.5)	(0.5)
Total amount reclassified from Accumulated other comprehensive loss, net of tax	0.2	0.2
Net change from periodic revaluations	(0.8)	(0.9)
Tax benefit	(0.1)	(0.1)
Total Other comprehensive income (loss)	(0.3)	(0.3)
Balance at end of period	(0.1)	(0.2)	$ 0.2
Cash flow hedges | Interest rate swaps
Other comprehensive income (loss):
Net amount reclassified to earnings (loss):	0.3	0.3
Cash flow hedges | Amount reclassified from accumulated other comprehensive income
Other comprehensive income (loss):
Net amount reclassified to earnings (loss):	$ 0.3	$ 0.3

Discontinued operations (Detail

Discontinued operations (Details) $ / shares in Units, $ in Millions	Jun. 26, 2015USD ($)itemMW	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)$ / shares	Jun. 30, 2015USD ($)
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Loss from operations of discontinued businesses, net of tax			$ (12.3)
Loss from operations of discontinued businesses, net of noncontrolling interests			$ (4.8)
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares			$ (0.03)
Discontinued Operations, Held-for-sale or Disposed of by Sale
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue			$ 16.7
Operations and maintenance			5.6
Depreciation and amortization			10.1
Total Project expenses			15.7
Change in fair value of derivatives			(7.3)
Equity in earnings of unconsolidated affiliates			(0.9)
Interest expense, net			(3.4)
Total Project other income (expense)			(11.6)
Loss from operations of discontinued businesses			(10.6)
Income tax expense			1.7
Loss from operations of discontinued businesses, net of tax			(12.3)
Net loss attributable to noncontrolling interests of discontinued businesses			(7.5)
Loss from operations of discontinued businesses, net of noncontrolling interests			$ (4.8)
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations (in dollars per share) | $ / shares			$ (0.03)
Wind Projects | Wind (Discontinued Operations) | APT | Discontinued Operations, Held-for-sale or Disposed of by Sale
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Cash provided by operating activities			$ 10.8
Cash provided by investing activities			1.4
Wind Projects | Wind (Discontinued Operations) | APT | Discontinued Operations, Disposed of by Sale
Discontinued operations
Gain on the disposal		$ 46.8		$ 46.8
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
Wind Projects | Wind (Discontinued Operations) | APT | Discontinued Operations, Held-for-sale
Current assets:
Cash and cash equivalents			6.2
Accounts receivable			11.2
Other current assets			2.4
Total current assets			19.8
Non-current assets:
Property, Plant & Equipment			700.5
Equity investments in unconsolidated affiliates			36.5
Other intangible assets, net			4.3
Restricted cash			17.9
Other assets			1.8
Assets held for sale			780.8
Current liabilities:
Accounts payable and other accrued liabilities			7.7
Current portion of long-term debt			6.4
Current portion of derivative instruments liability			4.8
Total current liabilities			18.9
Long-term liabilities
Long-term debt			242.4
Derivative instruments liability			15.7
Other long-term liabilities			4.1
Liabilities held for sale			281.1
Noncontrolling interests held for sale			$ 228.8
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%

Equity method investments in 38

Equity method investments in unconsolidated affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating results
Revenue	$ 33	$ 37.8
Project expenses	21.8	26.6
Project other income (expense)	(0.5)	(0.4)
Project income (loss)	10.7	10.8
Chambers
Operating results
Revenue	12.7	15.4
Project expenses	8.8	11.4
Project other income (expense)	(0.5)	(0.5)
Project income (loss)	3.4	3.5
Frederickson
Operating results
Revenue	5.1	4.7
Project expenses	4.5	4.1
Project income (loss)	0.6	0.6
Orlando
Operating results
Revenue	13.4	12.8
Project expenses	6.6	6.6
Project income (loss)	6.8	6.2
Other
Operating results
Revenue	1.8	4.9
Project expenses	1.9	4.5
Project other income (expense)		0.1
Project income (loss)	$ (0.1)	$ 0.5
Other | Maximum
Operating results
Percentage of ownership interest	10.00%

Long-term debt (Details)

Long-term debt (Details) CAD in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016CAD	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	May. 05, 2014USD ($)
Long-term debt
Total debt | CAD	CAD 210
Current maturities of long-term debt		$ 15.7	$ 15.8
Total long-term debt		666.9	682.7
Interest rate swaps
Long-term debt
Notional amount		228.9	302.3
London Interbank Offered Rate (LIBOR) | Interest rate swaps
Long-term debt
Notional amount		140.4
Aggregate principal amount of debt		447.9
Long-term debt excluding debentures
Long-term debt
Total debt		(15.7)	(15.8)
Less: unamortized deferred financing costs		(33.2)	(34.8)
Current maturities of long-term debt		15.7	15.8
Total long-term debt		666.9	682.7
Long-term debt excluding debentures | Senior secured term loan, due 2021
Long-term debt
Total debt		447.9	473.2
Current maturities of long-term debt		4.5	4.7
Long-term debt excluding debentures | Senior unsecured notes, due June 2036 (Cdn$210.0)
Long-term debt
Total debt		$ 161.7	151.7
Interest rate (as a percent)	5.95%	5.95%
Long-term debt excluding debentures | Epsilon Power Partners term facility, due 2019
Long-term debt
Total debt		$ 18	19.5
Current maturities of long-term debt		6	6
Long-term debt excluding debentures | Cadillac term loan, due 2025
Long-term debt
Total debt		28.9	29.5
Current maturities of long-term debt		2.6	2.5
Long-term debt excluding debentures | Piedmont term loan, due 2018
Long-term debt
Total debt		59	59
Current maturities of long-term debt		2.4	2.4
Long-term debt excluding debentures | Other long-term debt
Long-term debt
Total debt		0.3	0.4
Current maturities of long-term debt		$ 0.2	$ 0.2
Long-term debt excluding debentures | Minimum | Other long-term debt
Long-term debt
Interest rate (as a percent)	5.50%	5.50%
Long-term debt excluding debentures | Maximum | Other long-term debt
Long-term debt
Interest rate (as a percent)	6.70%	6.70%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Senior secured term loan, 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) | Piedmont term loan, due 2018
Long-term debt
Applicable margin (as a percent)	3.50%
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Interest rate swaps | Senior secured term loan, due 2021
Long-term debt
Notional amount		$ 140.4		$ 199
Aggregate principal amount of debt				$ 600

Long-term debt - New Credit Fac

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

May. 02, 2016CAD

May. 02, 2016USD ($)

Apr. 13, 2016CAD

Apr. 13, 2016USD ($)

Jul. 26, 2015USD ($)

Apr. 30, 2016USD ($)

Mar. 31, 2016CAD

Mar. 31, 2016USD ($)

Sep. 30, 2015USD ($)

Sep. 30, 2015USD ($)

Apr. 13, 2016USD ($)

Mar. 31, 2016USD ($)

Dec. 31, 2015USD ($)

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]

Interest rate (as a percent)

9.00%

Aggregate principal amount of debt repurchased

$ 310.9

Debt Instrument, Repurchase Amount

$ 330.4

$ 330.4

Redemption price percentage of principal amount

104.50%

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

$ 271.4

$ 277.7

Convertible Debentures | 6.25% Debentures due March 2017

Debt Instrument [Line Items]

Aggregate principal amount of debt | CAD

CAD 67.2

Interest rate (as a percent)

6.25%

6.25%

Convertible Debentures | 6.25% Debentures due March 2017 | Subsequent event

Debt Instrument [Line Items]

Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD

CAD 67.2

Convertible Debentures | 5.6% Debentures due June 2017

Debt Instrument [Line Items]

Aggregate principal amount of debt | CAD

CAD 75.8

Interest rate (as a percent)

5.60%

5.60%

Convertible Debentures | 5.6% Debentures due June 2017 | Subsequent event

Debt Instrument [Line Items]

Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD

CAD 75.8

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

Debt Instrument [Line Items]

Write-off of deferred financing costs

$ 1.3

Convertible Debentures | 5.75% Debentures due June 2019

Debt Instrument [Line Items]

Interest rate (as a percent)

5.75%

5.75%

Convertible Debentures | 6.00% Debenture due December 2019

Debt Instrument [Line Items]

Aggregate principal amount of debt | CAD

CAD 81

Interest rate (as a percent)

6.00%

6.00%

APLP Holdings | Subsequent event

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

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 | Subsequent event | 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 | Subsequent event | Maximum

Debt Instrument [Line Items]

Leverage ratio as defined in Credit Agreement

6

6

Interest coverage ratio as defined in Credit Agreement

4

4

APLP Holdings | Interest expense | Subsequent event

Debt Instrument [Line Items]

Write-off of deferred financing costs

$ 30

APLP Holdings | New Term Loans

Debt Instrument [Line Items]

Remaining proceeds of New Credit Facility

$ 105

APLP Holdings | New Term Loans | Subsequent event

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

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%

4.00%

APLP Holdings | New Credit Facilities | New Term Loans | Subsequent event

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%

3.00%

Original issue discount amount

21

Transaction costs and expenses

$ 14.4

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

Debt Instrument [Line Items]

Margin on variable interest rate

5.00%

5.00%

APLP Holdings | New Credit Facilities | New Revolver | Subsequent event

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

30 days

Commitment fee related to New Revolver, as a percent

0.75%

0.75%

APLP Holdings | New Credit Facilities | Letters of credit | Subsequent event

Debt Instrument [Line Items]

Aggregate principal amount of debt

$ 105.8

Period of debt service covered by debt service reserve fund

6 months

6 months

Amount of debt service reserve

$ 25.3

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

Debt Instrument [Line Items]

Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD

CAD 67.2

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

Debt Instrument [Line Items]

Proceeds deposited with trustee in advance of payment of certain 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]

Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures

111.8

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

Debt Instrument [Line Items]

Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures

$ 111.8

APLP Holdings | Convertible Debentures | 5.75% Debentures due June 2019

Debt Instrument [Line Items]

Interest rate (as a percent)

5.75%

5.75%

Amount of subordinated debt that may be repurchased with remaining proceeds

$ 105.3

APLP Holdings | Convertible Debentures | 6.00% Debenture due December 2019

Debt Instrument [Line Items]

Interest rate (as a percent)

6.00%

6.00%

Amount of subordinated debt that may be repurchased with remaining proceeds | CAD

CAD 81

APLP | New Credit Facilities | Maximum

Debt Instrument [Line Items]

Margin on variable interest rate

5.00%

5.00%

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

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) | Subsequent event

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%

6.25%

APLP | Convertible Debentures | 5.6% Debentures due June 2017

Debt Instrument [Line Items]

Interest rate (as a percent)

5.60%

5.60%

Convertible debentures (Details

Convertible debentures (Details) CAD in Millions, $ in Millions	Apr. 13, 2016CAD	Apr. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2016CAD	Mar. 31, 2016USD ($)
Convertible debentures
Convertible debentures					$ 277.7		$ 271.4
Convertible Debentures
Convertible debentures
Aggregate principal amount of debt					277.7		271.4
Less: unamortized deferred financing costs					(7.7)		(6.3)
Gain on repurchase of convertible debentures					$ (3.1)
Amount that may be purchased, as a percentage of public float					10.00%
Convertible Debentures | 6.25% Debentures due March 2017
Convertible debentures
Convertible debentures					$ 48.6		$ 51.8
Aggregate principal amount of debt | CAD						CAD 67.2
Convertible debentures stated interest rate percentage						6.25%	6.25%
Convertible Debentures | 5.6% Debentures due June 2017
Convertible debentures
Convertible debentures					54.8		$ 58.3
Aggregate principal amount of debt | CAD						CAD 75.8
Convertible debentures stated interest rate percentage						5.60%	5.60%
Convertible Debentures | 5.75% Debentures due June 2019
Convertible debentures
Convertible debentures					117		$ 105.3
Convertible debentures stated interest rate percentage						5.75%	5.75%
Convertible Debentures | 6.00% Debenture due December 2019
Convertible debentures
Convertible debentures					65		$ 62.3
Aggregate principal amount of debt | CAD						CAD 81
Convertible debentures stated interest rate percentage						6.00%	6.00%
Convertible Debentures | Subsequent event | 6.25% Debentures due March 2017
Convertible debentures
Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD	CAD 67.2
Convertible Debentures | Subsequent event | 5.6% Debentures due June 2017
Convertible debentures
Proceeds deposited with trustee in advance of payment of certain unsecured subordinated debentures | CAD	CAD 75.8
Convertible Debentures | Interest expense | Subsequent event | 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 instr42

Fair value of financial instruments - recurring (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Assets:
Restricted cash	$ 10	$ 15.2
Recurring
Assets:
Cash and cash equivalents	64.3	72.4
Restricted cash	10	15.2
Derivative instruments asset	0.6	0.3
Total	74.9	87.9
Liabilities:
Derivative instruments liability	62	57.5
Total	62	57.5
Recurring | Credit valuation adjustments
Liabilities:
Net increase in fair value	5.1	3.8
Pre-tax gain in other comprehensive income	0.5	0.4
Gain in change in fair value of derivatives	4.6	3.4
Recurring | Level 1
Assets:
Cash and cash equivalents	64.3	72.4
Restricted cash	10	15.2
Total	74.3	87.6
Recurring | Level 2
Assets:
Derivative instruments asset	0.6	0.3
Total	0.6	0.3
Liabilities:
Derivative instruments liability	62	57.5
Total	$ 62	$ 57.5

Accounting for derivative ins43

Accounting for derivative instruments and hedging activities (Details) CAD in Millions, $ in Millions	May. 05, 2014USD ($)	May. 05, 2014USD ($)	Jun. 30, 2014MMBTU	Mar. 31, 2016USD ($)MMBTU	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)MMBTU	Mar. 31, 2016CADitem	Mar. 31, 2016USD ($)item	Feb. 14, 2014USD ($)
Derivative instruments
Derivative Number of Contracts Designated as Cash Flow Hedges | item							1	1
Long-term debt | CAD							CAD 210
Long-term debt excluding debentures
Derivative instruments
Long-term debt						$ (15.8)		$ (15.7)
Senior secured term loan, due 2021 | Long-term debt excluding debentures
Derivative instruments
Long-term debt						$ 473.2		447.9
Adjusted Eurodollar Rate
Derivative instruments
Minimum percentage of variable rate base		1.00%
Applicable margin (as a percent)		3.75%
Gas purchase agreements | Ontario project
Derivative instruments
Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU			2,900,000
Gas purchase agreements | Morris Project
Derivative instruments
Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU				450,000
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				6,700,000		2,800,000
Natural gas swaps | Derivative instruments not designated as cash flow hedges
Derivative instruments
Gain (Loss) on Sale of Derivatives				$ 2	$ 12
Natural gas swaps during remainder of 2014 | Orlando project
Derivative instruments
Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando) | MMBTU				7,700,000
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)	4.75%	4.75%
Notional amount						$ 302.3		228.9
Maximum fixed interest rate (as a percent)	4.91%	4.91%
Interest rate swaps | Derivative instruments not designated as cash flow hedges
Derivative instruments
Gain (Loss) on Sale of Derivatives				$ 0.6	$ (1)
Interest rate swaps | Adjusted Eurodollar Rate
Derivative instruments
Notional amount	$ 199	$ 199						140.4
Aggregate principal amount of debt								$ 447.9
Interest rate swaps | Adjusted Eurodollar Rate | Senior secured term loan, due 2021 | Long-term debt excluding debentures
Derivative instruments
Notional amount	199	199
Aggregate principal amount of debt	$ 600	$ 600
Interest rate swaps | Adjusted Eurodollar Rate | Derivative instruments not designated as cash flow hedges
Derivative instruments
Swaption interest rate (as a percent)	1.16%	1.16%
Interest rate swaps | Adjusted Eurodollar Below One Percent
Derivative instruments
Swaption all in one interest rate (as a percent)	4.75%	4.75%
Interest rate swaps | Minimum | Adjusted Eurodollar Rate
Derivative instruments
Minimum percentage of variable rate base	1.00%
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%	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%
Applicable margin, low end of range (as a percent)							3.50%	3.50%
Applicable margin, high end of range (as a percent)							3.80%	3.80%
Interest rate swaps | Swaption interest rate from February, 2016 to November, 2017 | Piedmont
Derivative instruments
Swaption interest rate (as a percent)							4.47%	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 November, 2017 to November, 2030 | Piedmont
Derivative instruments
Swaption interest rate (as a percent)							4.47%	4.47%

Accounting for derivative ins44

Accounting for derivative instruments - forecasted trans (Details) kJ in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)kJMMBTU	Dec. 31, 2015USD ($)kJMMBTU
Natural gas swaps
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | MMBTU	6.7	2.8
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | kJ	22.4	25
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $	$ 228.9	$ 302.3

Accounting for derivative ins45

Accounting for derivative instruments - FV by Bal Sht Loc (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair value of derivative instruments
Derivative Assets	$ 0.6	$ 0.3
Derivative Liabilities	62	57.5
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	4.2	3.7
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	1	1
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	3.2	2.7
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets	0.6	0.3
Derivative Liabilities	57.8	53.8
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	2.4	2
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Assets		0.3
Derivative Liabilities	10	7.8
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current
Fair value of derivative instruments
Derivative Assets	0.2
Derivative Liabilities	3.8	5
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term
Fair value of derivative instruments
Derivative Assets	0.4
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current
Fair value of derivative instruments
Derivative Liabilities	28.3	28.7
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term
Fair value of derivative instruments
Derivative Liabilities	$ 13.3	$ 10.3

Accounting for derivative ins46

Accounting for derivative instruments - AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges	$ (0.5)	$ (0.5)
Realized from OCI during the period	0.2	0.2
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	0	0.1
Change in fair value of cash flow hedges	(0.5)	(0.5)
Realized from OCI during the period	0.2	0.2
Accumulated OCI balance at end of period	$ (0.3)	$ (0.2)

Accounting for derivative ins47

Accounting for derivative instruments - gain, loss - (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ (1.2)	$ (1.7)
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	(1.2)	(1.7)
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	11.6	1.3
Change in fair value of derivative instruments	(0.2)	1.6
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	2	12
Change in fair value of derivative instruments	1.8	(0.6)
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	0.6	(1)
Change in fair value of derivative instruments	$ (2.8)	$ (2.7)

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Components of income tax expenses (benefit)
Current income tax expense	$ 1.5	$ 1.1
Deferred tax expense (benefit)	0.1	(5.7)
Total income tax expense (benefit), net	$ 1.6	$ (4.6)
Reconciliation of income taxes
Canadian enacted statutory rate (as a percent)	26.00%	26.00%
Computed income taxes at Canadian statutory rate	$ 3	$ 5.2
Change in valuation allowance	2.8	2.9
Foreign exchange	2.5	1.8
Dividend withholding tax and other cash taxes	0.6
Other permanent differences	0.2	2.7
Countries with different tax rates	1.1	2.4
Capital losses on tax restructuring	0.4
Permanent differences	0.2	$ 2.7
Valuation allowance	$ 178.1

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	Jan. 22, 2015$ / shares	Mar. 31, 2016USD ($)item$ / sharesshares	Mar. 31, 2015USD ($)
Units
Outstanding at the beginning of the period (in shares) | shares		1,298,401
Granted (in shares) | shares		1,594,954
Vested and redeemed (in shares) | shares		(697,742)
Forfeitures (in shares) | shares		(7,431)
Outstanding at the end of the period (in shares) | shares		2,188,182
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		2.92
Forfeitures (in dollars per share) | $ / shares		2.71
Outstanding at the end of the period (in dollars per share) | $ / shares		$ 2.08
Long-term incentive plan
Weighted-Average Fair Value per Unit
Cash payments made for vested notional units | $		$ 0.1	$ 0.2
Compensation expense related to LTIP | $		$ 0.2	$ 0.4
Transition equity participation agreement
Transition equity participation agreement
Number of transition notional shares outstanding | shares		539,904
Vesting percentage		50.00%
Vesting period		4 years
Period after which remaining portions vests		2 years
Market price (in dollars per share) | $ / shares	$ 2.58
Minimum percentage by which weighted average Canadian dollar price exceeds market price	50.00%
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 | item		3

Basic and diluted earnings (l50

Basic and diluted earnings (loss) per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Numerator:
(Loss) gain from continuing operations attributable to Atlantic Power Corporation	$ (14.9)	$ 22.3
Loss from discontinued operations, net of tax		(4.8)
Net (loss) income attributable to Atlantic Power Corporation	$ (14.9)	$ 17.5
Denominator:
Weighted average basic shares outstanding	121.9	121.5
Dilutive potential shares:
LTIP notional units (in shares)	0.2	0.9
Potentially dilutive shares	122.1	122.4
Diluted (loss) earnings per share from continuing operations attributable to Atlantic Power Corporation	$ (0.12)	$ 0.17
Diluted (loss) per share from discontinued operations		(0.03)
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$ (0.12)	$ 0.14
Potentially dilutive shares from convertible debentures excluded from calculation of EPS	21.6	23.5

Equity (Details)

Equity (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	$ 435.2	$ 816.5
Net income (loss)	(12.9)	12.3
Realized and unrealized gain on hedging activities, net of tax	(0.3)	(0.3)
Foreign currency translation adjustments	18.5	(35.1)
Common share repurchases	(0.9)
Stock-based compensation	0.6	0.4
Dividends paid to noncontrolling interests		(2.7)
Dividends declared on common shares		(2.9)
Dividends declared on preferred shares of a subsidiary company	(2)	(2.3)
Balance at the end of the period	438.2	785.9
Total Atlantic Power Corporation Shareholder's Equity
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	213.9	356.2
Net income (loss)	(14.9)	17.5
Realized and unrealized gain on hedging activities, net of tax	(0.3)	(0.3)
Foreign currency translation adjustments	18.5	(35.1)
Common share repurchases	(0.9)
Stock-based compensation	0.6	0.4
Dividends declared on common shares		(2.9)
Balance at the end of the period	216.9	335.8
Preferred Shares of A Subsidiary Company
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	221.3	221.3
Net income (loss)	2	2.3
Dividends declared on preferred shares of a subsidiary company	(2)	(2.3)
Balance at the end of the period	$ 221.3	221.3
Noncontrolling Interests
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		239
Net income (loss)		(7.5)
Dividends paid to noncontrolling interests		(2.7)
Balance at the end of the period		$ 228.8

Segment and geographic inform52

Segment and geographic information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)segment	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Segment and geographic information
Number of Reportable Segments | segment	4
Project revenues	$ 106.4	$ 111.3
Segment assets	1,660	1,957.3	$ 1,674.6
Project Adjusted EBITDA	62.5	58.6
Change in fair value of derivative instruments	1.2	1.7
Depreciation and amortization	29.9	32.9
Interest, net	2.5	2.5
Other project expense (income)	0.2
Project income	28.7	21.5
Administration	6.1	9.4
Interest, net	16.6	25.7
Foreign exchange loss (gain)	19.8	(32.2)
Other income, net	(2.5)	(1.4)
(Loss) income from continuing operations before income taxes	(11.3)	20
Income tax expense (benefit)	1.6	(4.6)
Loss (income) from continuing operations	(12.9)	24.6
East U.S.
Segment and geographic information
Project revenues	39.4	37.6
Segment assets	802.5	861.5
Project Adjusted EBITDA	30.3	26.7
Change in fair value of derivative instruments	0.7	2.6
Depreciation and amortization	11	10.7
Interest, net	2.5	2.5
Project income	16.1	10.9
(Loss) income from continuing operations before income taxes	16.1	10.9
Loss (income) from continuing operations	16.1	10.9
West U.S.
Segment and geographic information
Project revenues	19.1	23
Segment assets	340.4	386.3
Project Adjusted EBITDA	7.5	10
Depreciation and amortization	9.9	9.7
Project income	(2.4)	0.3
(Loss) income from continuing operations before income taxes	(2.4)	0.3
Loss (income) from continuing operations	(2.4)	0.3
Canada
Segment and geographic information
Project revenues	47.7	50.4
Segment assets	439.4	618.3
Project Adjusted EBITDA	24.8	23.7
Change in fair value of derivative instruments	(0.4)	(1.6)
Depreciation and amortization	8.8	12.3
Project income	16.4	13
(Loss) income from continuing operations before income taxes	16.4	13
Loss (income) from continuing operations	16.4	13
Un-Allocated Corporate
Segment and geographic information
Project revenues	0.2	0.3
Segment assets	77.7	91.2
Project Adjusted EBITDA	(0.1)	(1.8)
Change in fair value of derivative instruments	0.9	0.7
Depreciation and amortization	0.2	0.2
Other project expense (income)	0.2
Project income	(1.4)	(2.7)
Administration	6.1	9.4
Interest, net	16.6	25.7
Foreign exchange loss (gain)	19.8	(32.2)
Other income, net	(2.5)	(1.4)
(Loss) income from continuing operations before income taxes	(41.4)	(4.2)
Income tax expense (benefit)	1.6	(4.6)
Loss (income) from continuing operations	$ (43)	$ 0.4

Segment and geographic inform53

Segment and geographic information - Geographic (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Revenue and Assets
Revenue	$ 106.4	$ 111.3
Property, Plant and Equipment, net of accumulated depreciation	777.8		$ 777.7
United States
Revenue and Assets
Revenue	58.7	60.8
Property, Plant and Equipment, net of accumulated depreciation	517.4		529.6
Canada
Revenue and Assets
Revenue	47.7	$ 50.5
Property, Plant and Equipment, net of accumulated depreciation	$ 260.4		$ 248.1

Segment and geographic inform54

Segment and geographic information - Risk (Details) - Revenues, net - Consolidated revenue	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	38.10%	33.70%
San Diego Gas & Electric
Consolidated revenue concentration
Percentage of consolidated revenue		14.40%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	14.20%	11.70%
Niagara Mohawk
Consolidated revenue concentration
Percentage of consolidated revenue	9.90%

Contingencies (Details)

Contingencies (Details) - Shareholder class action lawsuits - item	Aug. 30, 2013	May. 10, 2013	Mar. 31, 2016
Contingencies
Number of notices of actions relating to Canadian securities class action claims		3
Number of actions were succeeded by specific action with an amended claim	3
Number of actions by which specific Ontario actions were succeeded	1
Number of pending matters having material adverse impact on financial position or results of operations or have been reserved			0