Atlantic Power 10-Q 9 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 07, 2017
Document and Entity Information
Entity Registrant Name	ATLANTIC POWER CORP
Entity Central Index Key	1,419,242
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		115,211,976
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 122.4	$ 85.6
Restricted cash	12.5	13.3
Accounts receivable	48.8	37.3
Current portion of derivative instruments asset (Notes 6 and 7)	2.5	4
Inventory	20.3	16
Prepayments	6.7	5.9
Income taxes receivable	0.5
Other current assets	3.9	2.8
Total current assets	217.6	164.9
Property, plant, and equipment, net (Note 4)	652.6	733.2
Equity investments in unconsolidated affiliates (Note 3)	199.8	266.8
Power purchase agreements and intangible assets, net (Note 4)	201.6	246.2
Goodwill (Note 4)	36	36
Derivative instruments asset (Notes 6 and 7)	2.6	4.6
Other assets	3.7	5.1
Total assets	1,313.9	1,456.8
Current liabilities:
Accounts payable	3.2	4.5
Accrued interest	4.5	0.7
Other accrued liabilities	23	24.4
Current portion of long-term debt (Note 5)	156.5	111.9
Current portion of derivative instruments liability (Notes 6 and 7)	13.5	7.6
Other current liabilities	2.6	1.8
Total current liabilities	203.3	150.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)	637.3	749.2
Convertible debentures, net of unamortized deferred financing costs	105.5	100.4
Derivative instruments liability (Notes 6 and 7)	19.5	21.3
Deferred income taxes	26.5	68.3
Power purchase and fuel supply agreement liabilities, net	24.7	25.3
Asset retirement obligations, net	52.7	50.2
Other long-term liabilities	4.5	5.3
Total liabilities	1,074	1,170.9
Equity
Common shares, no par value, unlimited authorized shares; 115,211,976 and 114,649,888 issued and outstanding at September 30, 2017 and December 31, 2016	1,274.3	1,272.9
Accumulated other comprehensive loss (Note 2)	(132.3)	(148.5)
Retained deficit	(1,117.3)	(1,059.8)
Total Atlantic Power Corporation shareholders' equity	24.7	64.6
Preferred shares issued by a subsidiary company (Note 11)	215.2	221.3
Total equity	239.9	285.9
Total liabilities and equity	$ 1,313.9	$ 1,456.8

CONSOLIDATED BALANCE SHEETS - (

CONSOLIDATED BALANCE SHEETS - (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS
Common shares, no par value (in dollars per share)	$ 0	$ 0
Common Stock, Shares Authorized, Unlimited	Unlimited	Unlimited
Common shares, issued shares (in shares)	115,211,976	114,649,888
Common shares, outstanding shares (in shares)	115,211,976	114,649,888

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Project revenue:
Energy sales	$ 36.5	$ 40.7	$ 113.6	$ 138.4
Energy capacity revenue	37.9	44	85.7	113.2
Other	34.2	16.5	131.7	54.2
Total project revenue	108.6	101.2	331	305.8
Project expenses:
Fuel	26.2	36.8	79.1	110.8
Operations and maintenance	19.8	28.2	63.4	79.4
Depreciation and amortization	31.4	25.3	90.5	75.6
Total project costs	77.4	90.3	233	265.8
Project other income:
Change in fair value of derivative instruments (Notes 6 and 7)	(1.9)	9	(5.8)	20
Equity in earnings (loss) of unconsolidated affiliates (Note 3)	9.2	9.6	(36.1)	27.9
Interest, net	(2.2)	(2.4)	(6.6)	(6.9)
Impairment (Note 4)	(57.3)	(84.7)	(57.3)	(84.7)
Other income, net	0.1	0.5	0.1	0.4
Total project other income (expense)	(52.1)	(68)	(105.7)	(43.3)
Project loss	(20.9)	(57.1)	(7.7)	(3.3)
Administrative and other expenses:
Administration	5.5	5.7	17.6	17.6
Interest expense, net	13.8	20	49.5	87.9
Foreign exchange loss (gain)	9.4	(3.4)	17.7	19.1
Other income, net		(1.7)		(3.9)
Total administrative and other expenses (income)	28.7	20.6	84.8	120.7
Loss from operations before income taxes	(49.6)	(77.7)	(92.5)	(124)
Income tax (benefit) expense (Note 8)	(15.9)	2.6	(38.5)	(14.2)
Net loss	(33.7)	(80.3)	(54)	(109.8)
Net (loss) income attributable to preferred shares of a subsidiary company	(0.8)	2.1	3.5	6.4
Net loss attributable to Atlantic Power Corporation	$ (32.9)	$ (82.4)	$ (57.5)	$ (116.2)
Net loss per share attributable to Atlantic Power Corporation shareholders: (Note 10)
Basic	$ (0.29)	$ (0.69)	$ (0.50)	$ (0.96)
Diluted	$ (0.29)	$ (0.69)	$ (0.50)	$ (0.96)
Weighted average number of common shares outstanding: (Note 9)
Basic (in shares)	115.3	119.3	115.1	120.9
Diluted (in shares)	115.3	119.3	115.1	120.9

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
Net loss	$ (33.7)	$ (80.3)	$ (54)	$ (109.8)
Other comprehensive loss, net of tax:
Unrealized loss on hedging activities			(0.3)	(0.6)
Net amount reclassified to earnings	0.1	0.2	0.5	0.5
Net unrealized gain (loss) on derivatives	0.1	0.2	0.2	(0.1)
Defined benefit plan, net of tax			0.1
Foreign currency translation adjustments	9.2	(22)	15.9	(2.6)
Other comprehensive income (loss), net of tax	9.3	(21.8)	16.2	(2.7)
Comprehensive loss	(24.4)	(102.1)	(37.8)	(112.5)
Less: Comprehensive (loss) income attributable to preferred share dividends of a subsidiary company	(0.8)	2.1	3.5	6.4
Comprehensive loss attributable to Atlantic Power Corporation	$ (23.6)	$ (104.2)	$ (41.3)	$ (118.9)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash provided by operating activities:
Net loss	$ (54)	$ (109.8)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	90.5	75.6
Gain on purchase and cancellation of convertible debentures		(4.7)
Loss on disposal of fixed assets	0.1	0.2
Stock-based compensation	1.6	1.4
Long-lived asset and goodwill impairment	57.3	84.7
Equity in loss (earnings) from unconsolidated affiliates	36.1	(27.9)
Distributions from unconsolidated affiliates	30.9	36.5
Unrealized foreign exchange loss	17	19.1
Change in fair value of derivative instruments	5.8	(20)
Amortization of debt discount and deferred financing cost	7.8	41.7
Change in deferred income taxes	(42.1)	(16.8)
Change in other operating balances
Accounts receivable	(11.5)
Inventory	(4.2)	1.1
Prepayments and other assets	0.6	0.3
Accounts payable	0.3	0.4
Accruals and other liabilities	1.7	10.1
Cash provided by operating activities	137.9	91.9
Cash (used in) provided by investing activities:
Change in restricted cash	0.8	2.6
Reimbursement of costs for third party construction project		4.7
Purchase of property, plant and equipment	(5.7)	(6.5)
Cash (used in) provided by investing activities	(4.9)	0.8
Cash used in financing activities:
Proceeds from term loan facility, net of discount		679
Common share repurchases	(0.2)	(13.9)
Preferred share repurchase	(3.1)
Repayment of corporate and project-level debt	(86.3)	(526.4)
Repayment of convertible debentures	(0.1)	(187.4)
Deferred financing costs		(16.2)
Dividends paid to preferred shareholders	(6.5)	(6.4)
Cash used in financing activities:	(96.2)	(71.3)
Net increase in cash and cash equivalents	36.8	21.4
Cash and cash equivalents at beginning of period	85.6	72.4
Cash and cash equivalents at end of period	122.4	93.8
Supplemental cash flow information
Interest paid	44.2	43.3
Income taxes paid, net	$ 3.4	2.8
Accruals for construction in progress		$ 0.4

Nature of business

Nature of business	9 Months Ended
	Sep. 30, 2017
Nature of business
Nature of business	1. Nature of business General Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of September 30, 2017, our power generation projects 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 power generation projects across nine states in the United States and two provinces in Canada. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence before June 2019. Eighteen of our projects are majority‑owned. 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 condensed 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, 2016. Interim results are not necessarily indicative of results for the full year. In our opinion, the accompanying unaudited interim condensed consolidated financial statements present fairly our consolidated financial position as of September 30, 2017, the results of operations and comprehensive (loss) income for the three and nine months ended September 30, 2017 and 2016, and our cash flows for the nine months ended September 30, 2017 and 2016 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included. Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates ” in our Annual Report on Form 10-K for the year ended December 31, 2016. 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 Issued In May 2014, the Financial Accounting Standards Board (“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 was not permitted before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements. We have developed and are executing a project plan to assess the potential impact of the standard and have evaluated the majority of our most significant contracts (PPAs). We have approximately 12 PPAs at our consolidated projects that require further analysis under this standard. Currently we recognize energy revenue upon transmission to the customer. Capacity revenue is recognized when billed as hours are made available under the terms of the relevant PPA. Our current policy appears to be in compliance with the new standard’s focus on when the customer obtains control of the goods or services. However, these agreements are complex and still require analysis prior to reaching a conclusion as to how the adoption of the standard will impact our financial position, results of operations and cash flows. Upon adoption, we expect to utilize the cumulative-effect adjustment method upon adoption as of January 1, 2018. 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 expect to elect certain of the practical expedients permitted, including the expedient that permits us to retain our existing lease assessment and classification. We are currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While we are currently evaluating the impact the new guidance will have on our financial position and results of operations, we expect to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending our review of our existing lease contracts and PPAs currently accounted for as operating leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting this guidance at this time. In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements. In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the recognition of current and deferred incomes taxes for intra-entity asset transfers. Under the new guidance, current and deferred income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, are now recognized when the transfer occurs. The guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2017 with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements. In November 2016, the FASB issued authoritative guidance to address diversity in practice of presenting changes in restricted cash on the statement of cash flows. The new guidance requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Adoption of this guidance will be applied retrospectively. This guidance will change our presentation of restricted cash in the consolidated statements of cash flows upon adoption. If this guidance was adopted for the nine months ended September 30, 2017, cash flows provided by operations would decrease by $0.8 million and cash flows used in investing activities would increase by $0.8 million, and for the nine months ended September 30, 2016, cash flows provided by operating activities would increase by $2.6 million and cash flows used in investing activities would decrease by $2.6 million. In January 2017, the FASB issued authoritative guidance , which removes the requirement to perform a hypothetical purchase price allocation to measure goodwill impairment. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This guidance is effective for us for annual and interim periods beginning January 1, 2020, with early adoption permitted, and applied prospectively. We plan to adopt this guidance at the earlier of an event-driven impairment test in 2017 or when we perform our annual goodwill impairment test in the fourth quarter of 2017. We cannot assess the impact on our financial statements because the determination will be made based on a fair value measurement at the time the test is conducted. In May 2017, the FASB issued authoritative guidance to address diversity in practice and cost and complexity of applying the guidance relating to stock compensation to a change to the terms or conditions of a share-based payment award. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements. In August 2017, the FASB issued authoritative guidance to align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands and refines hedge accounting for both nonfinancial and financial risk components and aligns the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements.

Changes in accumulated other co

Changes in accumulated other comprehensive loss by component	9 Months Ended
	Sep. 30, 2017
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax
Changes in accumulated other comprehensive loss by component	2. Changes in accumulated other comprehensive loss by component The changes in accumulated other comprehensive loss by component were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Foreign currency translation Balance at beginning of period $ (141.6) $ (119.7) $ (148.3) $ (139.1) Other comprehensive loss: Foreign currency translation adjustments (1) 9.2 (22.0) 15.9 (2.6) Balance at end of period $ (132.4) $ (141.7) $ (132.4) $ (141.7) Pension Balance at beginning of period $ (0.8) $ (0.4) $ (0.9) $ (0.4) Other comprehensive loss: Curtailment gain — — 0.1 — Tax benefit (expense) — — — — Total Other comprehensive (loss) income before reclassifications, net of tax — — 0.1 — Total amount reclassified from accumulated other comprehensive loss, net of tax — — — — Total other comprehensive income — — 0.1 — Balance at end of period $ (0.8) $ (0.4) $ (0.8) $ (0.4) Cash flow hedges Balance at beginning of period $ 0.8 $ (0.1) $ 0.7 $ 0.2 Other comprehensive loss: Net change from periodic revaluations (0.1) 0.1 (0.6) (1.0) Tax benefit (expense) 0.1 (0.1) 0.3 0.4 Total Other comprehensive loss before reclassifications, net of tax — — (0.3) (0.6) Net amount reclassified to earnings: Interest rate swaps (2) 0.2 0.3 0.9 0.9 Tax expense (0.1) (0.1) (0.4) (0.4) Total amount reclassified from accumulated other comprehensive loss, net of tax 0.1 0.2 0.5 0.5 Total other comprehensive income (loss) 0.1 0.2 0.2 (0.1) Balance at end of period $ 0.9 $ 0.1 $ 0.9 $ 0.1 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). (2) This amount was included in interest expense, net on the accompanying consolidated statements of operations.

Equity method investments in un

Equity method investments in unconsolidated affiliates	9 Months Ended
	Sep. 30, 2017
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	3. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three and nine months ended September 30, 2017 and 2016, respectively, for our proportional ownership interest in equity method investments: Three Months Ended September 30, Nine Months Ended September 30, Operating results 2017 2016 2017 2016 Revenue Frederickson $ 5.9 $ 5.8 $ 16.0 $ 15.7 Orlando Cogen, LP 14.3 13.9 40.4 40.6 Koma Kulshan Associates 0.3 0.1 1.4 1.3 Chambers Cogen, LP 10.5 11.2 33.1 34.3 Selkirk Cogen Partners, LP — 3.1 1.8 5.9 31.0 34.1 92.7 97.8 Project expenses Frederickson 4.9 4.9 16.8 14.3 Orlando Cogen, LP 7.2 6.9 22.1 19.6 Koma Kulshan Associates 0.3 0.4 0.8 0.9 Chambers Cogen, LP 8.9 9.3 27.2 27.8 Selkirk Cogen Partners, LP — 2.6 2.8 5.9 21.3 24.1 69.7 68.5 Project other expense Frederickson — — — — Orlando Cogen, LP — — — — Koma Kulshan Associates — — — — Chambers Cogen, LP (0.5) (0.4) (48.5) (1.4) Selkirk Cogen Partners, LP — — (10.6) — (0.5) (0.4) (59.1) (1.4) Project income (loss) Frederickson 1.0 0.9 (0.8) 1.4 Orlando Cogen, LP 7.1 7.0 18.3 21.0 Koma Kulshan Associates — (0.3) 0.6 0.4 Chambers Cogen, LP 1.1 1.5 (42.6) 5.1 Selkirk Cogen Partners, LP — 0.5 (11.6) — Equity in earnings (loss) of unconsolidated affiliates $ 9.2 $ 9.6 $ (36.1) $ 27.9 Distributions from equity method investments (13.7) (13.0) (30.9) (36.5) Deficit in earnings of equity method investments, net of distributions $ (4.5) $ (3.4) $ (67.0) $ (8.6) We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long ‑ term investments. Therefore, we complete our assessments with a long ‑ term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value. In the second quarter of 2017, we performed impairment tests at our Chambers and Selkirk projects, which are accounted for under the equity method of accounting. Selkirk We own a 17.7% limited partner interest in Selkirk Cogen Partners, L.P. The project has operated as a merchant facility since the expiration of its PPA in August 2014. Since the expiration of its PPA, we have not received a distribution from Selkirk and have recorded a cumulative $1.2 million project loss. Based on the project’s history of providing no cash distributions while operating as a merchant facility, the short-term and long-term operational forecast, as well as the likelihood that further investment will be required in order to operate the facility, we determined that our investment in Selkirk is impaired and the decline in value is other than temporary. Accordingly, we recorded a $10.6 million full impairment in earnings from unconsolidated affiliates in the consolidated statements of operations in the second quarterly period of 2017. Chambers We own a 40% limited partner interest in Chambers Cogeneration Limited Partnership. The Chambers project operates under a PPA that expires in March 2024. Prior to our impairment analysis, Chambers was recorded as a $124 million component of our equity investments in unconsolidated affiliates on the consolidated balance sheets. We have recorded equity earnings of $3.4 million, $5.5 million and $6.5 million for the six months ended June 30, 2017, year ended December 31, 2016 and year ended December 31, 2015, respectively. During those periods, we also received cumulative distributions of $33.6 million from Chambers. During the second quarter of 2017, we performed an analysis of the post-PPA value of Chambers operating as a merchant facility. While declining power prices have been observed over the past several years, in our most recent long-term forecast, we identified a significant decrease in the long-term outlook for power prices in the region where Chambers operates. These forward prices, which were obtained from a third party, including forward prices of gas and coal, had a significant negative impact on the estimated discounted cash flows (“DCFs”) of Chambers post-PPA. The estimated post-PPA value is a significant component of the project’s overall value when compared to its carrying value of $124 million. When determining if this decrease in value is other than temporary, we considered the likelihood that future conditions would change such that the gas and coal prices currently observed in the forward pricing models would become more favorable over time in order for the plant to be profitable in a merchant market. We also engaged a separate third party to provide its outlook on post-PPA value for Chambers. It is our assessment that gas prices are likely to remain low when considering the current and expected future supply of shale gas. The third party provided similar conclusions to our assessment. Based on these factors, we determined that the decline in the fair value of our equity investment in Chambers is other than temporary. We recorded a $47.1 million impairment in earnings from unconsolidated affiliates in the consolidated statements of operations for the three months ended June 30, 2017. After recording the impairment, our equity investment in Chambers is $77.2 million, which represents its estimated fair value at June 30, 2017. We determine the fair value of our equity investments using an income approach with DCF models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The discounted cash flows utilized in our impairment tests are generally based on approved operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular investment and is based upon an assumed capital structure, cost of long ‑ term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third party sources. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of an equity method investment. The valuation of equity method investments is considered a level 3 fair value measurement, which means that the valuation of the investments reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the investments. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of an equity investment impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our investments may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

Long-lived assets and goodwill

Long-lived assets and goodwill	9 Months Ended
	Sep. 30, 2017
Long-lived assets and goodwill
Long-lived assets and goodwill	4. Long-lived assets and goodwill 2017 We test our long-lived assets and goodwill for impairment at least annually, or more often if deemed appropriate based on management’s determination of the occurrence of certain trigger events under our impairment policy. When we have an expectation that we will be unable to renew or renegotiate a PPA, the value of the project may be impaired such that we would record an impairment loss. Naval Station, North Island and Naval Training Center (“NTC”) (collectively, the “San Diego Projects”) sell power to San Diego Gas & Electric (“SDG&E”) under PPAs that are scheduled to expire in December 2019. In addition, the three projects supply steam to the U.S. Navy under agreements that provide these projects with the right to use the property at the respective sites on which each project is located (the "Navy agreements"). In August 2017, we were unsuccessful in obtaining contracts to provide the Navy with energy security that would have provided us with the right to use the Naval Station and North Island sites beyond February 2018. Following notification of the outcome of the Navy solicitation, we determined that it was unlikely that these projects will operate beyond the expiration of the Navy agreements. As a result, we performed long-lived asset impairment tests at each of these projects as of July 31, 2017. In order to test the recoverability of the long-lived assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by each of the San Diego Projects through their expected decommissioning dates. The carrying value of each asset group includes its recorded property, plant equipment and intangible assets related to PPAs. As a result of this test, we recorded a total $57.3 million impairment ($22.5 million at Naval Station, $13.5 million at NTC and $21.2 million at North Island) in the three and nine months ended September 30, 2017. This impairment is composed of an $18.2 million full impairment of intangible assets related to PPAs ($10.3 million at Naval Station, $3.6 million at NTC and $4.2 million at North Island) and a $39.1 million partial impairment of property, plant and equipment ($12.1 million at Naval Station, $9.9 million at NTC and $17.0 million at North Island). After recording the impairment, the San Diego projects have $7.7 million of property, plant and equipment at September 30, 2017, which represents our estimate of fair value based on the projects’ remaining undiscounted cash flows and salvage values. The San Diego projects have net removal obligations recorded of $4.6 million at September 30, 2017. We are in the process of evaluating the estimated removal costs and may have further adjustments to this amount in the three months ended December 31, 2017 as t he timing and final arrangements for decommissioning the sites have not been determined. 2016 In the third quarter of 2016, we performed an event-driven goodwill impairment test. While declining power prices have been observed over the prior two years, we identified a significant decrease in the long-term outlook for power prices in the regions where our reporting units operate in the third quarter of 2016. Because the estimated future cash flows of our reporting units are sensitive to fluctuations in forward power prices and these prices are the most impactful input in calculating a reporting unit’s fair value, we determined that it was appropriate to perform an event-driven impairment test. For two of our reporting units (Morris and Nipigon) we performed a qualitative assessment and concluded that it was likely that the fair values significantly exceed the carrying values. These reporting units have aggregate goodwill of $6.9 million and have PPAs with significant remaining time before their expiration and are not significantly impacted by the decrease in the long-term outlook for power prices. The other five of the reporting units tested (Curtis Palmer, Mamquam, North Bay, Kapuskasing and Moresby Lake) failed step 1 of our quantitative two‑step test. Because five reporting units failed step 1 of the two-step goodwill impairment test, we identified a triggering event and initiated a test of the recoverability of their long-lived assets. The asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the five asset groups tested, the North Bay and Kapuskasing asset groups (Canada segment) failed the recoverability test and we recorded property, plant and equipment impairment charges aggregating $5.9 million for the periods ended September 30, 2016. For these asset groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These assumptions include estimated cash flows under the remaining period of their respective PPAs. Subsequent to recording long-lived asset impairments, we performed the step 2 goodwill impairment test and recorded a $50.2 million full impairment at the Mamquam reporting unit, a $15.4 million partial impairment at the Curtis Palmer reporting unit, a $6.5 million full impairment at the North Bay reporting unit, a $6.7 million full impairment at the Kapuskasing reporting unit and no impairment at the Moresby Lake reporting unit for a total goodwill impairment charge of $78.8 million for the periods ended September 30, 2016. At the time of their acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Mamquam and Curtis Palmer reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the respective markets in which those plants operate, have declined from 2011 and from the dates of our previous impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices resulting from an abundance of shale gas. Our forecasts for DCFs also reflect a higher level of uncertainty for re‑contracting at prices than were previously forecasted in 2011. The decline in forward power prices for British Columbia since our prior goodwill impairment performed as of November 30, 2015, in particular, had a significant impact on the estimated DCFs of our Mamquam reporting unit and was the primary driver for its recorded goodwill impairment. British Columbia’s peak demand outlook has declined primarily due to a reduction in forecasted liquefaction build and need in the region and the associated loss of power demand. The resulting drop in the peak demand reduces the amount of needed capacity and therefore the capacity prices also were reduced. Furthermore, the PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill impairment test, we anticipate the PPA expiring two years before December 2027. As a result, the DCF model for Curtis Palmer utilizes forward power prices for that two-year period that are substantially lower than the prices under the current PPA. The long-lived asset and goodwill impairment charges were recorded in the third quarter of 2016 and not earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment assessment. While declining power prices have been observed over the past two years, the significant decrease in the long-term outlook for power prices in the regions where our reporting units operate identified in the third quarter of 2016 had the most significant impact to the key inputs to our long-term forecasted cash flow models. Additionally, the PPAs at our North Bay and Kapuskasing reporting units expire on December 31, 2017. As these projects approach the expiration date, the remaining estimated contracted future cash flows decrease. We determine the fair value of our reporting units using an income approach with DCF models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long‑lived asset recovery and step 1 and 2 goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents WACC consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long‑term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third-party sources. We utilized the assistance of valuation experts to perform step 1 and step 2 of the quantitative impairment test for several of our reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill. The valuation of long-lived assets and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

Long-term debt

Long-term debt	9 Months Ended
	Sep. 30, 2017
Long-term debt
Long-term debt	5. Long‑term debt Long‑term debt consists of the following: September 30, December 31, 2017 2016 Interest Rate Recourse Debt: Senior secured term loan facility, due 2023 (1) $ 562.7 $ 639.9 LIBOR (2) plus 4.25 % Senior unsecured notes, due June 2036 (Cdn$210.0) 168.3 156.4 5.95 % Non-Recourse Debt: Epsilon Power Partners term facility, due 2019 8.8 13.5 LIBOR plus 3.130 % Cadillac term loan, due 2025 24.8 27.0 LIBOR plus 1.37 % Piedmont term loan, due 2018 (3) 54.6 56.6 LIBOR plus 3.75 % Other long-term debt — 0.2 5.50 % - 6.70 % Less: unamortized discount (13.8) (17.2) Less: unamortized deferred financing costs (11.6) (15.3) Less: current maturities (156.5) (111.9) Total long-term debt $ 637.3 $ 749.2 Current maturities consist of the following: September 30, December 31, 2017 2016 Interest Rate Current Maturities: Senior secured term loan facility, due 2023 (1) $ 92.5 $ 100.0 LIBOR (2) plus 4.25 % Epsilon Power Partners term facility, due 2019 6.4 6.2 LIBOR plus 3.130 % Cadillac term loan, due 2025 3.0 3.0 LIBOR plus 1.37 % Piedmont term loan, due 2018 (3) 54.6 2.5 LIBOR plus 3.75 % Other short-term debt — 0.2 % - 6.70 % Total current maturities $ 156.5 $ 111.9 (1) On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the term loan credit agreement. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of senior secured term loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. (2) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $ 354.0 million of the $562.7 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2017. See Note 7, Accounting for derivative instruments and hedging activities for further details. On October 18, 2017, the repricing of the $562.7 million senior secured term loan facility became effective. As a result of the repricing, the interest rate margin on the term loan and revolver was reduced by 0.75% to LIBOR plus 3.50%. On October 30, 2017, we also extended the maturity date of our $200 million senior secured revolving credit facility by one year through April 13, 2022. (3) On October 13, 2017, we repaid the $54.6 million Piedmont term loan due August 2018, in full, with cash on hand. In addition to the principal repayment, we paid $0.1 million of accrued interest, $9.4 million to terminate interest rate swap agreements and wrote off $0.9 million of deferred financing costs. The swap termination costs and deferred financing costs write down will be recorded as interest expense in the three months ended December 31, 2017.

Fair value of financial instrum

Fair value of financial instruments	9 Months Ended
	Sep. 30, 2017
Fair value of financial instruments
Fair value of financial instruments	6. Fair value of financial instruments The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2017 and December 31, 2016. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. September 30, 2017 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 122.4 $ — $ — $ 122.4 Restricted cash 12.5 — — 12.5 Derivative instruments asset — 5.1 — 5.1 Total $ 134.9 $ 5.1 $ — $ 140.0 Liabilities: Derivative instruments liability $ — $ 33.0 $ — $ 33.0 Total $ — $ 33.0 $ — $ 33.0 December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 85.6 $ — $ — $ 85.6 Restricted cash 13.3 — — 13.3 Derivative instruments asset — 8.6 — 8.6 Total $ 98.9 $ 8.6 $ — $ 107.5 Liabilities: Derivative instruments liability $ — $ 28.9 $ — $ 28.9 Total $ — $ 28.9 $ — $ 28.9 The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk-free interest rate. We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of September 30, 2017, the credit valuation adjustments resulted in a $2.4 million net increase in fair value, which consists of a $0.2 million pre‑tax gain in other comprehensive income and a $2.2 million gain in change in fair value of derivative instruments. As of December 31, 2016, the credit valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.3 million pre‑tax gain in other comprehensive income and a $3.5 million gain in change in fair value of derivative instruments. The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.

Accounting for derivative instr

Accounting for derivative instruments and hedging activities	9 Months Ended
	Sep. 30, 2017
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	7. 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 and sale agreements We have entered into various gas purchase and sale agreements for our Nipigon projects that expire ranging from October 31, 2018 through December 31, 2022. In June 2014, Atlantic Power Limited 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. In December 2016, we entered into a gas purchase agreement for our Kenilworth project to fix the price of 0.8 million Mmbtu of natural purchases beginning on January 1, 2017 and expiring on December 31, 2017. We have also entered into various natural gas sales and purchase agreements for approximately 220,000 Mmbtu to effectively mitigate seasonal fluctuation of future natural gas prices at Morris through February 2018. These agreements do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments because we could not conclude that it is probable that these contracts will not settle net and will result in physical delivery. 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. 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 10.9 million Mmbtu of future natural gas purchases at Orlando, which is approximately 95%, 90%, 100% and 50% of our share of the expected natural gas purchases at the project in 2017, 2018, 2019 and 2020, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2017. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations. Interest rate swaps Atlantic Power Limited Partnership Holdings (“APLP Holdings”) has entered into several interest rate swap agreements to mitigate its exposure to changes in interest at the Adjusted Eurodollar Rate for $354.2 million notional amount of the $562.7 million aggregate principal amount of borrowings under the senior secured term loans outstanding as of September 30, 2017. These interest rate swap agreements expire at various dates through March 31, 2020. Borrowings under the senior secured term loans bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 4.25%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 5.25% all-in rate on the senior secured term loans . As a result of entering into the swap agreements, the all-in rate for $375.7 million of the senior secured term loans cannot be less than 5.25%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. The Piedmont project had interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable‑rate debt. The interest rate swap agreements effectively converted the floating rate debt from LIBOR plus an applicable margin of 3.75% to a fixed rate of 4.47% plus an applicable margin of 4.00% until the maturity of the debt in August 2018, resulting in an all‑in rate of 8.47%. The interest rate swaps were set to expire on November 30, 2030. The interest rate swap agreements were not designated as hedges, and changes in their fair market value were recorded in the consolidated statements of operations. In October 2017, the swaps were settled due to early repayment of the term loan. The settlement resulted in $9.4 million of interest expense, which will be recorded as interest expense in the three months ended December 31, 2017. The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.1% through 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. Foreign currency forward contracts We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our Medium Term Notes. Principal and interest payments for our senior secured term loans as well as our U.S dollar-denominated convertible debentures are made in U.S. dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the future interest and principal payments, preferred dividends and other working capital requirements. In March 2017, we entered into foreign exchange forward contracts to sell a total of Cdn$30 million at an exchange rate of 1.3381 in Cdn$10.0 million tranches on each of June 2017, September 2017 and December 2017. In July 2017, we entered into additional foreign exchange forward contracts to sell a total of Cdn$10 million at an exchange rate of 1.2481 in Cdn$3.33 million tranches on each of March 2018, June 2018 and December 2018. In July 2017, we also entered into foreign exchange forward contracts to sell a total of Cdn$10 million at an exchange rate of 1.2943 in tranches of Cdn$5.0 million in March 2018, Cdn$3.0 million in June 2018 and Cdn$2.0 million in December 2018. In September 2017, we entered into foreign exchange forward contracts to sell Cdn$5.0 million at an exchange rate of 1.2196 in September 2018. Foreign currency forward contracts are not designated as hedges, and changes in their market value are recorded in foreign exchange on the consolidated statements of operations at September 30, 2017. Volume of forecasted transactions We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for NPNS exemption at September 30, 2017 and December 31, 2016: September 30, December 31, Units 2017 2016 Natural gas swaps Natural Gas (Mmbtu) 9.0 4.9 Gas purchase agreements Natural Gas (Gigajoules) 10.5 11.3 Interest rate swaps Interest (US$) 434.6 506.9 Foreign currency forward contracts Dollars (Cdn$) 35.0 - Fair value of derivative instruments We disclose derivative instrument assets and liabilities on a trade‑by‑trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities : September 30, 2017 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.7 Interest rate swaps long-term — 1.8 Total derivative instruments designated as cash flow hedges — 2.5 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 1.4 8.8 Interest rate swaps long-term 2.6 — Natural gas swaps current 0.4 0.1 Natural gas swaps long-term — — Gas purchase agreements current 0.7 3.3 Gas purchase agreements long-term — 17.7 Foreign currency forward contracts current — 0.6 Total derivative instruments not designated as cash flow hedges 5.1 30.5 Total derivative instruments $ 5.1 $ 33.0 December 31, 2016 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.8 Interest rate swaps long-term — 2.0 Total derivative instruments designated as cash flow hedges — 2.8 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 0.4 1.9 Interest rate swaps long-term 4.5 6.5 Natural gas swaps current 3.9 0.8 Natural gas swaps long-term 0.1 — Gas purchase agreements current — 4.5 Gas purchase agreements long-term — 12.7 Total derivative instruments not designated as cash flow hedges 8.9 26.4 Total derivative instruments $ 8.9 $ 29.2 Accumulated other comprehensive income The following table summarizes the changes in the accumulated other comprehensive income (loss) (“OCI”) balance attributable to derivative financial instruments designated as a hedge, net of tax: Interest Rate Three Months Ended September 30, 2017 Swaps Accumulated OCI balance at June 30, 2017 $ Change in fair value of cash flow hedges — Realized from OCI during the period 0.1 Accumulated OCI balance at September 30, 2017 $ 0.9 Interest Rate Three Months Ended September 30, 2016 Swaps Accumulated OCI balance at June 30, 2016 $ Change in fair value of cash flow hedges — Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ 0.1 Interest Rate Nine Months Ended September 30, 2017 Swaps Accumulated OCI balance at January 1, 2017 $ 0.7 Change in fair value of cash flow hedges Realized from OCI during the period 0.5 Accumulated OCI balance at September 30, 2017 $ 0.9 Interest Rate Nine Months Ended September 30, 2016 Swaps Accumulated OCI balance at January 1, 2016 $ 0.2 Change in fair value of cash flow hedges (0.6) Realized from OCI during the period 0.5 Accumulated OCI balance at September 30, 2016 $ 0.1 Impact of derivative instruments on the consolidated statements of operations The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges: Classification of loss (gain) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2017 2016 2017 2016 Gas purchase agreements Fuel $ 3.1 $ 12.4 7.9 $ 36.4 Natural gas swaps Fuel (0.7) 0.6 (1.2) 4.0 Interest rate swaps Interest, net 0.9 1.0 2.6 2.7 The following table summarizes the unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges: Classification of gain (loss) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2017 2016 2017 2016 Natural gas swaps Change in fair value of derivatives $ 0.2 $ 0.2 $ (0.3) $ 6.0 Gas purchase agreements Change in fair value of derivatives (1.3) 5.6 (4.3) 16.8 Interest rate swaps Change in fair value of derivatives (0.8) 3.2 (1.2) (2.8) $ (1.9) $ 9.0 $ (5.8) $ 20.0 Foreign currency forwards Foreign exchange loss $ (0.2) $ — $ (0.7) $ —

Income taxes

Income taxes	9 Months Ended
	Sep. 30, 2017
Income tax benefit
Income taxes	8. Income taxes Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Current income tax expense $ 1.3 $ 0.8 $ 3.6 $ 2.6 Deferred income (benefit) expense (17.2) 1.8 (42.1) (16.8) Total income tax (benefit) expense, net $ (15.9) $ 2.6 $ (38.5) $ (14.2) For the three and nine months ended September 30, 2017 and 2016 Income tax benefit for the three months ended September 30, 2017 was $15.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $12.9 million. The primary items impacting the tax rate for the three months ended September 30, 2017 were $3.5 million related to a net increase to the Company's valuation allowances in Canada and $0.3 million of other permanent differences. These items were offset by $5.5 million relating to operating in higher tax rate jurisdictions and $1.3 million relating to foreign exchange. Income tax expense for the three months ended September 30, 2016 was $2.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $20.2 million. The primary item impacting the tax rate for the three months ended September 30, 2016 was $22.5 million related to goodwill impairment. In addition, the rate was further impacted by a net increase to our valuation allowances of $8.6 million, consisting primarily of increases of $9.3 million in Canada related to capital loss on intercompany notes, $1.9 million relating to operating in higher tax rate jurisdictions and $0.8 million of other permanent differences. Income tax benefit for the nine months ended September 30, 2017 was $38.5 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $24.1 million. The primary items impacting the tax rate for the nine months ended September 30, 2017 were $1.5 million related to a net increase to the Company's valuation allowances in Canada and $0.6 million relating to income taxes. These items were offset by $14.2 million relating to operating in higher tax rate jurisdictions and $2.3 million relating to foreign exchange. Income tax benefit for the nine months ended September 30, 2016 was $14.2 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $32.2 million. The primary items impacting the tax rate for the nine months ended September 30, 2016 were $22.5 million relating to goodwill impairment, $5.5 million relating to foreign exchange and $1.1 million of other permanent differences. In addition, the rate was further impacted by a net increase to the Company’s valuation allowances of $13.2 million, consisting primarily of increases of $31.6 million in Canada related to losses and a decrease of $18.4 million in the United States due to tax restructurings and additional earnings. These items were offset by $18.5 million Canadian capital losses recognized on tax restructurings, $3.0 million related to capital loss on intercompany notes and $2.8 million relating to operating in higher tax rate jurisdictions. As of September 30, 2017, we have recorded a valuation allowance of $ 187.5 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

Equity compensation plans

Equity compensation plans	9 Months Ended
	Sep. 30, 2017
Equity compensation plans
Equity compensation plans	9. Equity compensation plans Long‑term incentive plan (“LTIP”) The following table summarizes the changes in outstanding LTIP notional units during the nine months ended September 30, 2017: Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2016 2,101,118 2.08 Granted 1,817,463 2.38 Vested and redeemed (1,009,780) 2.22 Forfeitures (24,227) 2.32 Outstanding at September 30, 2017 2,884,574 $ 2.22 Cash payments made for vested notional units for the nine months ended September 30, 2017 and 2016 were $0.7 million and $0.4 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $0.9 million and $2.6 million for the three and nine months ended September 30, 2017 and $0.8 million and $0.9 million for the three and nine months ended September 30, 2016, respectively. Transition Equity Participation Agreement We also have 539,904 transition notional shares outstanding at September 30, 2017 under the Transition Equity Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted in January 2015 with respect to fiscal year 2015 will vest upon the four-year anniversary of the date of grant and the remaining portion will vest on or any time after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares on the TSX for at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015 (Cdn$3.18) by at least 50% (Cdn$4.77).

Basic and diluted loss per shar

Basic and diluted loss per share	9 Months Ended
	Sep. 30, 2017
Basic and diluted loss per share
Basic and diluted loss per share	10. Basic and diluted loss per share Basic loss per share is calculated by dividing net loss by the weighted average common shares outstanding during their respective periods. Diluted loss per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. Because we reported a loss for the three and nine months ended September 30, 2017 and 2016, respectively, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive. The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine months ended September 30, 2017 and 2016: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Numerator: Net loss attributable to Atlantic Power Corporation $ (32.9) $ (82.4) $ (57.5) $ (116.2) Denominator: Weighted average basic shares outstanding 115.3 119.3 115.1 120.9 Dilutive potential shares: Convertible debentures 8.1 8.1 8.1 14.9 LTIP notional units — 0.1 — 0.1 Potentially dilutive shares 123.4 127.5 123.2 135.9 Basic and diluted loss per share attributable to Atlantic Power Corporation $ (0.29) $ (0.69) $ (0.50) $ (0.96) The dilutive effect of our convertible debentures is calculated using the “if-converted method.” Under the if-converted method, the debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted EPS calculation for the entire period being presented. Interest expense, net of any income tax effects, would be added back to the numerator for purposes of the if-converted calculation. Potentially dilutive shares from convertible debentures of $8.1 million and $8.1 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2017, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from convertible debentures of $8.1 million and $14.9 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2016, respectively, because their impact would be anti-dilutive.

Equity

Equity	9 Months Ended
	Sep. 30, 2017
Equity
Equity	11. 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 and total equity for the nine months ended September 30, 2017 and 2016: Nine months ended September 30, 2017 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2017 $ 64.6 $ 221.3 $ 285.9 Net (loss) income (57.5) 3.5 (54.0) Realized and unrealized gain on hedging activities, net of tax 0.2 — 0.2 Foreign currency translation adjustment 15.9 — 15.9 Defined benefit plan, net of tax 0.1 — 0.1 Common share repurchases (0.2) — (0.2) Preferred share repurchases — (3.1) (3.1) Stock-based compensation 1.6 — 1.6 Dividends declared on preferred shares of a subsidiary company — (6.5) (6.5) Balance at September 30, 2017 $ 24.7 $ 215.2 $ 239.9 Nine months ended September 30, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2016 $ 213.9 $ 221.3 $ 435.2 Net (loss) income (116.2) 6.4 (109.8) Realized and unrealized loss on hedging activities, net of tax (0.1) — (0.1) Foreign currency translation adjustment (2.6) — (2.6) Common share repurchases (13.9) — (13.9) Stock-based compensation 1.4 — 1.4 Dividends declared on preferred shares of a subsidiary company — (6.4) (6.4) Balance at September 30, 2016 $ 82.5 $ 221.3 $ 303.8 Stock Repurchase Program In December 2015, our Board of Directors approved a normal course issuer bid (“NCIB”) for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd (“APPEL”), our wholly-owned subsidiary. The Board authorization permitted the Company to repurchase stock through open market repurchases. The NCIB expired on December 28, 2016. Through September 30, 2016, we repurchased and cancelled 5.7 million common shares at a total cost of $13.9 million. For the year ended December 31, 2016, we repurchased a cumulative 8.0 million common shares at a total cost of $19.5 million. Repurchases and retirement of common shares are recorded to common shares on the consolidated balance sheets. On December 29, 2016, we commenced a new NCIB that will expire on December 28, 2017 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIBs . Under the new NCIB, we may purchase up to approximately 11.3 million common shares, or 10% of our public float. Through September 30, 2017, we repurchased and cancelled 0.1 million common shares at a cost of $0.2 million. Through September 30, 2017, we also repurchased and cancelled 0.3 million of our Cdn$25.0 par value 4.85% Cumulative Redeemable Preferred Shares, Series 1 at Cdn$15.5 per share for a total payment of Cdn$3.9 million, resulting in a $3.0 million gain recorded in net (loss) income attributable to preferred shares of a subsidiary company in the three and nine months ended September 30, 2017.

Segment and geographic informat

Segment and geographic information	9 Months Ended
	Sep. 30, 2017
Segment and geographic information
Segment and geographic information	12. Segment and geographic information We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We analyze the performance of our operating segments based on Project Adjusted EBITDA, which is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. We use Project Adjusted EBITDA to provide comparative information about segment performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented as proportionately consolidated based on our ownership percentage in the reconciliation of Project Adjusted EBITDA to project income (loss). A reconciliation of Project Adjusted EBITDA to net loss for the three and nine months ended September 30, 2017 and 2016 is included in the tables below: Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2017 Project revenues $ 39.8 $ 35.1 $ 33.5 $ 0.2 $ 108.6 Segment assets 680.9 237.5 281.9 113.6 1,313.9 Project Adjusted EBITDA $ 30.6 $ 21.7 $ 24.6 $ 0.5 $ 77.4 Change in fair value of derivative instruments 1.3 — 1.3 (0.6) 2.0 Depreciation and amortization 11.8 10.6 14.0 0.2 36.6 Interest, net 2.5 — — — 2.5 Impairment — 57.3 — — 57.3 Other project income — — (0.1) — (0.1) Project income (loss) 15.0 (46.2) 9.4 0.9 (20.9) Administration — — — 5.5 5.5 Interest expense, net — — — 13.8 13.8 Foreign exchange loss — — — 9.4 9.4 Income (loss) from continuing operations before income taxes 15.0 (46.2) 9.4 (27.8) (49.6) Income tax benefit — — — (15.9) (15.9) Net income (loss) from continuing operations $ 15.0 $ (46.2) $ 9.4 $ (11.9) $ (33.7) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2016 Project revenues $ 31.3 $ 34.1 $ 35.6 $ 0.2 $ 101.2 Segment assets 764.9 328.9 325.3 102.8 1,521.9 Project Adjusted EBITDA $ 19.4 $ 21.3 $ 10.7 $ (0.1) $ 51.3 Change in fair value of derivative instruments (1.2) — (5.6) (2.2) (9.0) Depreciation and amortization 11.0 9.9 9.4 0.1 30.4 Interest, net 2.8 — — — 2.8 Impairment 15.4 — 69.3 — 84.7 Other project income — — — (0.5) (0.5) Project (loss) income (8.6) 11.4 (62.4) 2.5 (57.1) Administration — — — 5.7 5.7 Interest expense, net — — — 20.0 20.0 Foreign exchange gain — — — (3.4) (3.4) Other income, net — — — (1.7) (1.7) (Loss) income from continuing operations before income taxes (8.6) 11.4 (62.4) (18.1) (77.7) Income tax expense — — — 2.6 2.6 Net (loss) income from continuing operations $ (8.6) $ 11.4 $ (62.4) $ (20.7) $ (80.3) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2017 Project revenues $ 116.3 $ 86.2 $ 127.8 $ 0.7 $ 331.0 Segment assets 680.9 237.5 281.9 113.6 1,313.9 Project Adjusted EBITDA $ 86.8 $ 41.5 $ 97.3 $ 1.0 $ 226.6 Change in fair value of derivative instruments 3.3 — 5.4 (2.9) 5.8 Depreciation and amortization 34.2 30.6 40.4 0.4 105.6 Interest, net 8.0 — — — 8.0 Impairment — 57.3 — — 57.3 Other project expense (income) 57.7 — (0.1) — 57.6 Project (loss) income (16.4) (46.4) 51.6 3.5 (7.7) Administration — — — 17.6 17.6 Interest expense, net — — — 49.5 49.5 Foreign exchange loss — — — 17.7 17.7 (Loss) income from continuing operations before income taxes (16.4) (46.4) 51.6 (81.3) (92.5) Income tax benefit — — — (38.5) (38.5) Net (loss) income from continuing operations $ (16.4) $ (46.4) $ 51.6 $ (42.8) $ (54.0) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2016 Project revenues $ 104.3 $ 78.7 $ 122.0 $ 0.8 $ 305.8 Segment assets 764.9 328.9 325.3 102.8 1,521.9 Project Adjusted EBITDA $ 70.5 $ 43.4 $ 46.2 $ (0.2) $ 159.9 Change in fair value of derivative instruments (3.0) — (17.7) 0.6 (20.1) Depreciation and amortization 33.0 29.6 27.7 0.5 90.8 Interest, net 8.2 — — — 8.2 Impairment 15.4 — 69.3 — 84.7 Other project income — — — (0.4) (0.4) Project income (loss) 16.9 13.8 (33.1) (0.9) (3.3) Administration — — — 17.6 17.6 Interest expense, net — — — 87.9 87.9 Foreign exchange loss — — — 19.1 19.1 Other income, net — — — (3.9) (3.9) Income (loss) from continuing operations before income taxes 16.9 13.8 (33.1) (121.6) $ (124.0) Income tax benefit — — — (14.2) (14.2) Net income (loss) from continuing operations $ 16.9 $ 13.8 $ (33.1) $ (107.4) $ (109.8) The table below provides information, by country, about our consolidated operations for each of the three and nine months ended September 30, 2017 and 2016 and Property, Plant & Equipment as of September 30, 2017 and December 31, 2016, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located. Project Revenue Three Months Ended September 30, Project Revenue Nine Months Ended September 30, Property, Plant and 2017 2016 2017 2016 September 30, 2017 December 31, 2016 United States $ 75.1 $ 65.6 $ 203.2 $ 183.8 $ 437.0 $ 499.2 Canada 33.5 35.6 127.8 122.0 215.6 234.0 Total $ 108.6 $ 101.2 $ 331.0 $ 305.8 $ 652.6 $ 733.2 Independent Electricity System Operator (“IESO”), SDG&E, BC Hydro and Georgia Power Company provided 16.4%, 13.9%, 11.3% and 10.3%, respectively, of total consolidated revenues for the three months ended September 30, 2017. IESO, SDG&E, Niagara Mohawk and BC Hydro provided 19.3%, 11.1%, 10.7% and 10.3%, respectively, of total consolidated revenues for the nine months ended September 30, 2017. IESO, SDG&E, Georgia Power Company and BC Hydro provided 24.5%, 16.1%, 10.9% and 10.6%, respectively, of total consolidated revenues for the three months ended September 30, 2016. IESO, BC Hydro and SDG&E provided 28.0%, 11.6% and 11.5%, respectively, of total consolidated revenues for the nine months ended September 30, 2016. IESO and Ontario Electric Financial Corporation (“OEFC”) purchase electricity from the Calstock, Kapuskasing, Nipigon and North Bay projects in the Canada segment, San Diego Gas & Electric purchases electricity from the Naval Station, NTC, and North Island projects in the West U.S. segment, Georgia Power Company purchases electricity from the Piedmont project in the East U.S. segment, and BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment.

Guarantees and Contingencies

Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2017
Contingencies
Guarantees and Contingencies	13. Guarantees and Contingencies Guarantees We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Contingencies From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of September 30, 2017. OEFC Settlement On January 19, 2017, the Supreme Court of Canada denied the OEFC leave to appeal the Ontario Court of Appeal Decision concerning the interpretation of the price escalator for power sold to the OEFC under certain PPAs with non-utility generators. We were not party to that litigation. We did, however, enter into a standstill agreement with the OEFC in April 2015, with respect to our North Bay, Kapuskasing and Tunis projects, arising out of our disagreement with the OEFC over the interpretation of the price escalator calculation in our PPAs. Under the standstill agreement we reserved our right to bring claims against the OEFC and suspended the running of any applicable limitation period to bring such claims. On April 27, 2017, we entered into a settlement agreement with the OEFC with respect to our standstill agreement. Under the terms of the settlement, the OEFC has agreed to pay us approximately Cdn$36.4 million, representing the application of the price escalator calculation under the respective PPAs for power sold to the OEFC beginning in April 2013 and through December 31, 2017. A subsequent adjustment increased the total to approximately Cdn$37.8 million. Of the Cdn$37.8 million amount agreed upon in settlement, we have received Cdn$34.0 million (approximately $25.6 million) and recorded it as other revenue in the second and third quarters of 2017, the periods when all contingencies were resolved. The remaining Cdn $3.8 million of the settlement relates to the application of the price escalator to the enhanced dispatch contracts at North Bay and Kapuskasing and will be recognized as revenue, when earned, through the expiration date of December 31, 2017.

Summary of significant accounti

Summary of significant accounting policies (Policies)	9 Months Ended
	Sep. 30, 2017
Nature of business
Basis of presentation	Basis of presentation The interim condensed 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, 2016. Interim results are not necessarily indicative of results for the full year. In our opinion, the accompanying unaudited interim condensed consolidated financial statements present fairly our consolidated financial position as of September 30, 2017, the results of operations and comprehensive (loss) income for the three and nine months ended September 30, 2017 and 2016, and our cash flows for the nine months ended September 30, 2017 and 2016 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
Use of estimates	Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates ” in our Annual Report on Form 10-K for the year ended December 31, 2016. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Recently issued accounting standards	Recently issued accounting standards Issued In May 2014, the Financial Accounting Standards Board (“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 was not permitted before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements. We have developed and are executing a project plan to assess the potential impact of the standard and have evaluated the majority of our most significant contracts (PPAs). We have approximately 12 PPAs at our consolidated projects that require further analysis under this standard. Currently we recognize energy revenue upon transmission to the customer. Capacity revenue is recognized when billed as hours are made available under the terms of the relevant PPA. Our current policy appears to be in compliance with the new standard’s focus on when the customer obtains control of the goods or services. However, these agreements are complex and still require analysis prior to reaching a conclusion as to how the adoption of the standard will impact our financial position, results of operations and cash flows. Upon adoption, we expect to utilize the cumulative-effect adjustment method upon adoption as of January 1, 2018. 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 expect to elect certain of the practical expedients permitted, including the expedient that permits us to retain our existing lease assessment and classification. We are currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While we are currently evaluating the impact the new guidance will have on our financial position and results of operations, we expect to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending our review of our existing lease contracts and PPAs currently accounted for as operating leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting this guidance at this time. In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements. In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the recognition of current and deferred incomes taxes for intra-entity asset transfers. Under the new guidance, current and deferred income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, are now recognized when the transfer occurs. The guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2017 with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements. In November 2016, the FASB issued authoritative guidance to address diversity in practice of presenting changes in restricted cash on the statement of cash flows. The new guidance requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Adoption of this guidance will be applied retrospectively. This guidance will change our presentation of restricted cash in the consolidated statements of cash flows upon adoption. If this guidance was adopted for the nine months ended September 30, 2017, cash flows provided by operations would decrease by $0.8 million and cash flows used in investing activities would increase by $0.8 million, and for the nine months ended September 30, 2016, cash flows provided by operating activities would increase by $2.6 million and cash flows used in investing activities would decrease by $2.6 million. In January 2017, the FASB issued authoritative guidance , which removes the requirement to perform a hypothetical purchase price allocation to measure goodwill impairment. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This guidance is effective for us for annual and interim periods beginning January 1, 2020, with early adoption permitted, and applied prospectively. We plan to adopt this guidance at the earlier of an event-driven impairment test in 2017 or when we perform our annual goodwill impairment test in the fourth quarter of 2017. We cannot assess the impact on our financial statements because the determination will be made based on a fair value measurement at the time the test is conducted. In May 2017, the FASB issued authoritative guidance to address diversity in practice and cost and complexity of applying the guidance relating to stock compensation to a change to the terms or conditions of a share-based payment award. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements. In August 2017, the FASB issued authoritative guidance to align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands and refines hedge accounting for both nonfinancial and financial risk components and aligns the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements.

Changes in accumulated other 21

Changes in accumulated other comprehensive loss by component (Tables)	9 Months Ended
	Sep. 30, 2017
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax
Schedule of changes in accumulated other comprehensive loss by component	Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Foreign currency translation Balance at beginning of period $ (141.6) $ (119.7) $ (148.3) $ (139.1) Other comprehensive loss: Foreign currency translation adjustments (1) 9.2 (22.0) 15.9 (2.6) Balance at end of period $ (132.4) $ (141.7) $ (132.4) $ (141.7) Pension Balance at beginning of period $ (0.8) $ (0.4) $ (0.9) $ (0.4) Other comprehensive loss: Curtailment gain — — 0.1 — Tax benefit (expense) — — — — Total Other comprehensive (loss) income before reclassifications, net of tax — — 0.1 — Total amount reclassified from accumulated other comprehensive loss, net of tax — — — — Total other comprehensive income — — 0.1 — Balance at end of period $ (0.8) $ (0.4) $ (0.8) $ (0.4) Cash flow hedges Balance at beginning of period $ 0.8 $ (0.1) $ 0.7 $ 0.2 Other comprehensive loss: Net change from periodic revaluations (0.1) 0.1 (0.6) (1.0) Tax benefit (expense) 0.1 (0.1) 0.3 0.4 Total Other comprehensive loss before reclassifications, net of tax — — (0.3) (0.6) Net amount reclassified to earnings: Interest rate swaps (2) 0.2 0.3 0.9 0.9 Tax expense (0.1) (0.1) (0.4) (0.4) Total amount reclassified from accumulated other comprehensive loss, net of tax 0.1 0.2 0.5 0.5 Total other comprehensive income (loss) 0.1 0.2 0.2 (0.1) Balance at end of period $ 0.9 $ 0.1 $ 0.9 $ 0.1 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). (2) This amount was included in interest expense, net on the accompanying consolidated statements of operations.

Equity method investments in 22

Equity method investments in unconsolidated affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Equity method investments in unconsolidated affiliates
Summary of operating results	Three Months Ended September 30, Nine Months Ended September 30, Operating results 2017 2016 2017 2016 Revenue Frederickson $ 5.9 $ 5.8 $ 16.0 $ 15.7 Orlando Cogen, LP 14.3 13.9 40.4 40.6 Koma Kulshan Associates 0.3 0.1 1.4 1.3 Chambers Cogen, LP 10.5 11.2 33.1 34.3 Selkirk Cogen Partners, LP — 3.1 1.8 5.9 31.0 34.1 92.7 97.8 Project expenses Frederickson 4.9 4.9 16.8 14.3 Orlando Cogen, LP 7.2 6.9 22.1 19.6 Koma Kulshan Associates 0.3 0.4 0.8 0.9 Chambers Cogen, LP 8.9 9.3 27.2 27.8 Selkirk Cogen Partners, LP — 2.6 2.8 5.9 21.3 24.1 69.7 68.5 Project other expense Frederickson — — — — Orlando Cogen, LP — — — — Koma Kulshan Associates — — — — Chambers Cogen, LP (0.5) (0.4) (48.5) (1.4) Selkirk Cogen Partners, LP — — (10.6) — (0.5) (0.4) (59.1) (1.4) Project income (loss) Frederickson 1.0 0.9 (0.8) 1.4 Orlando Cogen, LP 7.1 7.0 18.3 21.0 Koma Kulshan Associates — (0.3) 0.6 0.4 Chambers Cogen, LP 1.1 1.5 (42.6) 5.1 Selkirk Cogen Partners, LP — 0.5 (11.6) — Equity in earnings (loss) of unconsolidated affiliates $ 9.2 $ 9.6 $ (36.1) $ 27.9 Distributions from equity method investments (13.7) (13.0) (30.9) (36.5) Deficit in earnings of equity method investments, net of distributions $ (4.5) $ (3.4) $ (67.0) $ (8.6)

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2017
Long-term debt
Schedule of long-term debt	September 30, December 31, 2017 2016 Interest Rate Recourse Debt: Senior secured term loan facility, due 2023 (1) $ 562.7 $ 639.9 LIBOR (2) plus 4.25 % Senior unsecured notes, due June 2036 (Cdn$210.0) 168.3 156.4 5.95 % Non-Recourse Debt: Epsilon Power Partners term facility, due 2019 8.8 13.5 LIBOR plus 3.130 % Cadillac term loan, due 2025 24.8 27.0 LIBOR plus 1.37 % Piedmont term loan, due 2018 (3) 54.6 56.6 LIBOR plus 3.75 % Other long-term debt — 0.2 5.50 % - 6.70 % Less: unamortized discount (13.8) (17.2) Less: unamortized deferred financing costs (11.6) (15.3) Less: current maturities (156.5) (111.9) Total long-term debt $ 637.3 $ 749.2
Schedule of current maturities	September 30, December 31, 2017 2016 Interest Rate Current Maturities: Senior secured term loan facility, due 2023 (1) $ 92.5 $ 100.0 LIBOR (2) plus 4.25 % Epsilon Power Partners term facility, due 2019 6.4 6.2 LIBOR plus 3.130 % Cadillac term loan, due 2025 3.0 3.0 LIBOR plus 1.37 % Piedmont term loan, due 2018 (3) 54.6 2.5 LIBOR plus 3.75 % Other short-term debt — 0.2 % - 6.70 % Total current maturities $ 156.5 $ 111.9 (1) On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the term loan credit agreement. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of senior secured term loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. (2) LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $ 354.0 million of the $562.7 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2017. See Note 7, Accounting for derivative instruments and hedging activities for further details. On October 18, 2017, the repricing of the $562.7 million senior secured term loan facility became effective. As a result of the repricing, the interest rate margin on the term loan and revolver was reduced by 0.75% to LIBOR plus 3.50%. On October 30, 2017, we also extended the maturity date of our $200 million senior secured revolving credit facility by one year through April 13, 2022. (3) On October 13, 2017, we repaid the $54.6 million Piedmont term loan due August 2018, in full, with cash on hand. In addition to the principal repayment, we paid $0.1 million of accrued interest, $9.4 million to terminate interest rate swap agreements and wrote off $0.9 million of deferred financing costs. The swap termination costs and deferred financing costs write down will be recorded as interest expense in the three months ended December 31, 2017.

Fair value of financial instr24

Fair value of financial instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	September 30, 2017 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 122.4 $ — $ — $ 122.4 Restricted cash 12.5 — — 12.5 Derivative instruments asset — 5.1 — 5.1 Total $ 134.9 $ 5.1 $ — $ 140.0 Liabilities: Derivative instruments liability $ — $ 33.0 $ — $ 33.0 Total $ — $ 33.0 $ — $ 33.0 December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 85.6 $ — $ — $ 85.6 Restricted cash 13.3 — — 13.3 Derivative instruments asset — 8.6 — 8.6 Total $ 98.9 $ 8.6 $ — $ 107.5 Liabilities: Derivative instruments liability $ — $ 28.9 $ — $ 28.9 Total $ — $ 28.9 $ — $ 28.9

Accounting for derivative ins25

Accounting for derivative instruments and hedging activities (Tables)	9 Months Ended
	Sep. 30, 2017
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	September 30, December 31, Units 2017 2016 Natural gas swaps Natural Gas (Mmbtu) 9.0 4.9 Gas purchase agreements Natural Gas (Gigajoules) 10.5 11.3 Interest rate swaps Interest (US$) 434.6 506.9 Foreign currency forward contracts Dollars (Cdn$) 35.0 -
Schedule of fair value of derivative instruments	September 30, 2017 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.7 Interest rate swaps long-term — 1.8 Total derivative instruments designated as cash flow hedges — 2.5 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 1.4 8.8 Interest rate swaps long-term 2.6 — Natural gas swaps current 0.4 0.1 Natural gas swaps long-term — — Gas purchase agreements current 0.7 3.3 Gas purchase agreements long-term — 17.7 Foreign currency forward contracts current — 0.6 Total derivative instruments not designated as cash flow hedges 5.1 30.5 Total derivative instruments $ 5.1 $ 33.0 December 31, 2016 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.8 Interest rate swaps long-term — 2.0 Total derivative instruments designated as cash flow hedges — 2.8 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 0.4 1.9 Interest rate swaps long-term 4.5 6.5 Natural gas swaps current 3.9 0.8 Natural gas swaps long-term 0.1 — Gas purchase agreements current — 4.5 Gas purchase agreements long-term — 12.7 Total derivative instruments not designated as cash flow hedges 8.9 26.4 Total derivative instruments $ 8.9 $ 29.2
Schedule of changes in OCI attributable to derivative financial instruments	Interest Rate Three Months Ended September 30, 2017 Swaps Accumulated OCI balance at June 30, 2017 $ Change in fair value of cash flow hedges — Realized from OCI during the period 0.1 Accumulated OCI balance at September 30, 2017 $ 0.9 Interest Rate Three Months Ended September 30, 2016 Swaps Accumulated OCI balance at June 30, 2016 $ Change in fair value of cash flow hedges — Realized from OCI during the period Accumulated OCI balance at September 30, 2016 $ 0.1 Interest Rate Nine Months Ended September 30, 2017 Swaps Accumulated OCI balance at January 1, 2017 $ 0.7 Change in fair value of cash flow hedges Realized from OCI during the period 0.5 Accumulated OCI balance at September 30, 2017 $ 0.9 Interest Rate Nine Months Ended September 30, 2016 Swaps Accumulated OCI balance at January 1, 2016 $ 0.2 Change in fair value of cash flow hedges (0.6) Realized from OCI during the period 0.5 Accumulated OCI balance at September 30, 2016 $ 0.1
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges	Classification of loss (gain) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2017 2016 2017 2016 Gas purchase agreements Fuel $ 3.1 $ 12.4 7.9 $ 36.4 Natural gas swaps Fuel (0.7) 0.6 (1.2) 4.0 Interest rate swaps Interest, net 0.9 1.0 2.6 2.7
Summary of the unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges	Classification of gain (loss) Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2017 2016 2017 2016 Natural gas swaps Change in fair value of derivatives $ 0.2 $ 0.2 $ (0.3) $ 6.0 Gas purchase agreements Change in fair value of derivatives (1.3) 5.6 (4.3) 16.8 Interest rate swaps Change in fair value of derivatives (0.8) 3.2 (1.2) (2.8) $ (1.9) $ 9.0 $ (5.8) $ 20.0 Foreign currency forwards Foreign exchange loss $ (0.2) $ — $ (0.7) $ —

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
	Sep. 30, 2017
Income tax benefit
Schedule of components of income tax benefit	Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Current income tax expense $ 1.3 $ 0.8 $ 3.6 $ 2.6 Deferred income (benefit) expense (17.2) 1.8 (42.1) (16.8) Total income tax (benefit) expense, net $ (15.9) $ 2.6 $ (38.5) $ (14.2)

Equity compensation plans (Tabl

Equity compensation plans (Tables)	9 Months Ended
	Sep. 30, 2017
Equity compensation plans
Schedule of changes in outstanding LTIP notional units	Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2016 2,101,118 2.08 Granted 1,817,463 2.38 Vested and redeemed (1,009,780) 2.22 Forfeitures (24,227) 2.32 Outstanding at September 30, 2017 2,884,574 $ 2.22

Basic and diluted earnings (los

Basic and diluted earnings (loss) per share (Tables)	9 Months Ended
	Sep. 30, 2017
Basic and diluted loss per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Numerator: Net loss attributable to Atlantic Power Corporation $ (32.9) $ (82.4) $ (57.5) $ (116.2) Denominator: Weighted average basic shares outstanding 115.3 119.3 115.1 120.9 Dilutive potential shares: Convertible debentures 8.1 8.1 8.1 14.9 LTIP notional units — 0.1 — 0.1 Potentially dilutive shares 123.4 127.5 123.2 135.9 Basic and diluted loss per share attributable to Atlantic Power Corporation $ (0.29) $ (0.69) $ (0.50) $ (0.96)

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Equity
Schedule of reconciliation of equity	Nine months ended September 30, 2017 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2017 $ 64.6 $ 221.3 $ 285.9 Net (loss) income (57.5) 3.5 (54.0) Realized and unrealized gain on hedging activities, net of tax 0.2 — 0.2 Foreign currency translation adjustment 15.9 — 15.9 Defined benefit plan, net of tax 0.1 — 0.1 Common share repurchases (0.2) — (0.2) Preferred share repurchases — (3.1) (3.1) Stock-based compensation 1.6 — 1.6 Dividends declared on preferred shares of a subsidiary company — (6.5) (6.5) Balance at September 30, 2017 $ 24.7 $ 215.2 $ 239.9 Nine months ended September 30, 2016 Total Atlantic Preferred shares Power Corporation issued by a subsidiary Shareholders’ Equity company Total Equity Balance at January 1, 2016 $ 213.9 $ 221.3 $ 435.2 Net (loss) income (116.2) 6.4 (109.8) Realized and unrealized loss on hedging activities, net of tax (0.1) — (0.1) Foreign currency translation adjustment (2.6) — (2.6) Common share repurchases (13.9) — (13.9) Stock-based compensation 1.4 — 1.4 Dividends declared on preferred shares of a subsidiary company — (6.4) (6.4) Balance at September 30, 2016 $ 82.5 $ 221.3 $ 303.8

Segment and geographic inform30

Segment and geographic information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment and geographic information
Reconciliation of Project Adjusted EBITDA to net income (loss) from continuing operations	Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2017 Project revenues $ 39.8 $ 35.1 $ 33.5 $ 0.2 $ 108.6 Segment assets 680.9 237.5 281.9 113.6 1,313.9 Project Adjusted EBITDA $ 30.6 $ 21.7 $ 24.6 $ 0.5 $ 77.4 Change in fair value of derivative instruments 1.3 — 1.3 (0.6) 2.0 Depreciation and amortization 11.8 10.6 14.0 0.2 36.6 Interest, net 2.5 — — — 2.5 Impairment — 57.3 — — 57.3 Other project income — — (0.1) — (0.1) Project income (loss) 15.0 (46.2) 9.4 0.9 (20.9) Administration — — — 5.5 5.5 Interest expense, net — — — 13.8 13.8 Foreign exchange loss — — — 9.4 9.4 Income (loss) from continuing operations before income taxes 15.0 (46.2) 9.4 (27.8) (49.6) Income tax benefit — — — (15.9) (15.9) Net income (loss) from continuing operations $ 15.0 $ (46.2) $ 9.4 $ (11.9) $ (33.7) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2016 Project revenues $ 31.3 $ 34.1 $ 35.6 $ 0.2 $ 101.2 Segment assets 764.9 328.9 325.3 102.8 1,521.9 Project Adjusted EBITDA $ 19.4 $ 21.3 $ 10.7 $ (0.1) $ 51.3 Change in fair value of derivative instruments (1.2) — (5.6) (2.2) (9.0) Depreciation and amortization 11.0 9.9 9.4 0.1 30.4 Interest, net 2.8 — — — 2.8 Impairment 15.4 — 69.3 — 84.7 Other project income — — — (0.5) (0.5) Project (loss) income (8.6) 11.4 (62.4) 2.5 (57.1) Administration — — — 5.7 5.7 Interest expense, net — — — 20.0 20.0 Foreign exchange gain — — — (3.4) (3.4) Other income, net — — — (1.7) (1.7) (Loss) income from continuing operations before income taxes (8.6) 11.4 (62.4) (18.1) (77.7) Income tax expense — — — 2.6 2.6 Net (loss) income from continuing operations $ (8.6) $ 11.4 $ (62.4) $ (20.7) $ (80.3) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2017 Project revenues $ 116.3 $ 86.2 $ 127.8 $ 0.7 $ 331.0 Segment assets 680.9 237.5 281.9 113.6 1,313.9 Project Adjusted EBITDA $ 86.8 $ 41.5 $ 97.3 $ 1.0 $ 226.6 Change in fair value of derivative instruments 3.3 — 5.4 (2.9) 5.8 Depreciation and amortization 34.2 30.6 40.4 0.4 105.6 Interest, net 8.0 — — — 8.0 Impairment — 57.3 — — 57.3 Other project expense (income) 57.7 — (0.1) — 57.6 Project (loss) income (16.4) (46.4) 51.6 3.5 (7.7) Administration — — — 17.6 17.6 Interest expense, net — — — 49.5 49.5 Foreign exchange loss — — — 17.7 17.7 (Loss) income from continuing operations before income taxes (16.4) (46.4) 51.6 (81.3) (92.5) Income tax benefit — — — (38.5) (38.5) Net (loss) income from continuing operations $ (16.4) $ (46.4) $ 51.6 $ (42.8) $ (54.0) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2016 Project revenues $ 104.3 $ 78.7 $ 122.0 $ 0.8 $ 305.8 Segment assets 764.9 328.9 325.3 102.8 1,521.9 Project Adjusted EBITDA $ 70.5 $ 43.4 $ 46.2 $ (0.2) $ 159.9 Change in fair value of derivative instruments (3.0) — (17.7) 0.6 (20.1) Depreciation and amortization 33.0 29.6 27.7 0.5 90.8 Interest, net 8.2 — — — 8.2 Impairment 15.4 — 69.3 — 84.7 Other project income — — — (0.4) (0.4) Project income (loss) 16.9 13.8 (33.1) (0.9) (3.3) Administration — — — 17.6 17.6 Interest expense, net — — — 87.9 87.9 Foreign exchange loss — — — 19.1 19.1 Other income, net — — — (3.9) (3.9) Income (loss) from continuing operations before income taxes 16.9 13.8 (33.1) (121.6) $ (124.0) Income tax benefit — — — (14.2) (14.2) Net income (loss) from continuing operations $ 16.9 $ 13.8 $ (33.1) $ (107.4) $ (109.8)
Schedule of revenue and property, plant and equipment by country	Project Revenue Three Months Ended September 30, Project Revenue Nine Months Ended September 30, Property, Plant and 2017 2016 2017 2016 September 30, 2017 December 31, 2016 United States $ 75.1 $ 65.6 $ 203.2 $ 183.8 $ 437.0 $ 499.2 Canada 33.5 35.6 127.8 122.0 215.6 234.0 Total $ 108.6 $ 101.2 $ 331.0 $ 305.8 $ 652.6 $ 733.2

Nature of business (Details)

Nature of business (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)statecontractprojectitemMW	Sep. 30, 2016USD ($)
Nature of business
Gross generating capacity of project (in MW) | MW	2,138
Ownership interest in power generation projects (in MW) | MW	1,500
Number of power generation projects	23
Number of states in which power generation projects operate | state	9
Number of provinces in which power generation projects operate | item	2
Number of projects which are majority owned	18
Recent accounting pronouncements adopted
Number of PPA's requiring further analysis | contract	12
Increase (decrease) in cash provided by operating activities | $	$ 137.9	$ 91.9
Increase (decrease) in cash provided by investing activities | $	$ (4.9)	0.8
Plant in service
Nature of business
Gross generating capacity of project (in MW) | MW	1,975
Ownership interest in power generation projects (in MW) | MW	1,337
Number of power generation projects	19
Plant not in service
Nature of business
Number of power generation projects	4
Plant Not In Service Due To Revised Contract [Member]
Nature of business
Number of power generation projects	3
Plant With Future Commencement Date [Member]
Nature of business
Contract term	15 years
ASU 2016-18 | Pro Forma [Member]
Recent accounting pronouncements adopted
Increase (decrease) in cash provided by operating activities | $	$ 0.8	2.6
Increase (decrease) in cash provided by investing activities | $	$ 0.8	$ 2.6

Changes in accumulated other 32

Changes in accumulated other comprehensive loss by component (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
AOCI Attributable to Parent, Net of Tax
Beginning Balance			$ 64.6
Amount reclassified
Ending Balance	$ 24.7		24.7
Cash flow hedges
AOCI Attributable to Parent, Net of Tax
Beginning Balance	0.8	$ (0.1)	0.7	$ 0.2
Other comprehensive loss:
Net change from periodic revaluations	(0.1)	0.1	(0.6)	(1)
Tax benefit (expense)	0.1	(0.1)	0.3	0.4
Total other comprehensive (loss) income before reclassifications, net of tax			(0.3)	(0.6)
Amount reclassified
Total other comprehensive loss) income	0.1	0.2	0.2	(0.1)
Ending Balance	0.9	0.1	0.9	0.1
Foreign currency translation
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(141.6)	(119.7)	(148.3)	(139.1)
Other comprehensive loss:
Foreign currency translation adjustments	9.2	(22)	15.9	(2.6)
Amount reclassified
Ending Balance	(132.4)	(141.7)	(132.4)	(141.7)
Accumulated other comprehensive loss, tax impacts related to rate changes	0	0	0	0
Pension
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(0.8)	(0.4)	(0.9)	(0.4)
Other comprehensive loss:
Curtailment gain			0.1
Total other comprehensive (loss) income before reclassifications, net of tax			0.1
Amount reclassified
Total other comprehensive loss) income			0.1
Ending Balance	(0.8)	(0.4)	(0.8)	(0.4)
Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
Tax expense.	(0.1)	(0.1)	(0.4)	(0.4)
Total amount reclassified from accumulated other comprehensive loss, net of tax	0.1	0.2	0.5	0.5
Amount reclassified from accumulated other comprehensive income | Foreign currency translation
Amount reclassified
Amounts reclassified to earnings, foreign currency	0	0	0	0
Interest rate swaps | Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
Amount reclassified from AOCI	$ (0.2)	$ (0.3)	$ (0.9)	$ (0.9)

Equity method investments in 33

Equity method investments in unconsolidated affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended		30 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Operating results
Revenue	$ 31	$ 34.1	$ 92.7	$ 97.8
Project expenses	21.3	24.1	69.7	68.5
Project other expense	(0.5)	(0.4)	(59.1)	(1.4)
Equity in (loss) earnings of unconsolidated affiliates	9.2	9.6	(36.1)	27.9
Distributions from equity method investments	(13.7)	(13)	(30.9)	(36.5)
Deficit in earnings of equity method investments, net of distributions	(4.5)	(3.4)	(67)	(8.6)
Frederickson
Operating results
Revenue	5.9	5.8	16	15.7
Project expenses	4.9	4.9	16.8	14.3
Project income (loss)	1	0.9	(0.8)	1.4
Orlando Cogen, LP
Operating results
Revenue	14.3	13.9	40.4	40.6
Project expenses	7.2	6.9	22.1	19.6
Project income (loss)	7.1	7	18.3	21
Koma Kulshan Associates
Operating results
Revenue	0.3	0.1	1.4	1.3
Project expenses	0.3	0.4	0.8	0.9
Project income (loss)		(0.3)	0.6	0.4
Chambers Cogen, LP
Operating results
Revenue	10.5	11.2	33.1	34.3
Project expenses	8.9	9.3	27.2	27.8
Project other expense	(0.5)	(0.4)	(48.5)	(1.4)
Project income (loss)	$ 1.1	1.5	(42.6)	5.1
Equity in (loss) earnings of unconsolidated affiliates			3.4		$ 5.5	$ 6.5
Distributions from equity method investments							$ (33.6)
Selkirk Cogen Partners, LP
Operating results
Revenue		3.1	1.8	5.9
Project expenses		2.6	2.8	$ 5.9
Project other expense			(10.6)
Project income (loss)		$ 0.5	(11.6)
Equity in (loss) earnings of unconsolidated affiliates			$ 1.2

Equity method investments in 34

Equity method investments in unconsolidated affiliates - impairments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended		30 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Equity in earnings of unconsolidated affiliates
Equity in (loss) earnings of unconsolidated affiliates	$ 9.2	$ 9.6	$ (36.1)	$ 27.9
Equity Method Investments.	199.8		199.8		$ 266.8
Distributions from unconsolidated affiliates	$ 13.7	$ 13	$ 30.9	$ 36.5
Chambers Cogen, LP
Equity in earnings of unconsolidated affiliates
Percentage of ownership interest	40.00%		40.00%
Equity in (loss) earnings of unconsolidated affiliates			$ 3.4		$ 5.5	$ 6.5
Equity impairment other than temporary	$ 47.1
Equity Method Investments.	124		124
Distributions from unconsolidated affiliates							$ 33.6
Estimated fair value of equity investment	$ 77.2		$ 77.2
Selkirk Cogen Partners, LP
Equity in earnings of unconsolidated affiliates
Percentage of ownership interest	17.70%		17.70%
Equity in (loss) earnings of unconsolidated affiliates			$ 1.2
Equity impairment other than temporary	$ 10.6

Long-lived assets and goodwill

Long-lived assets and goodwill (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)item	Sep. 30, 2017USD ($)project	Sep. 30, 2016USD ($)GWh	Dec. 31, 2016USD ($)
Goodwill, Impaired [Abstract]
Period of declining power prices		2 years
Goodwill (Note 4)	$ 36		$ 36		$ 36
Number of asset groups tested under step one | item		5
Impairment of goodwill		$ 78.8		$ 78.8
San Diego Projects
Long Lived Assets And Goodwill [Line Items]
Number of projects supplying steam | project			3
Asset Impairment Charges [Abstract]
Impairment of Ongoing Project	57.3		$ 57.3
Impairment of intangible assets related to PPAs	18.2		18.2
Partial impairment of PP&E	39.1		39.1
Project removal obligation	4.6		4.6
Goodwill, Impaired [Abstract]
Property, plant and equipment, fair value	7.7		7.7
Naval Station
Asset Impairment Charges [Abstract]
Impairment of Ongoing Project	22.5		22.5
Impairment of intangible assets related to PPAs	10.3		10.3
Partial impairment of PP&E	12.1		12.1
Naval Training Center
Asset Impairment Charges [Abstract]
Impairment of Ongoing Project	13.5		13.5
Impairment of intangible assets related to PPAs	3.6		3.6
Partial impairment of PP&E	9.9		9.9
North Island
Asset Impairment Charges [Abstract]
Impairment of Ongoing Project	21.2		21.2
Impairment of intangible assets related to PPAs	4.2		4.2
Partial impairment of PP&E	$ 17		$ 17
Morris And Nipigon
Goodwill, Impaired [Abstract]
Number of reporting units not significantly impacted by declining power prices | item		2
Goodwill (Note 4)		$ 6.9		6.9
North Bay And Kapuskasing
Goodwill, Impaired [Abstract]
Long lived asset impairment charge		5.9
North Bay
Goodwill, Impaired [Abstract]
Impairment of goodwill		6.5		6.5
Kapuskasing
Goodwill, Impaired [Abstract]
Impairment of goodwill		6.7		6.7
Mamquam
Goodwill, Impaired [Abstract]
Impairment of goodwill		50.2		50.2
Curtis Palmer
Goodwill, Impaired [Abstract]
Impairment of goodwill		15.4		$ 15.4
Quantity triggering agreement expiration | GWh				10,000
Expected period of expiration before specified date (in years)				2 years
Moresby Lake
Goodwill, Impaired [Abstract]
Impairment of goodwill		$ 0		$ 0

Long-term debt (Details)

Long-term debt (Details) CAD in Millions, $ in Millions	Oct. 28, 2017	Oct. 18, 2017USD ($)	Oct. 13, 2017USD ($)	Sep. 30, 2017CAD	Oct. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Long-term debt
Less: unamortized discount						$ (13.8)	$ (17.2)
Less: unamortized deferred financing costs						(11.6)	(15.3)
Less: current maturities						(156.5)	(111.9)
Less: current maturities						(156.5)	(111.9)
Total long-term debt						637.3	749.2
New term loan facility
Long-term debt
Length of extension to term of credit facility	1 year
Senior secured term loan facility, due 2023
Long-term debt
Long-term Debt, Gross						562.7	639.9
Less: current maturities						(92.5)	(100)
Applicable margin (as a percent)				4.25%
Senior unsecured notes, due June 2036 (Cdn$210.0)
Long-term debt
Long-term Debt, Gross						$ 168.3	156.4
Face amount of debt | CAD				CAD 210
Interest rate (as a percent)				5.95%		5.95%
Epsilon Power Partners term facility, due 2019
Long-term debt
Long-term Debt, Gross						$ 8.8	13.5
Less: current maturities						(6.4)	(6.2)
Cadillac term loan, due 2025
Long-term debt
Long-term Debt, Gross						24.8	27
Less: current maturities						(3)	(3)
Piedmont term loan, due 2018
Long-term debt
Long-term Debt, Gross						54.6	56.6
Less: current maturities						(54.6)	(2.5)
Applicable margin (as a percent)				3.75%
Other long-term debt
Long-term debt
Long-term Debt, Gross							0.2
Less: current maturities							(0.2)
Interest rate swaps
Long-term debt
Notional amount						434.6	$ 506.9
Interest rate swaps | New term loan facility
Long-term debt
Notional amount						$ 354
Forecast
Long-term debt
Interest rate margin reduction		(0.75%)
Applicable margin (as a percent)		3.50%
Forecast | New term loan facility
Long-term debt
Face amount of debt					$ 200
Amount of debt repriced		$ 562.7
Forecast | Piedmont term loan, due 2018
Long-term debt
Extinguishment of Debt, Amount			$ 54.6
Interest Paid			0.1
Payment to terminate interest rate swap agreements			9.4
Write-off of deferred financing costs			$ 0.9
Minimum | Other long-term debt
Long-term debt
Interest rate (as a percent)				5.50%		5.50%
Maximum | Other long-term debt
Long-term debt
Interest rate (as a percent)				6.70%		6.70%
London Interbank Offered Rate (LIBOR) | Epsilon Power Partners term facility, due 2019
Long-term debt
Applicable margin (as a percent)				3.13%
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) | New term loan facility
Long-term debt
Minimum percentage of variable rate base				1.00%

Fair value of financial instr37

Fair value of financial instruments - recurring (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Assets:
Restricted cash	$ 12.5	$ 13.3
Recurring
Assets:
Cash and cash equivalents	122.4	85.6
Restricted cash	12.5	13.3
Derivative instruments asset	5.1	8.6
Total	140	107.5
Liabilities:
Derivative instruments liability	33	28.9
Total	33	28.9
Recurring | Level 1
Assets:
Cash and cash equivalents	122.4	85.6
Restricted cash	12.5	13.3
Total	134.9	98.9
Recurring | Level 2
Assets:
Derivative instruments asset	5.1	8.6
Total	5.1	8.6
Liabilities:
Derivative instruments liability	33	28.9
Total	$ 33	$ 28.9

Fair value of financial instr38

Fair value of financial instruments - credit valuation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Recurring measurements of fair value hierarchy of financial assets and liabilities
Gain (Loss) on Derivative Instruments, Net, Pretax	$ (1.9)	$ 9	$ (5.8)	$ 20
Recurring | Credit valuation adjustments
Recurring measurements of fair value hierarchy of financial assets and liabilities
Net increase in fair value			2.4		$ 3.8
Pre-tax gain in other comprehensive income			0.2		0.3
Gain (Loss) on Derivative Instruments, Net, Pretax			$ 2.2		$ 3.5

Accounting for derivative ins39

Accounting for derivative instruments and hedging activities (Details) CAD in Thousands, kJ in Millions, $ in Millions

Oct. 18, 2017

Oct. 31, 2017USD ($)

Dec. 31, 2016USD ($)MMBTU

Jun. 30, 2014kJ

Sep. 30, 2017CADMMBTUitem

Dec. 31, 2016USD ($)MMBTU

Dec. 31, 2018CAD

Dec. 20, 2018CAD

Sep. 30, 2018

Jun. 30, 2018CAD

Jun. 20, 2018CAD

Mar. 31, 2018CAD

Mar. 20, 2018CAD

Dec. 31, 2017CAD

Oct. 30, 2017USD ($)

Sep. 30, 2017USD ($)item

Jul. 31, 2017CAD

Jun. 30, 2017CAD

Mar. 31, 2017CAD

Derivative instruments

Number of derivative contracts designated as cash flow hedges | item

1

1

New term loan facility

Derivative instruments

Minimum fixed interest rate (as a percent)

5.25%

5.25%

Piedmont term loan, due 2018

Derivative instruments

Remaining aggregate principal amount | $

$ 56.6

$ 56.6

$ 54.6

Applicable margin (as a percent)

3.75%

Senior secured term loans

Derivative instruments

Face amount of debt | $

$ 375.7

Adjusted Eurodollar Rate | New term loan facility

Derivative instruments

Minimum fixed interest rate (as a percent)

1.00%

1.00%

Forecast

Derivative instruments

Applicable margin (as a percent)

3.50%

Forecast | New term loan facility

Derivative instruments

Face amount of debt | $

$ 200

Forecast | Piedmont term loan, due 2018

Derivative instruments

Interest Expense, Debt | $

$ 9.4

Piedmont | London Interbank Offered Rate (LIBOR) | Piedmont term loan, due 2018

Derivative instruments

Applicable margin of derivative (as a percent)

3.75%

3.75%

Gas purchase agreements | Morris Project

Derivative instruments

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

220,000

Natural gas swaps

Derivative instruments

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

9,000,000

4,900,000

Natural gas swaps | Kenilworth project

Derivative instruments

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

800,000

Natural gas swaps | Orlando project

Derivative instruments

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

10,900,000

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

95.00%

Natural gas swaps during 2018 | Orlando project

Derivative instruments

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

90.00%

Natural gas swaps during 2019 | Orlando project

Derivative instruments

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

100.00%

Natural gas swaps during 2020 | Orlando project

Derivative instruments

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

50.00%

Interest rate swaps

Derivative instruments

Notional amount | $

$ 506.9

$ 506.9

$ 434.6

Interest rate swaps | New term loan facility

Derivative instruments

Notional amount | $

$ 354

Interest rate swaps | Swaption interest rate until February 15, 2019 | Cadillac Project

Derivative instruments

Swaption interest rate (as a percent)

6.10%

6.10%

Interest rate swaps | Derivative Swaption Interest Rate Until August 2018 [Member] | Piedmont

Derivative instruments

Applicable margin (as a percent)

4.00%

Swaption interest rate (as a percent)

4.47%

4.47%

Swaption all in one interest rate (as a percent)

8.47%

8.47%

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%

Foreign currency forward contracts

Derivative instruments

Notional amount | CAD

CAD 35,000

Foreign Exchange Forward Rate 1.3381 | Derivative instruments not designated as cash flow hedges

Derivative instruments

Notional amount | CAD

CAD 30,000

Notional amount increments | CAD

10,000

CAD 10,000

CAD 10,000

Foreign currency exchange rate

1.3381

Foreign Exchange Forward Rate 1.2481 | Derivative instruments not designated as cash flow hedges

Derivative instruments

Notional amount | CAD

CAD 10,000

Notional amount increments | CAD

CAD 3,330

CAD 3,330

CAD 3,330

Foreign currency exchange rate

1.2481

Foreign Exchange Forward Rate 1.2943 | Derivative instruments not designated as cash flow hedges

Derivative instruments

Notional amount | CAD

CAD 10,000

Notional amount increments | CAD

CAD 2,000

CAD 3,000

CAD 5,000

Foreign currency exchange rate

1.2943

Foreign Exchange Forward Rate 1.2196 | Derivative instruments not designated as cash flow hedges

Derivative instruments

Notional amount | CAD

CAD 5,000

Foreign currency exchange rate

1.2196

Epsilon Power Partners | New term loan facility

Derivative instruments

Remaining aggregate principal amount | $

$ 562.7

Epsilon Power Partners | Natural gas swaps | Ontario project

Derivative instruments

Notional amount, energy (in gigajoules: Ontario, in Mmbtu: Orlando and Morris) | kJ

2.9

Epsilon Power Partners | Interest rate swaps

Derivative instruments

Notional amount | $

$ 354.2

Epsilon Power Partners | Interest rate swaps | Adjusted Eurodollar Rate | New term loan facility

Derivative instruments

Applicable margin of derivative (as a percent)

4.25%

4.25%

Accounting for derivative ins40

Accounting for derivative instruments - forecasted trans (Details) kJ in Millions, MMBTU in Millions, CAD in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2017CADMMBTUkJ	Dec. 31, 2016USD ($)MMBTUkJ	Sep. 30, 2017USD ($)
Natural gas swaps
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | MMBTU	9	4.9
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | kJ	10.5	11.3
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $		$ 506.9	$ 434.6
Foreign currency forward contracts
Derivative instruments
Volume of forecasted transactions, (in dollars) | CAD	CAD 35

Accounting for derivative ins41

Accounting for derivative instruments - FV by Bal Sht Loc (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair value of derivative instruments
Derivative Assets	$ 5.1	$ 8.9
Derivative Liabilities	33	29.2
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	2.5	2.8
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	0.7	0.8
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	1.8	2
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets	5.1	8.9
Derivative Liabilities	30.5	26.4
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Assets	1.4	0.4
Derivative Liabilities	8.8	1.9
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Assets	2.6	4.5
Derivative Liabilities		6.5
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current
Fair value of derivative instruments
Derivative Assets	0.4	3.9
Derivative Liabilities	0.1	0.8
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term
Fair value of derivative instruments
Derivative Assets		0.1
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current
Fair value of derivative instruments
Derivative Assets	0.7
Derivative Liabilities	3.3	4.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term
Fair value of derivative instruments
Derivative Liabilities	17.7	$ 12.7
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Current
Fair value of derivative instruments
Derivative Liabilities	$ 0.6

Accounting for derivative ins42

Accounting for derivative instruments - AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges			$ (0.3)	$ (0.6)
Realized from OCI during the period	$ 0.1	$ 0.2	0.5	0.5
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	0.8	(0.1)	0.7	0.2
Change in fair value of cash flow hedges			(0.3)	(0.6)
Realized from OCI during the period	0.1	0.2	0.5	0.5
Accumulated OCI balance at end of period	$ 0.9	$ 0.1	$ 0.9	$ 0.1

Accounting for derivative ins43

Accounting for derivative instruments - gain, loss (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ (1.9)	$ 9	$ (5.8)	$ 20
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	(1.9)	9	(5.8)	20
Derivative instruments not designated as cash flow hedges | Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized (gains) and losses of derivative instruments	(0.7)	0.6	(1.2)	4
Change in fair value of derivative instruments	0.2	0.2	(0.3)	6
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	3.1	12.4	7.9	36.4
Change in fair value of derivative instruments	(1.3)	5.6	(4.3)	16.8
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	0.9	1	2.6	2.7
Change in fair value of derivative instruments	(0.8)	$ 3.2	(1.2)	$ (2.8)
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ (0.2)		$ (0.7)

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Components of income tax expenses (benefit)
Current income tax expense	$ 1.3	$ 0.8	$ 3.6	$ 2.6
Deferred income (expense) benefit	(17.2)	1.8	(42.1)	(16.8)
Total income tax (benefit) expense, net	(15.9)	$ 2.6	(38.5)	$ (14.2)
Reconciliation of income taxes
Canadian enacted statutory rate (as a percent)		26.00%		26.00%
Computed income taxes at 26% Canadian statutory rate	(12.9)	$ 20.2	(24.1)	$ 32.2
Operating in higher tax rate jurisdictions	5.5	1.9	14.2	2.8
Change in valuation allowance	3.5	8.6	1.5	13.2
Foreign exchange	1.3		2.3	5.5
Capital gain on intercompany notes		22.5
Other permanent differences	0.3	0.8		1.1
Capital loss on intercompany notes		9.3		3
Valuation allowance	$ 187.5		187.5
Income taxes impact on tax rate			$ 0.6
Goodwill impairment				22.5
Impairment of goodwill		78.8		78.8
United States
Reconciliation of income taxes
Capital losses on tax restructuring		18.4		18.4
Canada
Reconciliation of income taxes
Increase related to operating losses				31.6
Capital losses on tax restructuring		$ 18.5		$ 18.5

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	Jan. 22, 2015CAD / shares	Jan. 31, 2015	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2016USD ($)
Units
Outstanding at the beginning of the period (in shares)					2,101,118
Granted (in shares)					1,817,463
Vested and redeemed (in shares)					(1,009,780)
Forfeitures (in shares)					(24,227)
Outstanding at the end of the period (in shares)			2,884,574		2,884,574
Weighted-Average Fair Value per Unit
Outstanding at the beginning of the period (in dollars per share) | $ / shares					$ 2.08
Granted (in dollars per share) | $ / shares					2.38
Vested and redeemed (in dollars per share) | $ / shares					2.22
Forfeitures (in dollars per share) | $ / shares					2.32
Outstanding at the end of the period (in dollars per share) | $ / shares			$ 2.22		$ 2.22
Compensation expense related to LTIP | $					$ 2.6	$ 0.9
Long-term incentive plan
Weighted-Average Fair Value per Unit
Cash payments made for vested notional units | $					$ 0.7	$ 0.4
Compensation expense related to LTIP | $			$ 0.9	$ 0.8
Transition equity participation agreement
Transition equity participation agreement
Number of transition notional shares outstanding					539,904
Vesting percentage		50.00%
Vesting period					4 years
Period after which remaining portions vests					2 years
Share Price | CAD / shares	CAD 3.18
Minimum market price required for 3 consecutive months to vest remaining shares | CAD / shares	CAD 4.77
Transition equity participation agreement | Minimum
Transition equity participation agreement
Number of consecutive months, weighted average Canadian dollar price must exceed market price of share by 50% for vesting					3 months
Minimum percentage by which weighted average Canadian dollar price exceeds market price	50.00%

Basic and diluted loss per sh46

Basic and diluted loss per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Numerator:
Net loss attributable to Atlantic Power Corporation	$ (32.9)	$ (82.4)	$ (57.5)	$ (116.2)
Denominator:
Weighted average basic shares outstanding	115.3	119.3	115.1	120.9
Dilutive potential shares:
Convertible debentures (in shares)	8.1	8.1	8.1	14.9
LTIP notional units (in shares)		0.1		0.1
Potentially dilutive shares	123.4	127.5	123.2	135.9
Basic and diluted loss per share attributable to Atlantic Power Corporation	$ (0.29)	$ (0.69)	$ (0.50)	$ (0.96)

Equity (Details)

Equity (Details) CAD / shares in Units, shares in Millions, CAD in Millions, $ in Millions	3 Months Ended		9 Months Ended			10 Months Ended			12 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)shares	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017CADCAD / sharesshares	Sep. 30, 2017USD ($)shares	Sep. 30, 2016USD ($)shares	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)shares	Dec. 29, 2016shares
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				$ 285.9	$ 435.2				$ 303.8	$ 435.2
Net (loss) income				(54)	(109.8)
Realized and unrealized gain (loss) on hedging activities, net of tax				0.2	(0.1)
Foreign currency translation adjustments	$ 9.2	$ (22)		15.9	(2.6)
Defined benefit plan, net of tax				0.1
Common share repurchases				(0.2)	(13.9)
Preferred share repurchase				(3.1)
Stock-based compensation				1.6	1.4
Dividends declared on preferred shares of a subsidiary company				(6.5)	(6.4)
Balance at the end of the period	239.9	303.8	$ 239.9	239.9	303.8		$ 239.9	$ 303.8	$ 239.9	285.9
Stock Repurchase Program
Cost of shares repurchased and cancelled			$ 0.2			CAD 3.9		$ 13.9		$ 19.5
Share repurchase plan, number of shares authorized | shares											11.3
Stock repurchase program authorized amount											10.00%
Number of shares repurchased and cancelled | shares			0.1			0.3	0.3	5.7		8
Number of shares repurchased and cancelled (in dollar per share) | CAD / shares						CAD 25
Dividend rate on preferred shares (as a percent)									4.85%
Redemption price after specified date and thereafter (in Canadian dollars per share) | CAD / shares						CAD 15.50
Gain on redemption of preferred shares			$ 3
Total Atlantic Power Corporation Shareholder's Equity
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				64.6	213.9				$ 82.5	$ 213.9
Net (loss) income				(57.5)	(116.2)
Realized and unrealized gain (loss) on hedging activities, net of tax				0.2	(0.1)
Foreign currency translation adjustments				15.9	(2.6)
Defined benefit plan, net of tax				0.1
Common share repurchases				(0.2)	(13.9)
Stock-based compensation				1.6	1.4
Balance at the end of the period	24.7	82.5	24.7	24.7	82.5		$ 24.7	$ 82.5	24.7	64.6
Noncontrolling Interests
Increase (decrease) in shareholders' equity
Balance at the beginning of the period				221.3	221.3				221.3	221.3
Net (loss) income				3.5	6.4
Preferred share repurchase				(3.1)
Dividends declared on preferred shares of a subsidiary company				(6.5)	(6.4)
Balance at the end of the period	$ 215.2	$ 221.3	$ 215.2	$ 215.2	$ 221.3		$ 215.2	$ 221.3	$ 215.2	$ 221.3

Segment and geographic inform48

Segment and geographic information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)segment	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Segment and geographic information
Number of reportable segments | segment			4
Project revenues	$ 108.6	$ 101.2	$ 331	$ 305.8
Segment assets	1,313.9	1,521.9	1,313.9	1,521.9	$ 1,456.8
Project Adjusted EBITDA	77.4	51.3	226.6	159.9
Change in fair value of derivative instruments	2	(9)	5.8	(20.1)
Depreciation and amortization	36.6	30.4	105.6	90.8
Interest, net	2.5	2.8	8	8.2
Impairment	57.3	84.7	57.3	84.7
Other project expense (income)	(0.1)	(0.5)	57.6	(0.4)
Project loss	(20.9)	(57.1)	(7.7)	(3.3)
Administration	5.5	5.7	17.6	17.6
Interest expense, net	13.8	20	49.5	87.9
Foreign exchange loss	9.4	(3.4)	17.7	19.1
Other income, net		(1.7)		(3.9)
Loss from operations before income taxes	(49.6)	(77.7)	(92.5)	(124)
Income tax expense (benefit)	(15.9)	2.6	(38.5)	(14.2)
Net income (loss) from continuing operations	(33.7)	(80.3)	(54)	(109.8)
East
Segment and geographic information
Project revenues	39.8	31.3	116.3	104.3
Segment assets	680.9	764.9	680.9	764.9
Project Adjusted EBITDA	30.6	19.4	86.8	70.5
Change in fair value of derivative instruments	1.3	(1.2)	3.3	(3)
Depreciation and amortization	11.8	11	34.2	33
Interest, net	2.5	2.8	8	8.2
Impairment		15.4		15.4
Other project expense (income)			57.7
Project loss	15	(8.6)	(16.4)	16.9
Loss from operations before income taxes	15	(8.6)	(16.4)	16.9
Net income (loss) from continuing operations	15	(8.6)	(16.4)	16.9
West
Segment and geographic information
Project revenues	35.1	34.1	86.2	78.7
Segment assets	237.5	328.9	237.5	328.9
Project Adjusted EBITDA	21.7	21.3	41.5	43.4
Depreciation and amortization	10.6	9.9	30.6	29.6
Impairment	57.3		57.3
Project loss	(46.2)	11.4	(46.4)	13.8
Loss from operations before income taxes	(46.2)	11.4	(46.4)	13.8
Net income (loss) from continuing operations	(46.2)	11.4	(46.4)	13.8
Canada
Segment and geographic information
Project revenues	33.5	35.6	127.8	122
Segment assets	281.9	325.3	281.9	325.3
Project Adjusted EBITDA	24.6	10.7	97.3	46.2
Change in fair value of derivative instruments	1.3	(5.6)	5.4	(17.7)
Depreciation and amortization	14	9.4	40.4	27.7
Impairment		69.3		69.3
Other project expense (income)	(0.1)		(0.1)
Project loss	9.4	(62.4)	51.6	(33.1)
Loss from operations before income taxes	9.4	(62.4)	51.6	(33.1)
Net income (loss) from continuing operations	9.4	(62.4)	51.6	(33.1)
Un-Allocated Corporate
Segment and geographic information
Project revenues	0.2	0.2	0.7	0.8
Segment assets	113.6	102.8	113.6	102.8
Project Adjusted EBITDA	0.5	(0.1)	1	(0.2)
Change in fair value of derivative instruments	(0.6)	(2.2)	(2.9)	0.6
Depreciation and amortization	0.2	0.1	0.4	0.5
Other project expense (income)		(0.5)		(0.4)
Project loss	0.9	2.5	3.5	(0.9)
Administration	5.5	5.7	17.6	17.6
Interest expense, net	13.8	20	49.5	87.9
Foreign exchange loss	9.4	(3.4)	17.7	19.1
Other income, net		(1.7)		(3.9)
Loss from operations before income taxes	(27.8)	(18.1)	(81.3)	(121.6)
Income tax expense (benefit)	(15.9)	2.6	(38.5)	(14.2)
Net income (loss) from continuing operations	$ (11.9)	$ (20.7)	$ (42.8)	$ (107.4)

Segment and geographic inform49

Segment and geographic information - Geographic (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Revenue and Assets
Revenues	$ 108.6	$ 101.2	$ 331	$ 305.8
Property, plant, and equipment, net (Note 4)	652.6		652.6		$ 733.2
United States
Revenue and Assets
Revenues	75.1	65.6	203.2	183.8
Property, plant, and equipment, net (Note 4)	437		437		499.2
Canada
Revenue and Assets
Revenues	33.5	$ 35.6	127.8	$ 122
Property, plant, and equipment, net (Note 4)	$ 215.6		$ 215.6		$ 234

Segment and geographic inform50

Segment and geographic information - risk (Details) - Revenues, net	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	16.40%	24.50%	19.30%	28.00%
Niagara Mohawk
Consolidated revenue concentration
Percentage of consolidated revenue			10.70%
SDG&E
Consolidated revenue concentration
Percentage of consolidated revenue	13.90%	16.10%	11.10%	11.50%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	11.30%	10.60%	10.30%	11.60%
Georgia Power
Consolidated revenue concentration
Percentage of consolidated revenue	10.30%	10.90%

Guarantees and Contingencies (D

Guarantees and Contingencies (Details) CAD in Millions, $ in Millions	Apr. 27, 2017CAD	Sep. 30, 2017CADitem	Sep. 30, 2017USD ($)	Jun. 30, 2017CAD	Jun. 30, 2017USD ($)	Sep. 30, 2017CADitem
Contingencies
Number of pending matters expected to have a material adverse impact on financial position or results of operations, or have been reserved | item		0				0
Ontario Electricity Financial Corporation
Contingencies
Litigation settlement amount	CAD 36.4					CAD 37.8
Ontario Electricity Financial Corporation | Revenue
Contingencies
Payment received against litigation settlement		CAD 34	$ 25.6	CAD 34	$ 25.6
Ontario Electricity Financial Corporation | North Bay And Kapuskasing | Application Of Price Escalator To Enhanced Dispatch Contracts
Contingencies
Balance of litigation settlement receivable		CAD 3.8				CAD 3.8