Atlantic Power 10-Q 31 Oct 19 2019 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Oct. 30, 2019
Document and Entity Information
Entity Registrant Name	ATLANTIC POWER CORPORATION
Entity Central Index Key	0001419242
Document Type	10-Q
Document Period End Date	Sep. 30, 2019
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		109,328,782
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 58.1	$ 68.3
Restricted cash	1.7	2.1
Accounts receivable	35.3	35.7
Current portion of derivative instruments asset (Notes 8 and 9)	0.1	4.2
Inventory	18.2	15.8
Prepayments	5.2	4
Income taxes receivable	2.3	0.3
Lease receivable	1.5
Other current assets	0.7	5.9
Total current assets	123.1	136.3
Property, plant, and equipment, net	505.7	549.5
Equity investments in unconsolidated affiliates (Note 5)	152.6	140.8
Power purchase agreements and intangible assets, net	151.9	170.1
Goodwill	21.3	21.3
Derivative instruments asset (Notes 8 and 9)		0.3
Operating lease right-of-use assets (Note 1)	5.9
Insurance recovery receivable (Note 15)	24.2
Other assets	3.3	6.2
Total assets	988	1,024.5
Current liabilities:
Accounts payable	3.4	2.5
Accrued interest	3.5	2.3
Other accrued liabilities	19.4	20.2
Current portion of long-term debt (Note 6)	108.1	68.1
Current portion of derivative instruments liability (Notes 8 and 9)	10.8	4.5
Convertible debentures (Note 7)		18.1
Operating lease liabilities (Note 16)	1.5
Other current liabilities	0.6	0.2
Total current liabilities	147.3	115.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 6)	457.3	540.7
Convertible debentures, net of discount and unamortized deferred financing costs (Note 7)	79.1	75.7
Derivative instruments liability (Notes 8 and 9)	15.5	15.4
Deferred income taxes	6.9	9
Power purchase agreements and intangible liabilities, net	20.1	21.2
Asset retirement obligations, net	50.9	49.2
Operating lease liabilities (Note 16)	5
Other long-term liabilities	3.9	5
Total liabilities	786	832.1
Equity
Common shares, no par value, unlimited authorized shares; 109,379,611 and 108,341,738 issued and outstanding at September 30, 2019 and December 31, 2018	1,261.3	1,260.9
Accumulated other comprehensive loss (Note 4)	(143.1)	(146.2)
Retained deficit	(1,098.9)	(1,121.6)
Total Atlantic Power Corporation shareholders' equity	19.3	(6.9)
Preferred shares issued by a subsidiary company (Note 13)	182.7	199.3
Total equity	202	192.4
Total liabilities and equity	$ 988	$ 1,024.5

CONSOLIDATED BALANCE SHEETS - (

CONSOLIDATED BALANCE SHEETS - (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
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)	109,379,611	108,341,738
Common shares, outstanding shares (in shares)	109,379,611	108,341,738

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Project revenue:
Revenues	$ 71.1	$ 65.4	$ 215.4	$ 211.6
Project expenses:
Fuel	19.4	16.7	55.2	54
Operations and maintenance	19.5	18	54.6	66.5
Depreciation and amortization	16.2	21	48.5	65.7
Total project expenses	55.1	55.7	158.3	186.2
Project other income (loss):
Change in fair value of derivative instruments (Notes 8 and 9)	1.1		(8.3)	3.6
Equity in earnings of unconsolidated affiliates (Note 5)	12.1	10.2	34.4	33.7
Interest, net	(0.3)	(0.4)	(0.9)	(1.4)
Insurance loss (Note 15)	(1)		(1)
Other income (expense), net		6.7	(1.2)	6.7
Total project other income	11.9	16.5	23	42.6
Project income	27.9	26.2	80.1	68
Administrative and other expenses:
Administration	5.5	5.7	17.3	17.9
Interest expense, net	10.9	14.6	33	40.7
Foreign exchange (gain) loss	(2.8)	4.5	7.1	(9.1)
Other (income) expense, net	(0.2)	2.5	0.7	0.3
Total administrative and other expenses	13.4	27.3	58.1	49.8
Income (loss) from operations before income taxes	14.5	(1.1)	22	18.2
Income tax expense (Note 10)	0.2	3.6	2.4	7.7
Net income (loss)	14.3	(4.7)	19.6	10.5
Net income (loss) attributable to preferred shares of a subsidiary company (Note 13)	1.7	(1.5)	(3.1)	(1.6)
Net income (loss) attributable to Atlantic Power Corporation	$ 12.6	$ (3.2)	$ 22.7	$ 12.1
Net earnings (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 12)
Basic	$ 0.12	$ (0.03)	$ 0.21	$ 0.11
Diluted	$ 0.10	$ (0.03)	$ 0.19	$ 0.11
Weighted average number of common shares outstanding: (Note 12)
Basic (in shares)	109.4	111.1	109.4	112.8
Diluted (in shares)	137.8	111.1	138.3	142.3
Energy sales
Project revenue:
Revenues	$ 29.2	$ 25	$ 102.7	$ 94.8
Energy capacity revenue
Project revenue:
Revenues	38	29.5	99.8	72.9
Other
Project revenue:
Revenues	$ 3.9	$ 10.9	$ 12.9	$ 43.9

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income	$ 14.3	$ (4.7)	$ 19.6	$ 10.5
Other comprehensive income, net of tax:
Unrealized gain on hedging activities		0.1	(0.4)	0.3
Net amount reclassified to earnings		0.1	0.2	0.3
Net realized and unrealized (loss) gain on derivatives		0.2	(0.2)	0.6
Foreign currency translation adjustments	(1.6)	2.2	3.3	(5.3)
Other comprehensive income (loss), net of tax	(1.6)	2.4	3.1	(4.7)
Comprehensive income (loss)	12.7	(2.3)	22.7	5.8
Less: Comprehensive income (loss) attributable to preferred shares of a subsidiary company	1.7	(1.5)	(3.1)	(1.6)
Comprehensive income (loss) attributable to Atlantic Power Corporation	$ 11	$ (0.8)	$ 25.8	$ 7.4

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash provided by operating activities:
Net income	$ 19.6	$ 10.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	48.5	65.7
Gain on disposal of fixed assets and inventory	(0.1)
Other gain	(0.8)
Gain on step acquisition of equity investment		(6.7)
Share-based compensation	1.2	1.8
Asset retirement obligation	1.4
Insurance loss	1
Equity in earnings from unconsolidated affiliates	(34.4)	(33.7)
Distributions from unconsolidated affiliates	41.4	37.4
Unrealized foreign exchange loss (gain)	7.3	(8.6)
Change in fair value of derivative instruments	9.8	(3.3)
Amortization of debt discount, deferred financing costs and operating lease right-of-use assets	6.4	7.4
Change in deferred income taxes	(1.8)	5
Change in other operating balances
Accounts receivable	4.7	19.7
Inventory	0.3	0.8
Prepayments and other assets	(0.2)	3.2
Accounts payable	(1.3)	(1)
Accruals and other liabilities	1.5	(0.4)
Cash provided by operating activities	104.5	97.8
Cash used in investing activities:
Investment in unconsolidated affiliates	(18.7)
Cash paid for acquisition, net of cash received	(10)	(12.8)
Deposit for acquisition		(2.6)
Proceeds from asset sales	1.6
Purchase of property, plant and equipment	(0.9)	(1.5)
Cash used in investing activities:	(28)	(16.9)
Cash used in financing activities:
Proceeds from convertible debenture issuance		92.2
Repayment of convertible debentures	(18.5)	(88.1)
Common share repurchases	(0.8)	(12.3)
Preferred share repurchases	(8)	(8)
Repayment of corporate and project-level debt	(52.3)	(79.5)
Cash payments for vested LTIP units, including amounts withheld for taxes	(2)	(0.8)
Deferred financing costs		(5.1)
Dividends paid to preferred shareholders	(5.5)	(6.3)
Cash used in financing activities:	(87.1)	(107.9)
Net decrease in cash, restricted cash and cash equivalents	(10.6)	(27)
Cash, restricted cash and cash equivalents at beginning of period	70.4	84.9
Cash, restricted cash and cash equivalents at end of period	59.8	57.9
Supplemental cash flow information
Interest paid	27	30.3
Income taxes paid, net	3.5	$ 2.5
Accruals for construction in progress	$ 0.2

Nature of business

Nature of business	9 Months Ended
	Sep. 30, 2019
Nature of business
Nature of business	1. Nature of business General Atlantic Power is an independent power producer that owns power generation assets in eleven states in the United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of September 30, 2019, our portfolio consisted of twenty-one operating projects with an aggregate electric generating capacity of approximately 1,723 megawatts (“MW”) on a gross ownership basis and approximately 1,327 MW on a net ownership basis. Sixteen of the projects are majority‑owned by the Company. 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 (“TSX”) under the symbol “ATP” and on the New York Stock Exchange (“NYSE”) 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 155, 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, 2018. 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, 2019, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2019 and 2018, and our cash flows for the nine months ended September 30, 2019 and 2018, in accordance with U.S. generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included. Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair value of assets acquired and liabilities assumed in purchase accounting, 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, recovery of expected insurance proceeds, 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, 2018. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount. Recently adopted and issued accounting standards Accounting Standards Adopted 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. 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. In July 2018, the FASB issued further authoritative guidance to provide an additional transition method to adopt the new lease requirements by allowing entities to initially apply the requirements by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We elected this transition method. We adopted this guidance and related updates issued in July 2018 and December 2018 on January 1, 2019 and elected certain practical expedients permitted, including the expedient that permits us to retain our existing lease assessment and classification. The Company has elected not to apply the recognition requirements to short-term leases and not to separate non-lease components from associated lease components, for all classes of underlying assets. As the result of our adoption of the guidance, we recorded $6.4 million and $7.2 million of right-of-use assets and lease liabilities, respectively, in the consolidated balance sheets on January 1, 2019. We have no transitional adjustments to our opening retained earnings or our consolidated statements of operations. See Note 16, Leases for further information. 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. We adopted this guidance on January 1, 2019 and it did not have an impact on the consolidated financial statements. In February 2018, the FASB issued authoritative guidance to allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. We adopted this guidance on January 1, 2019 and it did not have an impact on the consolidated financial statements. Accounting Standards Issued In August 2018, the FASB issued authoritative guidance to modify the disclosure requirements on fair value measurement disclosures. The guidance requires removals of certain disclosures, such as the amount of and reasons for transfers between level 1 and level 2 of fair value hierarchy and the policy for timing of transfers between levels. The guidance further requires modifications and additions surrounding the disclosures of level 3 fair value measurements and related unrealized gains and losses. The guidance is effective for fiscal years beginning after December 15, 2019. We do not expect this to have a material impact to the consolidated financial statements upon adoption. In August 2018, the FASB issued authoritative guidance to remove disclosures that no longer are considered cost-beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The scope of the guidance is broad and includes reporting comprehensive income, debt modifications and extinguishments and other sub topics. The guidance is effective for fiscal years beginning after December 15, 2019. We are currently evaluating the impact that adoption will have on our disclosures.

Revenue from contracts

Revenue from contracts	9 Months Ended
	Sep. 30, 2019
Revenue from contracts
Revenue from contracts	2. Revenue from contracts Disaggregation of revenue We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. Each segment contains various power generation projects and performance obligations as described above. For more detailed information about reportable segments, see Note 14, Segment and geographical information . Revenue, receivables and contract liabilities by segment consists of following: Three Months Ended September 30, 2019 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 21.2 $ 3.0 $ 5.0 $ — $ 29.2 Energy capacity revenue 17.2 10.2 10.6 — 38.0 Steam energy and capacity revenue 0.2 — — — 0.2 Ancillary and transmission services 2.8 — 0.6 — 3.4 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue — 0.1 — — 0.1 41.4 13.3 16.2 0.2 71.1 Three Months Ended September 30, 2018 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 16.0 $ 3.3 $ 5.7 $ — $ 25.0 Energy capacity revenue 16.6 10.2 2.7 — 29.5 Steam energy and capacity revenue 2.7 — — — 2.7 Enhanced dispatch contracts — — 6.1 — 6.1 Ancillary and transmission services 1.0 — 0.6 — 1.6 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue — 0.3 — — 0.3 36.3 13.8 15.1 0.2 65.4 Nine Months Ended September 30, 2019 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 74.4 $ 8.9 $ 19.4 $ — $ 102.7 Energy capacity revenue 43.8 21.7 34.3 — 99.8 Steam energy and capacity revenue 0.1 — — — 0.1 Ancillary and transmission services 10.3 — 2.2 — 12.5 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue — (0.4) — — (0.4) 128.6 30.2 55.9 0.7 215.4 Nine Months Ended September 30, 2018 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 62.9 $ 10.1 $ 21.8 $ — $ 94.8 Energy capacity revenue 41.5 22.9 8.5 — 72.9 Steam energy and capacity revenue 8.9 2.8 — — 11.7 Waste heat revenue — — 0.1 — 0.1 Enhanced dispatch contracts — — 21.1 — 21.1 Ancillary and transmission services 3.6 — 6.8 — 10.4 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue — (0.1) — — (0.1) 116.9 35.7 58.3 0.7 211.6 Contract balances The following table provides information about receivables, contract assets and contract liabilities from contracts with customers. September 30, December 31, 2019 2018 Accounts receivables $ 35.3 $ 35.7 Contract liabilities 0.8 0.1 Contract liabilities as of September 30, 2019 include a $0.4 million water license fee at Mamquam, which is a pass-through cost, a $0.3 million fuel reserve fund at Dorchester and a $0.1 million steam sale credit at the San Diego plants. Contract liabilities as of December 31, 2018 include a $0.1 million steam sale credit at the San Diego plants, which was settled subsequently. We had no contract assets at September 30, 2019 and December 31, 2018.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2019
Acquisitions
Asset acquisitions	3. Acquisitions 2019 Transactions South Carolina Biomass Plants On July 31, 2019, we completed the acquisition of two biomass plants in South Carolina from EDF Renewables Inc. The Allendale plant is located in Allendale, South Carolina and has been in service since November 2013. The Dorchester plant is located in Harleyville, South Carolina and has been in service since October 2013 . The two plants are identical in design and each of the plants has a capacity of 20 megawatts . All of the output of the two plants is sold to Santee Cooper, a state-owned utility, under power purchase agreements that run to 2043. The biomass fuel for the plants consists primarily of mill and harvesting residues. We believe the acquisition represents a meaningful addition to the level and length of our existing contracted cash flows. The final consideration for the two plants was $12.6 million. In September 2018, we made a $2.6 million down payment for the acquisition of the plants and paid the remaining due at closing, less working capital adjustments and transaction costs, from discretionary cash and cash equivalents. The South Carolina biomass plants are reflected in our East U.S. segment. See Note 14, Segment and geographic information . The following is a summary of the estimated fair values of the assets acquired and liabilities assumed: Estimated fair values Cash (1) $ 1.4 Accounts receivable 4.3 Inventory 2.9 Property, plant, and equipment 4.0 Intangible assets 2.6 Accounts payable (2.0) Accrued liabilities (0.3) Other liabilities (0.3) Total purchase consideration $ 12.6 (1) The cash acquired was not received until October 2019. The $2.6 million of intangible assets recorded will be amortized straight-line through the remaining life of each plant’s PPA, which expire on October 31, 2043 (Dorchester) and November 18, 2043 (Allendale). AltaGas acquisition On August 13, 2019, we completed our acquisition of the equity ownership interests held by AltaGas Power Holdings (U.S.) Inc. ("AltaGas") in two contracted biomass plants in North Carolina and Michigan. Craven County Wood Energy (“Craven”) is a 48 megawatt (MW) biomass plant in North Carolina that has been in service since October 1990. We acquired a 50% interest in the plant from AltaGas. The remaining 50% interest is held by CMS Energy. Craven has a PPA with Duke Energy Carolinas that will expire on December 31, 2027. The plant burns wood waste, including wood chips, poultry litter, forestry residues, mill waste, bark and sawdust. Grayling Generating Station (“Grayling”) is a 37 MW biomass plant in Michigan that has been in service since June 1992. We acquired a 30% interest in the plant from AltaGas. The remaining interests are held by Fortistar (20%) and CMS Energy (50%). Grayling has a PPA with Consumers Energy, the utility subsidiary of CMS Energy, which will expire on December 31, 2027. The plant burns wood waste from local mills, forestry residues, mill waste and bark. Both plants are operated by an affiliate of CMS Energy. The purchase price totaled $18.7 million in cash consideration inclusive of approximately $0.2 million of acquisition-related transaction costs. Craven and Grayling are limited partnerships. We do not have financial control of the partnerships because decision making is shared and the partners must agree on all major decisions for each of the entities. Accordingly, we account for our ownership in Craven and Grayling under the equity method of accounting because our ownership is between five and fifty percent resulting in Atlantic Power Corporation maintaining more than minor influence over the partnerships’ operating and financing policies. 2018 Transaction Koma Kulshan Associates On June 18, 2018, we purchased a 0.5% general partner interest in Concrete Hydro Partners L.P. (“Concrete”) for $1.1 million from Mt. Baker Corporation with cash on-hand. Prior to the purchase, we owned a 0.5% general partner interest and a 99.0% limited partner interest in Concrete; following the purchase, we own 100% of the entity. Concrete is the owner of a 50% limited partner interest in Koma Kulshan Associates, L.P. (“Koma”). As a result of the purchase, our ownership of Koma increased from 49.75% to 50.00%. With 50.00% percent ownership of Koma, we did not have financial control of the entity as the two owner parties had joint control and substantive participating rights through the structure of the partnership agreement. Accordingly, since we did not obtain control of the project, we continued to account for Koma under the equity method of accounting as of June 30, 2018. The $1.1 million purchase was accounted for as an additional equity method investment in Koma. On July 27, 2018, we acquired the remaining 50% partnership interest in Koma from Covanta Energy Americas, Inc. (“Covanta”) for a total purchase price of $12.5 million including working capital. As a result of this purchase, we own 100% of Koma and consolidated the project on the date of the acquisition. We completed this acquisition because we view hydro projects as assets that will provide us both near and long-term value. The $12.5 million total purchase price was funded with cash on-hand. We assumed operation of the project from Covanta on the acquisition date of July 27, 2018. We recognized a $6.7 million gain recorded in other income in the consolidated statements of operations for the three and nine months ended September 30, 2018 as a result of remeasuring our previous 50% equity interest in Koma. The following is a summary of the estimated fair values of the assets acquired and liabilities assumed: Estimated fair values Cash $ 0.8 Working capital 0.1 Property, plant, and equipment 1.2 Intangible assets 24.8 Deferred tax liability (0.5) Asset retirement obligation (1.8) Total purchase consideration $ 24.6 The $24.8 million of intangible assets recorded will be amortized straight-line through the remaining life of Koma’s PPA, which expires on March 31, 2037.

Changes in accumulated other co

Changes in accumulated other comprehensive income (loss) by component	9 Months Ended
	Sep. 30, 2019
Changes in accumulated other comprehensive income (loss) by component
Changes in accumulated other comprehensive income (loss) by component	4. Changes in accumulated other comprehensive income (loss) by component The changes in accumulated other comprehensive income (loss) by component were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Foreign currency translation Balance at beginning of period $ (141.5) $ (141.8) $ (146.4) $ (134.3) Other comprehensive income (loss): Foreign currency translation adjustments (1) (1.6) 2.2 3.3 (5.3) Balance at end of period $ (143.1) $ (139.6) $ (143.1) $ (139.6) Pension Balance at beginning and end of period $ (1.4) $ (1.6) $ (1.4) $ (1.6) Cash flow hedges Balance at beginning of period $ 1.4 $ 1.5 $ 1.6 $ 1.1 Other comprehensive income (loss): Net change from periodic revaluations — 0.1 (0.4) 0.4 Tax expense — — — (0.1) Total Other comprehensive income (loss) before reclassifications, net of tax — 0.1 (0.4) 0.3 Net amount reclassified to earnings: Interest rate swaps (2) — 0.1 0.2 0.4 Tax benefit (expense) — — — (0.1) Total amount reclassified from accumulated other comprehensive income (loss), net of tax — 0.1 0.2 0.3 Total other comprehensive income (loss) — 0.2 (0.2) 0.6 Balance at end of period $ 1.4 $ 1.7 $ 1.4 $ 1.7 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss). 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, 2019
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	5. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three and nine months ended September 30, 2019 and 2018, respectively, for our proportional ownership interest in equity method investments: Three Months Ended September 30, Nine Months Ended September 30, Operating results 2019 2018 2019 2018 Revenue Frederickson $ 10.3 $ 5.9 $ 26.4 $ 15.7 Orlando Cogen, LP 15.6 15.1 46.4 44.7 Koma Kulshan Associates (1) — — — 1.2 Chambers Cogen, LP 9.4 10.6 30.0 33.4 Craven County Wood Energy, LP (2) 1.8 — 1.8 — Grayling Generating Station, LP (2) 0.8 — 0.8 — 37.9 31.6 105.4 95.0 Project expenses Frederickson 7.5 4.0 20.0 10.7 Orlando Cogen, LP 6.9 7.3 21.5 21.9 Koma Kulshan Associates (1) — — — 0.6 Chambers Cogen, LP 8.9 9.7 26.1 26.9 Craven County Wood Energy, LP (2) 1.6 — 1.6 — Grayling Generating Station, LP (2) 0.5 — 0.5 — 25.4 21.0 69.7 60.1 Project other expenses Frederickson — — — — Orlando Cogen, LP — — — — Koma Kulshan Associates (1) — — — — Chambers Cogen, LP (0.4) (0.4) (1.3) (1.2) Craven County Wood Energy, LP (2) — — — — Grayling Generating Station, LP (2) — — — — (0.4) (0.4) (1.3) (1.2) Project income Frederickson 2.8 1.9 6.4 5.0 Orlando Cogen, LP 8.7 7.8 24.9 22.8 Koma Kulshan Associates (1) — — — 0.6 Chambers Cogen, LP 0.1 0.5 2.6 5.3 Craven County Wood Energy, LP (2) 0.2 — 0.2 — Grayling Generating Station, LP (2) 0.3 — 0.3 — Equity in earnings of unconsolidated affiliates $ 12.1 $ 10.2 $ 34.4 $ 33.7 Distributions from equity method investments (16.0) (10.1) (41.4) (37.4) (Deficit) surplus of earnings of equity method investments, net of distributions $ (3.9) $ 0.1 $ (7.0) $ (3.7) (1) On July 27, 2018, we purchased the remaining 50% of Koma and consolidated the project. (2) On August 13, 2019, we completed the acquisition of the equity ownership interests held by AltaGas Power Holdings (U.S.) Inc. in two contracted biomass plants in North Carolina and Michigan. See Note 3, Asset acquisitions .

Long-term debt

Long-term debt	9 Months Ended
	Sep. 30, 2019
Long-term debt excluding debentures
Long-term debt	6. Long‑term debt Long‑term debt consists of the following: September 30, December 31, 2019 2018 Interest Rate Recourse Debt: Senior secured term loan facility, due 2023 (1) $ 400.0 $ 450.0 LIBOR (2) plus 2.75 % Senior unsecured notes, due June 2036 (Cdn$210.0) 158.6 154.0 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3) 18.7 21.0 LIBOR plus 1.61 % Less: unamortized discount (6.6) (9.0) Less: unamortized deferred financing costs (5.3) (7.2) Less: current maturities (108.1) (68.1) Total long-term debt $ 457.3 $ 540.7 Current maturities consist of the following: September 30, December 31, 2019 2018 Interest Rate Current Maturities: Senior secured term loan facility, due 2023 (1) $ 105.0 $ 65.0 LIBOR (2) plus 2.75 % Cadillac term loan, due 2025 (3) 3.1 3.1 LIBOR plus 1.61 % Total current maturities $ 108.1 $ 68.1 (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) London Interbank Offered Rate (“LIBOR”) cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $364.7 million of the $400.0 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2019. See Note 9, Accounting for derivative instruments and hedging activities for further details. (3) We have entered into interest rate swap agreements to economically fix our exposure to changes in interest rates for this non-recourse debt. See Note 9, Accounting for derivative instruments and hedging activities , for further details.

Convertible debentures

Convertible debentures	9 Months Ended
	Sep. 30, 2019
Convertible Debentures
Long-term debt	7 . Convertible debentures Convertible debentures consist of the following: September 30, December 31, 2019 2018 6.00% Debentures due January 2025 (Series E) (Cdn $115.0 million) $ 86.8 $ 84.3 6.00% Debentures due December 2019 (Series D) (Cdn $24.7 million) — 18.1 Less: Unamortized deferred financing costs (4.1) (4.6) Less: Unamortized discount (3.6) (4.0) Total current and long-term convertible debentures $ 79.1 $ 93.8 On April 10, 2019, we redeemed, in full, the aggregate principal amount of Cdn$24.7 million of the outstanding 6.00% Debentures due December 2019 (the “Series D Debentures”) and paid accrued interest of Cdn$0.4 million. Series E Debentures On January 29, 2018, we closed the Series E Debentures Offering of Cdn$100 million aggregate principal amount of Series E Debentures. We also granted the underwriters the option to purchase up to an additional Cdn$15 million aggregate principal amount of Series E Debentures at any time up to 30 days after the date of closing of the Series E Debentures offering to cover over-allotments. The underwriters exercised that option, for the full Cdn$15 million aggregate principal amount, on February 2, 2018. The Series E Debentures have a maturity date of January 31, 2025. The Series E Debentures bear interest at a rate of 6.00% per year, and are convertible into our common shares at an initial conversion rate of approximately 238.0952 common shares per Cdn$1,000 principal amount, representing a conversion price of Cdn$4.20 per common share. The Series E Debentures may not be redeemed by the Company prior to January 31, 2021 (except in certain limited circumstances following a change of control). On and after January 31, 2021 and prior to January 31, 2023, the Series E Debentures may be redeemed by us, in whole or in part from time to time, on not more than 60 days and not less than 30 days prior notice at a redemption price equal to their principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption, provided that the daily volume-weighted average trading price of our common shares on the Toronto Stock Exchange, averaged for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided, is not less than 125% of the conversion price at the time notice of redemption is given. On and after January 31, 2023 and prior to the maturity date, the Series E Debentures may be redeemed in whole or in part from time to time, on not more than 60 days and not less than 30 days prior notice, at a redemption price equal to their principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption. The Series E Debentures are our direct, subordinated, unsecured obligations and rank equally with the other series of debentures and with all other future subordinated unsecured indebtedness and rank subordinate to all of our existing and future senior indebtedness. On the initial closing date, we received net proceeds from the Series E Debentures offering, after deducting the underwriting fee and expenses, of approximately Cdn$94.7 million. We received an additional Cdn$14.4 million of net proceeds from the exercise of the over-allotment option. On March 2, 2018, we redeemed all of the $42.5 million remaining principal amount of Series C Debentures with the use of a portion of the proceeds from the Series E Debentures Offering. On March 3, 2018, we redeemed Cdn$56. 2 million principal amount of the Series D Debentures with the remaining proceeds from the Series E Debentures Offering. Series E Conversion Option We assessed the conversion option of the Series E Debentures and determined it should be separated from the host instrument and accounted for as an embedded derivative liability as the conversion option is in a currency different from our functional currency. Changes in the fair value of the conversion option derivative are recorded in the consolidated statements of operation. The conversion option derivative was initially measured at fair value ($4.7 million), with the host contract carried at a value equal to the difference between the carrying value of the Series E Debenture and the fair value of the derivative. Accordingly, no gain or loss was recorded on the initial measurement of the derivative. The fair value of the conversion option derivative liability was $2.8 million and $1.2 million at September 30, 2019 and December 31, 2018, respectively. The portion of the proceeds allocated to the separated derivative also created a discount of $4.7 million, which will be amortized to interest expense over the maturity period of the Series E Debentures. For additional information, see Note 9, Accounting for derivative instruments and hedging activities.

Fair value of financial instrum

Fair value of financial instruments	9 Months Ended
	Sep. 30, 2019
Fair value of financial instruments
Fair value of financial instruments	8. Fair value of financial instruments The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2019 and December 31, 2018. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. September 30, 2019 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 58.1 $ — $ — $ 58.1 Restricted cash 1.7 — — 1.7 Derivative instruments asset — 0.1 — 0.1 Total $ 59.8 $ 0.1 $ — $ 59.9 Liabilities: Derivative instruments liability $ — $ 23.5 $ 2.8 $ 26.3 Total $ — $ 23.5 $ 2.8 $ 26.3 December 31, 2018 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 68.3 $ — $ — $ 68.3 Restricted cash 2.1 — — 2.1 Derivative instruments asset — 4.5 — 4.5 Total $ 70.4 $ 4.5 $ — $ 74.9 Liabilities: Derivative instruments liability $ — $ 18.7 $ 1.2 $ 19.9 Total $ — $ 18.7 $ 1.2 $ 19.9 The fair values of our interest rate swaps, foreign exchange forward contracts, natural gas swaps and gas purchase agreements 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, 2019, the credit valuation adjustments resulted in a $1.1 million net increase in fair value, which consists of a $0.1 million pre‑tax gain in other comprehensive income and a $1.0 million gain in change in fair value of derivative instruments. As of December 31, 2018, the credit valuation adjustments resulted in a $1.0 million net increase in fair value, which consists of a $0.1 million pre‑tax gain in other comprehensive income and a $0.9 million gain in change in fair value of derivative instruments. The conversion option derivative for the Series E Debentures is classified within Level 3 of the fair value hierarchy. The significant unobservable inputs used in developing fair value include the volatility of our common shares and the fair value of the host contract, which is derived from recent similar convertible debenture offerings from peer companies. A discounted cash flow valuation technique is utilized to calculate the fair value of the conversion option derivative. The following table reconciles, for the nine months ended September 30, 2019 and 2018, the beginning and ending balances for the conversion option derivative that is recognized at fair value in the consolidated financial statements, using significant unobservable inputs: Fair value Nine Months Ended September 30, 2019 Beginning balance of liability at January 1, 2019 $ 1.2 Total unrealized loss 1.5 Currency transaction loss 0.1 Ending balance of liability at September 30, 2019 $ 2.8 Fair value Nine Months Ended September 30, 2018 Balance of liability at inception (January 2018) $ 4.7 Total unrealized loss 0.2 Ending balance of liability at September 30, 2018 $ 4.9 For cash and cash equivalents, accounts and other receivables, accounts payable and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments and is classified as Level 1 within the fair value hierarchy.

Accounting for derivative instr

Accounting for derivative instruments and hedging activities	9 Months Ended
	Sep. 30, 2019
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	9. Accounting for derivative instruments and hedging activities We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts. Gas purchase and sale agreements We have a gas purchase agreement at our Nipigon project that expires on December 31, 2022 under which we purchase a minimum of 6,500 Gigajoules (“Gj”) of natural gas per day at a price of Cdn$4.57 per Gj. This agreement does not qualify for the normal purchase normal sales (“NPNS”) exemption and is accounted for as a derivative financial instrument because we could not conclude that it is probable that this contract will not settle net and will result in physical delivery. This derivative financial instrument is recorded in the consolidated balance sheets at fair value and the changes in its fair market value are recorded in the consolidated statements of operations. We also have a corresponding gas sales agreement at Nipigon, whereby 6,500 Gj of natural gas per day is sold at the spot market price. This contract is not accounted for as a derivative. On April 23, 2019, we also entered into natural gas purchase agreements at our Morris project for approximately 700,000 MMBtu to effectively mitigate seasonal fluctuations of future natural gas prices from January 2020 through February 2020. This contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value. Changes in the fair market value of this contract are recorded in the consolidated statement of operations. Natural gas swaps Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. We have entered into various natural gas swaps to effectively fix the price of 17.4 million Mmbtu of future natural gas purchases at our Orlando project, which is approximately 100% of our share of the expected natural gas purchases in 2019 through 2023. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2019. 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. At September 30, 2019, these agreements totaled $364.7 million notional amount of the remaining $400.0 million aggregate principal amount of borrowings under the senior secured term loan facility (“Term Loan Facility”). These interest rate swap agreements expire at various dates through March 31, 2022. Borrowings under the $700.0 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 2.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 3.75% all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount. The weighted average rate of these swap agreements is 1.27%, resulting in an all-in rate of approximately 4.02% for $364.7 million of the Term Loan Facility. In January 2018, APLP Holdings entered into additional interest rate swap agreements. For the period beginning October 1, 2019 through December 31, 2020, we mitigated exposure to changes in interest rates for $200 million notional amount at a one-month LIBOR fixed rate of 2.42%. In May 2019, APLP Holdings entered into additional interest rate swap agreements. For the period beginning December 31, 2019 through December 31, 2020, we mitigated exposure to changes in interest rates for $60 million notional amount at a one-month LIBOR fixed rate of 2.17% and for the period beginning December 31, 2020 through March 31, 2022, we mitigated exposure to changes in interest rates for $80 million notional amount at a one-month LIBOR fixed rate of 1.97%. 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 income (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 due June 23, 2036 (“MTNs”). Principal and interest payments for our senior secured term loans 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. 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. As of September 30, 2019, we have no foreign currency forward contracts. 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, 2019 and December 31, 2018: September 30, December 31, Units 2019 2018 Natural gas swaps Natural Gas (MMbtu) 17.4 16.3 Gas purchase agreements Natural Gas (Gigajoules) 7.0 9.0 Interest rate swaps Interest (US$) 476.7 616.6 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, 2019 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.5 Interest rate swaps long-term — 1.2 Total derivative instruments designated as cash flow hedges — 1.7 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 1.4 Interest rate swaps long-term — 2.4 Natural gas swaps current 0.1 1.5 Natural gas swaps long-term — 3.6 Gas purchase agreements current — 4.6 Gas purchase agreements long-term — 8.3 Convertible debenture conversion option — 2.8 Total derivative instruments not designated as cash flow hedges 0.1 24.6 Total derivative instruments $ 0.1 $ 26.3 December 31, 2018 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.4 Interest rate swaps long-term — 1.0 Total derivative instruments designated as cash flow hedges — 1.4 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 4.2 — Interest rate swaps long-term 0.3 — Natural gas swaps current — 0.1 Natural gas swaps long-term — 1.4 Gas purchase agreements current — 2.8 Gas purchase agreements long-term — 13.0 Convertible debenture conversion option — 1.2 Total derivative instruments not designated as cash flow hedges 4.5 18.5 Total derivative instruments $ 4.5 $ 19.9 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, 2019 Swaps Accumulated OCI balance at July 1, 2019 $ Change in fair value of cash flow hedges — Realized from OCI during the period — Accumulated OCI balance at September 30, 2019 $ Interest Rate Three Months Ended September 30, 2018 Swaps Accumulated OCI balance at July 1, 2018 $ Change in fair value of cash flow hedges 0.1 Realized from OCI during the period Accumulated OCI balance at September 30, 2018 $ Interest Rate Nine Months Ended September 30, 2019 Swaps Accumulated OCI balance at January 1, 2019 $ 1.6 Change in fair value of cash flow hedges (0.4) Realized from OCI during the period 0.2 Accumulated OCI balance at September 30, 2019 $ Interest Rate Nine Months Ended September 30, 2018 Swaps Accumulated OCI balance at January 1, 2018 $ 1.1 Change in fair value of cash flow hedges 0.3 Realized from OCI during the period 0.3 Accumulated OCI balance at September 30, 2018 $ 1.7 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 2019 2018 2019 2018 Gas purchase agreements Fuel $ 2.1 $ 0.8 6.1 $ 2.5 Natural gas swaps Fuel 0.6 0.1 0.5 0.9 Interest rate swaps Interest, net (0.9) (0.6) (4.6) (1.7) The following table summarizes the unrealized (loss) gain resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges: Classification of (loss) gain Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2019 2018 2019 2018 Natural gas swaps Change in fair value of derivatives $ (1.0) $ (0.2) $ (3.5) $ (0.7) Gas purchase agreements Change in fair value of derivatives 3.7 0.5 3.5 2.1 Interest rate swaps Change in fair value of derivatives (1.6) (0.3) (8.3) 2.2 $ 1.1 $ — (8.3) 3.6 Convertible debenture conversion option Other (income) expense, net (0.3) (2.6) 1.5 (0.2) Foreign currency forwards Foreign exchange (gain) loss $ — $ (0.4) $ — $ 0.2 X

Income taxes

Income taxes	9 Months Ended
	Sep. 30, 2019
Income tax benefit
Income tax benefit	10. Income taxes Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Current income tax expense $ 1.3 $ 0.6 $ 4.2 $ 2.8 Deferred income tax (benefit) expense (1.1) 3.0 (1.8) 4.9 Total income tax expense, net $ 0.2 $ 3.6 $ 2.4 $ 7.7 For the three and nine months ended September 30, 2019 and 2018 Income tax expense for the three months ended September 30, 2019 was $0.2 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $3.9 million. The primary items impacting the tax rate for the three months ended September 30, 2019 was a net decrease to our valuation allowances of $4.4 million, consisting of $1.0 million of decreases in Canada and $3.4 million of decreases in the United States due to the utilization of net operating losses. These items were partially offset by $0.5 million relating to withholding and state taxes and $0.2 million of other permanent differences. Income tax expense for the three months ended September 30, 2018 was $3.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 27%, was $0.3 million. On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law, making significant changes to the U.S. Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"). Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017 which have been reflected in our 2017 year-end financials, limitation on the deduction of net business interest expense, and base erosion and anti-abuse tax. Based on estimates as of the date of this filing, we will not be subject to the base erosion and anti-abuse tax. Our interest expense deduction may be limited, but will not have a material impact on cash taxes. The primary items impacting the tax rate for the three months ended September 30, 2018 were $0.2 million relating to foreign exchange and a net increase to the Company's valuation allowances of $3.7 million, consisting of $3.7 million of increases in Canada due to losses and no changes in the United States for the period. Income tax expense for the nine months ended September 30, 2019 was $2.4 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $5.9 million. The primary items impacting the tax rate for the three months ended September 30, 2019 was a net decrease to our valuation allowances of $4.5 million, consisting of $4.4 million of increases in Canada and $8.9 million of decreases in the United States due to the utilization of net operating losses. In addition, the rate was further impacted by $1.0 million relating to foreign exchange. These items were partially offset by $1.3 million relating to withholding and state taxes and $0.7 million of other permanent differences. Income tax expense for the nine months ended September 30, 2018 was $7.7 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $4.7 million. The primary items impacting the tax rate for the nine months ended September 30, 2018 were a net increase to our valuation allowances of $4.5 million, consisting of $4.5 million of increases in Canada related to losses and no changes in the United States for the period. In addition, the rate was further impacted by $0.3 million relating to foreign exchange, $0.3 million relating to taxes and $0.1 million of other permanent differences. These items were partially offset by $1.3 million related to capital loss on intercompany notes and $0.9 million relating to changes in tax rates. As of September 30, 2019, we have recorded a valuation allowance of $135.2 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 timing on the reversal of deferred tax liabilities and 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, 2019
Equity compensation plans
Equity compensation plans	11. Equity compensation plans Long‑term incentive plan (“LTIP”) The following table summarizes the changes in outstanding LTIP notional units during the nine months ended September 30, 2019: Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2018 3,952,201 2.09 Granted 1,724,081 2.72 Vested and redeemed (1,864,989) 2.06 Forfeitures (15,108) 2.22 Outstanding at September 30, 2019 3,796,185 $ 2.39 On March 29, 2019, the compensation committee of our board of directors determined that all notional shares granted under the LTIP held by non-officer employees will be settled in cash following vesting, rather than two-thirds in common shares and one-third in cash. As a result of the modification, all future vesting of notional units for this employee group will be settled in cash. Prior to the modification, vested notional units were settled two-thirds in common shares and one-third in cash, which was utilized to pay employee withholding tax. The portion of LTIP grants settled in common shares was accounted for as equity awards. On the modification date, the equity awards were reclassified as liability awards and a liability equal to the modification-date fair value was recognized. The impact of the modification was not material. Cash payments made for vested notional units for the nine months ended September 30, 2019 and 2018 were $2.0 million and $0.8 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.1 million and $3.1 million for the three and nine months ended September 30, 2019 and $1.1 million and $2.6 million for the three and nine months ended September 30, 2018, respectively. Transition Equity Participation Agreement We also have 269,902 transition notional shares outstanding at September 30, 2019 under the Transition Equity Participation Agreement with James J. Moore, Jr. These notional shares 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 earnings (los

Basic and diluted earnings (loss) per share	9 Months Ended
	Sep. 30, 2019
Basic and diluted earnings (loss) per share
Basic and diluted earnings (loss) per share	12. Basic and diluted earnings (loss) per share Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to Atlantic Power Corporation by weighted average common shares outstanding during their respective periods. Shares issued and shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings (loss) per share is computed in a manner consistent with that of basic earnings (loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period . 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 earnings (loss) per share 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. The outstanding equity compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator, when dilutive, for purposes of computing diluted earnings per share under the treasury stock method . The following table sets forth the calculation of basic and diluted earnings (loss) per share for the three and nine months ended September 30, 2019 and 2018: Three Months Ended September 30, Nine Months Ended September 30, Basic 2019 2018 2019 2018 Numerator: Income (loss) attributable to Atlantic Power Corporation $ 12.6 $ (3.2) $ 22.7 $ 12.1 Denominator: Weighted average basic shares outstanding 109.4 111.1 109.4 112.8 Basic earnings (loss) per share attributable to Atlantic Power Corporation $ 0.12 $ (0.03) $ 0.21 $ 0.11 Diluted Numerator: Net income (loss) attributable to Atlantic Power Corporation $ 12.6 $ (3.2) $ 22.7 $ 12.1 Add: convertible debenture interest expense 1.0 — 3.1 3.5 13.6 (3.2) 25.8 15.6 Denominator: Weighted average basic shares outstanding 109.4 111.1 109.4 112.8 Convertible debentures 27.4 — 27.9 27.3 Share-based compensation 1.0 — 1.0 2.2 137.8 111.1 138.3 142.3 Diluted earnings (loss) per share attributable to Atlantic Power Corporation $ 0.10 $ (0.03) $ 0.19 $ 0.11 The following table summarizes our outstanding instruments that are anti-dilutive and were not included in the computation of our diluted earnings (loss) per share : Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Share-based compensation — 2.2 — — Convertible debentures — 29.1 — — Total — 31.3 — —

Equity

Equity	9 Months Ended
	Sep. 30, 2019
Equity
Equity	13. Equity The following tables provide reconciliations 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 three and nine months ended September 30, 2019 and 2018: Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at June 30, 2019 $ 1,260.9 $ (1,111.5) $ (141.5) $ 182.9 $ 190.8 Net income — 12.6 — 1.7 14.3 Share-based compensation 0.4 — — — 0.4 Common share repurchases — — — — — Preferred share repurchases — — — (0.1) (0.1) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) — — — (0.8) (0.8) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.348125 per share) — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.364858 per share) — — — (0.4) (0.4) Realized and unrealized loss on hedging activities, — — — — — Foreign currency translation adjustments — — (1.6) — (1.6) Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.10) $ 182.7 $ 202.0 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at June 30, 2018 $ 1,266.8 $ (1,143.2) $ (141.9) $ 206.3 $ 187.9 Net (loss) income — (3.2) — (1.5) (4.7) Share-based compensation 0.7 — — — 0.7 Common share repurchases (3.1) — — — (3.1) Preferred share repurchases — — — (3.5) (3.5) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) — — — (1.0) (1.0) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.348125 per share) — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.333654 per share) — — — (0.4) (0.4) Realized and unrealized gain on hedging activities, — — 0.2 — 0.2 Foreign currency translation adjustments — — 2.2 — 2.2 Balance at September 30, 2018 $ 1,264.5 $ (1,146.5) $ (139.5) $ 199.3 $ 177.8 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at January 1, 2019 $ 1,260.9 $ (1,121.6) $ (146.2) $ 199.3 $ 192.4 Net income (loss) — 22.7 — (3.1) 19.6 Share-based compensation 1.2 — — — 1.2 Common share repurchases (0.8) — — — (0.8) Preferred share repurchases — — — (8.0) (8.0) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — (2.6) (2.6) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.044375 per share) — — — (1.8) (1.8) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.091448 per share) — — — (1.1) (1.1) Realized and unrealized loss on hedging activities, — — (0.2) — (0.2) Foreign currency translation adjustments — — 3.3 — 3.3 Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 182.7 $ 202.0 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at January 1, 2018 $ 1,274.8 $ (1,158.4) $ (134.8) $ 215.2 $ 196.8 Net income (loss) — 12.1 — (1.6) 10.5 Share-based compensation 1.8 — — — 1.8 Common share repurchases (12.3) — — — (12.3) Preferred share repurchases — — — (8.0) (8.0) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — (3.2) (3.2) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.044375 per share) — — — (1.9) (1.9) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.977188 per share) — — — (1.2) (1.2) Realized and unrealized gain on hedging activities, — — 0.6 — 0.6 Foreign currency translation adjustments — — (5.3) — (5.3) Balance at September 30, 2018 $ 1,264.5 $ (1,146.5) $ (139.5) $ 199.3 $ 177.8 Share Repurchase Program On December 31, 2018, we commenced a new Normal Course Issuer Bid (“NCIB”) for each of our Series D and Series E Debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd. (“APPEL”), our wholly-owned subsidiary. The NCIBs expire on December 30, 2019 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the new NCIBs. Under the NCIB, we may purchase up to a total of 10,623,464 common shares based on 10% of our public float as of December 17, 2018 and we are limited to daily purchases of 10,300 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. All purchases made under the NCIBs will be made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the New York Stock Exchange (NYSE) in compliance with Rule 10b-18 under the U.S. Securities Exchange Act of 1934, as amended, or other designated exchanges and published marketplaces in the U.S. in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval. For the nine months ended September 30, 2019, we repurchased and cancelled 0.4 million common shares. In the nine months ended September 30, 2019, we repurchased and cancelled 427,500 shares of 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”), 100,377 shares of 7.0% Cumulative Rate Preferred Shares Series 2 (the “Series 2 Shares”) and 148,311 shares of Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of APPEL at a total cost of $8.0 million . With these repurchases, we reached the 10% limit on Series 1 and Series 3 repurchases under this NCIB. As a result of the repurchase, an $8.6 million loss was attributed to the preferred shares of a subsi diary company in the Consolidated Statements of Operations for the nine months ended September 30, 2019. The NCIB permits the Company to repurchase common and preferred shares and convertible debentures. In addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our convertible debentures and our APPEL preferred shares through open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the U.S. Securities Exchange Act of 1934, as amended, NCIBs, issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account our then current cash position and then anticipated cash obligations or business opportunities.

Segment and geographic informat

Segment and geographic information	9 Months Ended
	Sep. 30, 2019
Segment and geographic information
Segment and geographic information	14. Segment and geographic information We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We 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, impairment charges, insurance loss (gain), other (income) expenses 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. A reconciliation of Project Adjusted EBITDA to net income for the three and nine months ended September 30, 2019 and 2018 is included in the tables below: Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2019 Project revenues $ 41.4 $ 13.3 $ 16.2 $ 0.2 $ 71.1 Segment assets 588.6 157.4 176.4 65.6 988.0 Project Adjusted EBITDA $ 31.4 $ 11.6 $ 6.1 $ (0.2) $ 48.9 Change in fair value of derivative instruments 1.1 (3.7) 1.6 (1.0) Depreciation and amortization 11.7 5.7 2.8 — 20.2 Interest, net 0.8 — — — 0.8 Insurance loss 1.0 — — — 1.0 Other project (income) expense — — (0.1) 0.1 — Project income (loss) 16.8 5.9 7.1 (1.9) 27.9 Administration — — — 5.5 5.5 Interest expense, net — — — 10.9 10.9 Foreign exchange gain — — — (2.8) (2.8) Other income, net — — — (0.2) (0.2) Income (loss) before income taxes 16.8 5.9 7.1 (15.3) 14.5 Income tax expense — — — 0.2 0.2 Net income (loss) $ 16.8 $ 5.9 $ 7.1 $ (15.5) $ 14.3 Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2018 Project revenues $ 36.3 $ 13.8 $ 15.1 $ 0.2 $ 65.4 Segment assets 607.2 182.2 194.9 74.3 1,058.6 Project Adjusted EBITDA $ 25.5 $ 11.5 $ 8.3 $ 0.1 $ 45.4 Change in fair value of derivative instruments 0.5 — (0.8) 0.3 — Depreciation and amortization 11.6 5.5 7.9 — 25.0 Interest, net 0.7 (1.3) — — (0.6) Other project (income) expense — (5.3) — 0.1 (5.2) Project income (loss) 12.7 12.6 1.2 (0.3) 26.2 Administration — — — 5.7 5.7 Interest expense, net — — — 14.6 14.6 Foreign exchange loss — — — 4.5 4.5 Other expense, net — — — 2.5 2.5 Income (loss) before income taxes 12.7 12.6 1.2 (27.6) (1.1) Income tax expense — — — 3.6 3.6 Net income (loss) $ 12.7 $ 12.6 $ 1.2 $ (31.2) $ (4.7) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2019 Project revenues $ 128.6 $ 30.2 $ 55.9 $ 0.7 $ 215.4 Segment assets 588.6 157.4 176.4 65.6 988.0 Project Adjusted EBITDA $ 100.8 $ 24.5 $ 28.0 $ (0.1) $ 153.2 Change in fair value of derivative instruments 3.4 — (3.3) 8.2 8.3 Depreciation and amortization 34.8 17.3 8.4 0.1 60.6 Interest, net 2.3 (0.3) — — 2.0 Insurance loss 1.0 — — — 1.0 Other project expense — 1.2 — — 1.2 Project income (loss) 59.3 6.3 22.9 (8.4) 80.1 Administration — — — 17.3 17.3 Interest expense, net — — — 33.0 33.0 Foreign exchange loss — — — 7.1 7.1 Other expense, net — — — 0.7 0.7 Net income (loss) before income taxes 59.3 6.3 22.9 (66.5) 22.0 Income tax expense — — — 2.4 2.4 Net income (loss) $ 59.3 $ 6.3 $ 22.9 $ (68.9) $ 19.6 Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2018 Project revenues $ 116.9 $ 35.7 $ 58.3 $ 0.7 $ 211.6 Segment assets 607.2 182.2 194.9 74.3 1,058.6 Project Adjusted EBITDA $ 89.8 $ 16.9 $ 31.5 $ 0.3 $ 138.5 Change in fair value of derivative instruments 0.8 — (2.2) (2.1) (3.5) Depreciation and amortization 34.8 19.2 23.9 0.1 78.0 Interest, net 2.7 — — — 2.7 Other project income — (6.7) — — (6.7) Project income 51.5 4.4 9.8 2.3 68.0 Administration — — — 17.9 17.9 Interest expense, net — — — 40.7 40.7 Foreign exchange gain — — — (9.1) (9.1) Other expense, net — — — 0.3 0.3 Net income (loss) before income taxes 51.5 4.4 9.8 (47.5) $ 18.2 Income tax expense — — — 7.7 7.7 Net income (loss) $ 51.5 $ 4.4 $ 9.8 $ (55.2) $ 10.5 The table below provides information, by country, about our consolidated operations for each of the three and nine months ended September 30, 2019 and 2018 and Property, Plant & Equipment as of September 30, 2019 and December 31, 2018, 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 Project Revenue Property, Plant and Three Months Ended Nine Months Ended Equipment, net of September 30, September 30, accumulated depreciation 2019 2018 2019 2018 September 30, 2019 December 31, 2018 United States $ 54.9 $ 50.3 $ 159.5 $ 153.3 $ 354.9 $ 396.5 Canada 16.2 15.1 55.9 58.3 150.8 153.0 Total $ 71.1 $ 65.4 $ 215.4 $ 211.6 $ 505.7 $ 549.5 Concentration risk Georgia Power Company, Independent Electricity System Operator (“IESO”), Southern California Edison and Equistar Chemicals, LP provided 16.2%, 11.2%, 10.5% and 10.4%, respectively, of total consolidated revenues for the three months ended September 30, 2019. Georgia Power Company, Southern California Edison and Equistar Chemicals, LP provided 17.2%, 12.7% and 12.4%, respectively, of total consolidated revenues for the three months ended September 30, 2018. Niagara Mohawk, Georgia Power Company, IESO and Equistar Chemicals, LP provided 18.4%, 12.1%, 12.1% and 11.6%, respectively, of total consolidated revenues for the nine months ended September 30, 2019. Niagara Mohawk, BC Hydro, Georgia Power Company and Equistar Chemicals, LP provided 13.8%, 12.6%, 12.0% and 11.8%, respectively, of total consolidated revenues for the nine months ended September 30, 2018. Niagara Mohawk purchases electricity from the Curtis Palmer project in the East U.S. segment, IESO purchases electricity from the Calstock, Tunis and Nipigon projects in the Canada segment, Southern California Edison purchases electricity from the Oxnard project in the West U.S. segment, Equistar Chemicals, LP purchases electricity from the Morris project in the East 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, 2019
Guarantees and Contingencies
Guarantees and Contingencies	15. 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 Fire at Cadillac project On September 22, 2019, the Cadillac project experienced a malfunction in its steam turbine that began a cascade of events, sparking a fire. The fire was contained by the local fire department and did not result in any injuries or known environmental violations. Physical Damage The biomass plant suffered significant damage to the turbine, generator and other components in that area of the plant as a result of the fire. The boiler, cooling tower, fuel pile and fuel handling equipment were not affected. Cadillac is expected to be offline for an extended period. We are currently working to ascertain the full scope of damage to the plant and the cause of the fire. Our insurance covers the repair or replacement of the assets that experienced loss or damage. The property damage deductible under the policies insuring the Cadillac assets is $1.0 million. Based on current estimates to date, losses have exceeded the deductible under these insurance policies. Business Interruption Our insurance policies also provide coverage for interruption to Cadillac’s business, including lost profits. The policies also reimburse for other expenses and costs it has incurred relating to the damages and loss it has suffered. The policies provide for coverage during the reconstruction period. At this time, we are unable to determine the Cadillac plant’s expected return to service date. The business interruption deductible under the policies insuring the Cadillac assets is 45 days of lost production, which we estimate is an approximate $1.5 million impact to cash flows from operations. Impact The fire resulted in a triggering event to test the Cadillac’s asset group for long-lived asset impairment. Based on our expectation of insurance recoveries and a full repair of the plant, we did not record an impairment at Cadillac because its estimated undiscounted future cash flows exceed the carrying value of the asset group at September 30, 2019. Because the plant experienced significant damage and it is probable that insurance proceeds will be received in order to repair the facility, we applied accounting for gains and losses on involuntary conversions . Based on current loss estimates and expenses incurred through quarter-end, we recorded a $25 million write-down of Cadillac’s property, plant and equipment and a $0.2 million write-down of capital spares inventory. This is our best estimate at the time the loss was incurred, but may be subject to future adjustments based on actual experience of replacement cost. We also recorded a corresponding insurance receivable ($24.2 million) as a component of other assets, less the $1.0 million property damage deductible, which was recorded as a charge to other project income, because we believe that it is probable we will receive insurance recoveries up to our estimated plant write-down. As the plant is repaired, any costs incurred will be capitalized to property, plant and equipment. Insurance proceeds in excess of the net book value of the PP&E write-down, if any, would be recorded as a gain in the period those proceeds are received. We will begin to record business interruption insurance as a gain contingency after the 45-day deductible period expires and we either receive proceeds from our insurer or confirmation of pending proceeds. The Cadillac biomass plant is reflected in our East U.S. segment. General 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, 2019.

Leases

Leases	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Leases disclosure	16. Leases Real estate leases and equipment leases We lease our office properties and equipment under operating leases expiring on various dates through 2024. Certain operating lease agreements include provisions for scheduled rent increases over their lease terms. We recognize the effects of these scheduled rent increases on a straight-line basis over the lease term. One of our leased office properties is sub-leased to third parties. The sub-lease is an operating lease and the rental income received is recorded net of rental expense in the Consolidated Statements of Operations. On January 1, 2019, we implemented FASB ASU No. 2016-02, Leases (Topic 842). To calculate lease liabilities on the implementation date, we utilized an incremental borrowing rate of 3.75%, which is our minimum all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount. Operating Leases Operating Lease Liability As of September 30, 2019 Months remaining on the Lease Weighted average in months Real Estate and Equipment leases $6.5 151.0 48.4 The following table presents the components of lease expense. Three Months Ended September 30, Nine Months Ended September 30, 2019 2019 Lease cost: (1) Operating lease cost $ 0.5 $ 1.3 Sublease income (0.3) (0.9) Total lease cost $ 0.2 $ 0.4 (1) Short-term lease costs and finance lease costs are immaterial to the Company. The following table presents operating lease maturities and a reconciliation of the undiscounted cash flows to operating lease liabilities. Lease Income from Net lease Payments subleasing payments 2019 $ 0.5 $ (0.3) $ 0.2 2020 1.7 (1.1) 0.6 2021 1.7 (1.1) 0.6 2022 1.7 (1.1) 0.6 2023 1.2 (0.7) 0.5 Thereafter 0.1 — 0.1 Total operating lease payments $ 6.9 $ (4.3) $ 2.6 Less: present value discount (0.4) Total operating lease liabilities $ 6.5 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) : Operating cash flows from operating leases $ (1) Cash flows from finance leases are immaterial to the Company Lease assets obtained in exchange for new lease liabilities (non-cash): Operating $ Finance Weighted average remaining lease term (in years): Operating leases Finance leases Weighted average discount rate - operating leases % Weighted average discount rate - finance leases % The following table presents future minimum lease payments under operating leases, which at inception had a non-cancelable term of more than one year, as previously reported under the old lease standard on our 2018 Annual Report on Form 10-K. Lease Income from Net lease Payments subleasing payments 2019 $ 1.7 (1.1) $ 0.6 2020 1.4 (1.1) 0.3 2021 1.4 (1.1) 0.3 2022 1.4 (1.1) 0.3 2023 0.8 (0.7) 0.1 Thereafter — — — $ 6.7 (5.1) $ 1.6 We have no lease transactions with related parties. We did not utilize practical expedients for separating lease components for all operating leases that we lease. PPA Leases We have entered into PPAs to sell power at predetermined rates. PPAs were assessed as to whether they contain leases, which convey to the counterparty the right to control the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either operating or finance leases. We recognize lease income consistent with the recognition of energy sales and capacity revenue. When energy is delivered and capacity is provided, we recognize lease income as a component of energy sales and capacity revenue. Finance income related to leases or arrangements accounted for as finance leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income (loss) over the lease term. We elected the practical expedient that permits us to retain our existing lease assessment and classification. As of September 30, 2019, we have twelve PPAs accounted for as operating leases and one PPA accounted as a direct financing lease among our twenty-one projects in operation. No extension terms exist for our PPAs accounted for as leases and the remaining lease term varies from eight months to twenty-four years. At September 30, 2019, a net investment in lease of $1.5 million is recorded in current assets on the consolidated balance sheets for our direct financing lease. The following table provides lease income recorded as energy and capacity sales by segment from PPAs accounted for as operating leases: Rental Income from operating leases Rental Income from operating leases Three Months Ended Nine Months Ended September 30, September 30, 2019 2018 2019 2018 East U.S. $ 27.1 $ 20.6 $ 83.1 $ 68.5 West U.S. 5.7 5.9 17.0 15.3 Mamquam 2.4 2.5 8.4 9.6 Moresby Lake — 0.1 0.8 1.2 Williams Lake 2.4 3.2 10.2 15.9 Calstock 3.5 3.3 10.6 10.4 Tunis 1.2 — 3.3 — Canada 9.5 9.0 33.3 37.1 $ 42.3 $ 35.5 $ 133.4 $ 120.9 For certain of our PPAs accounted for as leases, the lessee has the option to purchase the plant. In May 2019, we entered into an agreement to sell Manchief to Public Service Company of Colorado (“PSCo”) following the expiration of the PPA in April 2022 for $45.2 million subject to working capital and other customary adjustments. BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.

Nature of business (Policies)

Nature of business (Policies)	9 Months Ended
	Sep. 30, 2019
Summary of significant accounting policies
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, 2018. 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, 2019, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2019 and 2018, and our cash flows for the nine months ended September 30, 2019 and 2018, in accordance with U.S. generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
Use of estimates	Use of estimates The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair value of assets acquired and liabilities assumed in purchase accounting, 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, recovery of expected insurance proceeds, 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, 2018. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
Recently adopted and issued accounting standards	Recently adopted and issued accounting standards Accounting Standards Adopted 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. 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. In July 2018, the FASB issued further authoritative guidance to provide an additional transition method to adopt the new lease requirements by allowing entities to initially apply the requirements by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We elected this transition method. We adopted this guidance and related updates issued in July 2018 and December 2018 on January 1, 2019 and elected certain practical expedients permitted, including the expedient that permits us to retain our existing lease assessment and classification. The Company has elected not to apply the recognition requirements to short-term leases and not to separate non-lease components from associated lease components, for all classes of underlying assets. As the result of our adoption of the guidance, we recorded $6.4 million and $7.2 million of right-of-use assets and lease liabilities, respectively, in the consolidated balance sheets on January 1, 2019. We have no transitional adjustments to our opening retained earnings or our consolidated statements of operations. See Note 16, Leases for further information. 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. We adopted this guidance on January 1, 2019 and it did not have an impact on the consolidated financial statements. In February 2018, the FASB issued authoritative guidance to allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. We adopted this guidance on January 1, 2019 and it did not have an impact on the consolidated financial statements. Accounting Standards Issued In August 2018, the FASB issued authoritative guidance to modify the disclosure requirements on fair value measurement disclosures. The guidance requires removals of certain disclosures, such as the amount of and reasons for transfers between level 1 and level 2 of fair value hierarchy and the policy for timing of transfers between levels. The guidance further requires modifications and additions surrounding the disclosures of level 3 fair value measurements and related unrealized gains and losses. The guidance is effective for fiscal years beginning after December 15, 2019. We do not expect this to have a material impact to the consolidated financial statements upon adoption. In August 2018, the FASB issued authoritative guidance to remove disclosures that no longer are considered cost-beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The scope of the guidance is broad and includes reporting comprehensive income, debt modifications and extinguishments and other sub topics. The guidance is effective for fiscal years beginning after December 15, 2019. We are currently evaluating the impact that adoption will have on our disclosures.

Revenue from contracts (Tables)

Revenue from contracts (Tables)	9 Months Ended
	Sep. 30, 2019
Revenue from contracts
Schedule of disaggregation of revenue	Three Months Ended September 30, 2019 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 21.2 $ 3.0 $ 5.0 $ — $ 29.2 Energy capacity revenue 17.2 10.2 10.6 — 38.0 Steam energy and capacity revenue 0.2 — — — 0.2 Ancillary and transmission services 2.8 — 0.6 — 3.4 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue — 0.1 — — 0.1 41.4 13.3 16.2 0.2 71.1 Three Months Ended September 30, 2018 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 16.0 $ 3.3 $ 5.7 $ — $ 25.0 Energy capacity revenue 16.6 10.2 2.7 — 29.5 Steam energy and capacity revenue 2.7 — — — 2.7 Enhanced dispatch contracts — — 6.1 — 6.1 Ancillary and transmission services 1.0 — 0.6 — 1.6 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue — 0.3 — — 0.3 36.3 13.8 15.1 0.2 65.4 Nine Months Ended September 30, 2019 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 74.4 $ 8.9 $ 19.4 $ — $ 102.7 Energy capacity revenue 43.8 21.7 34.3 — 99.8 Steam energy and capacity revenue 0.1 — — — 0.1 Ancillary and transmission services 10.3 — 2.2 — 12.5 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue — (0.4) — — (0.4) 128.6 30.2 55.9 0.7 215.4 Nine Months Ended September 30, 2018 Un-Allocated Consolidated East U.S. West U.S. Canada Corporate Total Project revenue: Energy sales $ 62.9 $ 10.1 $ 21.8 $ — $ 94.8 Energy capacity revenue 41.5 22.9 8.5 — 72.9 Steam energy and capacity revenue 8.9 2.8 — — 11.7 Waste heat revenue — — 0.1 — 0.1 Enhanced dispatch contracts — — 21.1 — 21.1 Ancillary and transmission services 3.6 — 6.8 — 10.4 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue — (0.1) — — (0.1) 116.9 35.7 58.3 0.7 211.6
Schedule of receivables, contract assets and contract liabilities from contracts	September 30, December 31, 2019 2018 Accounts receivables $ 35.3 $ 35.7 Contract liabilities 0.8 0.1

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2019
South Carolina Biomass Plant
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of preliminary purchase price allocation for the business combination	Estimated fair values Cash (1) $ 1.4 Accounts receivable 4.3 Inventory 2.9 Property, plant, and equipment 4.0 Intangible assets 2.6 Accounts payable (2.0) Accrued liabilities (0.3) Other liabilities (0.3) Total purchase consideration $ 12.6
Koma Kulshan Associates
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of preliminary purchase price allocation for the business combination	Estimated fair values Cash $ 0.8 Working capital 0.1 Property, plant, and equipment 1.2 Intangible assets 24.8 Deferred tax liability (0.5) Asset retirement obligation (1.8) Total purchase consideration $ 24.6

Changes in accumulated other _2

Changes in accumulated other comprehensive income (loss) by component (Tables)	9 Months Ended
	Sep. 30, 2019
Changes in accumulated other comprehensive income (loss) by component
Schedule of changes in accumulated other comprehensive income (loss)	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Foreign currency translation Balance at beginning of period $ (141.5) $ (141.8) $ (146.4) $ (134.3) Other comprehensive income (loss): Foreign currency translation adjustments (1) (1.6) 2.2 3.3 (5.3) Balance at end of period $ (143.1) $ (139.6) $ (143.1) $ (139.6) Pension Balance at beginning and end of period $ (1.4) $ (1.6) $ (1.4) $ (1.6) Cash flow hedges Balance at beginning of period $ 1.4 $ 1.5 $ 1.6 $ 1.1 Other comprehensive income (loss): Net change from periodic revaluations — 0.1 (0.4) 0.4 Tax expense — — — (0.1) Total Other comprehensive income (loss) before reclassifications, net of tax — 0.1 (0.4) 0.3 Net amount reclassified to earnings: Interest rate swaps (2) — 0.1 0.2 0.4 Tax benefit (expense) — — — (0.1) Total amount reclassified from accumulated other comprehensive income (loss), net of tax — 0.1 0.2 0.3 Total other comprehensive income (loss) — 0.2 (0.2) 0.6 Balance at end of period $ 1.4 $ 1.7 $ 1.4 $ 1.7 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).

Equity method investments in _2

Equity method investments in unconsolidated affiliates (Tables)	9 Months Ended
	Sep. 30, 2019
Equity method investments in unconsolidated affiliates
Summary of operating results	Three Months Ended September 30, Nine Months Ended September 30, Operating results 2019 2018 2019 2018 Revenue Frederickson $ 10.3 $ 5.9 $ 26.4 $ 15.7 Orlando Cogen, LP 15.6 15.1 46.4 44.7 Koma Kulshan Associates (1) — — — 1.2 Chambers Cogen, LP 9.4 10.6 30.0 33.4 Craven County Wood Energy, LP (2) 1.8 — 1.8 — Grayling Generating Station, LP (2) 0.8 — 0.8 — 37.9 31.6 105.4 95.0 Project expenses Frederickson 7.5 4.0 20.0 10.7 Orlando Cogen, LP 6.9 7.3 21.5 21.9 Koma Kulshan Associates (1) — — — 0.6 Chambers Cogen, LP 8.9 9.7 26.1 26.9 Craven County Wood Energy, LP (2) 1.6 — 1.6 — Grayling Generating Station, LP (2) 0.5 — 0.5 — 25.4 21.0 69.7 60.1 Project other expenses Frederickson — — — — Orlando Cogen, LP — — — — Koma Kulshan Associates (1) — — — — Chambers Cogen, LP (0.4) (0.4) (1.3) (1.2) Craven County Wood Energy, LP (2) — — — — Grayling Generating Station, LP (2) — — — — (0.4) (0.4) (1.3) (1.2) Project income Frederickson 2.8 1.9 6.4 5.0 Orlando Cogen, LP 8.7 7.8 24.9 22.8 Koma Kulshan Associates (1) — — — 0.6 Chambers Cogen, LP 0.1 0.5 2.6 5.3 Craven County Wood Energy, LP (2) 0.2 — 0.2 — Grayling Generating Station, LP (2) 0.3 — 0.3 — Equity in earnings of unconsolidated affiliates $ 12.1 $ 10.2 $ 34.4 $ 33.7 Distributions from equity method investments (16.0) (10.1) (41.4) (37.4) (Deficit) surplus of earnings of equity method investments, net of distributions $ (3.9) $ 0.1 $ (7.0) $ (3.7) (1) On July 27, 2018, we purchased the remaining 50% of Koma and consolidated the project. (2) On August 13, 2019, we completed the acquisition of the equity ownership interests held by AltaGas Power Holdings (U.S.) Inc. in two contracted biomass plants in North Carolina and Michigan. See Note 3, Asset acquisitions .

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2019
Schedule of current maturities	September 30, December 31, 2019 2018 Interest Rate Current Maturities: Senior secured term loan facility, due 2023 (1) $ 105.0 $ 65.0 LIBOR (2) plus 2.75 % Cadillac term loan, due 2025 (3) 3.1 3.1 LIBOR plus 1.61 % Total current maturities $ 108.1 $ 68.1 (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) London Interbank Offered Rate (“LIBOR”) cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $364.7 million of the $400.0 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2019. See Note 9, Accounting for derivative instruments and hedging activities for further details. (3) We have entered into interest rate swap agreements to economically fix our exposure to changes in interest rates for this non-recourse debt. See Note 9, Accounting for derivative instruments and hedging activities , for further details.
Long-term debt excluding debentures
Schedule of long-term debt	September 30, December 31, 2019 2018 Interest Rate Recourse Debt: Senior secured term loan facility, due 2023 (1) $ 400.0 $ 450.0 LIBOR (2) plus 2.75 % Senior unsecured notes, due June 2036 (Cdn$210.0) 158.6 154.0 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3) 18.7 21.0 LIBOR plus 1.61 % Less: unamortized discount (6.6) (9.0) Less: unamortized deferred financing costs (5.3) (7.2) Less: current maturities (108.1) (68.1) Total long-term debt $ 457.3 $ 540.7

Convertible debentures (Tables)

Convertible debentures (Tables)	9 Months Ended
	Sep. 30, 2019
Convertible Debentures
Schedule of long-term debt	September 30, December 31, 2019 2018 6.00% Debentures due January 2025 (Series E) (Cdn $115.0 million) $ 86.8 $ 84.3 6.00% Debentures due December 2019 (Series D) (Cdn $24.7 million) — 18.1 Less: Unamortized deferred financing costs (4.1) (4.6) Less: Unamortized discount (3.6) (4.0) Total current and long-term convertible debentures $ 79.1 $ 93.8

Fair value of financial instr_2

Fair value of financial instruments (Tables)	9 Months Ended
	Sep. 30, 2019
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	September 30, 2019 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 58.1 $ — $ — $ 58.1 Restricted cash 1.7 — — 1.7 Derivative instruments asset — 0.1 — 0.1 Total $ 59.8 $ 0.1 $ — $ 59.9 Liabilities: Derivative instruments liability $ — $ 23.5 $ 2.8 $ 26.3 Total $ — $ 23.5 $ 2.8 $ 26.3 December 31, 2018 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 68.3 $ — $ — $ 68.3 Restricted cash 2.1 — — 2.1 Derivative instruments asset — 4.5 — 4.5 Total $ 70.4 $ 4.5 $ — $ 74.9 Liabilities: Derivative instruments liability $ — $ 18.7 $ 1.2 $ 19.9 Total $ — $ 18.7 $ 1.2 $ 19.9
Schedule of FVM of conversion option derivative	Fair value Nine Months Ended September 30, 2019 Beginning balance of liability at January 1, 2019 $ 1.2 Total unrealized loss 1.5 Currency transaction loss 0.1 Ending balance of liability at September 30, 2019 $ 2.8 Fair value Nine Months Ended September 30, 2018 Balance of liability at inception (January 2018) $ 4.7 Total unrealized loss 0.2 Ending balance of liability at September 30, 2018 $ 4.9

Accounting for derivative ins_2

Accounting for derivative instruments and hedging activities (Tables)	9 Months Ended
	Sep. 30, 2019
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	September 30, December 31, Units 2019 2018 Natural gas swaps Natural Gas (MMbtu) 17.4 16.3 Gas purchase agreements Natural Gas (Gigajoules) 7.0 9.0 Interest rate swaps Interest (US$) 476.7 616.6
Schedule of fair value of derivative instruments	September 30, 2019 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.5 Interest rate swaps long-term — 1.2 Total derivative instruments designated as cash flow hedges — 1.7 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 1.4 Interest rate swaps long-term — 2.4 Natural gas swaps current 0.1 1.5 Natural gas swaps long-term — 3.6 Gas purchase agreements current — 4.6 Gas purchase agreements long-term — 8.3 Convertible debenture conversion option — 2.8 Total derivative instruments not designated as cash flow hedges 0.1 24.6 Total derivative instruments $ 0.1 $ 26.3 December 31, 2018 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.4 Interest rate swaps long-term — 1.0 Total derivative instruments designated as cash flow hedges — 1.4 Derivative instruments not designated as cash flow hedges: Interest rate swaps current 4.2 — Interest rate swaps long-term 0.3 — Natural gas swaps current — 0.1 Natural gas swaps long-term — 1.4 Gas purchase agreements current — 2.8 Gas purchase agreements long-term — 13.0 Convertible debenture conversion option — 1.2 Total derivative instruments not designated as cash flow hedges 4.5 18.5 Total derivative instruments $ 4.5 $ 19.9
Schedule of changes in OCI attributable to derivative financial instruments designated as cash flow hedges	Interest Rate Three Months Ended September 30, 2019 Swaps Accumulated OCI balance at July 1, 2019 $ Change in fair value of cash flow hedges — Realized from OCI during the period — Accumulated OCI balance at September 30, 2019 $ Interest Rate Three Months Ended September 30, 2018 Swaps Accumulated OCI balance at July 1, 2018 $ Change in fair value of cash flow hedges 0.1 Realized from OCI during the period Accumulated OCI balance at September 30, 2018 $ Interest Rate Nine Months Ended September 30, 2019 Swaps Accumulated OCI balance at January 1, 2019 $ 1.6 Change in fair value of cash flow hedges (0.4) Realized from OCI during the period 0.2 Accumulated OCI balance at September 30, 2019 $ Interest Rate Nine Months Ended September 30, 2018 Swaps Accumulated OCI balance at January 1, 2018 $ 1.1 Change in fair value of cash flow hedges 0.3 Realized from OCI during the period 0.3 Accumulated OCI balance at September 30, 2018 $ 1.7
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 2019 2018 2019 2018 Gas purchase agreements Fuel $ 2.1 $ 0.8 6.1 $ 2.5 Natural gas swaps Fuel 0.6 0.1 0.5 0.9 Interest rate swaps Interest, net (0.9) (0.6) (4.6) (1.7)
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 (loss) gain Three Months Ended September 30, Nine Months Ended September 30, recognized in income 2019 2018 2019 2018 Natural gas swaps Change in fair value of derivatives $ (1.0) $ (0.2) $ (3.5) $ (0.7) Gas purchase agreements Change in fair value of derivatives 3.7 0.5 3.5 2.1 Interest rate swaps Change in fair value of derivatives (1.6) (0.3) (8.3) 2.2 $ 1.1 $ — (8.3) 3.6 Convertible debenture conversion option Other (income) expense, net (0.3) (2.6) 1.5 (0.2) Foreign currency forwards Foreign exchange (gain) loss $ — $ (0.4) $ — $ 0.2

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
	Sep. 30, 2019
Income tax benefit
Schedule of components of income tax expense (benefit)	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Current income tax expense $ 1.3 $ 0.6 $ 4.2 $ 2.8 Deferred income tax (benefit) expense (1.1) 3.0 (1.8) 4.9 Total income tax expense, net $ 0.2 $ 3.6 $ 2.4 $ 7.7

Equity compensation plans (Tabl

Equity compensation plans (Tables)	9 Months Ended
	Sep. 30, 2019
Equity compensation plans
Schedule of changes in outstanding LTIP notional units	Grant Date Weighted-Average Units Fair Value per Unit Outstanding at December 31, 2018 3,952,201 2.09 Granted 1,724,081 2.72 Vested and redeemed (1,864,989) 2.06 Forfeitures (15,108) 2.22 Outstanding at September 30, 2019 3,796,185 $ 2.39

Basic and diluted earnings (l_2

Basic and diluted earnings (loss) per share (Tables)	9 Months Ended
	Sep. 30, 2019
Basic and diluted earnings (loss) per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	Three Months Ended September 30, Nine Months Ended September 30, Basic 2019 2018 2019 2018 Numerator: Income (loss) attributable to Atlantic Power Corporation $ 12.6 $ (3.2) $ 22.7 $ 12.1 Denominator: Weighted average basic shares outstanding 109.4 111.1 109.4 112.8 Basic earnings (loss) per share attributable to Atlantic Power Corporation $ 0.12 $ (0.03) $ 0.21 $ 0.11 Diluted Numerator: Net income (loss) attributable to Atlantic Power Corporation $ 12.6 $ (3.2) $ 22.7 $ 12.1 Add: convertible debenture interest expense 1.0 — 3.1 3.5 13.6 (3.2) 25.8 15.6 Denominator: Weighted average basic shares outstanding 109.4 111.1 109.4 112.8 Convertible debentures 27.4 — 27.9 27.3 Share-based compensation 1.0 — 1.0 2.2 137.8 111.1 138.3 142.3 Diluted earnings (loss) per share attributable to Atlantic Power Corporation $ 0.10 $ (0.03) $ 0.19 $ 0.11
Schedule of computation of our diluted earnings (loss) per share	Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Share-based compensation — 2.2 — — Convertible debentures — 29.1 — — Total — 31.3 — —

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2019
Equity
Schedule of reconciliation of equity	Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at June 30, 2019 $ 1,260.9 $ (1,111.5) $ (141.5) $ 182.9 $ 190.8 Net income — 12.6 — 1.7 14.3 Share-based compensation 0.4 — — — 0.4 Common share repurchases — — — — — Preferred share repurchases — — — (0.1) (0.1) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) — — — (0.8) (0.8) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.348125 per share) — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.364858 per share) — — — (0.4) (0.4) Realized and unrealized loss on hedging activities, — — — — — Foreign currency translation adjustments — — (1.6) — (1.6) Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.10) $ 182.7 $ 202.0 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at June 30, 2018 $ 1,266.8 $ (1,143.2) $ (141.9) $ 206.3 $ 187.9 Net (loss) income — (3.2) — (1.5) (4.7) Share-based compensation 0.7 — — — 0.7 Common share repurchases (3.1) — — — (3.1) Preferred share repurchases — — — (3.5) (3.5) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) — — — (1.0) (1.0) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.348125 per share) — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.333654 per share) — — — (0.4) (0.4) Realized and unrealized gain on hedging activities, — — 0.2 — 0.2 Foreign currency translation adjustments — — 2.2 — 2.2 Balance at September 30, 2018 $ 1,264.5 $ (1,146.5) $ (139.5) $ 199.3 $ 177.8 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at January 1, 2019 $ 1,260.9 $ (1,121.6) $ (146.2) $ 199.3 $ 192.4 Net income (loss) — 22.7 — (3.1) 19.6 Share-based compensation 1.2 — — — 1.2 Common share repurchases (0.8) — — — (0.8) Preferred share repurchases — — — (8.0) (8.0) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — (2.6) (2.6) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.044375 per share) — — — (1.8) (1.8) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.091448 per share) — — — (1.1) (1.1) Realized and unrealized loss on hedging activities, — — (0.2) — (0.2) Foreign currency translation adjustments — — 3.3 — 3.3 Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 182.7 $ 202.0 Accumulated Preferred Other Shares of a Total Common Retained Comprehensive Subsidiary Shareholders’ Shares Deficit (loss) income Company Equity Balance at January 1, 2018 $ 1,274.8 $ (1,158.4) $ (134.8) $ 215.2 $ 196.8 Net income (loss) — 12.1 — (1.6) 10.5 Share-based compensation 1.8 — — — 1.8 Common share repurchases (12.3) — — — (12.3) Preferred share repurchases — — — (8.0) (8.0) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — (3.2) (3.2) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.044375 per share) — — — (1.9) (1.9) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.977188 per share) — — — (1.2) (1.2) Realized and unrealized gain on hedging activities, — — 0.6 — 0.6 Foreign currency translation adjustments — — (5.3) — (5.3) Balance at September 30, 2018 $ 1,264.5 $ (1,146.5) $ (139.5) $ 199.3 $ 177.8

Segment and geographic inform_2

Segment and geographic information (Tables)	9 Months Ended
	Sep. 30, 2019
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, 2019 Project revenues $ 41.4 $ 13.3 $ 16.2 $ 0.2 $ 71.1 Segment assets 588.6 157.4 176.4 65.6 988.0 Project Adjusted EBITDA $ 31.4 $ 11.6 $ 6.1 $ (0.2) $ 48.9 Change in fair value of derivative instruments 1.1 (3.7) 1.6 (1.0) Depreciation and amortization 11.7 5.7 2.8 — 20.2 Interest, net 0.8 — — — 0.8 Insurance loss 1.0 — — — 1.0 Other project (income) expense — — (0.1) 0.1 — Project income (loss) 16.8 5.9 7.1 (1.9) 27.9 Administration — — — 5.5 5.5 Interest expense, net — — — 10.9 10.9 Foreign exchange gain — — — (2.8) (2.8) Other income, net — — — (0.2) (0.2) Income (loss) before income taxes 16.8 5.9 7.1 (15.3) 14.5 Income tax expense — — — 0.2 0.2 Net income (loss) $ 16.8 $ 5.9 $ 7.1 $ (15.5) $ 14.3 Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Three Months Ended September 30, 2018 Project revenues $ 36.3 $ 13.8 $ 15.1 $ 0.2 $ 65.4 Segment assets 607.2 182.2 194.9 74.3 1,058.6 Project Adjusted EBITDA $ 25.5 $ 11.5 $ 8.3 $ 0.1 $ 45.4 Change in fair value of derivative instruments 0.5 — (0.8) 0.3 — Depreciation and amortization 11.6 5.5 7.9 — 25.0 Interest, net 0.7 (1.3) — — (0.6) Other project (income) expense — (5.3) — 0.1 (5.2) Project income (loss) 12.7 12.6 1.2 (0.3) 26.2 Administration — — — 5.7 5.7 Interest expense, net — — — 14.6 14.6 Foreign exchange loss — — — 4.5 4.5 Other expense, net — — — 2.5 2.5 Income (loss) before income taxes 12.7 12.6 1.2 (27.6) (1.1) Income tax expense — — — 3.6 3.6 Net income (loss) $ 12.7 $ 12.6 $ 1.2 $ (31.2) $ (4.7) Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2019 Project revenues $ 128.6 $ 30.2 $ 55.9 $ 0.7 $ 215.4 Segment assets 588.6 157.4 176.4 65.6 988.0 Project Adjusted EBITDA $ 100.8 $ 24.5 $ 28.0 $ (0.1) $ 153.2 Change in fair value of derivative instruments 3.4 — (3.3) 8.2 8.3 Depreciation and amortization 34.8 17.3 8.4 0.1 60.6 Interest, net 2.3 (0.3) — — 2.0 Insurance loss 1.0 — — — 1.0 Other project expense — 1.2 — — 1.2 Project income (loss) 59.3 6.3 22.9 (8.4) 80.1 Administration — — — 17.3 17.3 Interest expense, net — — — 33.0 33.0 Foreign exchange loss — — — 7.1 7.1 Other expense, net — — — 0.7 0.7 Net income (loss) before income taxes 59.3 6.3 22.9 (66.5) 22.0 Income tax expense — — — 2.4 2.4 Net income (loss) $ 59.3 $ 6.3 $ 22.9 $ (68.9) $ 19.6 Un-Allocated East U.S. West U.S. Canada Corporate Consolidated Nine Months Ended September 30, 2018 Project revenues $ 116.9 $ 35.7 $ 58.3 $ 0.7 $ 211.6 Segment assets 607.2 182.2 194.9 74.3 1,058.6 Project Adjusted EBITDA $ 89.8 $ 16.9 $ 31.5 $ 0.3 $ 138.5 Change in fair value of derivative instruments 0.8 — (2.2) (2.1) (3.5) Depreciation and amortization 34.8 19.2 23.9 0.1 78.0 Interest, net 2.7 — — — 2.7 Other project income — (6.7) — — (6.7) Project income 51.5 4.4 9.8 2.3 68.0 Administration — — — 17.9 17.9 Interest expense, net — — — 40.7 40.7 Foreign exchange gain — — — (9.1) (9.1) Other expense, net — — — 0.3 0.3 Net income (loss) before income taxes 51.5 4.4 9.8 (47.5) $ 18.2 Income tax expense — — — 7.7 7.7 Net income (loss) $ 51.5 $ 4.4 $ 9.8 $ (55.2) $ 10.5
Schedule of revenue and property, plant and equipment by country	Project Revenue Project Revenue Property, Plant and Three Months Ended Nine Months Ended Equipment, net of September 30, September 30, accumulated depreciation 2019 2018 2019 2018 September 30, 2019 December 31, 2018 United States $ 54.9 $ 50.3 $ 159.5 $ 153.3 $ 354.9 $ 396.5 Canada 16.2 15.1 55.9 58.3 150.8 153.0 Total $ 71.1 $ 65.4 $ 215.4 $ 211.6 $ 505.7 $ 549.5

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Leases [Abstract]
Schedule of operating lease information	Three Months Ended September 30, Nine Months Ended September 30, 2019 2019 Lease cost: (1) Operating lease cost $ 0.5 $ 1.3 Sublease income (0.3) (0.9) Total lease cost $ 0.2 $ 0.4 (1) Short-term lease costs and finance lease costs are immaterial to the Company.
Schedule of future minimum lease commitments for operating leases under Topic 840	Lease Income from Net lease Payments subleasing payments 2019 $ 1.7 (1.1) $ 0.6 2020 1.4 (1.1) 0.3 2021 1.4 (1.1) 0.3 2022 1.4 (1.1) 0.3 2023 0.8 (0.7) 0.1 Thereafter — — — $ 6.7 (5.1) $ 1.6
Schedule of rental income from operating leases	Rental Income from operating leases Rental Income from operating leases Three Months Ended Nine Months Ended September 30, September 30, 2019 2018 2019 2018 East U.S. $ 27.1 $ 20.6 $ 83.1 $ 68.5 West U.S. 5.7 5.9 17.0 15.3 Mamquam 2.4 2.5 8.4 9.6 Moresby Lake — 0.1 0.8 1.2 Williams Lake 2.4 3.2 10.2 15.9 Calstock 3.5 3.3 10.6 10.4 Tunis 1.2 — 3.3 — Canada 9.5 9.0 33.3 37.1 $ 42.3 $ 35.5 $ 133.4 $ 120.9
Schedule of other information	Lease Income from Net lease Payments subleasing payments 2019 $ 0.5 $ (0.3) $ 0.2 2020 1.7 (1.1) 0.6 2021 1.7 (1.1) 0.6 2022 1.7 (1.1) 0.6 2023 1.2 (0.7) 0.5 Thereafter 0.1 — 0.1 Total operating lease payments $ 6.9 $ (4.3) $ 2.6 Less: present value discount (0.4) Total operating lease liabilities $ 6.5 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) : Operating cash flows from operating leases $ (1) Cash flows from finance leases are immaterial to the Company Lease assets obtained in exchange for new lease liabilities (non-cash): Operating $ Finance Weighted average remaining lease term (in years): Operating leases Finance leases Weighted average discount rate - operating leases % Weighted average discount rate - finance leases %
Schedule of Operating leases	Operating Leases Operating Lease Liability As of September 30, 2019 Months remaining on the Lease Weighted average in months Real Estate and Equipment leases $6.5 151.0 48.4

Nature of business (Details)

Nature of business (Details) MW in Thousands	9 Months Ended
	Sep. 30, 2019stateregionprojectMW
Nature of business
Number of states in which power generation projects operate | state	11
Number of provinces in which power generation projects operate | region	2
Number of power generation projects	21
Gross generating capacity of project (in MW) | MW	1,723
Ownership interest in power generation projects (in MW) | MW	1,327
Number of projects which are majority owned	16
Number of project which are in operation	21

Nature of business - Accounting

Nature of business - Accounting Standards Adopted (Details) - USD ($) $ in Millions	Sep. 30, 2019	Jan. 01, 2019
Operating lease right of use asset	$ 5.9
Operating lease liability	$ 6.5
ASU 2016-02
Operating lease right of use asset		$ 6.4
Operating lease liability		$ 7.2

Revenue from contracts - Disagg

Revenue from contracts - Disaggregation of revenue (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)segment	Sep. 30, 2018USD ($)
Disaggregation of revenue
Number of reportable segments | segment			4
Total revenue	$ 71.1	$ 65.4	$ 215.4	$ 211.6
East U.S.
Disaggregation of revenue
Total revenue	41.4	36.3	128.6	116.9
West U.S.
Disaggregation of revenue
Total revenue	13.3	13.8	30.2	35.7
Canada
Disaggregation of revenue
Total revenue	16.2	15.1	55.9	58.3
Un-Allocated Corporate
Disaggregation of revenue
Total revenue	0.2	0.2	0.7	0.7
Energy sales
Disaggregation of revenue
Project revenue	29.2	25	102.7	94.8
Total revenue	29.2	25	102.7	94.8
Energy sales | East U.S.
Disaggregation of revenue
Project revenue	21.2	16	74.4	62.9
Energy sales | West U.S.
Disaggregation of revenue
Project revenue	3	3.3	8.9	10.1
Energy sales | Canada
Disaggregation of revenue
Project revenue	5	5.7	19.4	21.8
Energy capacity revenue
Disaggregation of revenue
Project revenue	38	29.5	99.8	72.9
Total revenue	38	29.5	99.8	72.9
Energy capacity revenue | East U.S.
Disaggregation of revenue
Project revenue	17.2	16.6	43.8	41.5
Energy capacity revenue | West U.S.
Disaggregation of revenue
Project revenue	10.2	10.2	21.7	22.9
Energy capacity revenue | Canada
Disaggregation of revenue
Project revenue	10.6	2.7	34.3	8.5
Other
Disaggregation of revenue
Miscellaneous revenue	0.1	0.3	(0.4)	(0.1)
Total revenue	3.9	10.9	12.9	43.9
Other | West U.S.
Disaggregation of revenue
Miscellaneous revenue	0.1	0.3	(0.4)	(0.1)
Steam energy and capacity revenue
Disaggregation of revenue
Project revenue	0.2	2.7	0.1	11.7
Steam energy and capacity revenue | East U.S.
Disaggregation of revenue
Project revenue	0.2	2.7	0.1	8.9
Steam energy and capacity revenue | West U.S.
Disaggregation of revenue
Project revenue				2.8
Enhanced dispatch contracts
Disaggregation of revenue
Project revenue		6.1		21.1
Enhanced dispatch contracts | Canada
Disaggregation of revenue
Project revenue		6.1		21.1
Ancillary and transmission services
Disaggregation of revenue
Project revenue	3.4	1.6	12.5	10.4
Ancillary and transmission services | East U.S.
Disaggregation of revenue
Project revenue	2.8	1	10.3	3.6
Ancillary and transmission services | Canada
Disaggregation of revenue
Project revenue	0.6	0.6	2.2	6.8
Asset management and operation
Disaggregation of revenue
Project revenue	0.2	0.2	0.7	0.7
Asset management and operation | Un-Allocated Corporate
Disaggregation of revenue
Project revenue	$ 0.2	$ 0.2	$ 0.7	0.7
Waste heat revenue
Disaggregation of revenue
Project revenue				0.1
Waste heat revenue | Canada
Disaggregation of revenue
Project revenue				$ 0.1

Revenue from contracts - Contra

Revenue from contracts - Contract balances (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Accounts receivable	$ 35.3	$ 35.7
Contract liabilities	0.8	0.1
Water license fee	0.4
Fuel reserve fund	0.3
Contract assets	0	0
San Diego Projects
Disaggregation of Revenue [Line Items]
Contract liabilities	$ 0.1	$ 0.1

Acquisitions - (Details)

Acquisitions - (Details) - South Carolina Biomass Plant	Jul. 31, 2019USD ($)MWh	Sep. 30, 2019USD ($)
Asset acquisitions
Number Of Plants Acquired	2
Plant Capacity | MWh	20
Final consideration	$ 12,600,000
Down payment		$ 2,600,000
Fair Value Measurements Nonrecurring
Estimated fair values
Cash	1,400,000
Accounts receivable	4,300,000
Inventory	2,900,000
Property, plant, and equipment	4,000,000
Intangible assets	2,600,000
Accounts payable	(2,000,000)
Accrued liabilities	(300,000)
Other liabilities	(300,000)
Total purchase consideration	$ 12,600,000

Acquisitions - AltaGas acquisit

Acquisitions - AltaGas acquisition (Details) $ in Millions	Aug. 13, 2019USD ($)MWhPlant	Jun. 18, 2018
Asset acquisitions
Percentage of equity method ownership interest		100.00%
AltaGas Acquisition [Member] | Craven | CMS Energy [Member]
Asset acquisitions
Percentage of interest	50.00%
AltaGas Acquisition [Member] | Grayling | CMS Energy [Member]
Asset acquisitions
Percentage of interest	50.00%
AltaGas Acquisition [Member] | Grayling | Fortistar [Member]
Asset acquisitions
Percentage of interest	20.00%
AltaGas Acquisition [Member]
Asset acquisitions
Number Of Plants Acquired | Plant	2
Purchase price | $	$ 18.7
Acquisition related transaction cost | $	$ 0.2
AltaGas Acquisition [Member] | Minimum
Asset acquisitions
Percentage of equity method ownership interest	5.00%
AltaGas Acquisition [Member] | Maximum
Asset acquisitions
Percentage of equity method ownership interest	50.00%
AltaGas Acquisition [Member] | Craven
Asset acquisitions
Plant Capacity | MWh	48
Interest acquired in the plant	50.00%
AltaGas Acquisition [Member] | Grayling
Asset acquisitions
Number Of Plants Acquired | MWh	37
Interest acquired in the plant	30.00%

Acquisitions - Koma Kulshan Ass

Acquisitions - Koma Kulshan Associates (Details) $ in Millions	Jul. 27, 2018USD ($)	Jun. 18, 2018USD ($)item	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 17, 2018
Asset acquisitions
Percentage of equity method ownership interest		100.00%
Gain on fair value adjustment to equity investment resulting from step acquisition				$ 6.7
Koma Kulshan Associates
Asset acquisitions
Percentage of equity method ownership interest	50.00%	50.00%			49.75%
Number of owner parties with joint control | item		2
Concrete
Asset acquisitions
Percentage of general partner interest purchased		0.50%
Purchase price of partnership interest		$ 1.1
Concrete | Koma Kulshan Associates
Asset acquisitions
Percentage of equity method ownership interest		50.00%
Koma Kulshan Associates
Asset acquisitions
Purchase price	$ 12.5
Interest acquired in the plant	100.00%
Intangible assets	$ 24.8
Koma Kulshan Associates | Koma Kulshan Associates
Asset acquisitions
Gain on fair value adjustment to equity investment resulting from step acquisition			$ 6.7	$ 6.7
Concrete | General Partner
Asset acquisitions
Percentage of equity method ownership interest					0.50%
Concrete | Limited Partner
Asset acquisitions
Percentage of equity method ownership interest					99.00%
Covanta | Koma Kulshan Associates
Asset acquisitions
Percentage of general partner interest purchased	50.00%
Purchase price	$ 12.5

Acquisitions - Estimated Fair V

Acquisitions - Estimated Fair Values (Details) - Koma Kulshan Associates $ in Millions	Jul. 27, 2018USD ($)
Estimated fair values
Cash	$ 0.8
Working capital	0.1
Property, plant, and equipment	1.2
Intangible assets	24.8
Deferred tax liability	(0.5)
Asset retirement obligation	(1.8)
Total purchase consideration	$ 24.6

Changes in accumulated other _3

Changes in accumulated other comprehensive income (loss) by component (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
AOCI Attributable to Parent, Net of Tax
Beginning Balance			$ (6.9)
Amount reclassified
Ending Balance	$ 19.3		19.3
Balance at beginning and end of period	19.3		(6.9)
Foreign currency translation
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(141.5)	$ (141.8)	(146.4)	$ (134.3)
Other comprehensive income (loss):
Foreign currency translation adjustments	(1.6)	2.2	3.3	(5.3)
Amount reclassified
Ending Balance	(143.1)	(139.6)	(143.1)	(139.6)
Balance at beginning and end of period	(141.5)	(141.8)	(146.4)	(134.3)
Accumulated other comprehensive loss, tax impacts related to rate changes	0	0	0	0
Pension
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(1.4)	(1.6)	(1.4)	(1.6)
Amount reclassified
Balance at beginning and end of period	(1.4)	(1.6)	(1.4)	(1.6)
Cash flow hedges
AOCI Attributable to Parent, Net of Tax
Beginning Balance	1.4	1.5	1.6	1.1
Other comprehensive income (loss):
Net change from periodic revaluations		0.1	(0.4)	0.4
Tax expense				(0.1)
Total Other comprehensive income (loss) before reclassifications, net of tax		0.1	(0.4)	0.3
Amount reclassified
Total other comprehensive (loss) income		0.2	(0.2)	0.6
Ending Balance	1.4	1.7	1.4	1.7
Balance at beginning and end of period	1.4	1.5	1.6	1.1
Amount reclassified from accumulated other comprehensive income | Foreign currency translation
Amount reclassified
Amounts reclassified to earnings, foreign currency	$ 0	0	0	0
Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
Tax benefit (expense)				(0.1)
Total amount reclassified from accumulated other comprehensive (loss) income, net of tax		0.1	0.2	0.3
Interest rate swaps | Amount reclassified from accumulated other comprehensive income | Cash flow hedges
Amount reclassified
Interest rate swaps		$ (0.1)	$ (0.2)	$ (0.4)

Equity method investments in _3

Equity method investments in unconsolidated affiliates - Op Results (Details) $ in Millions	Aug. 13, 2019Plant	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Jul. 27, 2018	Jun. 18, 2018	Jun. 17, 2018
Operating results
Revenue		$ 37.9	$ 31.6	$ 105.4	$ 95
Project expenses		25.4	21	69.7	60.1
Project other expenses		(0.4)	(0.4)	(1.3)	(1.2)
Equity in earnings of unconsolidated affiliates		12.1	10.2	34.4	33.7
Distributions from equity method investments		(16)	(10.1)	(41.4)	(37.4)
Deficit of earnings of equity method investments, net of distributions		(3.9)	0.1	(7)	(3.7)
Percentage of equity method ownership interest							100.00%
North Carolina And Michigan [Member]
Operating results
Number of contracted biomass plants | Plant	2
Frederickson
Operating results
Revenue		10.3	5.9	26.4	15.7
Project expenses		7.5	4	20	10.7
Project income		2.8	1.9	6.4	5
Orlando Cogen, LP
Operating results
Revenue		15.6	15.1	46.4	44.7
Project expenses		6.9	7.3	21.5	21.9
Project income		8.7	7.8	24.9	22.8
Koma Kulshan Associates
Operating results
Revenue					1.2
Project expenses					0.6
Project income					0.6
Percentage of equity method ownership interest						50.00%	50.00%	49.75%
Chambers Cogen, LP
Operating results
Revenue		9.4	10.6	30	33.4
Project expenses		8.9	9.7	26.1	26.9
Project other expenses		(0.4)	(0.4)	(1.3)	(1.2)
Project income		0.1	$ 0.5	2.6	$ 5.3
Craven County Wood Energy, LP
Operating results
Revenue		1.8		1.8
Project expenses		1.6		1.6
Project income		0.2		0.2
Grayling Generating Station, LP
Operating results
Revenue		0.8		0.8
Project expenses		0.5		0.5
Project income		$ 0.3		$ 0.3

Long-term debt (Details)

Long-term debt (Details) $ in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2019CAD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Long-term debt
Less: unamortized discount		$ (6.6)	$ (9)
Less: unamortized deferred financing costs		(5.3)	(7.2)
Less: current maturities		(108.1)	(68.1)
Total long-term debt		457.3	540.7
Current maturities		(108.1)	(68.1)
Senior secured term loan facility, due 2023
Long-term debt
Long-term Debt, Gross		400	450
Current maturities		(105)	(65)
Applicable margin (as a percent)	2.75%
Senior unsecured notes, due June 2036 (Cdn$210.0)
Long-term debt
Long-term Debt, Gross		$ 158.6	154
Face amount of debt	$ 210
Interest rate (as a percent)	5.95%	5.95%
Cadillac term loan, due 2025
Long-term debt
Long-term Debt, Gross		$ 18.7	21
Current maturities		(3.1)	(3.1)
Interest rate swaps
Long-term debt
Notional amount		476.7	$ 616.6
Interest rate swaps | Senior secured term loan facility, due 2023
Long-term debt
Notional amount		364.7
London Interbank Offered Rate (LIBOR)
Long-term debt
Minimum percentage of variable rate base	1.00%
London Interbank Offered Rate (LIBOR) | Cadillac term loan, due 2025
Long-term debt
Applicable margin (as a percent)	1.61%
Long-term debt excluding debentures | Senior secured term loan facility, due 2023
Long-term debt
Long-term Debt, Gross		$ 400

Convertible debentures (Details

Convertible debentures (Details) $ in Millions, $ in Millions	Sep. 30, 2019CAD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Convertible debentures
Less: unamortized deferred financing costs		$ 4.1	$ 4.6
Less: Unamortized discount		(3.6)	(4)
6.00% Debenture Due January 31, 2025
Convertible debentures
Long-term Debt, Gross		86.8	84.3
6.00% Debenture due December 2019
Convertible debentures
Long-term Debt, Gross			18.1
Convertible Debentures
Convertible debentures
Total current and long-term convertible debentures		$ 79.1	$ 93.8
Convertible Debentures | 6.00% Debenture Due January 31, 2025
Convertible debentures
Convertible debentures stated interest rate percentage	6.00%	6.00%
Long-term Debt, Gross	$ 115
Convertible Debentures | 6.00% Debenture due December 2019
Convertible debentures
Convertible debentures stated interest rate percentage	6.00%	6.00%	6.00%
Long-term Debt, Gross	$ 24.7
Series E Debentures | 6.00% Debenture Due January 31, 2025
Convertible debentures
Convertible debentures stated interest rate percentage			6.00%

Convertible debentures - Series

Convertible debentures - Series D Debentures (Details) $ in Millions, $ in Millions	Sep. 30, 2019USD ($)	Apr. 10, 2019CAD ($)	Apr. 10, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 03, 2018CAD ($)
Convertible debentures
Accrued interest	$ 3.5			$ 2.3
6.00% Debenture due December 2019
Convertible debentures
Remaining aggregate principal amount				$ 18.1
Series D Debentures
Convertible debentures
Notice to redeem remaining principal amount					$ 56.2
Series D Debentures | 6.00% Debenture due December 2019
Convertible debentures
Notice to redeem remaining principal amount		$ 24.7
Accrued interest			$ 0.4

Convertible debentures - Seri_2

Convertible debentures - Series E Debentures (Details) $ / shares in Units, $ in Millions, $ in Millions	Feb. 02, 2018CAD ($)	Jan. 29, 2018CAD ($)item$ / shares	Jan. 29, 2018USD ($)item	Dec. 31, 2018	Mar. 03, 2018CAD ($)	Mar. 02, 2018CAD ($)
Series E Debentures
Convertible debentures
Sale offering, principal amount			$ 100
Amount of underwriters option to purchase additional debentures		$ 15
Sale of offering, principal amount after issuance costs		$ 94.7
Series E Debentures | Maximum
Convertible debentures
Period of underwriters option to purchase		30 days	30 days
Series E Debentures | Over-Allotment Option
Convertible debentures
Net proceeds from issuance of convertible debentures, after underwriting discounts and expenses	$ 15
Sale of offering, principal amount after issuance costs		$ 14.4
Series E Debentures | 6.00% Debenture Due January 31, 2025
Convertible debentures
Convertible debentures stated interest rate percentage				6.00%
Conversion rate of the debentures (in Shares per Dollar)		238.0952	238.0952
Conversion price of shares (in dollars per share) | $ / shares		$ 4.20
Period of prior notice of redemption		30 days	30 days
Number of consecutive trading days used to determine weighted average trading price | item		20	20
Number of days common stock price must exceed threshold percentage | item		5	5
Series E Debentures | 6.00% Debenture Due January 31, 2025 | Maximum
Convertible debentures
Period of prior notice of redemption		60 days	60 days
Series E Debentures | 6.00% Debenture Due January 31, 2025 | Minimum
Convertible debentures
Debt instrument, redemption price threshold, percentage		125.00%	125.00%
Series D Debentures
Convertible debentures
Notice to redeem remaining principal amount					$ 56.2
Series C Debentures
Convertible debentures
Notice to redeem remaining principal amount						$ 42.5

Convertible debentures - Seri_3

Convertible debentures - Series E Conversion Option (Details) $ in Thousands, $ in Millions	Jan. 29, 2018USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 29, 2018CAD ($)
Convertible debentures
Derivative Liabilities measured at fair value		$ 26,300	$ 19,900
Series E Debentures
Convertible debentures
Derivative Liabilities measured at fair value		2,800	$ 1,200	$ 4.7
Gain (loss) on derivatives	$ 0
Derivative fair value of derivative liability discount		$ 4,700

Fair value of financial instr_3

Fair value of financial instruments - recurring (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Assets:
Restricted cash	$ 1.7	$ 2.1
Recurring
Assets:
Cash and cash equivalents	58.1	68.3
Restricted cash	1.7	2.1
Derivative instruments asset	0.1	4.5
Total	59.9	74.9
Liabilities:
Derivative instruments liability	26.3	19.9
Total	26.3	19.9
Recurring | Level 1
Assets:
Cash and cash equivalents	58.1	68.3
Restricted cash	1.7	2.1
Total	59.8	70.4
Recurring | Level 2
Assets:
Derivative instruments asset	0.1	4.5
Total	0.1	4.5
Liabilities:
Derivative instruments liability	23.5	18.7
Total	23.5	18.7
Recurring | Level 3
Liabilities:
Derivative instruments liability	2.8	1.2
Total	$ 2.8	$ 1.2

Fair value of financial instr_4

Fair value of financial instruments - credit valuation (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Asset acquisitions
Gain (Loss) on Derivative Instruments, Net, Pretax	$ 1.1	$ (8.3)	$ 3.6
Recurring | Credit valuation adjustments
Asset acquisitions
Net increase in fair value		1.1		$ 1
Pre-tax gain in other comprehensive income		0.1		0.1
Gain (Loss) on Derivative Instruments, Net, Pretax		$ 1		$ 0.9

Fair value of financial instr_5

Fair value of financial instruments - Conversion Option Derivative (Details) - Derivative Financial Instruments, Assets - Level 3 - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance of liability	$ 1.2	$ 4.7
Total unrealized gain (loss)	1.5	0.2
Currency transaction gain (loss)	0.1
Ending balance of liability	$ 2.8	$ 4.9

Accounting for derivative ins_3

Accounting for derivative instruments and hedging activities (Details) MMBTU in Thousands, $ in Millions, J in Billions	Apr. 23, 2019MMBTU	Sep. 30, 2019USD ($)JMMBTUitemcontract$ / J	Dec. 31, 2018USD ($)MMBTU	May 31, 2019USD ($)	Jan. 31, 2018USD ($)
Derivative instruments
Number of derivative contracts designated as cash flow hedges | item		1
Adjusted Eurodollar Rate
Derivative instruments
Applicable margin (as a percent)		2.75%
Nipigon Project
Derivative instruments
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | J		6,500
Gas purchase agreements | Nipigon Project
Derivative instruments
Price per Gj | $ / J		4.57
Gas purchase agreements | Nipigon Project | Minimum
Derivative instruments
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | J		6,500
Gas purchase and sales agreements
Derivative instruments
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | MMBTU	700,000
Natural gas swaps
Derivative instruments
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | MMBTU		17,400	16,300
Natural gas swaps | Orlando project
Derivative instruments
Amount of future natural gas purchases to fix the price (in Mmbtu) | MMBTU		17,400
Natural gas swaps during 2016 | Orlando project
Derivative instruments
Percentage of the entity's share in required natural gas purchases hedge		100.00%
Interest rate swaps
Derivative instruments
Notional amount		$ 476.7	$ 616.6
Minimum fixed interest rate (as a percent)		3.75%
Swaption interest rate (as a percent)		1.27%
Swaption all in one interest rate (as a percent)		4.02%
Interest rate swaps | Minimum | Adjusted Eurodollar Rate
Derivative instruments
Minimum fixed interest rate (as a percent)		1.00%
Interest rate swaps | Swaption interest rate until February 15, 2019 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)		6.10%
Interest rate swaps | Swaption interest rate from February 16, 2019 to February 15, 2023 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)		6.30%
Interest rate swaps | Swaption interest rate after February 15, 2023 | Cadillac Project
Derivative instruments
Swaption interest rate (as a percent)		6.40%
Foreign currency forward contracts | Derivative instruments not designated as cash flow hedges
Derivative instruments
Number of forward contracts | contract		0
APLP Holdings | Senior secured term loans
Derivative instruments
Face amount of debt		$ 700
APLP Holdings | Interest rate swaps | Adjusted Eurodollar Rate
Derivative instruments
Notional amount		364.7
APLP Holdings | Interest rate swaps | Adjusted Eurodollar Rate | Senior secured term loans | Long-term debt excluding debentures
Derivative instruments
Remaining aggregate principal amount		$ 400
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From October 1, 2019 To December 31, 2020
Derivative instruments
Notional amount					$ 200
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From October 1, 2019 To December 31, 2020 | One-month LIBOR
Derivative instruments
Swaption interest rate (as a percent)					2.42%
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From December 31, 2019 to December 31, 2020
Derivative instruments
Notional amount				$ 60
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From December 31, 2019 to December 31, 2020 | One-month LIBOR
Derivative instruments
Swaption interest rate (as a percent)				2.17%
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From December 31, 2020 to March 31, 2022
Derivative instruments
Notional amount				$ 80
APLP Holdings | Interest rate swaps | Derivative Swaption Interest Rate From December 31, 2020 to March 31, 2022 | One-month LIBOR
Derivative instruments
Swaption interest rate (as a percent)				1.97%

Accounting for derivative ins_4

Accounting for derivative instruments - forecasted transactions (Details) kJ in Millions, MMBTU in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019USD ($)kJMMBTU	Dec. 31, 2018USD ($)kJMMBTU
Natural gas swaps
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | MMBTU	17.4	16.3
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | kJ	7	9
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $	$ 476.7	$ 616.6

Accounting for derivative ins_5

Accounting for derivative instruments - FV by Bal Sht Loc (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Fair value of derivative instruments
Derivative Assets	$ 0.1	$ 4.5
Derivative Liabilities	26.3	19.9
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	1.7	1.4
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Liabilities	0.5	0.4
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	1.2	1
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets	0.1	4.5
Derivative Liabilities	24.6	18.5
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current
Fair value of derivative instruments
Derivative Assets		4.2
Derivative Liabilities	1.4
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term
Fair value of derivative instruments
Derivative Assets		0.3
Derivative Liabilities	2.4
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current
Fair value of derivative instruments
Derivative Assets	0.1
Derivative Liabilities	1.5	0.1
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term
Fair value of derivative instruments
Derivative Liabilities	3.6	1.4
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current
Fair value of derivative instruments
Derivative Liabilities	4.6	2.8
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term
Fair value of derivative instruments
Derivative Liabilities	8.3	13
Derivative instruments not designated as cash flow hedges | Convertible Debentures | Current
Fair value of derivative instruments
Derivative Liabilities	$ 2.8	$ 1.2

Accounting for derivative ins_6

Accounting for derivative instruments - AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges		$ 0.1	$ (0.4)	$ 0.3
Realized from OCI during the period		(0.1)	(0.2)	(0.3)
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	$ 1.4	1.5	1.6	1.1
Change in fair value of cash flow hedges		0.1	(0.4)	0.3
Realized from OCI during the period		0.1	0.2	0.3
Accumulated OCI balance at end of period	$ 1.4	$ 1.7	$ 1.4	$ 1.7

Accounting for derivative ins_7

Accounting for derivative instruments - gain, loss (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ 1.1		$ (8.3)	$ 3.6
Derivative instruments not designated as cash flow hedges | Gas and Interest Rate Swaps
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	1.1		(8.3)	3.6
Derivative instruments not designated as cash flow hedges | Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	0.6	$ 0.1	0.5	0.9
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	(1)	(0.2)	(3.5)	(0.7)
Derivative instruments not designated as cash flow hedges | Gas purchase agreements
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	2.1	0.8	6.1	2.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	3.7	0.5	3.5	2.1
Derivative instruments not designated as cash flow hedges | Interest rate swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	(0.9)	(0.6)	(4.6)	(1.7)
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	(1.6)	(0.3)	(8.3)	2.2
Derivative instruments not designated as cash flow hedges | Convertible Debentures | Other income (expense), net
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments	$ (0.3)	(2.6)	$ 1.5	(0.2)
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Foreign exchange loss
Impact of derivative instruments on the consolidated statements of operations
Change in fair value of derivative instruments		$ (0.4)		$ 0.2

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Components of income tax expenses (benefit)
Current income tax expense	$ 1.3	$ 0.6	$ 4.2	$ 2.8
Deferred income tax (benefit) expense	(1.1)	3	(1.8)	4.9
Total income tax expense, net	$ 0.2	$ 3.6	$ 2.4	$ 7.7

Income tax expense - Other (Det

Income tax expense - Other (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of income taxes
Enacted statutory income tax rate					35.00%	21.00%
Tax expense	$ 200	$ 3,600	$ 2,400	$ 7,700
Impact related to withholding and state taxes	500		1,300	300
Increase (decrease) in the valuation allowance	(4,400)	3,700	(4,500)	4,500
Impact relating to foreign exchange	1,000	$ 200		300
Other permanent differences	200		700	100
Capital loss on intercompany notes				1,300
Changes in tax rates				$ 900
Valuation allowance	$ 135,200		$ 135,200
Canada
Reconciliation of income taxes
Enacted statutory income tax rate	27.00%	27.00%	27.00%	27.00%
Computed income taxes at Canadian statutory rate	$ 3,900	$ 300	$ 5,900	$ 4,700
Canada | Net operating losses
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	(1,000)	3,700	4,400	4,500
United States
Reconciliation of income taxes
Increase (decrease) in the valuation allowance		$ 0		$ 0
United States | Net operating losses
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	$ (3,400)		$ (8,900)

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	Jan. 22, 2015$ / shares	Sep. 30, 2019USD ($)$ / sharesshares	Mar. 28, 2019$ / sharesshares	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2018USD ($)
Units
Outstanding at the beginning of the period (in shares) | shares			3,952,201		3,952,201
Granted (in shares) | shares					1,724,081
Vested and redeemed (in shares) | shares					(1,864,989)
Forfeitures (in shares) | shares					(15,108)
Outstanding at the end of the period (in shares) | shares		3,796,185			3,796,185
Weighted-Average Fair Value per Unit
Outstanding at the beginning of the period (in dollars per share)			$ 2.09		$ 2.09
Granted (in dollars per share)					2.72
Vested and redeemed (in dollars per share)					2.06
Forfeitures (in dollars per share)					2.22
Outstanding at the end of the period (in dollars per share)		$ 2.39			$ 2.39
Long-term incentive plan
Weighted-Average Fair Value per Unit
Portion of notional units settled in common stock prior to Plan modification			0.6667%
Portion of notional units settled in cash prior to Plan modification			0.3333%
Cash payments made for vested notional units | $					$ 2	$ 0.8
Compensation expense related to LTIP | $		$ 1.1		$ 1.1	$ 3.1	$ 2.6
Transition equity participation agreement
Transition equity participation agreement
Number of transition notional shares outstanding | shares					269,902
Period after which remaining portions vests					2 years
Minimum market price required for 3 consecutive months to vest remaining shares	$ 4.77
Share Price	$ 3.18
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 earnings (l_3

Basic and diluted earnings (loss) per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Numerator:
Net income (loss) attributable to Atlantic Power Corporation	$ 12.6	$ (3.2)	$ 22.7	$ 12.1
Add: convertible debenture interest expense	1		3.1	3.5
Net income (loss) available to common stockholder, Diluted	$ 13.6	$ (3.2)	$ 25.8	$ 15.6
Denominator:
Weighted average basic shares outstanding	109.4	111.1	109.4	112.8
Basic (loss) earnings per share attributable to Atlantic Power Corporation	$ 0.12	$ (0.03)	$ 0.21	$ 0.11
Convertible debentures (in shares)	27.4		27.9	27.3
Share-based compensation (in shares)	1		1	2.2
Weighted Average Number of Potentially Diluted Shares	137.8	111.1	138.3	142.3
Basic earnings (loss) per share attributable to Atlantic Power Corporation	$ 0.12	$ (0.03)	$ 0.21	$ 0.11
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$ 0.10	$ (0.03)	$ 0.19	$ 0.11
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS		$ 31.3
Share-based compensation.
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS		2.2
Convertible Debentures
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS		$ 29.1

Equity (Details)

Equity (Details) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2019$ / shares	Sep. 30, 2019USD ($)	Sep. 30, 2018$ / shares	Sep. 30, 2018USD ($)	Sep. 30, 2019$ / shares	Sep. 30, 2019USD ($)	Sep. 30, 2018$ / shares	Sep. 30, 2018USD ($)
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		$ 190.8		$ 187.9		$ 192.4		$ 196.8
Net (loss) income		14.3		(4.7)		19.6		10.5
Share-based compensation		0.4		0.7		1.2		1.8
Common share repurchases				(3.1)		(0.8)		(12.3)
Preferred share repurchases		(0.1)		(3.5)		(8)		(8)
Realized and unrealized gain (loss) on hedging activities, net of tax				0.2		(0.2)		0.6
Foreign currency translation adjustments		(1.6)		2.2		3.3		(5.3)
Balance at the end of the period		202		177.8		202		177.8
Series 1 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		(0.8)		(1)		(2.6)		(3.2)
Dividends on preferred shares of a subsidiary company (in CAD per share) | $ / shares	$ 0.303125		$ 0.303125		$ 0.909375		$ 0.909375
Series 2 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		(0.6)		(0.6)		(1.8)		(1.9)
Dividends on preferred shares of a subsidiary company (in CAD per share) | $ / shares	0.348125		0.348125		1.044375		1.044375
Series 3 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		(0.4)		(0.4)		(1.1)		(1.2)
Dividends on preferred shares of a subsidiary company (in CAD per share) | $ / shares	$ 0.364858		$ 0.333654		$ 1.091448		$ 0.977188
Common Shares
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		1,260.9		1,266.8		1,260.9		1,274.8
Share-based compensation		0.4		0.7		1.2		1.8
Common share repurchases				(3.1)		(0.8)		(12.3)
Balance at the end of the period		1,261.3		1,264.5		1,261.3		1,264.5
Retained Deficit
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		(1,111.5)		(1,143.2)		(1,121.6)		(1,158.4)
Net (loss) income		12.6		(3.2)		22.7		12.1
Balance at the end of the period		(1,098.9)		(1,146.5)		(1,098.9)		(1,146.5)
Accumulated Other Comprehensive Income (loss)
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		(141.5)		(141.9)		(146.2)		(134.8)
Realized and unrealized gain (loss) on hedging activities, net of tax				0.2		(0.2)		0.6
Foreign currency translation adjustments		(1.6)		2.2		3.3		(5.3)
Balance at the end of the period		(143.1)		(139.5)		(143.1)		(139.5)
Preferred Shares of a Subsidiary Company
Increase (decrease) in shareholders' equity
Balance at the beginning of the period		182.9		206.3		199.3		215.2
Net (loss) income		1.7		(1.5)		(3.1)		(1.6)
Preferred share repurchases		(0.1)		(3.5)		(8)		(8)
Balance at the end of the period		182.7		199.3		182.7		199.3
Preferred Shares of a Subsidiary Company | Series 1 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		(0.8)		(1)		(2.6)		(3.2)
Preferred Shares of a Subsidiary Company | Series 2 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		(0.6)		(0.6)		(1.8)		(1.9)
Preferred Shares of a Subsidiary Company | Series 3 preferred
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company		$ (0.4)		$ (0.4)		$ (1.1)		$ (1.2)

Equity - Share Repurchase Progr

Equity - Share Repurchase Program (Details) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019USD ($)shares	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)shares	Sep. 30, 2018USD ($)	Dec. 31, 2018shares
Stock Repurchase Program
Current ratio of repurchased shares to public float (as a percent)	10.00%		10.00%
Common shares repurchased and canceled (in shares)			400,000
Payments for Repurchase of Redeemable Preferred Stock | $			$ 8	$ 8
Gain (loss) attributable to preferred shares of a subsidiary company | $	$ 1.7	$ (1.5)	$ (3.1)	$ (1.6)
Series 1 Shares
Stock Repurchase Program
Common shares repurchased and canceled (in shares)			427,500
Dividend percent of cumulative redeemable preferred shares			4.85
Series 2 Shares
Stock Repurchase Program
Number of shares authorized for repurchase	100,377		100,377
Dividend percent of cumulative redeemable preferred shares			7
Series 3 Shares
Stock Repurchase Program
Number of shares authorized for repurchase	148,311		148,311
Payments for Repurchase of Redeemable Preferred Stock | $			$ 8
NCIB
Stock Repurchase Program
Public float amount used to determine share amount, percent					10.00%
Gain (loss) attributable to preferred shares of a subsidiary company | $			$ (8.6)
Maximum | NCIB
Stock Repurchase Program
Number of shares authorized for repurchase					10,623,464
Stock Repurchase Program Number Of Shares Authorized To Be Repurchased Per Day					10,300

Segment and geographic inform_3

Segment and geographic information - EBITDA (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)segment	Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Segment and geographic information
Number of reportable segments | segment			4
Project revenues	$ 71.1	$ 65.4	$ 215.4	$ 211.6
Segment assets	988	1,058.6	988	1,058.6	$ 1,024.5
Project Adjusted EBITDA	48.9	45.4	153.2	138.5
Change in fair value of derivative instruments	(1)		8.3	(3.5)
Depreciation and amortization	20.2	25	60.6	78
Interest, net	0.8	(0.6)	2	2.7
Insurance loss	1		1
Other project (income) expense		(5.2)	1.2	(6.7)
Project income	27.9	26.2	80.1	68
Administration	5.5	5.7	17.3	17.9
Interest expense, net	10.9	14.6	33	40.7
Foreign exchange (gain) loss	(2.8)	4.5	7.1	(9.1)
Other expenses, net	(0.2)	2.5	0.7	0.3
Income (loss) from operations before income taxes	14.5	(1.1)	22	18.2
Income tax benefit (expenses)	0.2	3.6	2.4	7.7
Net income (loss)	14.3	(4.7)	19.6	10.5
East U.S.
Segment and geographic information
Project revenues	41.4	36.3	128.6	116.9
Segment assets	588.6	607.2	588.6	607.2
Project Adjusted EBITDA	31.4	25.5	100.8	89.8
Change in fair value of derivative instruments	1.1	0.5	3.4	0.8
Depreciation and amortization	11.7	11.6	34.8	34.8
Interest, net	0.8	0.7	2.3	2.7
Insurance loss	1		1
Project income	16.8	12.7	59.3	51.5
Income (loss) from operations before income taxes	16.8	12.7	59.3	51.5
Net income (loss)	16.8	12.7	59.3	51.5
West U.S.
Segment and geographic information
Project revenues	13.3	13.8	30.2	35.7
Segment assets	157.4	182.2	157.4	182.2
Project Adjusted EBITDA	11.6	11.5	24.5	16.9
Depreciation and amortization	5.7	5.5	17.3	19.2
Interest, net		(1.3)	(0.3)
Other project (income) expense		(5.3)	1.2	(6.7)
Project income	5.9	12.6	6.3	4.4
Income (loss) from operations before income taxes	5.9	12.6	6.3	4.4
Net income (loss)	5.9	12.6	6.3	4.4
Canada
Segment and geographic information
Project revenues	16.2	15.1	55.9	58.3
Segment assets	176.4	194.9	176.4	194.9
Project Adjusted EBITDA	6.1	8.3	28	31.5
Change in fair value of derivative instruments	(3.7)	(0.8)	(3.3)	(2.2)
Depreciation and amortization	2.8	7.9	8.4	23.9
Other project (income) expense	(0.1)
Project income	7.1	1.2	22.9	9.8
Income (loss) from operations before income taxes	7.1	1.2	22.9	9.8
Net income (loss)	7.1	1.2	22.9	9.8
Un-Allocated Corporate
Segment and geographic information
Project revenues	0.2	0.2	0.7	0.7
Segment assets	65.6	74.3	65.6	74.3
Project Adjusted EBITDA	(0.2)	0.1	(0.1)	0.3
Change in fair value of derivative instruments	1.6	0.3	8.2	(2.1)
Depreciation and amortization			0.1	0.1
Other project (income) expense	0.1	0.1
Project income	(1.9)	(0.3)	(8.4)	2.3
Administration	5.5	5.7	17.3	17.9
Interest expense, net	10.9	14.6	33	40.7
Foreign exchange (gain) loss	(2.8)	4.5	7.1	(9.1)
Other expenses, net	(0.2)	2.5	0.7	0.3
Income (loss) from operations before income taxes	(15.3)	(27.6)	(66.5)	(47.5)
Income tax benefit (expenses)	0.2	3.6	2.4	7.7
Net income (loss)	$ (15.5)	$ (31.2)	$ (68.9)	$ (55.2)

Segment and geographic inform_4

Segment and geographic information - Geographic (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Revenue and Assets
Project revenues	$ 71.1	$ 65.4	$ 215.4	$ 211.6
Property, Plant and Equipment, net of accumulated depreciation	505.7		505.7		$ 549.5
United States.
Revenue and Assets
Project revenues	54.9	50.3	159.5	153.3
Property, Plant and Equipment, net of accumulated depreciation	354.9		354.9		396.5
Canada.
Revenue and Assets
Project revenues	16.2	$ 15.1	55.9	$ 58.3
Property, Plant and Equipment, net of accumulated depreciation	$ 150.8		$ 150.8		$ 153

Segment and geographic inform_5

Segment and geographic information - risk (Details) - Revenues, net - Consolidated revenue	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Georgia Power
Consolidated revenue concentration
Percentage of consolidated revenue	16.20%	17.20%	12.10%	12.00%
Southern California Edison
Consolidated revenue concentration
Percentage of consolidated revenue	10.50%	12.70%
Equistar Chemicals, LP
Consolidated revenue concentration
Percentage of consolidated revenue	10.40%	12.40%	11.60%	11.80%
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	11.20%		12.10%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue				12.60%
Niagara Mohawk
Consolidated revenue concentration
Percentage of consolidated revenue			18.40%	13.80%

Guarantees and Contingencies (D

Guarantees and Contingencies (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019USD ($)item	Sep. 30, 2019USD ($)item
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
Insurance receivable	$ 24.2	$ 24.2
Insurance	1	1
Cadillac Project
Contingencies
Estimate damages claimed for statutory misrepresentation	1	$ 1
Business interruption loss period		45 days
Business interruption expected revenue loss		$ 1.5
Impairment		25
Write-down of capital spares		0.2
Insurance receivable	$ 24.2	24.2
Insurance		$ 1

Leases - Real estate and equipm

Leases - Real estate and equipment (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)item	Jan. 01, 2019
Operating lease information
Number of properties subleased | item	1
Rate used to determine lease liabilities at implementation date		3.75%
Operating Lease, Liability | $	$ 6.5
Months remaining on the Lease	151 months
Operating Lease, Weighted Average Remaining Lease Term	48 months 12 days

Leases - Lease cost (Details)

Leases - Lease cost (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Lease cost:
Operating lease cost	$ 0.5	$ 1.3
Sublease income	(0.3)	(0.9)
Total lease cost	$ 0.2	$ 0.4

Leases - Operating lease maturi

Leases - Operating lease maturities - Topic 842 (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)item
Operating lease information
Number of lease transactions with related parties | item	0
Future minimum lease commitments
2019	$ 0.5
2020	1.7
2021	1.7
2022	1.7
2023	1.2
Thereafter	0.1
Total operating lease payments	6.9
Less: present value discount	(0.4)
Total operating lease liabilities	6.5
Income from subleasing
2019	(0.3)
2020	(1.1)
2021	(1.1)
2022	(1.1)
2023	(0.7)
Thereafter
Total income from subleasing	(4.3)
Net lease payments
2019	0.2
2020	0.6
2021	0.6
2022	0.6
2023	0.5
Thereafter	0.1
Total net lease payments	$ 2.6

Leases - Operating lease matu_2

Leases - Operating lease maturities - Supplemental Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 0.5
Lease assets obtained in exchange for new lease liabilities (non-cash):
Operating	0.7
Finance	$ 0.1
Weighted average items:
Weighted average remaining lease term (in years), Operating leases	48 months 12 days
Weighted average remaining lease term (in years), Finance leases	2 years 8 months 12 days
Weighted average discount rate - operating leases	3.87%
Weighted average discount rate - finance leases	3.75%

Leases - Operating lease matu_3

Leases - Operating lease maturities - Topic 840 (Details) $ in Millions	Sep. 30, 2019USD ($)
Income from subleasing
2019	$ 1.7
2020	1.4
2021	1.4
2022	1.4
2023	0.8
Thereafter
Income from subleasing	6.7
Future minimum lease commitments
2019	(1.1)
2020	(1.1)
2021	(1.1)
2022	(1.1)
2023	(0.7)
Future minimum lease commitments	(5.1)
Net lease obligations
2019	(0.6)
2020	(0.3)
2021	(0.3)
2022	(0.3)
2023	(0.1)
Net lease obligations	$ (1.6)

Leases - PPA Leases (Details)

Leases - PPA Leases (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2019USD ($)	Sep. 30, 2019USD ($)project	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)agreementproject	Sep. 30, 2018USD ($)
Lessor, Lease, Description [Line Items]
Lease, Practical Expedients, Package [true false]				true
Number of PPAs accounted for as operating leases | agreement				12
Number of PPAs accounted for as direct financing leases | project				1
Number of project which are in operation | project		21		21
Lessor, Operating Lease, Existence of Option to Extend [true false]				false
Assets and Liabilities, Lessor [Abstract]
Net investment in direct financing lease		$ 1.5		$ 1.5
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 42.3	$ 35.5	$ 133.4	$ 120.9
Minimum
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Term of Contract		8 months		8 months
Lessor, Direct Financing Lease, Term of Contract		8 months		8 months
Maximum
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Term of Contract		24 years		24 years
Lessor, Direct Financing Lease, Term of Contract		24 years		24 years
Manchief
Operating Lease Lessor Sale Of Plant [Abstract]
Sales price of Manchief plant	$ 45.2
Mamquam
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 2.4	2.5	$ 8.4	9.6
Mamquam | BC Hydro
Operating Lease Lessor Sale Of Plant [Abstract]
Period of time between the anniversaries the option to purchase will become exercisable after the option is first exercisable				5 years
Moresby Lake
Operating Lease, Lease Income [Abstract]
Rental income from operating leases			0.1	$ 0.8	1.2
Williams Lake
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		2.4	3.2	10.2	15.9
Calstock
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		3.5	3.3	10.6	10.4
Tunis
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		1.2		3.3
East U.S.
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		27.1	20.6	83.1	68.5
West U.S.
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		5.7	5.9	17	15.3
Canada
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 9.5	$ 9	$ 33.3	$ 37.1