Atlantic Power 10-Q9 Nov 202020 Q3 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2020	Nov. 06, 2020
Cover [Abstract]
Entity Registrant Name	ATLANTIC POWER CORPORATION
Entity Central Index Key	0001419242
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	001-34691
Entity Incorporation, State or Country Code	A1
Entity Tax Identification Number	55-0886410
Entity Address, Address Line One	3 Allied Drive, Suite 155
Entity Address, City or Town	Dedham
Entity Address, State or Province	MA
Entity Address, Postal Zip Code	02026
City Area Code	617
Local Phone Number	977-2400
Title of 12(b) Security	Common Shares
Trading Symbol	AT
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		89,222,568
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 30.3	$ 74.9
Restricted cash	2.6	7.7
Accounts receivable	29.4	30.4
Insurance recovery receivable (Note 13)		13.5
Current portion of derivative instruments asset (Notes 6 and 7)		0.7
Inventory	19.5	18.6
Prepayments	5.5	3.8
Income taxes receivable	2.4	1.8
Lease receivable		0.9
Other current assets	0.2	0.4
Total current assets	89.9	152.7
Property, plant, and equipment, net	494.8	502.1
Equity method investments in unconsolidated affiliates (Note 4)	91.4	96.6
Power purchase agreements and intangible assets, net	125.8	144.3
Goodwill	21.3	21.3
Operating lease right-of-use assets (Note 14)	4.9	6.3
Deferred income taxes (Note 8)	11.7	10.4
Other assets	0.6	1.9
Total assets	840.4	935.6
Current liabilities:
Accounts payable	4	8.9
Accrued interest	3.4	2.6
Other accrued liabilities	19.3	20.8
Current portion of long-term debt (Note 5)	91	76.4
Current portion of derivative instruments liability (Notes 6 and 7)	10.6	12
Operating lease liabilities (Note 14)	2	2
Other current liabilities	0.6	0.2
Total current liabilities	130.9	122.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)	399.7	473.5
Convertible debentures, net of discount and unamortized deferred financing costs	79.8	81.1
Derivative instruments liability (Notes 6 and 7)	9.1	15.9
Deferred income taxes (Note 8)	25.8	23.7
Power purchase agreements and intangible liabilities, net	18.1	19.8
Asset retirement obligations, net	50.2	51.5
Operating lease liabilities (Note 14)	3.4	4.8
Other long-term liabilities	4.1	4.7
Total liabilities	721.1	797.9
Equity
Common shares, no par value, unlimited authorized shares; 89,222,568 and 108,675,294 issued and outstanding at September 30, 2020 and December 31, 2019 (Note 11)	1,219.4	1,259.9
Accumulated other comprehensive loss (Note 3)	(144.7)	(140.7)
Retained deficit	(1,124.2)	(1,164.2)
Total Atlantic Power Corporation shareholders' deficit	(49.5)	(45)
Preferred shares issued by a subsidiary company (Note 11)	168.8	182.7
Total equity	119.3	137.7
Total liabilities and equity	$ 840.4	$ 935.6

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2020	Dec. 31, 2019
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)	89,222,568	108,675,294
Common shares, outstanding shares (in shares)	89,222,568	108,675,294

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Project revenue:
Project revenue	$ 65.2	$ 71.1	$ 200.3	$ 215.4
Project expenses:
Fuel	17.5	19.4	51.3	55.2
Operations and maintenance	21.2	19.5	64	54.6
Depreciation and amortization	14.5	16.2	45.3	48.5
Total project expenses	53.2	55.1	160.6	158.3
Project other income (loss):
Change in fair value of derivative instruments (Notes 6 and 7)	8.1	1.1	5.6	(8.3)
Equity in earnings of unconsolidated affiliates (Note 4)	12.1	12.1	31.8	34.4
Interest, net	(0.4)	(0.3)	(1)	(0.9)
Insurance gain (loss) (Note 13)	6.2	(1)	6.2	(1)
Other expense, net			0	(1.2)
Total project other income (loss)	26	11.9	42.6	23
Project income	38	27.9	82.3	80.1
Administrative and other expenses:
Administration	5.6	5.5	16.8	17.3
Interest expense, net	10.8	10.9	31.7	33
Foreign exchange loss (gain)	5.1	(2.8)	(6.2)	7.1
Other (income) expense, net (Note 6)	(3.8)	(0.2)	(2.7)	0.7
Total administrative and other expenses	17.7	13.4	39.6	58.1
Income from operations before income taxes	20.3	14.5	42.7	22
Income tax expense (Note 8)	2.5	0.2	5.2	2.4
Net income	17.8	14.3	37.5	19.6
Net income (loss) attributable to preferred shares of a subsidiary company (Note 11)	1.6	1.7	(2.5)	(3.1)
Net income attributable to Atlantic Power Corporation	$ 16.2	$ 12.6	$ 40	$ 22.7
Net earnings per share attributable to Atlantic Power Corporation shareholders: (Note 10)
Basic (in dollars per share)	$ 0.18	$ 0.12	$ 0.41	$ 0.21
Diluted (in dollars per share)	$ 0.15	$ 0.10	$ 0.34	$ 0.19
Weighted average number of common shares outstanding: (Note 10)
Basic (in shares)	89.5	109.4	98.1	109.4
Diluted (in shares)	117.8	137.8	126.4	138.3
Energy sales
Project revenue:
Project revenue	$ 30.3	$ 29.2	$ 102.1	$ 102.7
Energy capacity revenue
Project revenue:
Project revenue	29.7	38	84.8	99.8
Miscellaneous revenue
Project revenue:
Project revenue	$ 5.2	$ 3.9	$ 13.4	$ 12.9

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 17.8	$ 14.3	$ 37.5	$ 19.6
Other comprehensive income, net of tax:
Unrealized loss on hedging activities			(0.5)	(0.4)
Net amount reclassified to earnings	0.1		0.3	0.2
Net realized and unrealized gain (loss) on derivatives	0.1		(0.2)	(0.2)
Foreign currency translation adjustments	2.5	(1.6)	(3.8)	3.3
Other comprehensive income (loss), net of tax	2.6	(1.6)	(4)	3.1
Comprehensive income	20.4	12.7	33.5	22.7
Less: Comprehensive income (loss) attributable to preferred shares of a subsidiary company	1.6	1.7	(2.5)	(3.1)
Comprehensive income attributable to Atlantic Power Corporation	$ 18.8	$ 11	$ 36	$ 25.8

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Cash provided by operating activities:
Net income	$ 37.5	$ 19.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	45.3	48.5
Share-based compensation	1.1	1.2
Other gain		(0.8)
Asset retirement obligations		1.4
Gain on disposal of fixed assets and inventory	(0.8)	(0.1)
Insurance loss	(6.2)	1
Equity in earnings from unconsolidated affiliates	(31.8)	(34.4)
Distributions from unconsolidated affiliates	37.3	41.4
Unrealized foreign exchange (gain) loss	(6.6)	7.3
Change in fair value of derivative instruments	(7.3)	9.8
Amortization of debt discount and deferred financing costs	4.7	5.3
Non-cash operating lease expense	1.4	1.1
Deferred income taxes	0.6	(1.8)
Change in other operating balances
Accounts receivable	1.2	4.7
Inventory	(1)	0.3
Prepayments and other assets	(0.4)	(0.2)
Accounts payable	(6.1)	(1.3)
Accruals and other liabilities	(3)	1.5
Cash provided by operating activities	72.1	104.5
Cash used in investing activities:
Investment in unconsolidated affiliate		(18.7)
Insurance proceeds	12.7
Cash paid for acquisition, net of cash received		(10)
Proceeds from sales of assets	0.9	1.6
Purchase of property, plant and equipment	(23)	(0.9)
Cash used in investing activities	(9.4)	(28)
Cash used in financing activities:
Common share repurchases	(41.6)	(0.8)
Preferred share repurchases	(6.4)	(8)
Repayment of corporate and project-level debt	(57.1)	(52.3)
Repayment of convertible debentures		(18.5)
Cash payments for vested LTIP withheld for taxes	(0.7)	(2)
Deferred financing costs	(1.6)
Dividends paid to preferred shareholders	(5)	(5.5)
Cash used in financing activities	(112.4)	(87.1)
Net decrease in cash, restricted cash and cash equivalents	(49.7)	(10.6)
Cash, restricted cash and cash equivalents at beginning of period	82.6	70.4
Cash, restricted cash and cash equivalents at end of period	32.9	59.8
Supplemental cash flow information
Interest paid	26.6	27
Income taxes paid, net	3.8	3.5
Accruals for construction in progress	$ 1.7	$ 0.2

Nature of business

Nature of business	9 Months Ended
Nature of business	Sep. 30, 2020
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, 2020, 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 1066 West Hastings Street, Suite 2600, Vancouver, British Columbia V6E 3X1, 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. 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, 2019. 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, 2020, the results of operations and comprehensive income for the three and nine months ended September 30, 2020 and 2019, and our cash flows for the nine months ended September 30, 2020 and 2019, in accordance with U.S. generally accepted accounting principles (“GAAP”). 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 method 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 COVID-19 Pandemic There are many uncertainties regarding the ongoing coronavirus (“COVID-19”) pandemic, and we are closely monitoring the impact of COVID-19 on all aspects of our business, including how it will impact our customers, employees, suppliers, vendors and business partners. We have taken extra precautions for our employees who continue to work at our facilities and have implemented work-from-home policies where appropriate. Currently, we do not anticipate any employee layoffs and are continuing to maintain the high level of reliability and availability of our plants. We continue to implement strong physical and cybersecurity measures to ensure that our systems remain functional in order to serve our operational needs with a remote workforce and to keep our operations running to ensure uninterrupted service to our offtakers. Recently adopted and issued accounting standards Accounting standards adopted In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance amends the guidance on measuring credit losses on financial assets held at amortized cost. ASU 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. This guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted ASU 2016-13 on January 1, 2020 and it did not have a material impact on the condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurements” 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 adopted this guidance on January 1, 2020 and it did not have an impact on the condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-09, “Codification Improvements” 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 adopted this guidance on January 1, 2020 and it did not have a material impact on the condensed consolidated financial statements. Accounting standards to be implemented In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans (Subtopic 715-20)”, to improve the effectiveness of benefit plan disclosures in the notes to financial statements by facilitating clear communication of the information required by GAAP that is most important to users of each entity’s financial statements. The amendments in this ASU modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Additionally, the amendments in this ASU remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The amendments in this ASU are effective for fiscal years ending after December 15, 2020, for public business entities and early adoption is permitted for all entities. We are currently evaluating the impact that adoption will have on our disclosures. In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. We are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements. In March 2020, the FASB issued amendments to the guidance for reference rate reform through ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the effects of reference rate reform on financial reporting.” The amendments in this update provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022. The amendments are elective and are effective upon issuance for all entities. We

Revenue from contracts

Revenue from contracts	9 Months Ended
Revenue from contracts	Sep. 30, 2020
Revenue from contracts
Revenue from contracts	2. Revenue from contracts Disaggregation of revenue We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management’s structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for the comparative 2019 period has been revised to conform to the new segment presentation. Each segment contains various power generation projects and performance obligations. For more detailed information about reportable segments, see Note 12, Segment and geographical information Three Months Ended September 30, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 14.3 $ 7.5 $ 8.5 $ — $ 30.3 Energy capacity revenue 12.2 17.5 — — 29.7 Steam energy and capacity revenue — 2.5 — — 2.5 Waste heat revenue 0.1 — — — 0.1 Ancillary and transmission services — 0.7 0.7 — 1.4 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue 0.1 0.9 — — 1.0 26.7 29.1 9.2 0.2 65.2 Three Months Ended September 30, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 12.4 $ 7.7 $ 9.1 $ — $ 29.2 Energy capacity revenue 13.7 24.3 — — 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 26.1 35.1 9.7 0.2 71.1 Nine Months Ended September 30, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 40.6 $ 18.4 $ 43.1 $ — $ 102.1 Energy capacity revenue 26.2 58.6 — — 84.8 Steam energy and capacity revenue — 6.8 — — 6.8 Waste heat revenue 0.5 — — — 0.5 Ancillary and transmission services — 2.2 2.4 — 4.6 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue 0.1 0.7 — — 0.8 67.4 86.7 45.5 0.7 200.3 Nine Months Ended September 30, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 30.7 $ 23.6 $ 48.4 $ — $ 102.7 Energy capacity revenue 33.7 66.1 — — 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 0.1 (0.5) — — (0.4) 64.5 99.6 50.6 0.7 215.4 Contract balances Contract liabilities as of September 30, 2020 include a $0.2 million fuel reserve fund at Dorchester (Solid Fuel segment), a $0.1 million steam sale credit at the San Diego plants (Natural Gas segment), and $0.4 million water license fee at Mamquam (Hydroelectric segment). Contract liabilities as of December 31, 2019 include a $0.2 million fuel reserve fund at Dorchester and a $0.1 million steam sale credit at the San Diego plants. We had no contract assets at September 30, 2020 and December 31, 2019.

Changes in accumulated other co

Changes in accumulated other comprehensive loss by component	9 Months Ended
	Sep. 30, 2020
Changes in accumulated other comprehensive loss by component
Changes in accumulated other comprehensive loss by component	3. Changes in accumulated other comprehensive loss by component The changes in accumulated other comprehensive (loss) income by component were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Foreign currency translation Balance at beginning of period $ (146.9) $ (141.5) $ (140.6) $ (146.4) Other comprehensive income (loss): Foreign currency translation adjustments (1) 2.5 (1.6) (3.8) 3.3 Balance at end of period $ (144.4) $ (143.1) $ (144.4) $ (143.1) Pension Balance at beginning and end of period (2) $ (1.7) $ (1.4) $ (1.7) $ (1.4) Cash flow hedges Balance at beginning of period $ 1.3 $ 1.4 $ 1.6 $ 1.6 Other comprehensive (loss) income: Net change from periodic revaluations — — (0.7) (0.4) Tax benefit — — 0.2 — Total other comprehensive (loss) income before reclassifications, net of tax — — (0.5) (0.4) Net amount reclassified to earnings: Interest rate swaps (3) 0.2 — 0.4 0.2 Tax expense (0.1) — (0.1) — Total amount reclassified from accumulated other comprehensive income, net of tax 0.1 — 0.3 0.2 Total other comprehensive loss 0.1 — (0.2) (0.2) Balance at end of period $ 1.4 $ 1.4 $ 1.4 $ 1.4 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings. (2) Quarterly activity was immaterial. (3) This amount was included in interest expense, net on the accompanying condensed consolidated statements of operations .

Equity method investments in un

Equity method investments in unconsolidated affiliates	9 Months Ended
Equity method investments in unconsolidated affiliates	Sep. 30, 2020
Equity method investments in unconsolidated affiliates
Equity method investments in unconsolidated affiliates	4. Equity method investments in unconsolidated affiliates The following summarizes the operating results for the three and nine months ended September 30, 2020 and 2019, respectively, for our proportional ownership interest in equity method investments: Three Months Ended September 30, Nine Months Ended September 30, Operating results 2020 2019 2020 2019 Revenue Frederickson $ 8.3 $ 10.3 $ 22.4 $ 26.4 Orlando Cogen, LP 15.7 15.6 44.8 46.4 Chambers Cogen, LP 9.4 9.4 29.1 30.0 Craven County Wood Energy, LP (1) 2.4 1.8 6.2 1.8 Grayling Generating Station, LP (1) 0.4 0.8 2.0 0.8 36.2 37.9 104.5 105.4 Project expenses Frederickson 5.8 7.5 16.3 20.0 Orlando Cogen, LP 6.7 6.9 19.8 21.5 Chambers Cogen, LP 7.7 8.9 23.7 26.1 Craven County Wood Energy, LP (1) 2.6 1.6 8.3 1.6 Grayling Generating Station, LP (1) 0.9 0.5 3.4 0.5 23.7 25.4 71.5 69.7 Project other expenses Frederickson — — — — Orlando Cogen, LP — — — — Chambers Cogen, LP (0.3) (0.4) (1.1) (1.3) Craven County Wood Energy, LP (1) — — — — Grayling Generating Station, LP (1) (0.1) — (0.1) — (0.4) (0.4) (1.2) (1.3) Net income (loss) Frederickson 2.5 2.8 6.1 6.4 Orlando Cogen, LP 9.0 8.7 25.0 24.9 Chambers Cogen, LP 1.4 0.1 4.3 2.6 Craven County Wood Energy, LP (1) (0.2) 0.2 (2.1) 0.2 Grayling Generating Station, LP (1) (0.6) 0.3 (1.5) 0.3 Equity in earnings of unconsolidated affiliates $ 12.1 $ 12.1 $ 31.8 $ 34.4 Distributions from equity method investments (15.7) (16.0) (37.3) (41.4) Deficit in earnings of equity method investments, net of distributions $ (3.6) $ (3.9) $ (5.5) $ (7.0) (1) We acquired our equity interests in Craven County Wood Energy, LP and Grayling Generating Station, LP on August 13, 2019.

Long-term debt

Long-term debt	9 Months Ended
Long-term debt	Sep. 30, 2020
Long-term debt
Long-term debt	5. Long-term debt Long-term debt consists of the following: September 30, December 31, 2020 2019 Interest Rate Recourse Debt: Senior secured term loan facility, due 2025 (1) $ 326.0 $ 380.0 LIBOR (2) plus 2.50 % Senior unsecured notes, due June 2036 (Cdn$210.0) 157.4 161.7 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3)(4) 15.6 18.7 LIBOR plus 1.61 % Less: unamortized discount (4.1) (5.8) Less: unamortized deferred financing costs (4.2) (4.7) Less: current maturities (91.0) (76.4) Total long-term debt $ 399.7 $ 473.5 Current maturities consist of the following: September 30, December 31, 2020 2019 Interest Rate Current Maturities: Senior secured term loan facility, due 2025 (1) $ 88.0 $ 72.5 LIBOR (2) plus 2.50 % Cadillac term loan, due 2025 (3) 3.0 3.9 LIBOR plus 1.61 % Total current maturities $ 91.0 $ 76.4 (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 of the $326.0 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2020. See Note 7, 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 7, Accounting for derivative instruments and hedging activities , for further details. (4) The Cadillac term loan credit agreement (the “Cadillac Term Loan”) contains various affirmative and negative covenants which relate to, including, among other things, the operation of the Cadillac plant, compliance with laws, incurrence of additional debt and restricted payments (as defined in the Cadillac Term Loan). One of the negative covenants requires the Cadillac project to meet certain key financial ratios, including a debt service coverage ratio (as defined in the Cadillac Term Loan). Beginning March 31, 2020, and as of September 30, 2020, we determined that the Cadillac project did not fulfill the debt service coverage ratio as required by the Cadillac Term Loan. Due to the breach of the covenant, the Cadillac project is prevented from making restricted payments (as defined in the Cadillac Term Loan) until several conditions are met, including, among other things, (i) the debt service coverage ratio for the most-recently ended period of four consecutive fiscal quarters is at least 1.2 to 1.0 and (ii) the projected debt service coverage ratio for the four consecutive fiscal quarters immediately following the period described in (i) is at least 1.2 to 1.0. We have not made any restricted payments (as defined in the Cadillac Term Loan) since July 31, 2019. Term Loan Amendment and Repricing Extension of Revolving Credit Facility On March 18, 2020, we executed an amendment to our Revolver. The amendment provides for an extension of the Revolver maturity date to April 2025, to coincide with the maturity date of the senior Term Loan. Both the Revolver and the Term Loan are at our APLP Holdings subsidiary. In conjunction with the extension, the Revolver capacity was reduced to $180 million from $200 million previously. The amendment allows an upsizing of the Revolver capacity by up to $30 million, to a maximum aggregate amount of $210 million, subject to approval of the two letter of credit issuer banks and increased commitments by existing or new lenders. Such an upsizing would not require a further amendment. There were no other significant changes to the terms of the Revolver. As a result of the extension, during the nine months ended September 30, 2020, we recorded $0.9 million of new deferred financing costs, which will be amortized over the remaining term of the Revolver. At September 30, 2020, we had no borrowings under the Revolver and utilized $78.0 million of borrowing capacity for letters of credit. Renewal of Shelf Registration Statement On August 24, 2020, we filed a shelf registration statement on Form S-3, which was declared effective by the SEC on August 25, 2020 (the “Shelf Registration Statement”), and is available for use for three years in the United States. The Shelf Registration Statement allows the Company to sell from time to time up to $250 million of common shares, debt securities, warrants, subscription receipts or units comprised of any combination of these securities, for its own account in one or more offerings. We also filed a base short-form prospectus dated August 24, 2020 qualifying the distribution of such securities concurrently with Canadian securities regulators.

Fair value of financial instrum

Fair value of financial instruments	9 Months Ended
Fair value of financial instruments	Sep. 30, 2020
Fair value of financial instruments
Fair value of financial instruments	6. Fair value of financial instruments The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2020 and December 31, 2019. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. September 30, 2020 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 30.3 $ — $ — $ 30.3 Restricted cash 2.6 — — 2.6 Derivative instruments asset — — — — Total $ 32.9 $ — $ — $ 32.9 Liabilities: Derivative instruments liability $ — $ 18.2 $ 1.5 $ 19.7 Total $ — $ 18.2 $ 1.5 $ 19.7 December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 74.9 $ — $ — $ 74.9 Restricted cash 7.7 — — 7.7 Derivative instruments asset — 0.7 — 0.7 Total $ 82.6 $ 0.7 $ — $ 83.3 Liabilities: Derivative instruments liability $ — $ 24.7 $ 3.2 $ 27.9 Total $ — $ 24.7 $ 3.2 $ 27.9 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, 2020, the credit valuation adjustments resulted in a $0.5 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $0.4 million gain in change in fair value of derivative instruments. As of December 31, 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. 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, 2020 and 2019, the beginning and ending balances for the conversion option derivative that is recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs: Fair value Nine Months Ended September 30, 2020 Beginning balance of liability at January 1, 2020 $ 3.2 Total unrealized gain (1.8) Currency transaction loss 0.1 Ending balance of liability at September 30, 2020 $ 1.5 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 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, 2020
Accounting for derivative instruments and hedging activities
Accounting for derivative instruments and hedging activities	7. Accounting for derivative instruments and hedging activities We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts. Gas purchase and sale agreements We have 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 condensed consolidated balance sheets at fair value and the changes in its fair market value are recorded in the condensed consolidated statements of operations. We also have a corresponding gas sales agreement at Nipigon, whereby On May 15, 2020, we also entered into natural gas purchase agreements at our Morris project for approximately 700,000 MMBtu from January 2021 through February 2021 to effectively mitigate seasonal fluctuations of future natural gas prices. This contract is accounted for as a derivative financial instrument and is recorded in the condensed consolidated balance sheet at fair value. Changes in the fair market value of this contract are recorded in the condensed 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 condensed consolidated balance sheets at fair value and the changes in their fair market value are recorded in the condensed consolidated statements of operations. We have entered into various natural gas swaps to effectively fix the price of 13.5 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 2020 through 2023. These contracts are accounted for as derivative financial instruments and are recorded in the condensed consolidated balance sheet at fair value at September 30, 2020. Changes in the fair market value of these contracts are recorded in the condensed consolidated statement of operations. Interest rate swaps 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, 2020, these agreements totaled $326 million notional amount of the remaining $326 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 2.50%. Based on the terms of the Term Loan Facility, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 3.50% all-in rate on the Term Loan Facility for the remaining principal amount. The weighted average rate of these swap agreements is 2.23%, resulting in an all-in rate of approximately 4.73% for $326 million of the Term Loan Facility. The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.3% through February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of the Cadillac Term Loan. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss). Foreign currency forward contracts We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our Medium Term Notes due June 23, 2036 (“MTNs”). Principal and interest payments for our Term Loan are made in U.S. dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the future interest and principal payments, preferred dividends and other working capital requirements. Foreign currency forward contracts are not designated as hedges, and changes in their market value are recorded in foreign exchange on the condensed consolidated statements of operations. As of September 30, 2020, we have no foreign currency forward contracts. Volume of forecasted transactions We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for NPNS exemption at September 30, 2020 and December 31, 2019: September 30, December 31, Units 2020 2019 Natural gas swaps Natural Gas (MMBtu) 13.5 16.3 Gas purchase agreements Natural Gas (Gigajoules) 6.0 6.4 Interest rate swaps Interest (US$) 421.6 468.4 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, 2020 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.6 Interest rate swaps long-term — 1.1 Total derivative instruments designated as cash flow hedges — 1.7 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 4.8 Interest rate swaps long-term — 1.9 Natural gas swaps current — 0.1 Natural gas swaps long-term — 1.7 Gas purchase agreements current — 3.6 Gas purchase agreements long-term — 4.4 Convertible debenture conversion option — 1.5 Total derivative instruments not designated as cash flow hedges — 18.0 Total derivative instruments $ — $ 19.7 December 31, 2019 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.4 Interest rate swaps long-term — 1.1 Total derivative instruments designated as cash flow hedges — 1.5 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 1.9 Interest rate swaps long-term — 1.1 Natural gas swaps current — 1.9 Natural gas swaps long-term — 4.2 Gas purchase agreements current 0.7 4.6 Gas purchase agreements long-term — 9.5 Convertible debenture conversion option — 3.2 Total derivative instruments not designated as cash flow hedges 0.7 26.4 Total derivative instruments $ 0.7 $ 27.9 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, 2020 Swaps Accumulated OCI balance at July 1, 2020 $ 1.3 Change in fair value of cash flow hedges — Realized from OCI during the period 0.1 Accumulated OCI balance at September 30, 2020 $ 1.4 Interest Rate Three Months Ended September 30, 2019 Swaps Accumulated OCI balance at July 1, 2019 $ 1.4 Change in fair value of cash flow hedges — Realized from OCI during the period — Accumulated OCI balance at September 30, 2019 $ 1.4 Interest Rate Nine Months Ended September 30, 2020 Swaps Accumulated OCI balance at January 1, 2020 $ 1.6 Change in fair value of cash flow hedges (0.5) Realized from OCI during the period 0.3 Accumulated OCI balance at September 30, 2020 $ 1.4 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 $ 1.4 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 2020 2019 2020 2019 Gas purchase agreements Fuel $ 2.1 $ 2.1 $ 6.2 $ 6.1 Natural gas swaps Fuel 0.8 0.6 2.4 0.5 Interest rate swaps Interest, net 1.7 (0.9) 2.9 (4.6) 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 2020 2019 2020 2019 Natural gas swaps Change in fair value of derivatives $ 3.8 $ (1.0) $ 4.4 $ (3.5) Gas purchase agreements Change in fair value of derivatives 2.5 3.7 4.9 3.5 Interest rate swaps Change in fair value of derivatives 1.8 (1.6) (3.7) (8.3) $ 8.1 $ 1.1 $ 5.6 $ (8.3) Convertible debenture conversion option Other (income) expense, net $ (3.8) $ (0.3) $ (1.8) $ 1.5 X

Income taxes

Income taxes	9 Months Ended
Income taxes	Sep. 30, 2020
Income taxes
Income taxes	8. Income taxes The following table summarizes the current and deferred portions of the net income tax expense: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Current income tax expense $ 2.1 $ 1.3 $ 4.5 $ 4.2 Deferred income tax expense (benefit) 0.4 (1.1) 0.7 (1.8) Total income tax expense, net $ 2.5 $ 0.2 $ 5.2 $ 2.4 For the three and nine months ended September 30, 2020 and 2019 Income tax expense for the three months ended September 30, 2020 was $2.5 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $5.5 million. The primary items impacting the tax rate for the three months ended September 30, 2020 were a net decrease to our valuation allowances of $2.7 million, consisting of $0.2 million increases in Canada due to the incurrence of operating losses and $2.9 million decreases in the United States due to the utilization of net operating losses, and $1.4 million relating to foreign exchange losses. These items were partially offset by $1.1 million relating to withholding, federal and state taxes. 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 item 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 in both jurisdictions. This item was partially offset by $0.5 million relating to withholding, federal and state taxes and $0.2 million of other permanent differences. Income tax expense for the nine months ended September 30, 2020 was $5.2 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $11.5 million. The primary item impacting the tax rate for the nine months ended September 30, 2020 was a net decrease to our valuation allowances of $11.6 million, consisting of $3.6 million decreases in Canada and $8.0 million decreases in the United States due to the utilization of net operating losses in both jurisdictions. This item was offset by $2.7 million related to changes in estimates due to tax filings, $1.7 million relating to withholding, federal and state taxes and $0.9 million of other permanent differences. 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 due to the incurrence of operating losses 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, federal and state taxes and $0.7 million of other permanent differences. As of September 30, 2020, we have recorded a valuation allowance of $133.8 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

Equity compensation plans

Equity compensation plans	9 Months Ended
Equity compensation plans	Sep. 30, 2020
Equity compensation plans
Equity compensation plans	9. Equity compensation plans Long-term incentive plan (“LTIP”) The following table summarizes the changes in outstanding LTIP notional shares during the nine months ended September 30, 2020: Grant Date Weighted-Average Notional Shares Fair Value per Notional Share Outstanding at December 31, 2019 3,578,092 $ 2.38 Granted 1,866,748 2.49 Vested and redeemed (1,702,571) 2.34 Forfeitures (31,929) 2.42 Outstanding at September 30, 2020 3,710,340 $ 2.45 Cash payments made for vested notional shares for the nine months ended September 30, 2020 and 2019 were $3.3 million and $2.0 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.0 million and $3.0 million for the three and nine months ended September 30, 2020, respectively, and $1.1 million and $3.1 million for the three and nine months ended September 30, 2019, respectively. Transition Equity Participation Agreement We also have 269,952 transition notional shares outstanding at September 30, 2020 under the Transition Equity Participation Agreement with James J. Moore, Jr. These notional shares will vest if the weighted average Canadian dollar closing price of our common shares on the Toronto Stock Exchange exceeds Cdn$4.77 for at least three consecutive calendar months. These notional shares will also vest in the event that Mr. Moore is terminated without cause, resigns for good reason, or dies.

Basic and diluted earnings per

Basic and diluted earnings per share	9 Months Ended
Basic and diluted earnings per share	Sep. 30, 2020
Basic and diluted earnings per share
Basic and diluted earnings per share	10. Basic and diluted earnings per share Basic earnings per share is calculated by dividing net income 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. computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period . 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 per share for the three and nine months ended September 30, 2020 and 2019: Three Months Ended September 30, Nine Months Ended September 30, Basic 2020 2019 2020 2019 Numerator: Net income attributable to Atlantic Power Corporation $ 16.2 $ 12.6 $ 40.0 $ 22.7 Denominator: Weighted average basic shares outstanding 89.5 109.4 98.1 109.4 Basic earnings per share attributable to Atlantic Power Corporation $ 0.18 $ 0.12 $ 0.41 $ 0.21 Diluted Numerator: Net income attributable to Atlantic Power Corporation $ 16.2 $ 12.6 $ 40.0 $ 22.7 Add: convertible debenture interest expense 1.0 1.0 2.8 3.1 17.2 13.6 42.8 25.8 Denominator: Weighted average basic shares outstanding 89.5 109.4 98.1 109.4 Share-based compensation 0.9 1.0 0.9 1.0 Convertible debentures 27.4 27.4 27.4 27.9 117.8 137.8 126.4 138.3 Diluted earnings per share attributable to Atlantic Power Corporation $ 0.15 $ 0.10 $ 0.34 $ 0.19

Equity

Equity	9 Months Ended
Equity	Sep. 30, 2020
Equity
Equity	11. 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, 2020 and 2019: Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Deficit Company Equity Balance at June 30, 2020 $ 1,224.6 $ (1,140.4) $ (147.3) $ (63.1) $ 168.8 $ 105.7 Net income — 16.2 — 16.2 1.6 17.8 Share-based compensation 0.3 — — 0.3 — 0.3 Common share repurchases (5.5) — — (5.5) — (5.5) 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$0.358688 per share) — — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.286976 per share) — — — — (0.2) (0.2) Realized and unrealized loss on hedging activities, net of tax — — 0.1 0.1 — 0.1 Foreign currency translation adjustments — — 2.5 2.5 — 2.5 Balance at September 30, 2020 $ 1,219.4 $ (1,124.2) $ (144.7) $ (49.5) $ 168.8 $ 119.3 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Equity Company Equity Balance at June 30, 2019 $ 1,260.9 $ (1,111.5) $ (141.5) $ 7.9 $ 182.9 $ 190.8 Net income — 12.6 — 12.6 1.7 14.3 Share-based compensation 0.4 — — 0.4 — 0.4 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) Foreign currency translation adjustments — — (1.6) (1.6) — (1.6) Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 19.3 $ 182.7 $ 202.0 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Deficit Company Equity Balance at January 1, 2020 $ 1,259.9 $ (1,164.2) $ (140.7) $ (45.0) $ 182.7 $ 137.7 Net income (loss) — 40.0 — 40.0 (2.5) 37.5 Share-based compensation 1.1 — — 1.1 — 1.1 Common share repurchases (41.6) — — (41.6) — (41.6) Preferred share repurchases — — — — (6.4) (6.4) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — — (2.4) (2.4) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.076064 per share) — — — — (1.9) (1.9) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.013464 per share) — — — — (0.7) (0.7) Realized and unrealized loss on hedging activities, net of tax — — (0.2) (0.2) — (0.2) Foreign currency translation adjustments — — (3.8) (3.8) — (3.8) Balance at September 30, 2020 $ 1,219.4 $ (1,124.2) $ (144.7) $ (49.5) $ 168.8 $ 119.3 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Equity Company Equity Balance at January 1, 2019 $ 1,260.9 $ (1,121.6) $ (146.2) $ (6.9) $ 199.3 $ 192.4 Net income (loss) — 22.7 — 22.7 (3.1) 19.6 Share-based compensation 1.2 — — 1.2 — 1.2 Common share repurchases (0.8) — — (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, net of tax — — (0.2) (0.2) — (0.2) Foreign currency translation adjustments — — 3.3 3.3 — 3.3 Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 19.3 $ 182.7 $ 202.0 Share Repurchase Programs Normal Course Issuer Bid On December 31, 2019, we commenced a new Normal Course Issuer Bid (“NCIB”) for our 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, 2020 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIBs. Under the NCIB, we may purchase up to a total of 10,578,799 common shares based on 10% of our public float as of December 17, 2019 and we are limited to daily purchases of 9,243 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. We may also purchase up to Cdn$11.5 million of Series E Debentures; 384,750 shares of 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”); 223,072 shares of 7.0% Cumulative Rate Preferred Shares Series 2 (the “Series 2 Shares”); and 133,031 shares of Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of APPEL. 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), or other designated exchanges and published marketplaces in the United States in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval. The NCIB permits the Company to repurchase common and preferred shares and Series E Debentures. In addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our Series E 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 Exchange Act, 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. Beginning on March 25, 2020, we commenced a Substantial Issuer Bid (“SIB”) (described below) that expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL. In the nine months ended September 30, 2020, we repurchased and cancelled 7,540,105 common shares under the NCIB at a total cost of $15.8 million. In the nine months ended September 30, 2020, we also repurchased and cancelled 381,794 Series 1 Shares, 62,365 Series 2 Shares and 120,000 Series 3 Shares of APPEL at a total cost of $6.4 million. As a result of the repurchase, a $7.4 million loss was attributed to the preferred shares of a subsidiary company in the condensed consolidated statements of operations for the nine months ended September 30, 2020. Substantial Issuer Bid On March 25, 2020, we commenced a SIB for the purchase of up to $25 million common shares. This was equivalent to 12,820,512 common shares, or approximately 12% of our total issued and outstanding common shares based on a $1.95 per share purchase price (the minimum price per common share under the offer) as measured on the date of commencement. The SIB expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL. The SIB proceeded by way of a “modified Dutch auction.” Holders of common shares were able to tender to the offer by: (i) auction tenders in which they specified the number of common shares being tendered at a price of not less than US The purchase price paid by the Company for each validly deposited common share was based on the number of common shares validly deposited pursuant to auction tenders and purchase price tenders, and the prices specified by shareholders making auction tenders. The purchase price was the lowest price which enabled the Company to purchase common shares up to the maximum amount available for auction tenders and purchase price tenders, determined in accordance with the terms of the offer. Common shares that were deposited at or below the final determined purchase price were purchased at such purchase price. Common shares that were not taken up in connection with the offer, including common shares deposited pursuant to auction tenders at prices above the purchase price, were returned to the shareholders. We repurchased and cancelled 12,500,000 common shares under the SIB at a total cost of $25.8 million, including transaction costs, upon its expiration on April 30, 2020.

Segment and geographic informat

Segment and geographic information	9 Months Ended
Segment and geographic information	Sep. 30, 2020
Segment and geographic information
Segment and geographic information	12. Segment and geographic information We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management’s structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for the comparative 2019 period has been revised to conform to the new segment presentation. 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. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about 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 method 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, 2020 and 2019 is included in the tables below: Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Three Months Ended September 30, 2020 Project revenues $ 26.7 $ 29.1 $ 9.2 $ 0.2 $ 65.2 Segment assets 229.7 208.4 353.0 49.3 840.4 Project Adjusted EBITDA $ 17.1 $ 27.1 $ 5.6 $ (0.3) $ 49.5 Change in fair value of derivative instruments — (6.3) — (1.8) (8.1) Depreciation and amortization 5.7 8.2 4.9 — 18.8 Interest, net 0.6 — — 0.2 0.8 Project income 10.8 25.2 0.7 1.3 38.0 Administration — — — 5.6 5.6 Interest expense, net — — — 10.8 10.8 Foreign exchange loss — — — 5.1 5.1 Other income, net — — — (3.8) (3.8) Net income (loss) before income taxes 10.8 25.2 0.7 (16.4) 20.3 Income tax expense — — — 2.5 2.5 Net income (loss) $ 10.8 $ 25.2 $ 0.7 $ (18.9) $ 17.8 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Three Months Ended September 30, 2019 Project revenues $ 26.1 $ 35.1 $ 9.7 $ 0.2 $ 71.1 Segment assets 295.6 251.3 371.6 78.7 997.2 Project Adjusted EBITDA $ 13.2 $ 29.6 $ 6.3 $ (0.2) $ 48.9 Change in fair value of derivative instruments — (2.6) — 1.6 (1.0) Depreciation and amortization 6.0 9.3 4.9 — 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) 5.4 23.0 1.4 (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) Net income (loss) before income taxes 5.4 23.0 1.4 (15.3) 14.5 Income tax expense — — — 0.2 0.2 Net income (loss) $ 5.4 $ 23.0 $ 1.4 $ (15.5) $ 14.3 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Nine Months Ended September 30, 2020 Project revenues $ 67.4 $ 86.7 $ 45.5 $ 0.7 $ 200.3 Segment assets 229.7 208.4 353.0 49.3 840.4 Project Adjusted EBITDA $ 23.3 $ 79.1 $ 35.7 $ (1.0) $ 137.1 Change in fair value of derivative instruments — (9.3) — 3.7 (5.6) Depreciation and amortization 16.8 26.6 14.7 0.2 58.3 Interest, net 2.0 — — 0.1 2.1 Project income (loss) 4.5 61.8 21.0 (5.0) 82.3 Administration — — — 16.8 16.8 Interest expense, net — — — 31.7 31.7 Foreign exchange gain — — — (6.2) (6.2) Other income, net — — — (2.7) (2.7) Net income (loss) before income taxes 4.5 61.8 21.0 (44.6) 42.7 Income tax expense — — — 5.2 5.2 Net income (loss) $ 4.5 $ 61.8 $ 21.0 $ (49.8) $ 37.5 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Nine Months Ended September 30, 2019 Project revenues $ 64.5 $ 99.6 $ 50.6 $ 0.7 $ 215.4 Segment assets 295.6 251.3 371.6 78.7 997.2 Project Adjusted EBITDA $ 31.5 $ 80.6 $ 41.2 $ (0.1) $ 153.2 Change in fair value of derivative instruments — 0.1 — 8.2 8.3 Depreciation and amortization 17.9 28.0 14.6 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) 10.3 51.6 26.6 (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 10.3 51.6 26.6 (66.5) 22.0 Income tax expense — — — 2.4 2.4 Net income (loss) $ 10.3 $ 51.6 $ 26.6 $ (68.9) $ 19.6 The tables below provide information, by country, about our consolidated operations for the three and nine months ended September 30, 2020 and 2019 and for Property, Plant and Equipment, PPAs and other intangible assets and total assets as of September 30, 2020 and December 31, 2019, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located. Project revenue Three Months Ended Nine Months Ended September 30, September 30, 2020 2019 2020 2019 United States $ 46.5 $ 54.9 $ 140.1 $ 159.5 Canada 18.7 16.2 60.2 55.9 Total $ 65.2 $ 71.1 $ 200.3 $ 215.4 Property, Plant and PPAs and Equipment, net of other intangible assets, net of accumulated depreciation accumulated amortization Total assets September 30, 2020 December 31, 2019 September 30, 2020 December 31, 2019 September 30, 2020 December 31, 2019 United States $ 357.7 $ 353.9 $ 124.8 $ 142.8 $ 666.5 $ 762.3 Canada 137.1 148.2 1.0 1.5 173.9 173.3 Total $ 494.8 $ 502.1 $ 125.8 $ 144.3 $ 840.4 $ 935.6 Concentration risk Georgia Power Company, Independent Electricity System Operator (“IESO”), BC Hydro, and Equistar Chemicals, LP, provided 15.5%, 12.2%, 11.3%, and 10.7%, respectively, of total consolidated revenues for the three months ended September 30, 2020. Georgia Power Company, 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. Niagara Mohawk, IESO, Georgia Power Company, BC Hydro, and Equistar Chemicals, LP provided 16.1%, 13.5%, 11.6%, 11.2% and 10.8%, respectively, of total consolidated revenues for the nine months ended September 30, 2020. 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 purchases electricity from the Curtis Palmer project in the Hydroelectric segment, IESO purchases electricity from the Calstock, Tunis, and Nipigon projects in the Solid Fuel and Natural Gas segments, Georgia Power Company purchases electricity from the Piedmont project in the Solid Fuel segment, Equistar Chemicals, LP purchases electricity from the Morris project in the Natural Gas segment, and BC Hydro purchases electricity from the Mamquam and Moresby Lake projects in the Hydroelectric segment and the Williams Lake project in the Solid Fuel segment.

Guarantees and Contingencies

Guarantees and Contingencies	9 Months Ended
Guarantees and Contingencies	Sep. 30, 2020
Guarantees and Contingencies
Guarantees and Contingencies	13. Guarantees and Contingencies Guarantees We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Contingencies 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 plant’s fire protection system and 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. Reconstruction of Cadillac was completed in late July 2020 and the plant was recommissioned, tested and returned to service on August 20, 2020. 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. 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. The business interruption deductible under the policies insuring the Cadillac assets is 45 days of lost production, which we estimate had an approximate $1.4 million impact to cash flows from operations in the year ended December 31, 2019, the period when the deductible was fulfilled. Impact The Cadillac biomass plant is a component of our Solid Fuel segment. 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 the date of the incident. Because the plant experienced significant damage and it was probable that insurance proceeds would be received in order to repair the facility, we applied accounting for gains and losses on involuntary conversions. Insurance proceeds received in excess of incurred losses will be accounted for as gain contingencies. Reimbursements for lost profits, or business interruption losses, are accounted for as a gain contingency because lost profits are not considered an incurred loss. Based on loss estimates and expenses incurred through September 30, 2019, we recorded a $25 million write-down of Cadillac’s property, plant and equipment and a $0.3 million write-down of capital spares inventory in the three months ended September 30, 2019. We also recorded a corresponding insurance receivable ($24.2 million), a component of other current assets, less the $1.0 million property damage deductible, which was recorded as a charge to other project income, because we believed that it was probable we would receive insurance recoveries up to our estimated plant write-down. As the plant was repaired, any costs incurred were capitalized to property, plant and equipment. During the three months ended December 31, 2019, we recorded an additional $0.6 million write-down of fuel inventory, with a corresponding increase to the insurance receivable. During the year ended December 31, 2019, we received $11.3 million of insurance proceeds with respect to the fire at Cadillac, which were applied against the cumulative insurance receivable of $24.8 million. We received insurance proceeds of $7.0 million and $19.7 million for the three and nine months ended September 30, 2020, respectively, bringing the total cumulative proceeds received to $31.0 million. As of September 30, 2020, the insurance receivable balance has been reduced to zero. During the third quarter 2020, we recorded business interruption proceeds of $6.2 million. These business interruption proceeds are included in other project income on our condensed consolidated statements of operations. As of November 6, 2020, we estimate additional insurance recoveries related to business interruption losses and property losses in the range of $10.0 to $11.0 million in settlement of the claim. We expect all contingencies related to the remaining business interruption losses and property losses to be resolved once final payment is received from the insurers, which is when we will recognize the reimbursements on our condensed consolidated statement of operations. 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, 2020.

Leases

Leases	9 Months Ended
Leases	Sep. 30, 2020
Leases
Leases	14. 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 condensed 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 was our minimum all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount. The following table presents the components of lease expense. Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Lease cost: (1) Operating lease cost $ 0.5 $ 0.5 $ 1.6 $ 1.3 Sublease income (0.3) (0.3) (0.8) (0.9) Total lease cost $ 0.2 $ 0.2 $ 0.8 $ 0.4 (1) The following table presents operating and finance lease maturities and a reconciliation of the undiscounted cash flows to operating lease liabilities. Lease Income from Net lease Payments subleasing payments 2020 $ 0.6 $ (0.3) $ 0.3 2021 2.0 (1.1) 0.9 2022 1.7 (1.1) 0.6 2023 1.2 (0.7) 0.5 2024 0.1 — 0.1 Thereafter — — — Total operating lease payments $ 5.6 $ (3.2) $ 2.4 Less: present value discount (0.2) Total operating lease liabilities $ 5.4 Lease Payments 2020 $ — 2021 0.1 2022 0.1 Thereafter — Total finance lease payments $ 0.2 Less: amount representing interest (0.1) Total finance lease liabilities $ 0.1 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) Operating cash flows from operating leases $ 0.8 Weighted average remaining lease term (in years): Operating leases 2.9 Finance leases 1.7 Weighted average discount rate - operating leases 3.9 % Weighted average discount rate - finance leases 4.1 % (1) We have no lease transactions with related parties. 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, 2020, we have ten PPAs accounted for as operating leases 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 nineteen months to twenty-three years . 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, 2020 2019 2020 2019 Solid Fuel $ 19.0 $ 26.1 $ 51.1 $ 64.4 Natural Gas 7.0 6.5 19.0 18.4 Hydroelectric 9.2 9.7 45.5 50.6 $ 35.2 $ 42.3 $ 115.6 $ 133.4 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
Nature of business (Policies)	Sep. 30, 2020
Nature of business
Basis of presentation	Basis of presentation The interim condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2019. 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, 2020, the results of operations and comprehensive income for the three and nine months ended September 30, 2020 and 2019, and our cash flows for the nine months ended September 30, 2020 and 2019, in accordance with U.S. generally accepted accounting principles (“GAAP”). 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 method 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
COVID-19 Pandemic	COVID-19 Pandemic There are many uncertainties regarding the ongoing coronavirus (“COVID-19”) pandemic, and we are closely monitoring the impact of COVID-19 on all aspects of our business, including how it will impact our customers, employees, suppliers, vendors and business partners. We have taken extra precautions for our employees who continue to work at our facilities and have implemented work-from-home policies where appropriate. Currently, we do not anticipate any employee layoffs and are continuing to maintain the high level of reliability and availability of our plants. We continue to implement strong physical and cybersecurity measures to ensure that our systems remain functional in order to serve our operational needs with a remote workforce and to keep our operations running to ensure uninterrupted service to our offtakers.
Recently adopted and issued accounting standards	Recently adopted and issued accounting standards Accounting standards adopted In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance amends the guidance on measuring credit losses on financial assets held at amortized cost. ASU 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. This guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted ASU 2016-13 on January 1, 2020 and it did not have a material impact on the condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurements” 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 adopted this guidance on January 1, 2020 and it did not have an impact on the condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-09, “Codification Improvements” 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 adopted this guidance on January 1, 2020 and it did not have a material impact on the condensed consolidated financial statements. Accounting standards to be implemented In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans (Subtopic 715-20)”, to improve the effectiveness of benefit plan disclosures in the notes to financial statements by facilitating clear communication of the information required by GAAP that is most important to users of each entity’s financial statements. The amendments in this ASU modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Additionally, the amendments in this ASU remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The amendments in this ASU are effective for fiscal years ending after December 15, 2020, for public business entities and early adoption is permitted for all entities. We are currently evaluating the impact that adoption will have on our disclosures. In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. We are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements. In March 2020, the FASB issued amendments to the guidance for reference rate reform through ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the effects of reference rate reform on financial reporting.” The amendments in this update provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022. The amendments are elective and are effective upon issuance for all entities. We

Revenue from contracts (Tables)

Revenue from contracts (Tables)	9 Months Ended
Revenue from contracts (Tables)	Sep. 30, 2020
Revenue from contracts
Schedule of disaggregation of revenue	Three Months Ended September 30, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 14.3 $ 7.5 $ 8.5 $ — $ 30.3 Energy capacity revenue 12.2 17.5 — — 29.7 Steam energy and capacity revenue — 2.5 — — 2.5 Waste heat revenue 0.1 — — — 0.1 Ancillary and transmission services — 0.7 0.7 — 1.4 Asset management and operation — — — 0.2 0.2 Miscellaneous revenue 0.1 0.9 — — 1.0 26.7 29.1 9.2 0.2 65.2 Three Months Ended September 30, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 12.4 $ 7.7 $ 9.1 $ — $ 29.2 Energy capacity revenue 13.7 24.3 — — 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 26.1 35.1 9.7 0.2 71.1 Nine Months Ended September 30, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 40.6 $ 18.4 $ 43.1 $ — $ 102.1 Energy capacity revenue 26.2 58.6 — — 84.8 Steam energy and capacity revenue — 6.8 — — 6.8 Waste heat revenue 0.5 — — — 0.5 Ancillary and transmission services — 2.2 2.4 — 4.6 Asset management and operation — — — 0.7 0.7 Miscellaneous revenue 0.1 0.7 — — 0.8 67.4 86.7 45.5 0.7 200.3 Nine Months Ended September 30, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 30.7 $ 23.6 $ 48.4 $ — $ 102.7 Energy capacity revenue 33.7 66.1 — — 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 0.1 (0.5) — — (0.4) 64.5 99.6 50.6 0.7 215.4

Changes in accumulated other _2

Changes in accumulated other comprehensive loss by component (Tables)	9 Months Ended
	Sep. 30, 2020
Changes in accumulated other comprehensive loss by component
Schedule of changes in accumulated other comprehensive (loss) income	The changes in accumulated other comprehensive (loss) income by component were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Foreign currency translation Balance at beginning of period $ (146.9) $ (141.5) $ (140.6) $ (146.4) Other comprehensive income (loss): Foreign currency translation adjustments (1) 2.5 (1.6) (3.8) 3.3 Balance at end of period $ (144.4) $ (143.1) $ (144.4) $ (143.1) Pension Balance at beginning and end of period (2) $ (1.7) $ (1.4) $ (1.7) $ (1.4) Cash flow hedges Balance at beginning of period $ 1.3 $ 1.4 $ 1.6 $ 1.6 Other comprehensive (loss) income: Net change from periodic revaluations — — (0.7) (0.4) Tax benefit — — 0.2 — Total other comprehensive (loss) income before reclassifications, net of tax — — (0.5) (0.4) Net amount reclassified to earnings: Interest rate swaps (3) 0.2 — 0.4 0.2 Tax expense (0.1) — (0.1) — Total amount reclassified from accumulated other comprehensive income, net of tax 0.1 — 0.3 0.2 Total other comprehensive loss 0.1 — (0.2) (0.2) Balance at end of period $ 1.4 $ 1.4 $ 1.4 $ 1.4 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings. (2) Quarterly activity was immaterial. (3) This amount was included in interest expense, net on the accompanying condensed consolidated statements of operations .

Equity method investments in _2

Equity method investments in unconsolidated affiliates (Tables)	9 Months Ended
	Sep. 30, 2020
Equity method investments in unconsolidated affiliates
Summary of operating results	Three Months Ended September 30, Nine Months Ended September 30, Operating results 2020 2019 2020 2019 Revenue Frederickson $ 8.3 $ 10.3 $ 22.4 $ 26.4 Orlando Cogen, LP 15.7 15.6 44.8 46.4 Chambers Cogen, LP 9.4 9.4 29.1 30.0 Craven County Wood Energy, LP (1) 2.4 1.8 6.2 1.8 Grayling Generating Station, LP (1) 0.4 0.8 2.0 0.8 36.2 37.9 104.5 105.4 Project expenses Frederickson 5.8 7.5 16.3 20.0 Orlando Cogen, LP 6.7 6.9 19.8 21.5 Chambers Cogen, LP 7.7 8.9 23.7 26.1 Craven County Wood Energy, LP (1) 2.6 1.6 8.3 1.6 Grayling Generating Station, LP (1) 0.9 0.5 3.4 0.5 23.7 25.4 71.5 69.7 Project other expenses Frederickson — — — — Orlando Cogen, LP — — — — Chambers Cogen, LP (0.3) (0.4) (1.1) (1.3) Craven County Wood Energy, LP (1) — — — — Grayling Generating Station, LP (1) (0.1) — (0.1) — (0.4) (0.4) (1.2) (1.3) Net income (loss) Frederickson 2.5 2.8 6.1 6.4 Orlando Cogen, LP 9.0 8.7 25.0 24.9 Chambers Cogen, LP 1.4 0.1 4.3 2.6 Craven County Wood Energy, LP (1) (0.2) 0.2 (2.1) 0.2 Grayling Generating Station, LP (1) (0.6) 0.3 (1.5) 0.3 Equity in earnings of unconsolidated affiliates $ 12.1 $ 12.1 $ 31.8 $ 34.4 Distributions from equity method investments (15.7) (16.0) (37.3) (41.4) Deficit in earnings of equity method investments, net of distributions $ (3.6) $ (3.9) $ (5.5) $ (7.0) (1) We acquired our equity interests in Craven County Wood Energy, LP and Grayling Generating Station, LP on August 13, 2019.

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
Long-term debt (Tables)	Sep. 30, 2020
Schedule of current maturities	Current maturities consist of the following: September 30, December 31, 2020 2019 Interest Rate Current Maturities: Senior secured term loan facility, due 2025 (1) $ 88.0 $ 72.5 LIBOR (2) plus 2.50 % Cadillac term loan, due 2025 (3) 3.0 3.9 LIBOR plus 1.61 % Total current maturities $ 91.0 $ 76.4 (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 of the $326.0 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2020. See Note 7, 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 7, Accounting for derivative instruments and hedging activities , for further details. (4) The Cadillac term loan credit agreement (the “Cadillac Term Loan”) contains various affirmative and negative covenants which relate to, including, among other things, the operation of the Cadillac plant, compliance with laws, incurrence of additional debt and restricted payments (as defined in the Cadillac Term Loan). One of the negative covenants requires the Cadillac project to meet certain key financial ratios, including a debt service coverage ratio (as defined in the Cadillac Term Loan). Beginning March 31, 2020, and as of September 30, 2020, we determined that the Cadillac project did not fulfill the debt service coverage ratio as required by the Cadillac Term Loan. Due to the breach of the covenant, the Cadillac project is prevented from making restricted payments (as defined in the Cadillac Term Loan) until several conditions are met, including, among other things, (i) the debt service coverage ratio for the most-recently ended period of four consecutive fiscal quarters is at least 1.2 to 1.0 and (ii) the projected debt service coverage ratio for the four consecutive fiscal quarters immediately following the period described in (i) is at least 1.2 to 1.0. We have not made any restricted payments (as defined in the Cadillac Term Loan) since July 31, 2019.
Long-term debt excluding debentures
Schedule of long-term debt	September 30, December 31, 2020 2019 Interest Rate Recourse Debt: Senior secured term loan facility, due 2025 (1) $ 326.0 $ 380.0 LIBOR (2) plus 2.50 % Senior unsecured notes, due June 2036 (Cdn$210.0) 157.4 161.7 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3)(4) 15.6 18.7 LIBOR plus 1.61 % Less: unamortized discount (4.1) (5.8) Less: unamortized deferred financing costs (4.2) (4.7) Less: current maturities (91.0) (76.4) Total long-term debt $ 399.7 $ 473.5

Fair value of financial instr_2

Fair value of financial instruments (Tables)	9 Months Ended
Fair value of financial instruments (Tables)	Sep. 30, 2020
Fair value of financial instruments
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	September 30, 2020 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 30.3 $ — $ — $ 30.3 Restricted cash 2.6 — — 2.6 Derivative instruments asset — — — — Total $ 32.9 $ — $ — $ 32.9 Liabilities: Derivative instruments liability $ — $ 18.2 $ 1.5 $ 19.7 Total $ — $ 18.2 $ 1.5 $ 19.7 December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 74.9 $ — $ — $ 74.9 Restricted cash 7.7 — — 7.7 Derivative instruments asset — 0.7 — 0.7 Total $ 82.6 $ 0.7 $ — $ 83.3 Liabilities: Derivative instruments liability $ — $ 24.7 $ 3.2 $ 27.9 Total $ — $ 24.7 $ 3.2 $ 27.9
Schedule of FVM of conversion option derivative	Fair value Nine Months Ended September 30, 2020 Beginning balance of liability at January 1, 2020 $ 3.2 Total unrealized gain (1.8) Currency transaction loss 0.1 Ending balance of liability at September 30, 2020 $ 1.5 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

Accounting for derivative ins_2

Accounting for derivative instruments and hedging activities (Tables)	9 Months Ended
	Sep. 30, 2020
Accounting for derivative instruments and hedging activities
Schedule of notional volumes of forecasted transactions	September 30, December 31, Units 2020 2019 Natural gas swaps Natural Gas (MMBtu) 13.5 16.3 Gas purchase agreements Natural Gas (Gigajoules) 6.0 6.4 Interest rate swaps Interest (US$) 421.6 468.4
Schedule of fair value of derivative instruments	September 30, 2020 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.6 Interest rate swaps long-term — 1.1 Total derivative instruments designated as cash flow hedges — 1.7 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 4.8 Interest rate swaps long-term — 1.9 Natural gas swaps current — 0.1 Natural gas swaps long-term — 1.7 Gas purchase agreements current — 3.6 Gas purchase agreements long-term — 4.4 Convertible debenture conversion option — 1.5 Total derivative instruments not designated as cash flow hedges — 18.0 Total derivative instruments $ — $ 19.7 December 31, 2019 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.4 Interest rate swaps long-term — 1.1 Total derivative instruments designated as cash flow hedges — 1.5 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 1.9 Interest rate swaps long-term — 1.1 Natural gas swaps current — 1.9 Natural gas swaps long-term — 4.2 Gas purchase agreements current 0.7 4.6 Gas purchase agreements long-term — 9.5 Convertible debenture conversion option — 3.2 Total derivative instruments not designated as cash flow hedges 0.7 26.4 Total derivative instruments $ 0.7 $ 27.9
Schedule of changes in OCI attributable to derivative financial instruments designated as cash flow hedges	Interest Rate Three Months Ended September 30, 2020 Swaps Accumulated OCI balance at July 1, 2020 $ 1.3 Change in fair value of cash flow hedges — Realized from OCI during the period 0.1 Accumulated OCI balance at September 30, 2020 $ 1.4 Interest Rate Three Months Ended September 30, 2019 Swaps Accumulated OCI balance at July 1, 2019 $ 1.4 Change in fair value of cash flow hedges — Realized from OCI during the period — Accumulated OCI balance at September 30, 2019 $ 1.4 Interest Rate Nine Months Ended September 30, 2020 Swaps Accumulated OCI balance at January 1, 2020 $ 1.6 Change in fair value of cash flow hedges (0.5) Realized from OCI during the period 0.3 Accumulated OCI balance at September 30, 2020 $ 1.4 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 $ 1.4
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges	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 2020 2019 2020 2019 Gas purchase agreements Fuel $ 2.1 $ 2.1 $ 6.2 $ 6.1 Natural gas swaps Fuel 0.8 0.6 2.4 0.5 Interest rate swaps Interest, net 1.7 (0.9) 2.9 (4.6)
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 2020 2019 2020 2019 Natural gas swaps Change in fair value of derivatives $ 3.8 $ (1.0) $ 4.4 $ (3.5) Gas purchase agreements Change in fair value of derivatives 2.5 3.7 4.9 3.5 Interest rate swaps Change in fair value of derivatives 1.8 (1.6) (3.7) (8.3) $ 8.1 $ 1.1 $ 5.6 $ (8.3) Convertible debenture conversion option Other (income) expense, net $ (3.8) $ (0.3) $ (1.8) $ 1.5

Income taxes (Tables)

Income taxes (Tables)	9 Months Ended
Income taxes (Tables)	Sep. 30, 2020
Income taxes
Schedule of components of income tax expense	Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Current income tax expense $ 2.1 $ 1.3 $ 4.5 $ 4.2 Deferred income tax expense (benefit) 0.4 (1.1) 0.7 (1.8) Total income tax expense, net $ 2.5 $ 0.2 $ 5.2 $ 2.4

Equity compensation plans (Tabl

Equity compensation plans (Tables)	9 Months Ended
Equity compensation plans (Tables)	Sep. 30, 2020
Equity compensation plans
Schedule of changes in outstanding LTIP notional units	Grant Date Weighted-Average Notional Shares Fair Value per Notional Share Outstanding at December 31, 2019 3,578,092 $ 2.38 Granted 1,866,748 2.49 Vested and redeemed (1,702,571) 2.34 Forfeitures (31,929) 2.42 Outstanding at September 30, 2020 3,710,340 $ 2.45

Basic and diluted earnings pe_2

Basic and diluted earnings per share (Tables)	9 Months Ended
Basic and diluted earnings per share (Tables)	Sep. 30, 2020
Basic and diluted earnings per share
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	Three Months Ended September 30, Nine Months Ended September 30, Basic 2020 2019 2020 2019 Numerator: Net income attributable to Atlantic Power Corporation $ 16.2 $ 12.6 $ 40.0 $ 22.7 Denominator: Weighted average basic shares outstanding 89.5 109.4 98.1 109.4 Basic earnings per share attributable to Atlantic Power Corporation $ 0.18 $ 0.12 $ 0.41 $ 0.21 Diluted Numerator: Net income attributable to Atlantic Power Corporation $ 16.2 $ 12.6 $ 40.0 $ 22.7 Add: convertible debenture interest expense 1.0 1.0 2.8 3.1 17.2 13.6 42.8 25.8 Denominator: Weighted average basic shares outstanding 89.5 109.4 98.1 109.4 Share-based compensation 0.9 1.0 0.9 1.0 Convertible debentures 27.4 27.4 27.4 27.9 117.8 137.8 126.4 138.3 Diluted earnings per share attributable to Atlantic Power Corporation $ 0.15 $ 0.10 $ 0.34 $ 0.19

Equity (Tables)

Equity (Tables)	9 Months Ended
Equity (Tables)	Sep. 30, 2020
Equity
Schedule of reconciliation of equity	Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Deficit Company Equity Balance at June 30, 2020 $ 1,224.6 $ (1,140.4) $ (147.3) $ (63.1) $ 168.8 $ 105.7 Net income — 16.2 — 16.2 1.6 17.8 Share-based compensation 0.3 — — 0.3 — 0.3 Common share repurchases (5.5) — — (5.5) — (5.5) 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$0.358688 per share) — — — — (0.6) (0.6) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.286976 per share) — — — — (0.2) (0.2) Realized and unrealized loss on hedging activities, net of tax — — 0.1 0.1 — 0.1 Foreign currency translation adjustments — — 2.5 2.5 — 2.5 Balance at September 30, 2020 $ 1,219.4 $ (1,124.2) $ (144.7) $ (49.5) $ 168.8 $ 119.3 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Equity Company Equity Balance at June 30, 2019 $ 1,260.9 $ (1,111.5) $ (141.5) $ 7.9 $ 182.9 $ 190.8 Net income — 12.6 — 12.6 1.7 14.3 Share-based compensation 0.4 — — 0.4 — 0.4 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) Foreign currency translation adjustments — — (1.6) (1.6) — (1.6) Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 19.3 $ 182.7 $ 202.0 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Deficit Company Equity Balance at January 1, 2020 $ 1,259.9 $ (1,164.2) $ (140.7) $ (45.0) $ 182.7 $ 137.7 Net income (loss) — 40.0 — 40.0 (2.5) 37.5 Share-based compensation 1.1 — — 1.1 — 1.1 Common share repurchases (41.6) — — (41.6) — (41.6) Preferred share repurchases — — — — (6.4) (6.4) Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.909375 per share) — — — — (2.4) (2.4) Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.076064 per share) — — — — (1.9) (1.9) Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.013464 per share) — — — — (0.7) (0.7) Realized and unrealized loss on hedging activities, net of tax — — (0.2) (0.2) — (0.2) Foreign currency translation adjustments — — (3.8) (3.8) — (3.8) Balance at September 30, 2020 $ 1,219.4 $ (1,124.2) $ (144.7) $ (49.5) $ 168.8 $ 119.3 Accumulated Total Preferred Other Atlantic Power Shares of a Common Retained Comprehensive Corporation Subsidiary Total Shares Deficit (loss) income Shareholders' Equity Company Equity Balance at January 1, 2019 $ 1,260.9 $ (1,121.6) $ (146.2) $ (6.9) $ 199.3 $ 192.4 Net income (loss) — 22.7 — 22.7 (3.1) 19.6 Share-based compensation 1.2 — — 1.2 — 1.2 Common share repurchases (0.8) — — (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, net of tax — — (0.2) (0.2) — (0.2) Foreign currency translation adjustments — — 3.3 3.3 — 3.3 Balance at September 30, 2019 $ 1,261.3 $ (1,098.9) $ (143.1) $ 19.3 $ 182.7 $ 202.0

Segment and geographic inform_2

Segment and geographic information (Tables)	9 Months Ended
Segment and geographic information (Tables)	Sep. 30, 2020
Segment and geographic information
Reconciliation of Project Adjusted EBITDA to net income (loss) from continuing operations	Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Three Months Ended September 30, 2020 Project revenues $ 26.7 $ 29.1 $ 9.2 $ 0.2 $ 65.2 Segment assets 229.7 208.4 353.0 49.3 840.4 Project Adjusted EBITDA $ 17.1 $ 27.1 $ 5.6 $ (0.3) $ 49.5 Change in fair value of derivative instruments — (6.3) — (1.8) (8.1) Depreciation and amortization 5.7 8.2 4.9 — 18.8 Interest, net 0.6 — — 0.2 0.8 Project income 10.8 25.2 0.7 1.3 38.0 Administration — — — 5.6 5.6 Interest expense, net — — — 10.8 10.8 Foreign exchange loss — — — 5.1 5.1 Other income, net — — — (3.8) (3.8) Net income (loss) before income taxes 10.8 25.2 0.7 (16.4) 20.3 Income tax expense — — — 2.5 2.5 Net income (loss) $ 10.8 $ 25.2 $ 0.7 $ (18.9) $ 17.8 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Three Months Ended September 30, 2019 Project revenues $ 26.1 $ 35.1 $ 9.7 $ 0.2 $ 71.1 Segment assets 295.6 251.3 371.6 78.7 997.2 Project Adjusted EBITDA $ 13.2 $ 29.6 $ 6.3 $ (0.2) $ 48.9 Change in fair value of derivative instruments — (2.6) — 1.6 (1.0) Depreciation and amortization 6.0 9.3 4.9 — 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) 5.4 23.0 1.4 (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) Net income (loss) before income taxes 5.4 23.0 1.4 (15.3) 14.5 Income tax expense — — — 0.2 0.2 Net income (loss) $ 5.4 $ 23.0 $ 1.4 $ (15.5) $ 14.3 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Nine Months Ended September 30, 2020 Project revenues $ 67.4 $ 86.7 $ 45.5 $ 0.7 $ 200.3 Segment assets 229.7 208.4 353.0 49.3 840.4 Project Adjusted EBITDA $ 23.3 $ 79.1 $ 35.7 $ (1.0) $ 137.1 Change in fair value of derivative instruments — (9.3) — 3.7 (5.6) Depreciation and amortization 16.8 26.6 14.7 0.2 58.3 Interest, net 2.0 — — 0.1 2.1 Project income (loss) 4.5 61.8 21.0 (5.0) 82.3 Administration — — — 16.8 16.8 Interest expense, net — — — 31.7 31.7 Foreign exchange gain — — — (6.2) (6.2) Other income, net — — — (2.7) (2.7) Net income (loss) before income taxes 4.5 61.8 21.0 (44.6) 42.7 Income tax expense — — — 5.2 5.2 Net income (loss) $ 4.5 $ 61.8 $ 21.0 $ (49.8) $ 37.5 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Nine Months Ended September 30, 2019 Project revenues $ 64.5 $ 99.6 $ 50.6 $ 0.7 $ 215.4 Segment assets 295.6 251.3 371.6 78.7 997.2 Project Adjusted EBITDA $ 31.5 $ 80.6 $ 41.2 $ (0.1) $ 153.2 Change in fair value of derivative instruments — 0.1 — 8.2 8.3 Depreciation and amortization 17.9 28.0 14.6 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) 10.3 51.6 26.6 (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 10.3 51.6 26.6 (66.5) 22.0 Income tax expense — — — 2.4 2.4 Net income (loss) $ 10.3 $ 51.6 $ 26.6 $ (68.9) $ 19.6
Schedule of revenue and property, plant and equipment by country	The tables below provide information, by country, about our consolidated operations for the three and nine months ended September 30, 2020 and 2019 and for Property, Plant and Equipment, PPAs and other intangible assets and total assets as of September 30, 2020 and December 31, 2019, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located. Project revenue Three Months Ended Nine Months Ended September 30, September 30, 2020 2019 2020 2019 United States $ 46.5 $ 54.9 $ 140.1 $ 159.5 Canada 18.7 16.2 60.2 55.9 Total $ 65.2 $ 71.1 $ 200.3 $ 215.4 Property, Plant and PPAs and Equipment, net of other intangible assets, net of accumulated depreciation accumulated amortization Total assets September 30, 2020 December 31, 2019 September 30, 2020 December 31, 2019 September 30, 2020 December 31, 2019 United States $ 357.7 $ 353.9 $ 124.8 $ 142.8 $ 666.5 $ 762.3 Canada 137.1 148.2 1.0 1.5 173.9 173.3 Total $ 494.8 $ 502.1 $ 125.8 $ 144.3 $ 840.4 $ 935.6

Leases (Tables)

Leases (Tables)	9 Months Ended
Leases (Tables)	Sep. 30, 2020
Leases
Schedule of operating lease information	Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Lease cost: (1) Operating lease cost $ 0.5 $ 0.5 $ 1.6 $ 1.3 Sublease income (0.3) (0.3) (0.8) (0.9) Total lease cost $ 0.2 $ 0.2 $ 0.8 $ 0.4 (1)
Schedule of other information	Lease Income from Net lease Payments subleasing payments 2020 $ 0.6 $ (0.3) $ 0.3 2021 2.0 (1.1) 0.9 2022 1.7 (1.1) 0.6 2023 1.2 (0.7) 0.5 2024 0.1 — 0.1 Thereafter — — — Total operating lease payments $ 5.6 $ (3.2) $ 2.4 Less: present value discount (0.2) Total operating lease liabilities $ 5.4 Lease Payments 2020 $ — 2021 0.1 2022 0.1 Thereafter — Total finance lease payments $ 0.2 Less: amount representing interest (0.1) Total finance lease liabilities $ 0.1 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) Operating cash flows from operating leases $ 0.8 Weighted average remaining lease term (in years): Operating leases 2.9 Finance leases 1.7 Weighted average discount rate - operating leases 3.9 % Weighted average discount rate - finance leases 4.1 % (1)
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, 2020 2019 2020 2019 Solid Fuel $ 19.0 $ 26.1 $ 51.1 $ 64.4 Natural Gas 7.0 6.5 19.0 18.4 Hydroelectric 9.2 9.7 45.5 50.6 $ 35.2 $ 42.3 $ 115.6 $ 133.4

Nature of business (Details)

Nature of business (Details) MW in Thousands	9 Months Ended
Nature of business (Details) MW in Thousands	Sep. 30, 2020regionstateprojectMW
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 \| project	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 \| project	16

Revenue from contracts - Disagg

Revenue from contracts - Disaggregation of revenue (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020USD ($)	Sep. 30, 2019USD ($)	Sep. 30, 2020USD ($)segment	Sep. 30, 2019USD ($)
Disaggregation of revenue
Total revenue	$ 65.2	$ 71.1	$ 200.3	$ 215.4
Number of reportable segments \| segment			4
Solid Fuel
Disaggregation of revenue
Total revenue	26.7	26.1	$ 67.4	64.5
Natural Gas
Disaggregation of revenue
Total revenue	29.1	35.1	86.7	99.6
Hydroelectric
Disaggregation of revenue
Total revenue	9.2	9.7	45.5	50.6
Corporate
Disaggregation of revenue
Total revenue	0.2	0.2	0.7	0.7
Energy sales
Disaggregation of revenue
Project revenue	30.3	29.2	102.1	102.7
Total revenue	30.3	29.2	102.1	102.7
Energy sales \| Solid Fuel
Disaggregation of revenue
Project revenue	14.3	12.4	40.6	30.7
Energy sales \| Natural Gas
Disaggregation of revenue
Project revenue	7.5	7.7	18.4	23.6
Energy sales \| Hydroelectric
Disaggregation of revenue
Project revenue	8.5	9.1	43.1	48.4
Energy capacity revenue
Disaggregation of revenue
Project revenue	29.7	38	84.8	99.8
Total revenue	29.7	38	84.8	99.8
Energy capacity revenue \| Solid Fuel
Disaggregation of revenue
Project revenue	12.2	13.7	26.2	33.7
Energy capacity revenue \| Natural Gas
Disaggregation of revenue
Project revenue	17.5	24.3	58.6	66.1
Steam energy and capacity revenue
Disaggregation of revenue
Project revenue	2.5	0.2	6.8	0.1
Steam energy and capacity revenue \| Natural Gas
Disaggregation of revenue
Project revenue	2.5	0.2	6.8	0.1
Waste heat revenue
Disaggregation of revenue
Project revenue	0.1		0.5
Waste heat revenue \| Solid Fuel
Disaggregation of revenue
Project revenue	0.1		0.5
Ancillary and transmission services
Disaggregation of revenue
Project revenue	1.4	3.4	4.6	12.5
Ancillary and transmission services \| Natural Gas
Disaggregation of revenue
Project revenue	0.7	2.8	2.2	10.3
Ancillary and transmission services \| Hydroelectric
Disaggregation of revenue
Project revenue	0.7	0.6	2.4	2.2
Asset management and operation
Disaggregation of revenue
Project revenue	0.2	0.2	0.7	0.7
Asset management and operation \| Corporate
Disaggregation of revenue
Project revenue	0.2	0.2	0.7	0.7
Miscellaneous revenue
Disaggregation of revenue
Miscellaneous revenue	1	0.1	0.8	(0.4)
Total revenue	5.2	3.9	13.4	12.9
Miscellaneous revenue \| Solid Fuel
Disaggregation of revenue
Miscellaneous revenue	0.1		0.1	0.1
Miscellaneous revenue \| Natural Gas
Disaggregation of revenue
Miscellaneous revenue	$ 0.9	$ 0.1	$ 0.7	$ (0.5)

Revenue from contracts - Contra

Revenue from contracts - Contract balances (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract assets	$ 0	$ 0
Dorchester
Disaggregation of Revenue [Line Items]
Contract liabilities	0.2	0.2
San Diego Projects
Disaggregation of Revenue [Line Items]
Contract liabilities	0.1	$ 0.1
Mamquam
Disaggregation of Revenue [Line Items]
Contract liabilities	$ 0.4

Changes in accumulated other _3

Changes in accumulated other comprehensive loss by component (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
AOCI Attributable to Parent, Net of Tax
Beginning Balance			$ (45)
Net amount reclassified to earnings:
Ending Balance	$ (49.5)		(49.5)
Foreign currency translation
AOCI Attributable to Parent, Net of Tax
Beginning Balance	(146.9)	$ (141.5)	(140.6)	$ (146.4)
Other comprehensive income (loss):
Foreign currency translation adjustments	2.5	(1.6)	(3.8)	3.3
Net amount reclassified to earnings:
Ending Balance	(144.4)	(143.1)	(144.4)	(143.1)
Accumulated other comprehensive loss, tax impacts related to rate changes	0	0	0	0
Pension
AOCI Attributable to Parent, Net of Tax
Beginning Balance			(1.7)	(1.4)
Net amount reclassified to earnings:
Ending Balance	(1.7)	(1.4)	(1.7)	(1.4)
Cash flow hedges
AOCI Attributable to Parent, Net of Tax
Beginning Balance	1.3	1.4	1.6	1.6
Other comprehensive income (loss):
Net change from periodic revaluations			(0.7)	(0.4)
Tax benefit			0.2	0
Total other comprehensive (loss) income before reclassifications, net of tax			(0.5)	(0.4)
Net amount reclassified to earnings:
Total other comprehensive loss	0.1		(0.2)	(0.2)
Ending Balance	1.4	1.4	1.4	1.4
Amount reclassified from accumulated other comprehensive income \| Foreign currency translation
Net amount reclassified to earnings:
Amounts reclassified to earnings, foreign currency	0	$ 0	0	0
Amount reclassified from accumulated other comprehensive income \| Cash flow hedges
Net amount reclassified to earnings:
Tax expense	(0.1)		(0.1)	0
Total amount reclassified from accumulated other comprehensive income, net of tax	0.1		0.3	0.2
Amount reclassified from accumulated other comprehensive income \| Cash flow hedges \| Interest rate swaps
Net amount reclassified to earnings:
Interest rate swaps	$ 0.2		$ 0.4	$ 0.2

Equity method investments in _3

Equity method investments in unconsolidated affiliates - Op Results (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Operating results
Revenue	$ 65.2	$ 71.1	$ 200.3	$ 215.4
Net income (loss)	17.8	14.3	37.5	19.6
Equity in earnings of unconsolidated affiliates	12.1	12.1	31.8	34.4
Distributions from equity method investments			(37.3)	(41.4)
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Operating results
Revenue	36.2	37.9	104.5	105.4
Project expenses	23.7	25.4	71.5	69.7
Project other expenses	(0.4)	(0.4)	(1.2)	(1.3)
Equity in earnings of unconsolidated affiliates	12.1	12.1	31.8	34.4
Distributions from equity method investments	(15.7)	(16)	(37.3)	(41.4)
Deficit in earnings of equity method investments, net of distributions	(3.6)	(3.9)	(5.5)	(7)
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] \| Frederickson
Operating results
Revenue	8.3	10.3	22.4	26.4
Project expenses	5.8	7.5	16.3	20
Net income (loss)	2.5	2.8	6.1	6.4
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] \| Orlando Cogen, LP
Operating results
Revenue	15.7	15.6	44.8	46.4
Project expenses	6.7	6.9	19.8	21.5
Net income (loss)	9	8.7	25	24.9
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] \| Chambers Cogen, LP
Operating results
Revenue	9.4	9.4	29.1	30
Project expenses	7.7	8.9	23.7	26.1
Project other expenses	(0.3)	(0.4)	(1.1)	(1.3)
Net income (loss)	1.4	0.1	4.3	2.6
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] \| Craven County Wood Energy, LP
Operating results
Revenue	2.4	1.8	6.2	1.8
Project expenses	2.6	1.6	8.3	1.6
Net income (loss)	(0.2)	0.2	(2.1)	0.2
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] \| Grayling Generating Station, LP
Operating results
Revenue	0.4	0.8	2	0.8
Project expenses	0.9	0.5	3.4	0.5
Project other expenses	(0.1)		(0.1)
Net income (loss)	$ (0.6)	$ 0.3	$ (1.5)	$ 0.3

Long-term debt (Details)

Long-term debt (Details) $ in Millions	Aug. 24, 2020USD ($)	Jan. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Sep. 30, 2020CAD ($)	Sep. 30, 2020USD ($)	Mar. 18, 2020USD ($)	Mar. 17, 2020USD ($)	Jan. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Long-term debt
Less: unamortized discount					$ (4,100,000)					$ (5,800,000)
Less: unamortized deferred financing costs					(4,200,000)					(4,700,000)
Less: current maturities					(91,000,000)					(76,400,000)
Total long-term debt					399,700,000					473,500,000
Current maturities					(91,000,000)					(76,400,000)
Term loan maturity		2 years
Payments of Financing Costs			$ 1,600,000
Shelf Registration authorized amount	$ 250,000,000
Availability of future shelf registration period	3 years
Senior secured term loans \| APLP Holdings
Long-term debt
Minimum percentage of variable rate base		1.00%
Applicable margin (as a percent)		2.50%
Write-off of deferred financing costs		$ 500,000
Debt repriced								$ 380
Interest rate margin reduction due to repricing, as a percent		0.25%
Interest rate margin additional reduction due to repricing, as a percent		0.25%
Payments of Financing Costs			$ 700,000
Cadillac term loan, due 2025
Long-term debt
Debt service coverage ratio			1.20%
Debt service coverage ratio, consecutive term			4
Debt service coverage projected ratio			1.20%
Debt service coverage projected ratio, consecutive term			4
Revolver \| APLP Holdings
Long-term debt
Line of Credit Facility, Amount Outstanding					0
Borrowing capacity						$ 180,000,000	$ 200,000,000
Payments of Financing Costs			$ 900,000
Letters of credit \| APLP Holdings
Long-term debt
Line of Credit Facility, Amount Outstanding					78,000,000
Maximum \| Senior secured term loans \| APLP Holdings
Long-term debt
Leverage ratio as defined in Credit Agreement								2.75
Maximum \| Revolver \| APLP Holdings
Long-term debt
Borrowing capacity						210,000,000
Upsizing borrowing capacity						$ 30,000,000
London Interbank Offered Rate (LIBOR) \| Senior secured term loan facility, due 2025
Long-term debt
Minimum percentage of variable rate base			1.00%
Long-term debt excluding debentures \| Senior secured term loan facility, due 2025
Long-term debt
Long-term Debt, Gross					326,000,000					380,000,000
Current maturities					(88,000,000)					(72,500,000)
Long-term debt excluding debentures \| Senior unsecured notes, due June 2036
Long-term debt
Long-term Debt, Gross				$ 210	$ 157,400,000				$ 210	161,700,000
Interest rate (as a percent)				5.95%	5.95%
Long-term debt excluding debentures \| Cadillac term loan, due 2025
Long-term debt
Long-term Debt, Gross					$ 15,600,000					18,700,000
Current maturities					$ (3,000,000)					$ (3,900,000)
Long-term debt excluding debentures \| London Interbank Offered Rate (LIBOR) \| Senior secured term loan facility, due 2025
Long-term debt
Applicable margin (as a percent)			2.50%
Long-term debt excluding debentures \| London Interbank Offered Rate (LIBOR) \| Cadillac term loan, due 2025
Long-term debt
Applicable margin (as a percent)			1.61%

Fair value of financial instr_3

Fair value of financial instruments - recurring (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Assets:
Cash and cash equivalents	$ 30.3	$ 74.9
Restricted cash	2.6	7.7
Derivative instruments asset		0.7
Total	32.9	83.3
Liabilities:
Derivative instruments liability	19.7	27.9
Total	19.7	27.9
Level 1
Assets:
Cash and cash equivalents	30.3	74.9
Restricted cash	2.6	7.7
Total	32.9	82.6
Level 2
Assets:
Derivative instruments asset		0.7
Total		0.7
Liabilities:
Derivative instruments liability	18.2	24.7
Total	18.2	24.7
Level 3
Liabilities:
Derivative instruments liability	1.5	3.2
Total	$ 1.5	$ 3.2

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, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Asset acquisitions
Gain in change in fair value of derivative instruments	$ 8.1	$ 1.1	$ 5.6	$ (8.3)
Recurring \| Credit valuation adjustments
Asset acquisitions
Net increase in fair value			0.5		$ 1.1
Pre-tax gain in other comprehensive income			0.1		0.1
Gain in change in fair value of derivative instruments			$ 0.4		$ 1

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, 2020	Sep. 30, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance of liability	$ 3.2	$ 1.2
Total unrealized gain (loss)	(1.8)	1.5
Currency transaction loss	0.1	0.1
Ending balance of liability	$ 1.5	$ 2.8

Accounting for derivative ins_3

Accounting for derivative instruments and hedging activities (Details) $ in Millions, J in Billions	May 15, 2020MMBTU	Jan. 31, 2020	Sep. 30, 2020USD ($)JMMBTUitemcontract$ / J	Dec. 31, 2019USD ($)MMBTU
Derivative instruments designated as cash flow hedges
Derivative instruments
Number of derivative contracts designated as cash flow hedges \| item			1
Adjusted Eurodollar Rate
Derivative instruments
Applicable margin (as a percent)			2.50%
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 agreements \| Morris Project
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			13,500,000	16,300,000
Natural gas swaps \| Orlando project
Derivative instruments
Amount of future natural gas purchases to fix the price (in Mmbtu) \| MMBTU			13,500,000
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			$ 421.6	$ 468.4
Derivative, Average Swaption Interest Rate			2.23%
Swaption interest rate (as a percent)			4.73%
Interest rate swaps \| Adjusted Eurodollar Rate
Derivative instruments
Derivative, Floor Interest Rate			1.00%
Interest rate swaps \| Minimum
Derivative instruments
Minimum fixed interest rate (as a percent)			3.50%
Interest rate swaps \| Swaption interest rate until 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
Applicable margin (as a percent)		2.50%
APLP Holdings \| Interest rate swaps \| Adjusted Eurodollar Rate \| Senior secured term loans \| Long-term debt excluding debentures
Derivative instruments
Notional amount			326
Remaining aggregate principal amount			326
Face amount of debt			$ 326

Accounting for derivative ins_4

Accounting for derivative instruments and hedging activities - forecasted transactions (Details) kJ in Millions, MMBTU in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020USD ($)kJMMBTU	Dec. 31, 2019USD ($)kJMMBTU
Natural gas swaps
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) \| MMBTU	13.5	16.3
Gas purchase agreements
Derivative instruments
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) \| kJ	6	6.4
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) \| $	$ 421.6	$ 468.4

Accounting for derivative ins_5

Accounting for derivative instruments and hedging activities - FV by Bal Sht Loc (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair value of derivative instruments
Derivative Assets		$ 0.7
Derivative Liabilities	$ 19.7	27.9
Derivative instruments designated as cash flow hedges
Fair value of derivative instruments
Derivative Liabilities	1.7	1.5
Derivative instruments designated as cash flow hedges \| Interest rate swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	0.6	0.4
Derivative instruments designated as cash flow hedges \| Interest rate swaps \| Long-term
Fair value of derivative instruments
Derivative Liabilities	1.1	1.1
Derivative instruments not designated as cash flow hedges
Fair value of derivative instruments
Derivative Assets		0.7
Derivative Liabilities	18	26.4
Derivative instruments not designated as cash flow hedges \| Interest rate swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	4.8	1.9
Derivative instruments not designated as cash flow hedges \| Interest rate swaps \| Long-term
Fair value of derivative instruments
Derivative Liabilities	1.9	1.1
Derivative instruments not designated as cash flow hedges \| Natural gas swaps \| Current
Fair value of derivative instruments
Derivative Liabilities	0.1	1.9
Derivative instruments not designated as cash flow hedges \| Natural gas swaps \| Long-term
Fair value of derivative instruments
Derivative Liabilities	1.7	4.2
Derivative instruments not designated as cash flow hedges \| Gas purchase agreements \| Current
Fair value of derivative instruments
Derivative Assets		0.7
Derivative Liabilities	3.6	4.6
Derivative instruments not designated as cash flow hedges \| Gas purchase agreements \| Long-term
Fair value of derivative instruments
Derivative Liabilities	4.4	9.5
Derivative instruments not designated as cash flow hedges \| Convertible Debentures \| Current
Fair value of derivative instruments
Derivative Liabilities	$ 1.5	$ 3.2

Accounting for derivative ins_6

Accounting for derivative instruments and hedging activities - AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
AOCI Attributable to Parent, Net of Tax
Change in fair value of cash flow hedges			$ (0.5)	$ (0.4)
Realized from OCI during the period	$ (0.1)		(0.3)	(0.2)
Interest rate swaps
AOCI Attributable to Parent, Net of Tax
Accumulated OCI balance at beginning of period	1.3	$ 1.4	1.6	1.6
Change in fair value of cash flow hedges	0	0	(0.5)	(0.4)
Realized from OCI during the period	0.1	0	0.3	0.2
Accumulated OCI balance at end of period	$ 1.4	$ 1.4	$ 1.4	$ 1.4

Accounting for derivative ins_7

Accounting for derivative instruments and hedging activities - gain, loss (Details) - Derivative instruments not designated as cash flow hedges - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Gas and Interest Rate Swaps
Impact of derivative instruments on the consolidated statements of operations
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments	$ 8.1	$ 1.1	$ 5.6	$ (8.3)
Natural gas swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	0.8	0.6	2.4	0.5
Natural gas swaps \| Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments	3.8	(1)	4.4	(3.5)
Gas purchase agreements
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	2.1	2.1	6.2	6.1
Gas purchase agreements \| Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments	2.5	3.7	4.9	3.5
Interest rate swaps
Impact of derivative instruments on the consolidated statements of operations
Realized loss (gain) for derivative instruments	1.7	(0.9)	2.9	(4.6)
Interest rate swaps \| Change in fair value of derivatives
Impact of derivative instruments on the consolidated statements of operations
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments	1.8	(1.6)	(3.7)	(8.3)
Convertible Debentures \| Other (income) expense, net
Impact of derivative instruments on the consolidated statements of operations
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments	$ (3.8)	$ (0.3)	$ (1.8)	$ 1.5

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Income taxes (Details) - USD ($) $ in Millions	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Components of income tax expenses (benefit)
Current income tax expense	$ 2.1	$ 1.3	$ 4.5	$ 4.2
Deferred income tax expense (benefit)	0.4	(1.1)	0.7	(1.8)
Total income tax expense, net	$ 2.5	$ 0.2	$ 5.2	$ 2.4

Income taxes - Other (Details)

Income taxes - Other (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Income taxes - Other (Details) - USD ($) $ in Millions	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Reconciliation of income taxes
Enacted statutory income tax rate	27.00%	27.00%	27.00%	27.00%
Tax expense	$ 2.5	$ 0.2	$ 5.2	$ 2.4
Computed income tax (benefit) expense at Canadian statutory rate	5.5	3.9	11.5	5.9
Impact related to change in estimates			2.7
Other permanent differences		0.2	0.9	0.7
Impact related to withholding federal and state taxes	1.1	0.5	1.7	1.3
Valuation allowance	133.8		133.8
Increase (decrease) in the valuation allowance	(2.7)	(4.4)	(11.6)	(4.5)
Foreign exchange	1.4			1
Canada
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	0.2	(1)	(3.6)	4.4
United States
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	$ (2.9)	$ (3.4)	$ (8)	$ (8.9)

Equity compensation plans (Deta

Equity compensation plans (Details) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020USD ($)$ / sharesshares	Sep. 30, 2019USD ($)	Sep. 30, 2020USD ($)$ / sharesshares	Sep. 30, 2019USD ($)	Sep. 30, 2020$ / shares
Units
Outstanding at the beginning of the period (in shares) \| shares			3,578,092
Granted (in shares) \| shares			1,866,748
Vested and redeemed (in shares) \| shares			(1,702,571)
Forfeitures (in shares) \| shares			(31,929)
Outstanding at the end of the period (in shares) \| shares	3,710,340		3,710,340
Weighted-Average Fair Value per Unit
Outstanding at the beginning of the period (in dollars per share) \| $ / shares			$ 2.38
Granted (in dollars per share) \| $ / shares			2.49
Vested and redeemed (in dollars per share) \| $ / shares			2.34
Forfeitures (in dollars per share) \| $ / shares			2.42
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 2.45		$ 2.45
Long-term incentive plan
Weighted-Average Fair Value per Unit
Cash payments made for vested notional units \| $			$ 3.3	$ 2
Compensation expense related to LTIP \| $	$ 1	$ 1.1	$ 3	$ 3.1
Transition equity participation agreement
Transition equity participation agreement
Number of transition notional shares outstanding \| shares			269,952
Minimum market price required for 3 consecutive months to vest remaining shares \| $ / shares					$ 4.77
Transition equity participation agreement \| Minimum
Transition equity participation agreement
Number of consecutive months, weighted average Canadian dollar price must exceed market price of share by 50% for vesting			3 months

Basic and diluted earnings pe_3

Basic and diluted earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Numerator:
Net income attributable to Atlantic Power Corporation	$ 16.2	$ 12.6	$ 40	$ 22.7
Add: convertible debenture interest expense	1	1	2.8	3.1
Net income (loss) available to common stockholder, Diluted	$ 17.2	$ 13.6	$ 42.8	$ 25.8
Denominator:
Weighted average basic shares outstanding	89.5	109.4	98.1	109.4
Basic earnings per share attributable to Atlantic Power Corporation	$ 0.18	$ 0.12	$ 0.41	$ 0.21
Share-based compensation (in shares)	0.9	1	0.9	1
Convertible debentures (in shares)	27.4	27.4	27.4	27.9
Weighted Average Number of Potentially Diluted Shares	117.8	137.8	126.4	138.3
Diluted earnings per share attributable to Atlantic Power Corporation	$ 0.15	$ 0.10	$ 0.34	$ 0.19

Equity (Details)

Equity (Details) $ in Millions	3 Months Ended				9 Months Ended
Equity (Details) $ in Millions	Sep. 30, 2020USD ($)	Sep. 30, 2020$ / shares	Sep. 30, 2019USD ($)	Sep. 30, 2019$ / shares	Sep. 30, 2020USD ($)	Sep. 30, 2020$ / shares	Sep. 30, 2019USD ($)	Sep. 30, 2019$ / shares
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	$ 105.7		$ 190.8		$ 137.7		$ 192.4
Net income (loss)	17.8		14.3		37.5		19.6
Share-based compensation	0.3		0.4		1.1		1.2
Common share repurchases	(5.5)				(41.6)		(0.8)
Preferred share repurchases			(0.1)		(6.4)		(8)
Realized and unrealized loss on hedging activities, net of tax	0.1				(0.2)		(0.2)
Foreign currency translation adjustments	2.5		(1.6)		(3.8)		3.3
Balance at the end of the period	119.3		202		119.3		202
Series 1
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	(0.8)		(0.8)		(2.4)		(2.6)
Dividends on preferred shares of a subsidiary company (in CAD per share) \| $ / shares		$ 0.303125		$ 0.303125		$ 0.909375		$ 0.909375
Series 2
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	(0.6)		(0.6)		(1.9)		(1.8)
Dividends on preferred shares of a subsidiary company (in CAD per share) \| $ / shares		0.358688		0.348125		1.076064		1.044375
Series 3
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	(0.2)		(0.4)		(0.7)		(1.1)
Dividends on preferred shares of a subsidiary company (in CAD per share) \| $ / shares		$ 0.286976		$ 0.364858		$ 1.013464		$ 1.091448
Common Shares
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	1,224.6		1,260.9		1,259.9		1,260.9
Share-based compensation	0.3		0.4		1.1		1.2
Common share repurchases	(5.5)				(41.6)		(0.8)
Balance at the end of the period	1,219.4		1,261.3		1,219.4		1,261.3
Retained Deficit
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	(1,140.4)		(1,111.5)		(1,164.2)		(1,121.6)
Net income (loss)	16.2		12.6		40		22.7
Balance at the end of the period	(1,124.2)		(1,098.9)		(1,124.2)		(1,098.9)
Accumulated Other Comprehensive (loss) income
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	(147.3)		(141.5)		(140.7)		(146.2)
Realized and unrealized loss on hedging activities, net of tax	0.1				(0.2)		(0.2)
Foreign currency translation adjustments	2.5		(1.6)		(3.8)		3.3
Balance at the end of the period	(144.7)		(143.1)		(144.7)		(143.1)
Total Atlantic Power Corporation Shareholder's Deficit
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	(63.1)		7.9		(45)		(6.9)
Net income (loss)	16.2		12.6		40		22.7
Share-based compensation	0.3		0.4		1.1		1.2
Common share repurchases	(5.5)				(41.6)		(0.8)
Realized and unrealized loss on hedging activities, net of tax	0.1				(0.2)		(0.2)
Foreign currency translation adjustments	2.5		(1.6)		(3.8)		3.3
Balance at the end of the period	(49.5)		19.3		(49.5)		19.3
Preferred Shares of a Subsidiary Company
Increase (decrease) in shareholders' equity
Balance at the beginning of the period	168.8		182.9		182.7		199.3
Net income (loss)	1.6		1.7		(2.5)		(3.1)
Preferred share repurchases			(0.1)		(6.4)		(8)
Balance at the end of the period	168.8		182.7		168.8		182.7
Preferred Shares of a Subsidiary Company \| Series 1
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	(0.8)		(0.8)		(2.4)		(2.6)
Preferred Shares of a Subsidiary Company \| Series 2
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	(0.6)		(0.6)		(1.9)		(1.8)
Preferred Shares of a Subsidiary Company \| Series 3
Increase (decrease) in shareholders' equity
Dividends on preferred shares of a subsidiary company	$ (0.2)		$ (0.4)		$ (0.7)		$ (1.1)

Equity - Share Repurchase Progr

Equity - Share Repurchase Program (Details) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Apr. 30, 2020USD ($)shares	Sep. 30, 2020USD ($)shares	Sep. 30, 2019USD ($)	Sep. 30, 2020USD ($)shares	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)shares	Mar. 25, 2020USD ($)$ / sharesshares
Stock Repurchase Program
Payments for Repurchase of Redeemable Preferred Stock \| $				$ 6.4	$ 8
Gain (loss) attributable to preferred shares of a subsidiary company \| $		$ 1.6	$ 1.7	$ (2.5)	$ (3.1)
Common Stock, Shares, Outstanding		89,222,568		89,222,568		108,675,294
Cumulative Preferred Stock
Stock Repurchase Program
Shares repurchased and canceled \| $				$ 6.4
Series 1 Shares
Stock Repurchase Program
Shares repurchased and canceled (in shares)				381,794
Series 2 Shares
Stock Repurchase Program
Shares repurchased and canceled (in shares)				62,365
Series 3 Shares
Stock Repurchase Program
Shares repurchased and canceled (in shares)				120,000
NCIB
Stock Repurchase Program
Public float amount used to determine share amount, percent						10.00%
Shares repurchased and canceled (in shares)				7,540,105
Shares repurchased and canceled \| $				$ 15.8
Gain (loss) attributable to preferred shares of a subsidiary company \| $				$ (7.4)
NCIB \| Series 1 Shares
Stock Repurchase Program
Number of shares authorized for repurchase						384,750
Dividend percent of cumulative redeemable preferred shares				4.85
NCIB \| Series 2 Shares
Stock Repurchase Program
Number of shares authorized for repurchase						223,072
Dividend percent of cumulative redeemable preferred shares				7
NCIB \| Series 3 Shares
Stock Repurchase Program
Number of shares authorized for repurchase						133,031
SIB
Stock Repurchase Program
Number of shares authorized for repurchase							12,820,512
Shares repurchased and canceled (in shares)	12,500,000
Shares repurchased and canceled \| $	$ 25.8
Share repurchase authorized amount \| $							$ 25
Number of share repurchase authorized as percentage of common stock issued and outstanding							12.00%
Share purchase price increment \| $ / shares							$ 0.05
Minimum \| SIB
Stock Repurchase Program
Share purchase price \| $ / shares							1.95
Maximum \| NCIB
Stock Repurchase Program
Number of shares authorized for repurchase						10,578,799
Stock Repurchase Program Number Of Shares Authorized To Be Repurchased Per Day						9,243
Maximum \| SIB
Stock Repurchase Program
Share purchase price \| $ / shares							$ 2.20
Series E Debentures \| NCIB
Stock Repurchase Program
Share repurchase authorized amount \| $						$ 11.5

Segment and geographic inform_3

Segment and geographic information - EBITDA (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020USD ($)	Sep. 30, 2019USD ($)	Sep. 30, 2020USD ($)segment	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)
Segment and geographic information
Number of reportable segments \| segment			4
Project revenues	$ 65.2	$ 71.1	$ 200.3	$ 215.4
Segment assets	840.4	997.2	840.4	997.2	$ 935.6
Project Adjusted EBITDA	49.5	48.9	137.1	153.2
Change in fair value of derivative instruments	(8.1)	(1)	(5.6)	8.3
Depreciation and amortization	18.8	20.2	58.3	60.6
Interest, net	0.8	0.8	2.1	2
Insurance loss	(6.2)	1	(6.2)	1
Other project (income) expense				1.2
Project income (loss)	38	27.9	82.3	80.1
Administration	5.6	5.5	16.8	17.3
Interest expense, net	10.8	10.9	31.7	33
Foreign exchange (gain) loss	5.1	(2.8)	(6.2)	7.1
Other income (expenses), net	(3.8)	(0.2)	(2.7)	0.7
Net income (loss) before income taxes	20.3	14.5	42.7	22
Income tax expense	2.5	0.2	5.2	2.4
Net income (loss)	17.8	14.3	37.5	19.6
Solid Fuel
Segment and geographic information
Project revenues	26.7	26.1	67.4	64.5
Segment assets	229.7	295.6	229.7	295.6
Project Adjusted EBITDA	17.1	13.2	23.3	31.5
Depreciation and amortization	5.7	6	16.8	17.9
Interest, net	0.6	0.8	2	2.3
Insurance loss		1		1
Project income (loss)	10.8	5.4	4.5	10.3
Net income (loss) before income taxes	10.8	5.4	4.5	10.3
Net income (loss)	10.8	5.4	4.5	10.3
Natural Gas
Segment and geographic information
Project revenues	29.1	35.1	86.7	99.6
Segment assets	208.4	251.3	208.4	251.3
Project Adjusted EBITDA	27.1	29.6	79.1	80.6
Change in fair value of derivative instruments	(6.3)	(2.6)	(9.3)	0.1
Depreciation and amortization	8.2	9.3	26.6	28
Interest, net				(0.3)
Other project (income) expense		(0.1)		1.2
Project income (loss)	25.2	23	61.8	51.6
Net income (loss) before income taxes	25.2	23	61.8	51.6
Net income (loss)	25.2	23	61.8	51.6
Hydroelectric
Segment and geographic information
Project revenues	9.2	9.7	45.5	50.6
Segment assets	353	371.6	353	371.6
Project Adjusted EBITDA	5.6	6.3	35.7	41.2
Depreciation and amortization	4.9	4.9	14.7	14.6
Project income (loss)	0.7	1.4	21	26.6
Net income (loss) before income taxes	0.7	1.4	21	26.6
Net income (loss)	0.7	1.4	21	26.6
Corporate
Segment and geographic information
Project revenues	0.2	0.2	0.7	0.7
Segment assets	49.3	78.7	49.3	78.7
Project Adjusted EBITDA	(0.3)	(0.2)	(1)	(0.1)
Change in fair value of derivative instruments	(1.8)	1.6	3.7	8.2
Depreciation and amortization			0.2	0.1
Interest, net	0.2		0.1
Other project (income) expense		0.1
Project income (loss)	1.3	(1.9)	(5)	(8.4)
Administration	5.6	5.5	16.8	17.3
Interest expense, net	10.8	10.9	31.7	33
Foreign exchange (gain) loss	5.1	(2.8)	(6.2)	7.1
Other income (expenses), net	(3.8)	(0.2)	(2.7)	0.7
Net income (loss) before income taxes	(16.4)	(15.3)	(44.6)	(66.5)
Income tax expense	2.5	0.2	5.2	2.4
Net income (loss)	$ (18.9)	$ (15.5)	$ (49.8)	$ (68.9)

Segment and geographic inform_4

Segment and geographic information - Geographic (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Revenue and Assets
Project revenues	$ 65.2	$ 71.1	$ 200.3	$ 215.4
Property, Plant and Equipment, net of accumulated depreciation	494.8		494.8		$ 502.1
PPA'S and other intangible assets, net of accumulated amortization	125.8		125.8		144.3
Assets	840.4	997.2	840.4	997.2	935.6
United States
Revenue and Assets
Project revenues	46.5	54.9	140.1	159.5
Property, Plant and Equipment, net of accumulated depreciation	357.7		357.7		353.9
PPA'S and other intangible assets, net of accumulated amortization	124.8		124.8		142.8
Assets	666.5		666.5		762.3
Canada
Revenue and Assets
Project revenues	18.7	$ 16.2	60.2	$ 55.9
Property, Plant and Equipment, net of accumulated depreciation	137.1		137.1		148.2
PPA'S and other intangible assets, net of accumulated amortization	1		1		1.5
Assets	$ 173.9		$ 173.9		$ 173.3

Segment and geographic inform_5

Segment and geographic information - risk (Details) - Revenues, net - Consolidated revenue	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Georgia Power
Consolidated revenue concentration
Percentage of consolidated revenue	15.50%	16.20%	11.60%	12.10%
Southern California Edison
Consolidated revenue concentration
Percentage of consolidated revenue		10.50%
Niagara Mohawk
Consolidated revenue concentration
Percentage of consolidated revenue			16.10%	18.40%
Independent Electricity System Operator
Consolidated revenue concentration
Percentage of consolidated revenue	12.20%	11.20%	13.50%	12.10%
BC Hydro
Consolidated revenue concentration
Percentage of consolidated revenue	11.30%		11.20%
Equistar Chemicals, LP
Consolidated revenue concentration
Percentage of consolidated revenue	10.70%	10.40%	10.80%	11.60%

Guarantees and Contingencies (D

Guarantees and Contingencies (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Nov. 06, 2020
Contingencies
Insurance	$ (6.2)		$ 1	$ (6.2)	$ 1
Insurance Recoveries				31
Minimum \| Scenario, Plan [Member]
Contingencies
Estimated additional insurance recoveries related to business interruption losses and property losses							$ 10
Maximum \| Scenario, Plan [Member]
Contingencies
Estimated additional insurance recoveries related to business interruption losses and property losses							$ 11
Cadillac Project
Contingencies
Estimate damages claimed for statutory misrepresentation	1			1
Business interruption loss period						45 days
Business interruption expected revenue loss						$ 1.4
Impairment					25
Write-down of capital spares		$ 0.6	0.3
Insurance receivable	0	$ 24.8	$ 24.2	0	24.2	24.8
Insurance					$ 1
Insurance Recoveries	7			$ 19.7		$ 11.3
Gain on business interruption insurance recovery	6.2
Gain on Business Interruption Insurance Recovery	$ 6.2

Leases - Real estate and equipm

Leases - Real estate and equipment (Details) $ in Millions	9 Months Ended
Leases - Real estate and equipment (Details) $ in Millions	Sep. 30, 2020USD ($)item	Jan. 01, 2019
Operating Lease Commitments
Number of properties subleased \| item	1
Rate used to determine lease liabilities at implementation date		3.75%
Operating Lease, Liability \| $	$ 5.4

Leases - Lease cost (Details)

Leases - Lease cost (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Leases - Lease cost (Details) - USD ($) $ in Millions	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Lease cost:
Operating lease cost	$ 0.5	$ 0.5	$ 1.6	$ 1.3
Sublease income	(0.3)	(0.3)	(0.8)	(0.9)
Total lease cost	$ 0.2	$ 0.2	$ 0.8	$ 0.4

Leases - Operating lease maturi

Leases - Operating lease maturities - Topic 842 (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020USD ($)item
Operating Lease Commitments
Number of lease transactions with related parties \| item	0
Future minimum lease commitments
2020	$ 0.6
2021	2
2022	1.7
2023	1.2
2024	0.1
Total operating lease payments	5.6
Less: present value discount	(0.2)
Total operating lease liabilities	5.4
Finance lease payment
2021	0.1
2022	0.1
Total finance lease payments	0.2
Less: amount representing interest	(0.1)
Total finance lease liabilities	0.1
Income from subleasing
2020	(0.3)
2021	(1.1)
2022	(1.1)
2023	(0.7)
Total income from subleasing	(3.2)
Net lease payments
2020	0.3
2021	0.9
2022	0.6
2023	0.5
2024	0.1
Total net lease payments	$ 2.4

Leases - Operating lease matu_2

Leases - Operating lease maturities - Supplemental Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 0.8
Weighted average items:
Weighted average remaining lease term (in years), Operating leases	2 years 10 months 24 days
Weighted average remaining lease term (in years), Finance leases	1 year 8 months 12 days
Weighted average discount rate - operating leases	3.90%
Weighted average discount rate - finance leases	4.10%

Leases - PPA Leases (Details)

Leases - PPA Leases (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
Leases - PPA Leases (Details) $ in Millions	May 31, 2019USD ($)	Sep. 30, 2020USD ($)projectagreement	Sep. 30, 2019USD ($)	Sep. 30, 2020USD ($)projectagreement	Sep. 30, 2019USD ($)
Lessor, Lease, Description [Line Items]
Lease, Practical Expedients, Package [true false]				true
Number of PPAs accounted for as operating leases \| agreement		10		10
Number of project which are in operation \| project		21		21
Lessor, Operating Lease, Existence of Option to Extend [true false]				false
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 35.2	$ 42.3	$ 115.6	$ 133.4
Minimum
Lessor, Lease, Description [Line Items]
Remaining lease term				19 months
Maximum
Lessor, Lease, Description [Line Items]
Remaining lease term				23 years
Manchief
Operating Lease Lessor Sale Of Plant [Abstract]
Sales price of Manchief plant	$ 45.2
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
Solid Fuel
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		19	26.1	$ 51.1	64.4
Natural Gas
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		7	6.5	19	18.4
Hydroelectric
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 9.2	$ 9.7	$ 45.5	$ 50.6