10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2020
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

COMMISSION FILE NUMBER 001-34691

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia, Canada (State or other jurisdiction of incorporation or organization)	55-0886410 (I.R.S. Employer Identification No.)
3 Allied Drive, Suite 155 Dedham, MA (Address of principal executive offices)	02026 (Zip code)

(617) 977-2400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading symbol	Name of Exchange on which registered
Common Shares, no par value, and the associated Rights to Purchase Common Shares	AT	The New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer ☐	Accelerated filer ☒	Non-accelerated filer ☐	Smaller reporting company ☒
Emerging growth company ☐

If an emerging company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The number of shares outstanding of the registrant’s Common Stock as of November 6, 2020 was 89,222,568.

ATLANTIC POWER CORPORATION

FORM 10-Q

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2020

Index

	General :		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of September 30, 2020 (unaudited) and December 31, 2019	4
		Consolidated Statements of Operations for the three and nine months ended September 30, 2020 (unaudited) and September 30, 2019 (unaudited)	5
		Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2020 (unaudited) and September 30, 2019 (unaudited)	6
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 (unaudited) and September 30, 2019 (unaudited)	7
		Condensed Notes to Consolidated Financial Statements (unaudited)	8
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	65
ITEM 4.		CONTROLS AND PROCEDURES	65
		PART II—OTHER INFORMATION
ITEM 1A.		RISK FACTORS	65
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	66
ITEM 6.		EXHIBITS	69

GENERAL

In this Quarterly Report on Form 10-Q, references to “Cdn$” and “Canadian dollars” are to the lawful currency of Canada and references to “$”, “US$” and “U.S. dollars” are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10-Q to “we,” “us,” “our,” “Atlantic Power” and the “Company” refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

3

ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)

	September 30,		December 31,
	2020		2019
Assets	(unaudited)
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
Liabilities
Current liabilities:
Accounts payable	$	4.0	$	8.9
Accrued interest		3.4		2.6
Other accrued liabilities		19.3		20.8
Current portion of long-term debt (Note 5)		91.0		76.4
Current portion of derivative instruments liability (Notes 6 and 7)		10.6		12.0
Operating lease liabilities (Note 14)		2.0		2.0
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)		(45.0)
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

See accompanying notes to consolidated financial statements.

4

ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions of U.S. dollars, except per share amounts)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Project revenue:
Energy sales (Note 2)	$	30.3	$	29.2	$	102.1	$	102.7
Energy capacity revenue (Note 2)		29.7		38.0		84.8		99.8
Other (Note 2)		5.2		3.9		13.4		12.9
		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		64.0		54.6
Depreciation and amortization		14.5		16.2		45.3		48.5
		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)		(0.9)
Insurance gain (loss) (Note 13)		6.2		(1.0)		6.2		(1.0)
Other expense, net		—		—		—		(1.2)
		26.0		11.9		42.6		23.0
Project income		38.0		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		33.0
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
		17.7		13.4		39.6		58.1
Income from operations before income taxes		20.3		14.5		42.7		22.0
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	$	40.0	$	22.7
Net earnings per share attributable to Atlantic Power Corporation shareholders: (Note 10)
Basic	$	0.18	$	0.12	$	0.41	$	0.21
Diluted		0.15		0.10		0.34		0.19
Weighted average number of common shares outstanding: (Note 10)
Basic		89.5		109.4		98.1		109.4
Diluted		117.8		137.8		126.4		138.3

See accompanying notes to consolidated financial statements.

5

ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions of U.S. dollars)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
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)		(4.0)		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	$	11.0	$	36.0	$	25.8

See accompanying notes to consolidated financial statements.

6

ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)

	Nine months ended
	September 30,
	2020		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		—		1.0
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)		0.3
Prepayments and other assets		(0.4)		(0.2)
Accounts payable		(6.1)		(1.3)
Accruals and other liabilities		(3.0)		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		—		(10.0)
Proceeds from sales of assets		0.9		1.6
Purchase of property, plant and equipment		(23.0)		(0.9)
Cash used in investing activities		(9.4)		(28.0)
Cash used in financing activities:
Common share repurchases		(41.6)		(0.8)
Preferred share repurchases		(6.4)		(8.0)
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)		(2.0)
Deferred financing costs		(1.6)		—
Dividends paid to preferred shareholders		(5.0)		(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	$	27.0
Income taxes paid, net	$	3.8	$	3.5
Accruals for construction in progress	$	1.7	$	0.2

See accompanying notes to consolidated financial statements.

7

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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

8

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2019. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

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. While COVID-19 did not materially adversely affect our financial results and business operations in the nine months ended September 30, 2020, we are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. We will continue to assess the evolving impact of the COVID-19 pandemic and intend to make adjustments accordingly.

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.

9

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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 are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements.

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. Revenue by segment consists of the following:

10

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

	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

11

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

	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.

12

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

13

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

14

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

15

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

Term Loan Amendment and Repricing

In January 2020, APLP Holdings Limited Partnership (“APLP Holdings”) completed the repricing of the $380 million term loan (the “Term Loan”) and the senior secured revolving credit facility (the “Revolver”). As a result of the repricing, the interest rate margin on the Term Loan and the Revolver was reduced by 0.25% to LIBOR plus 2.50% with no change to the 1.00% LIBOR floor. An additional 0.25% step down in the interest rate margin will become effective in the event the Leverage Ratio (as defined in the Credit Agreement) is 2.75:1.00 or lower. Additionally, APLP Holdings amended its existing Term Loan to extend the maturity date by two years to April 2025. The repricing also adds customary new provisions relating to the replacement of LIBOR as the benchmark for the Eurodollar Rate (as defined in the Credit Agreement). Targeted debt balances were adjusted to reflect the previously announced anticipated closing of the sale of our Manchief power plant in 2022, resulting in lower targeted debt repayment in 2020 and higher targeted debt repayment in 2022 as compared to the previous schedule. During the nine months ended September 30, 2020, we recorded $0.7 million of new deferred financing costs associated with the amendment, which will be amortized over the remaining terms of the Term Loan and the Revolver. Additionally, we wrote off $0.5 million of existing deferred financing costs to interest expense.

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.

16

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

17

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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 Measurement Using Significant Unobservable Inputs (Level 3)
	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 Measurement Using Significant Unobservable Inputs (Level 3)
	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.

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

18

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

also have a corresponding gas sales agreement at Nipigon, whereby 6,500 Gj of natural gas per day is sold at the spot market price. This contract is not accounted for as a derivative.

On 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

19

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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

20

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

	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

21

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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

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

22

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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

23

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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. Diluted earnings per share is 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 dilutive effect of our Series E Debentures is calculated using the “if-converted method.” Under the if-converted method, the Series E Debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted earnings per share calculation for the entire period being presented. Interest expense, net of any income tax effects, would be added back to the numerator for purposes of the if-converted calculation. The outstanding equity compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator, when dilutive, for purposes of computing diluted earnings per share under the treasury stock method.

The following table sets forth the calculation of basic and diluted earnings 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

24

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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

25

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

					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.

26

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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$1.95 and not more than US$2.20 per common share in increments of US$0.05 per common share, or (ii) purchase price tenders in which they did not specify a price per common share, but rather agreed to have a specified number of common shares purchased at the purchase price determined by auction tenders.

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.

27

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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

28

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

	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

29

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

	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.

30

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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.

31

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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

32

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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⁾ Short-term lease costs and finance lease costs are immaterial to the Company

33

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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⁾ Cash flows from finance leases are immaterial to the Company

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

34

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per-share amounts)

(Unaudited)

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.

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FORWARD-LOOKING INFORMATION

Certain statements in this Quarterly Report on Form 10-Q constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “outlook,” “objective,” “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “should,” “plans,” “continue,” or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10-Q include, but are not limited to, statements with respect to the following:

● the impact of COVID-19 on the economy and our operations, including the measures taken by governmental authorities to address it (or failure to implement additional stimulus measures), which may precipitate or exacerbate other risks and/or uncertainties, and the current resurgence in new cases of COVID-19 might lead to reinstatement of restrictions on individuals and businesses;
​

● our ability to generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities;

● the outcome or impact of our business strategy to increase our intrinsic value on a per-share basis through disciplined management of our balance sheet and cost structure and internal investments in our fleet, external acquisitions and repurchases of debt, common and preferred securities;

● our ability to renew or enter into new PPAs on favorable terms or at all after the expiration of our current agreements;

● our ability to meet the financial covenants under our senior secured term loans and other indebtedness;

● our ability to ensure that our plants operate safely and effectively;

● expectations regarding maintenance and capital expenditures; and

● the impact of legislative, regulatory, competitive and technological changes.

Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10-Q. Such forward-looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward-looking statement made by us or on our behalf.

Forward looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. In addition, a number of factors could cause actual results to differ materially from the results discussed in the forward looking statements, including, but not limited to, the factors included in the filings Atlantic Power makes from time to time with the SEC and the risk factors described under “Item 1A. Risk Factors” in our Annual Report on Form 10 K for the year ended December 31, 2019, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and in this Quarterly Report on Form 10-Q. To the extent any risk factors in our Annual Report on Form 10-K for the year ended December 31, 2019 or in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 or in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 relate to the factual information disclosed elsewhere in this Quarterly Report on Form 10 Q, including with respect to our business plan and any updates to our business strategy, such risk factors should be read in light of such information. Our business is both highly competitive and subject to various risks.

36

These risks include, without limitation:

● deterioration in global economic and financial market conditions generally, including as a result of pandemic health issues (including COVID-19 and its effects, among other things, on global supply, demand, and distribution disruptions as the COVID-19 pandemic continues and results in an increasingly prolonged period of travel, commercial and/or other similar restrictions and limitations) and the effects on electricity demand;

● the expiration or termination of PPAs and our ability to renew or enter into new PPAs on favorable terms or at all;

● the dependence of our projects on their electricity and thermal energy customers;

● exposure of certain of our projects to fluctuations in the price of electricity or natural gas;

● the dependence of our projects on third-party suppliers;

● projects not operating according to plan;

● risks inherent in the use of derivative instruments;

● the effects of weather, which affects demand for electricity and fuel as well as operating conditions;

● revenues from hydropower plants are highly dependent on precipitation and associated weather events;

● the adequacy of our insurance coverage, the timeliness of our insurance payouts, and our estimates of insurance coverage;

● risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events;

● increased competition, including for acquisitions;

● our limited control over the operation of certain minority-owned projects;

● transfer restrictions on our equity interests in certain projects;

● the impact of hostile cyber intrusions;

● labor disruptions;

● our pension plan may require additional future contributions;

● our ability to retain, motivate and recruit executives and other key employees;

● the impact of significant energy, environmental and other regulations on our projects;

● noncompliance with federal reliability standards may subject us and our projects to penalties;

● additional regulatory requirements mandating limitations on greenhouse gas emissions or requiring efficiency improvements;

● the impact of Canadian and U.S. federal income tax laws on our business;

● the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian Corruption of Foreign Public Officials Act;

37

● the impact of failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002;

● our ability to service our debt obligations or generate sufficient cash flow to pay preferred dividends;

● our indebtedness and financing arrangements and the terms, covenants and restrictions included in our senior secured term loans;

● the discontinuation, reform or replacement of LIBOR;

● exchange rate fluctuations;

● the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and changes in our creditworthiness;

● our ability to access liquidity for the ongoing operation of our business and the execution of our business plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt;

● unstable capital and credit markets;

● the anti-takeover protections in the British Columbia Business Corporations Act (the “BCBCA”) and our Articles of Continuance;

● U.S., Canadian and/or global economic conditions and uncertainty;

● the impact of impairment of goodwill, long-lived assets or equity method investments; and

● increasing competition.

Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include third-party projections of regional fuel and electric capacity and energy prices that are based on assumptions about future economic conditions and courses of action. Although the forward-looking statements contained in this Quarterly Report on Form 10-Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10-Q may be considered “financial outlook” for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10-Q. These forward-looking statements are made as of the date of this Quarterly Report on Form 10-Q and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and results of operations of Atlantic Power should be read in conjunction with the interim condensed consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q. All dollar amounts discussed below are in millions of U.S. dollars except per share amounts, or unless otherwise stated. The interim financial statements have been prepared in accordance with GAAP.

OVERVIEW

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 PPAs, which seek to minimize exposure to changes in commodity prices. As of September 30, 2020, our portfolio

38

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.

We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). Our PPAs have expiration dates ranging from December 16, 2020 (Calstock) to November 2043 (Allendale). We also sell steam from a number of our projects to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.

We directly operate and maintain sixteen of our operating power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

Available Information

Access to our Quarterly Reports on Form 10-Q, Annual Reports on Form 10-K, Current Reports on Form 8-K, and amendments to these reports filed with or furnished to the Securities and Exchange Commission (“SEC”) pursuant to Section 13(a) or 15(d) of the Exchange Act may be obtained free of charge through the Investors section of our website at https://investors.atlanticpower.com/corporate-profile as soon as is reasonably practical after we electronically file or furnish these reports. In addition, our filings with the SEC may be accessed through the SEC’s website at www.sec.gov and our filings with the Canadian Securities Administrators (“CSA”) may be accessed through the CSA’s System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com. Except for the documents specifically incorporated by reference into this Form 10-Q, information contained on our website or the SEC or CSA websites is not incorporated by reference in the Form 10-Q and should not be considered to be a part of the Form 10-Q. We have included our website address and that of the SEC and CSA only as inactive textual references and do not intend them to be active links to such websites. All statements made in any of our securities filings, including all forward-looking statements or information, are made as of the date of the document in which the statement is included, and we do not assume or undertake any obligation to update any of those statements or documents unless we are required to do so by applicable law. We are not a foreign private issuer, as defined in Rule 3b-4 under the Exchange Act.

RECENT DEVELOPMENTS

Cadillac Repair Update

On September 22, 2019, the Cadillac project experienced a malfunction in its steam turbine that began a cascade of events, sparking a fire that resulted in significant damage to the turbine, generator and other components in that area of the plant. 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. Reconstruction of Cadillac was completed in late July 2020 and the plant was recommissioned, tested and returned to service on August 20, 2020. Although the plant incurred significant damage, the financial impact has been limited by our comprehensive insurance coverage.

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. Proceeds were applied against the Cadillac insurance receivable, reducing the balance to zero as of September 30, 2020. Reimbursements for lost profits, or business interruption losses, were accounted for as a gain contingency because lost profits are not considered an incurred loss. During the third quarter 2020, we recorded business interruption proceeds of $6.2 million. These business interruption proceeds are included in other project income (loss) 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.

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In the nine months ended September 30, 2020, we recorded $21.8 million of capital additions related to repairs at Cadillac and cumulative additions of $26.8 million since the inception of the reconstruction.

Substantial Issuer Bid

On March 25, 2020, we commenced a SIB for the purchase of up to $25 million of 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. 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.

Share buybacks

Under the NCIB, we repurchased and cancelled 7,540,105 million shares at a cost of $15.8 million during 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.

Status of Calstock and Oxnard PPAs

In May 2020, the PPA with the Ontario Electricity Financial Corporation for Calstock, which had been scheduled to expire in June 2020, was extended to December 16, 2020 under existing terms. The extension provides the provincial government additional time to evaluate the future role of the Calstock plant and biomass generation in the province.

Our Oxnard project is currently operating under a Reliability Must-Run (RMR) contract with the California Independent System Operator (CAISO) through December 31, 2020. The RMR contract is based upon the plant’s cost of service and is subject to the approval of the Federal Energy Regulatory Commission (FERC), which is pending.

On August 28, 2020, we executed an agreement to sell Resource Adequacy (RA) capacity from the Oxnard plant effective January 1, 2021 through December 31, 2021. Capacity provided under the agreement will be used to satisfy the load obligations of a community choice aggregator. Under the RA agreement, Oxnard will receive a fixed monthly capacity payment. The capacity payment alone represents an improved outcome compared to a potential RMR alternative for 2021. The RA agreement also provides the opportunity for the plant to receive revenue from the potential sale of energy and ancillary services as well as other non-capacity revenues. 

COVID-19 Pandemic

We are one of many companies providing essential services during this national emergency related to the COVID-19 pandemic. 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 our 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.

This is a rapidly evolving situation that could lead to extended disruption of economic activity. To date, we have not experienced significant issues to our business related to COVID-19. Nonetheless, as a result of the spread of COVID-19 in the United States and Canada, it is difficult to assess the impact on our customers, which may impact our financial results going forward. In addition, while we have not experienced significant supply chain issues so far, we continue to closely manage and monitor developments in our supply chain, particularly as it relates to fuel procurement. An extended slowdown of the U.S. economy, demand for commodities and/or material changes in governmental policy

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could result in lower demand for electricity and natural gas as well as adversely affect the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and prospects.

OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of November 6, 2020, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region. Our customers are generally large utilities and other parties with investment-grade credit ratings, as measured by Standard & Poor’s (“S&P”). For customers rated by Moody’s, we substitute the corresponding S&P rating in the table below. Customers that have assigned ratings at the top end of the range of investment-grade have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the lower end of the range of investment-grade have weaker capacity. Agency ratings are subject to change, and there can be no assurance that a rating agency will continue to rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other obligations.

Project

Location

Type

MW

Economic Interest

Net MW

Primary Electric Purchasers

Power Contract Expiry

Customer Credit Rating (S&P)

Solid Fuel Segment

Allendale

South Carolina

Biomass

20

100.00

%

20

South Carolina Public Service Authority

November 2043

A (1)

Cadillac

Michigan

Biomass

40

100.00

%

40

Consumers Energy

June 2028

A-

Calstock

Ontario

Biomass

35

100.00

%

35

Ontario Electricity Financial Corporation

December 2020 (2)

AA- (1)

Chambers(3)

New Jersey

Coal

262

40.00

%

89

Atlantic City Electric (4)

March 2024

A-

16

Chemours Co.

March 2024

B+

Craven(3)

North Carolina

Biomass

48

50.00

%

24

Duke Energy Carolinas, LLC

December 2027

A-

Dorchester

South Carolina

Biomass

20

100.00

%

20

South Carolina Public Service Authority

October 2043

A (1)

Grayling(3)

Michigan

Biomass

37

30.00

%

11

Consumers Energy

December 2027

A-

Piedmont

Georgia

Biomass

55

100.00

%

55

Georgia Power

September 2032

A-

Williams Lake

British Columbia

Biomass

66

100.00

%

66

BC Hydro

September 2029

AAA (1)

Natural Gas Segment

Frederickson(3)

Washington

Natural Gas

250

50.15

%

50

Benton Co. PUD

August 2022

AA- (1)

45

Grays Harbor PUD

August 2022

A+ (1)

30

Franklin Co. PUD

August 2022

A+ (1)

Kenilworth

New Jersey

Natural Gas

29

100.00

%

29

Merck & Co., Inc.

September 2021

AA-

Merchant

N/A

NR

Manchief (5)

Colorado

Natural Gas

300

100.00

%

300

Public Service Company of Colorado

April 2022

A-

Morris (6)

Illinois

Natural Gas

177

100.00

%

100

Merchant

N/A

NR

77

Equistar Chemicals, LP (7)

December 2034

BBB (8)

Nipigon

Ontario

Natural Gas

40

100.00

%

40

Independent Electricity System Operator

December 2022

AA- (1)

Orlando(3)

Florida

Natural Gas

129

50.00

%

65

Duke Energy Florida, LLC

December 2023

A-

Oxnard

California

Natural Gas

49

100.00

%

49

California Independent System Operator

December 2020 (9)

A+

Tunis

Ontario

Natural Gas

37

100.00

%

37

Independent Electricity System Operator

October 2033

AA- (1)

Hydroelectric Segment

Curtis Palmer

New York

Hydro

60

100.00

%

60

Niagara Mohawk Power Corporation

December 2027 (10)

A-

Koma Kulshan

Washington

Hydro

13

100.00

%

13

Puget Sound Energy

March 2037

BBB

Mamquam(11)

British Columbia

Hydro

50

100.00

%

50

BC Hydro

September 2027

AAA (1)

Moresby Lake

British Columbia

Hydro

6

100.00

%

6

BC Hydro

August 2022

AAA (1)

(1) Customer is rated by Moody’s but not S&P; therefore, the rating shown in the table is the S&P rating that corresponds to the actual Moody’s rating.

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(2) The PPA with the Ontario Electricity Financial Corporation, which had been scheduled to expire in June 2020, was extended to December 16, 2020 on existing terms. The extension provides the provincial government additional time to evaluate the future role of the Calstock plant and biomass generation in the province.

(3) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

(4) The base PPA with Atlantic City Electric (“ACE”) makes up the majority of the revenue from the 89 Net MW. For sales of energy and capacity not purchased by ACE under the base PPA and sold to the spot market, profits are shared with ACE under a separate power sales agreement.

(5) In May 2019, we entered into an agreement to sell Manchief to PSCo following the expiration of the PPA in April 2022 for $45.2 million subject to working capital and other customary adjustments.

(6) Equistar has an option to purchase Morris that is exercisable in December 2020 and in December 2027.

(7) Equistar has the right under the PPA to take up to 77 MW, but on average has taken approximately 50 MW.

(8) Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.

(9) The PPA with Southern California Edison expired on May 25, 2020 and was not renewed or extended. The Company executed an RMR contract with the California Independent System Operator that became effective June 1, 2020 and will expire December 31, 2020. The RMR contract is conditioned upon the approval of the FERC; the application for approval was submitted to the FERC on May 28, 2020 and is pending. On August 28, 2020, we executed an agreement to sell RA capacity from the Oxnard plant effective January 1, 2021 through December 31, 2021.

(10) The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. From January 6, 1995 through September 30, 2020, the facility has generated 8,301 GWh under its PPA. Based on cumulative generation to date, we expect the PPA to expire prior to December 2027.

(11) BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.

Non-operating Natural Gas Plants

In August 2018, we terminated discussions with the Navy regarding site control for our Naval Station, Naval Training Center (“NTC”) and North Island projects located in San Diego, California. We are in the process of decommissioning all three sites, which is a requirement of our land use agreements with the Navy.

Our Kapuskasing and North Bay projects are both 40 MW natural gas plants located in the Province of Ontario. These projects formerly had PPAs with the OEFC that expired in December 2017. These plants are currently being maintained, but do not operate because they do not have PPAs or a merchant market where operations would be profitable.

42

Consolidated Overview and Results of Operations

Performance highlights

The following table provides a summary of our consolidated results of operations for the three and nine months ended September 30, 2020 and 2019, which are analyzed in greater detail below:

	Three months ended				Nine months ended
	September 30,				September 30,
(in millions of U.S. dollars, except as otherwise stated)	2020		2019		2020		2019
Project revenue	$	65.2	$	71.1	$	200.3	$	215.4
Project income		38.0		27.9		82.3		80.1
Net income attributable to Atlantic Power Corporation		16.2		12.6		40.0		22.7
Net cash provided by operating activities		27.8		36.4		72.1		104.5
Net cash used in investing activities		(6.5)		(29.1)		(9.4)		(28.0)
Net cash used in financing activities		(26.9)		(20.3)		(112.4)		(87.1)
Earnings per share attributable to Atlantic Power Corporation—basic		0.18		0.12		0.41		0.21
Earnings per share attributable to Atlantic Power Corporation—diluted		0.15		0.10		0.34		0.19
Project Adjusted EBITDA(1)		49.5		48.9		137.1		153.2

(1) See reconciliation and definition in Supplementary Non-GAAP Financial Information.

Project revenue decreased by $5.9 million to $65.2 million in the three months ended September 30, 2020 from $71.1 million in the three months ended September 30, 2019. The primary drivers of the decrease are as follows:

● Oxnard – the new RMR contract, which became effective in June 2020 and will expire in December 2020, provides for lower energy and capacity revenue than the previous contract, resulting in a decrease in project revenue of $6.0 million;

● Cadillac – the project was non-operational through August 20, 2020 following the fire in September 2019, resulting in a $1.6 million decrease in energy and capacity revenue;

● Piedmont – a combination of forced and planned maintenance outages at our Piedmont project resulted in a $1.4 million decrease in revenue from the comparable 2019 period; and

● Curtis Palmer – lower water flows resulted in a decrease in project revenue of $1.4 million from the comparable 2019 period.

These decreases in project revenue were partially offset by increases in project revenue resulting from:

● Williams Lake – a $1.8 million increase in revenue from the comparable 2019 period primarily due to the project’s new energy purchase agreement that became effective in October 2019, and higher generation than the comparable 2019 period; and

● Allendale and Dorchester – the Allendale and Dorchester projects contributed $1.8 million of revenue in the three months ended September 30, 2020. The projects were purchased in July 2019.

Consolidated project income increased by $10.1 million to $38.0 million in the three months ended September 30, 2020 from $27.9 million in the three months ended September 30, 2019. The primary drivers of the increase are as follows:

● Derivative instruments – the change in the fair value of our derivative instruments increased $7.0 million from the comparable 2019 period;

43

● Business interruption proceeds – Insurance recoveries related to business interruption losses of $6.2 million were recognized at Cadillac; and

● Fuel expenses – fuel expenses decreased by $1.9 million from the comparable 2019 period primarily due to a decrease of $1.8 million at our Oxnard project, due to the new RMR contract and lower generation for the project.

These increases in project income were partially offset by a decrease in project income resulting from:

● Project revenue – project revenue decreased $5.9 million as discussed above.

Project revenue decreased by $15.1 million to $200.3 million in the nine months ended September 30, 2020 from $215.4 million in the nine months ended September 30, 2019. The primary drivers of the decrease are as follows:

● Cadillac – the project was non-operational through August 20, 2020 following the fire in September 2019, resulting in a $10.3 million decrease in energy and capacity revenue;

● Oxnard – the new RMR contract, effective from June 2020 through December 2020, provides for lower energy and capacity revenue than the previous contract, resulting in a decrease in project revenue of $9.7 million;

● Curtis Palmer – lower water flows resulted in a $7.4 million decrease in revenue from the comparable 2019 period;

● Morris – there was a $5.9 million decrease in project revenue at our Morris project due to lower fuel index prices than in 2019; and

● Piedmont – a combination of forced and planned maintenance outages at our Piedmont project resulted in a $3.0 million decrease in revenue from the comparable 2019 period.

These decreases in project revenue were partially offset by increases in project revenue resulting from:

● Allendale and Dorchester – the Allendale and Dorchester projects contributed $14.3 million of revenue in the nine months ended September 30, 2020. The projects were purchased in July 2019;

● Williams Lake – a $1.3 million increase in revenue from the comparable 2019 period primarily due to the project’s new energy purchase agreement that became effective in October 2019;

● Kenilworth – a $1.2 million increase in revenue from the comparable 2019 period, primarily due to a steam revenue adjustment;

● Mamquam – higher water flows resulted in a $0.9 million increase in revenue from the comparable 2019 period; and

● Nipigon – a $0.9 million increase in capacity revenue due to contractual rate escalation and the project’s savings pool shared by Nipigon and the offtaker.

Consolidated project income increased by $2.2 million to $82.3 million in the nine months ended September 30, 2020 from $80.1 million in the nine months ended September 30, 2019. The primary drivers of the increase are as follows:

● Derivative instruments – the change in the fair value of our derivative instruments increased $13.9 million from the comparable 2019 period;

● Business interruption proceeds – Insurance recoveries related to business interruption losses of $6.2 million were recognized at Cadillac;

44

● Fuel expenses – fuel expenses decreased by $3.9 million from the comparable 2019 period primarily due to a decrease of $6.1 million at our Morris project due to lower fuel index prices, a decrease of $3.2 million at our Oxnard project, due to the new RMR contract and lower generation for the project, and a decrease of $2.3 million at our Cadillac project, which was non-operational through August 20, 2020 following the fire in September 2019, partially offset by a combined increase of $6.9 million at our Allendale project and our Dorchester project; and

● Depreciation and amortization expense – depreciation and amortization expense decreased by $3.2 million from the comparable 2019 period primarily due to a decrease of $1.4 million at our Oxnard project and a decrease of $1.1 million at our Calstock project, as their PPA intangibles were fully amortized in June and May of 2020, respectively.

These increases in project income were offset by decreases in project income resulting from:

● Project revenue – project revenue decreased $15.1 million as discussed above; and

● Operation and maintenance expenses – operation and maintenance expenses increased by $9.4 million from the comparable 2019 period primarily due to an increase of $7.1 million at our Allendale project and our Dorchester project, which were purchased in July 2019, an increase of $2.8 million at our Williams Lake project due to extensive planned maintenance, including replacement of the project’s cooling tower, and an increase of $1.6 million at our Morris project due to gas turbine maintenance expense. These increases were partially offset by a decrease of $3.3 million at our Oxnard project, which underwent a maintenance outage in the comparable 2019 period.

A detailed discussion of project income by segment is provided in Consolidated Overview and Results of Operations below. The discussion of Project Adjusted EBITDA by segment begins on page 57.

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 comparative 2019 period has been revised to conform to the new segment presentation. The segment classified as Corporate (formerly Un-Allocated Corporate) includes activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects and intercompany eliminations. These costs are not allocated to the operating segments when determining segment profit or loss. Project income is the primary GAAP measure of our operating results and is discussed below by reportable segment.

45

Three months ended September 30, 2020 compared to the three months ended September 30, 2019

The following table provides our consolidated results of operations:

	Three months ended September 30,
	2020		2019		$ change		% change
Project revenue:
Energy sales	$	30.3	$	29.2	$	1.1	3.8	%
Energy capacity revenue		29.7		38.0		(8.3)	(21.8)	%
Other		5.2		3.9		1.3	33.3	%
		65.2		71.1		(5.9)	(8.3)	%
Project expenses:
Fuel		17.5		19.4		(1.9)	(9.8)	%
Operations and maintenance		21.2		19.5		1.7	8.7	%
Depreciation and amortization		14.5		16.2		(1.7)	(10.5)	%
		53.2		55.1		(1.9)	(3.4)	%
Project other income (loss):
Change in fair value of derivative instruments		8.1		1.1		7.0	NM (1)
Equity in earnings of unconsolidated affiliates		12.1		12.1		—	—	%
Interest expense, net		(0.4)		(0.3)		(0.1)	33.3	%
Insurance gain (loss)		6.2		(1.0)		7.2	NM
		26.0		11.9		14.1	NM
Project income		38.0		27.9		10.1	36.2	%
Administrative and other expenses (income):
Administration		5.6		5.5		0.1	1.8	%
Interest expense, net		10.8		10.9		(0.1)	(0.9)	%
Foreign exchange loss (gain)		5.1		(2.8)		7.9	NM
Other income, net		(3.8)		(0.2)		(3.6)	NM
		17.7		13.4		4.3	32.1	%
Income from operations before income taxes		20.3		14.5		5.8	40.0	%
Income tax expense		2.5		0.2		2.3	NM
Net income		17.8		14.3		3.5	24.5	%
Net income attributable to preferred shares of a subsidiary company		1.6		1.7		(0.1)	(5.9)	%
Net income attributable to Atlantic Power Corporation	$	16.2	$	12.6	$	3.6	28.6	%

⁽¹⁾ NM is defined as “not meaningful” and includes changes greater than 100%.

46

	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
Other		0.2		4.1		0.7		0.2		5.2
		26.7		29.1		9.2		0.2		65.2
Project expenses:
Fuel		9.4		8.1		—		—		17.5
Operations and maintenance		9.9		7.1		3.6		0.6		21.2
Depreciation and amortization		3.1		6.5		4.9		—		14.5
		22.4		21.7		8.5		0.6		53.2
Project other income (loss):
Change in fair value of derivative instruments		—		6.3		—		1.8		8.1
Equity in earnings of unconsolidated affiliates		0.6		11.5		—		—		12.1
Interest expense, net		(0.3)		—		—		(0.1)		(0.4)
Insurance gain		6.2		—		—		—		6.2
		6.5		17.8		—		1.7		26.0
Project income	$	10.8	$	25.2	$	0.7	$	1.3	$	38.0

	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
Other		—		3.1		0.6		0.2		3.9
		26.1		35.1		9.7		0.2		71.1
Project expenses:
Fuel		8.4		11.0		—		—		19.4
Operations and maintenance		7.8		7.8		3.4		0.5		19.5
Depreciation and amortization		3.7		7.6		4.9		—		16.2
		19.9		26.4		8.3		0.5		55.1
Project other income (loss):
Change in fair value of derivative instruments		—		2.7		—		(1.6)		1.1
Equity in earnings of unconsolidated affiliates		0.5		11.6		—		—		12.1
Interest expense, net		(0.3)		—		—		—		(0.3)
Insurance loss		(1.0)		—		—		—		(1.0)
		(0.8)		14.3		—		(1.6)		11.9
Project income (loss)	$	5.4	$	23.0	$	1.4	$	(1.9)	$	27.9

Solid Fuel

Project income for the three months ended September 30, 2020 increased $5.4 million from the comparable 2019 period primarily due to:

● increased project income of $6.3 million at Cadillac primarily due to insurance proceeds of $6.2 million for business interruption losses as a result of the fire at the project in September 2019;

● increased project income of $1.3 million at Chambers primarily due to lower fuel consumption and improved heat rate than the comparable 2019 period; and

● increased project income of $1.0 million at Williams Lake primarily due to the project’s new energy purchase agreement that became effective in October 2019, and higher generation than the comparable 2019 period, which resulted in a $1.8 million increase in project revenue from the comparable 2019 period.

47

These increases were partially offset by:

● decreased project income of $1.1 million at Piedmont due to maintenance outages in the current period;

● decreased project income of $0.8 million at Grayling due to a maintenance outage in the current period; and

● decreased project income of $0.6 million at Calstock primarily due to a $0.8 million increase in fuel expenses from the comparable 2019 period, partially offset by a $0.4 million decrease in intangible amortization as the project’s PPA intangibles were fully amortized in May 2019.

Natural Gas

Project income for the three months ended September 30, 2020 increased $2.2 million from the comparable 2019 period primarily due to:

● increased project income of $5.0 million at Orlando primarily due to a $4.9 million increase in the fair value of natural gas swaps;

● increased project income of $0.6 million at Nipigon primarily due to a $0.6 million decrease in maintenance expense due to major maintenance at the project in the comparable 2019 period; and

● increased project income of $0.6 million at Manchief primarily due to higher dispatch than the comparable 2019 period.

These increases were partially offset by:

● decreased project income of $2.1 million at Morris due to increased gas turbine maintenance expense of $1.1 million and a lower gross margin from lower PJM pricing; and

● decreased project income of $2.0 million at Oxnard due to the new RMR contract, effective from June 2020 through December 2020, which provides for lower energy and capacity revenue than the previous contract.

Hydroelectric

Project income for the three months ended September 30, 2020 decreased $0.7 million from the comparable 2019 period primarily due to:

● decreased project income of $1.7 million at Curtis Palmer primarily due to lower water flows than the comparable 2019 period.

Corporate

Project income for the three months ended September 30, 2020 increased $3.2 million from the comparable 2019 period primarily due to a $5.4 million increase in the fair value of interest rate swap agreements related to the senior secured credit facility.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to any specific project and are allocated to the Corporate segment. These costs include the activities that support the executive and administrative offices, treasury function, costs of being a public registrant, costs to develop or acquire future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate taxes. Significant non-cash items that impact Administrative and other expenses (income), and that are subject to potentially significant fluctuations include the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these non-cash items.

48

Administration

Administration expense for the three months ended September 30, 2020 did not change materially from the three months ended September 30, 2019.

Interest expense, net

Interest expense for the three months ended September 30, 2020 did not change materially from the three months ended September 30, 2019.

Foreign exchange loss

Foreign exchange loss increased by $7.9 million to a $5.1 million loss in the three months ended September 30, 2020 from a $2.8 million gain in the comparable 2019 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and Series E Debentures). The Canadian dollar appreciated 2.1% against the U.S. dollar from June 30, 2020 to September 30, 2020, as compared to a 1.2% depreciation in the comparable 2019 period.

Other income, net

Other income, net increased by $3.6 million for the three months ended September 30, 2020 from the comparable 2019 period primarily due to a $3.5 million change in the fair value of the conversion option of the Series E Debentures.

Income tax expense

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.

49

Nine months ended September 30, 2020 compared to the nine months ended September 30, 2019

The following table provides our consolidated results of operations:

	Nine months ended September 30,
	2020		2019		$ change		% change
Project revenue:
Energy sales	$	102.1	$	102.7	$	(0.6)	(0.6)	%
Energy capacity revenue		84.8		99.8		(15.0)	(15.0)	%
Other		13.4		12.9		0.5	3.9	%
		200.3		215.4		(15.1)	(7.0)	%
Project expenses:
Fuel		51.3		55.2		(3.9)	(7.1)	%
Operations and maintenance		64.0		54.6		9.4	17.2	%
Depreciation and amortization		45.3		48.5		(3.2)	(6.6)	%
		160.6		158.3		2.3	1.5	%
Project other income (loss):
Change in fair value of derivative instruments		5.6		(8.3)		13.9	NM
Equity in earnings of unconsolidated affiliates		31.8		34.4		(2.6)	(7.6)	%
Interest expense, net		(1.0)		(0.9)		(0.1)	11.1	%
Insurance gain (loss)		6.2		(1.0)		7.2	NM
Other expense, net		—		(1.2)		1.2	NM
		42.6		23.0		19.6	85.2	%
Project income		82.3		80.1		2.2	2.7	%
Administrative and other expenses (income):
Administration		16.8		17.3		(0.5)	(2.9)	%
Interest expense, net		31.7		33.0		(1.3)	(3.9)	%
Foreign exchange (gain) loss		(6.2)		7.1		(13.3)	NM
Other (income) expense, net		(2.7)		0.7		(3.4)	NM
		39.6		58.1		(18.5)	(31.8)	%
Income from operations before income taxes		42.7		22.0		20.7	94.1	%
Income tax expense		5.2		2.4		2.8	NM
Net income		37.5		19.6		17.9	91.3	%
Net loss attributable to preferred shares of a subsidiary company		(2.5)		(3.1)		0.6	(19.4)	%
Net income attributable to Atlantic Power Corporation	$	40.0	$	22.7	$	17.3	76.2	%

	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
Other		0.6		9.7		2.4		0.7		13.4
		67.4		86.7		45.5		0.7		200.3
Project expenses:
Fuel		26.0		25.3		—		—		51.3
Operations and maintenance		33.5		18.9		9.8		1.8		64.0
Depreciation and amortization		9.4		21.1		14.7		0.1		45.3
		68.9		65.3		24.5		1.9		160.6
Project other income (loss):
Change in fair value of derivative instruments		—		9.3		—		(3.7)		5.6
Equity in earnings of unconsolidated affiliates		0.7		31.1		—		—		31.8
Interest expense, net		(0.9)		—		—		(0.1)		(1.0)
Insurance gain		6.2		—		—		—		6.2
		6.0		40.4		—		(3.8)		42.6
Project income (loss)	$	4.5	$	61.8	$	21.0	$	(5.0)	$	82.3

50

	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
Other		0.1		9.9		2.2		0.7		12.9
		64.5		99.6		50.6		0.7		215.4
Project expenses:
Fuel		21.6		33.6		—		—		55.2
Operations and maintenance		22.4		22.0		9.4		0.8		54.6
Depreciation and amortization		11.2		22.6		14.6		0.1		48.5
		55.2		78.2		24.0		0.9		158.3
Project other income (loss):
Change in fair value of derivative instruments		(0.1)		—		—		(8.2)		(8.3)
Equity in earnings of unconsolidated affiliates		3.1		31.3		—		—		34.4
Interest (expense) income, net		(1.0)		0.1		—		—		(0.9)
Insurance loss		(1.0)		—		—		—		(1.0)
Other expense, net		—		(1.2)		—		—		(1.2)
		1.0		30.2		—		(8.2)		23.0
Project income (loss)	$	10.3	$	51.6	$	26.6	$	(8.4)	$	80.1

Solid Fuel

Project income for the nine months ended September 30, 2020 decreased $5.8 million from the comparable 2019 period primarily due to:

● decreased project income of $2.3 million at Craven as a result of extended rotor repairs at the project during 2020. The project was purchased in August 2019 and therefore had a limited impact on project income in the comparable 2019 period;

● decreased project income of $1.9 million at Williams Lake primarily due to a $2.3 million increase in maintenance expenses from replacement of the cooling tower and contractual curtailment of the project from April through July 2020 under the new PPA;

● decreased project income of $1.7 million at Grayling as a result of extended rotor and generator repairs at the project during 2020. The project was purchased in August 2019 and therefore had a limited impact on project income in the comparable 2019 period; and

● decreased project income of $1.5 million at Piedmont primarily due to maintenance outages.

These decreases were partially offset by:

● increased project income of $1.6 million at Chambers primarily due to lower fuel consumption and improved heat rate than the comparable 2019 period.

Natural Gas

Project income for the nine months ended September 30, 2020 increased $10.2 million from the comparable 2019 period primarily due to:

● increased project income of $5.8 million at Nipigon primarily due to a $2.6 million increase in the fair value of the fuel agreement accounted for as a derivative financial instrument, a $1.2 million decrease in maintenance expense due to major maintenance at the project in the comparable 2019 period and a $0.9 million increase in capacity revenue due to contractual rate escalation and the project’s savings pool shared by Nipigon and the offtaker;

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● increased project income of $6.2 million at Orlando primarily due to a $7.9 million increase in the fair value of natural gas swaps, partially offset by a $1.9 million increase in fuel expense due to unfavorable fuel prices;

● increased project income of $1.0 million at Kenilworth primarily due to a steam revenue adjustment; and

● increased project income of $0.6 million, $0.7 million and $0.4 million at Naval Station, NTC and North Island, respectively, which ceased operations in February 2018, and incurred project losses in the comparable 2019 period primarily related to asset retirement obligations.

These increases were partially offset by:

● decreased project income of $2.8 million at Morris primarily due increased gas turbine maintenance expense of $1.3 million and a lower gross margin from lower PJM pricing; and

● decreased project income of $1.9 million at Oxnard primarily due to the new RMR contract, effective from June 2020 to December 2020, that provides for lower energy and capacity revenue than the previous contract.

Hydroelectric

Project income for the nine months ended September 30, 2020 decreased $5.6 million from the comparable 2019 period primarily due to:

● decreased project income of $8.0 million at Curtis Palmer primarily due to lower water flows than the comparable 2019 period.

This decrease was partially offset by:

● increased project income of $1.0 million at Mamquam primarily due to higher water flows than the comparable 2019 period.

Corporate

Project income for the nine months ended September 30, 2020 increased $3.4 million from the comparable 2019 period primarily due to a $4.5 million increase in the fair value of interest rate swap agreements related to the senior secured credit facility.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to any specific project and are allocated to the Corporate segment. These costs include the activities that support the executive and administrative offices, treasury function, costs of being a public registrant, costs to develop or acquire future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate taxes. Significant non-cash items that impact Administrative and other expenses (income), and that are subject to potentially significant fluctuations include the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these non-cash items.

Administration

Administration expense for the nine months ended September 30, 2020 did not change materially from the nine months ended September 30, 2019.

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Interest expense, net

Interest expense decreased by $1.3 million to $31.7 million in the nine months ended September 30, 2020 from $33.0 million in the comparable period in 2019, primarily due to lower outstanding debt balances than the comparable 2019 period, as well as a lower interest rate on our senior secured credit facility.

Foreign exchange (gain) loss

Foreign exchange loss decreased by $13.3 million to a $6.2 million gain in the nine months ended September 30, 2020 from a $7.1 million loss in the comparable 2019 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and Series E Debentures). The Canadian dollar depreciated 2.7% against the U.S. dollar from December 31, 2019 to September 30, 2020, as compared to a 2.9% appreciation in the comparable 2019 period.

Other income, net

Other income, net for the nine months ended September 30, 2020 increased by $3.4 million primarily due to a $3.3 million change in the fair value of the conversion option of the Series E Debentures.

Income tax expense

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.

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Project Operating Performance

Two of the primary metrics we utilize to measure the operating performance of our projects are generation and availability. Generation measures the net output of our proportionate project ownership percentage in megawatt hours (“MWh”). Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority of our projects were able to achieve their respective capacity payments. For projects where reduced availability adversely impacted capacity payments, the impact was not material for the three and nine months ended September 30, 2020, with the exception of the Cadillac project. While the reduction in availability at the Cadillac project impacted capacity payments for the period ended September 30, 2020, we recovered these capacity payments through the business interruption insurance recoveries for the period. The terms of our PPAs provide for certain levels of planned and unplanned outages. All references below are denominated in net Gigawatt hours (“net GWh”).

Generation

	Generation
	Three months ended September 30,
			% change
(in Net GWh)	2020	2019	2020 vs. 2019
Segment
Solid Fuel	370.6	390.6	(5.1)	%
Natural Gas	673.0	772.4	(12.9)	%
Hydroelectric	110.8	105.3	5.2	%
Total	1,154.4	1,268.3	(9.0)	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

Aggregate power generation for the three months ended September 30, 2020 decreased 9.0% from the comparable 2019 period primarily due to:

● decreased generation in the Natural Gas segment primarily due to a 108.5 net GWh decrease in generation at Frederickson due to lower dispatch than the comparable 2019 period and a 38.2 net GWh decrease in generation at Oxnard under the new RMR contract, effective from June 2020 through December 2020, as the project runs only when it is called upon to operate. These decreases were partially offset by a 63.7 net GWh increase at Manchief due to higher dispatch than the comparable 2019 period; and

● decreased generation in the Solid Fuel segment primarily due to a 27.7 net GWh decrease at Piedmont due to maintenance outages and an 11.8 net GWh decrease at Cadillac due to an extended outage as a result of the fire in September 2019. These were partially offset by a combined 25.4 net GWh increase at Allendale and Dorchester, which were acquired in July 2019.

These decreases were partially offset by:

● increased generation in the Hydroelectric segment primarily due to an 8.7 net GWh increase in generation at Mamquam due to snowpack remaining slightly higher than the historical average, and increased generation of 4.3 and 3.4 net GWh at Koma Kulshan and Moresby Lake, respectively. This was partially offset by a 10.9 net GWh decrease in generation at Curtis Palmer due to lower water flows in the current period.

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	Generation
	Nine months ended September 30,
			% change
(in Net GWh)	2020	2019	2020 vs. 2019
Segment
Solid Fuel	1,049.7	1,121.4	(6.4)	%
Natural Gas	1,718.5	1,871.7	(8.2)	%
Hydroelectric	497.1	506.3	(1.8)	%
Total	3,265.3	3,499.4	(6.7)	%

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Aggregate power generation for the nine months ended September 30, 2020 decreased 6.7% from the comparable 2019 period primarily due to:

● decreased generation in the Natural Gas segment primarily due to a 90.9 net GWh decrease in generation at Frederickson due to lower dispatch than the comparable 2019 period, a 58.5 net GWh decrease in generation at Oxnard under the new RMR contract, effective from June 2020 through December 2020, as the project runs only when it is called upon to operate, and a 39.3 net GWh decrease in generation at Morris due to lower PJM pricing in the period. These decreases were partially offset by a 71.6 net GWh increase in generation at Manchief due to higher dispatch than the comparable 2019 period;

● decreased generation in the Solid Fuel segment of 145.0 net GWh at Williams Lake primarily due to the contractual curtailment during the months of May, June and July under the new PPA. The extended outage at Cadillac due to a fire in September 2019 and outages at Piedmont accounted for an additional 139.0 decrease in net GWh, with generation decreases of 74.6 and 64.4 net GWh, respectively. These decreases were partially offset by a combined generation increase of 228.5 net GWh at Allendale, Dorchester, Craven and Grayling, which were acquired in July 2019; and

● decreased generation in the Hydroelectric segment, primarily due to a 56.1 net GWh decrease at Curtis Palmer as a result of lower water flows than in 2019. These decreases were partially offset by increased generation at Mamquam of 31.3 net GWh, Koma Kulshan of 8.9 net GWh, and Moresby Lake of 6.7 net GWh due to higher water flows than the comparable 2019 period.

Availability

	Availability
	Three months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Segment
Solid Fuel	75.4	%	79.9	%	(4.5)	%
Natural Gas	96.8	%	98.8	%	(2.0)	%
Hydroelectric	93.4	%	97.8	%	(4.4)	%
Weighted average	87.3	%	95.1	%	(7.8)	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

Aggregate power availability for the three months ended September 30, 2020 decreased 7.8% from the comparable 2019 period primarily due to:

● decreased availability in the Solid Fuel segment primarily due to the fire at Cadillac in September 2019 and outages at Piedmont in the current quarterly period;

● decreased availability in the Hydroelectric segment primarily due to planned outages at Curtis Palmer, partially offset by increased availability at Mamquam and Moresby Lake due to forced outages in the comparable 2019 period; and

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● decreased availability in the Natural Gas segment primarily due to planned outages at Kenilworth in the current quarterly period, partially offset by increased availability at Nipigon due to maintenance outages in the comparable 2019 period.

	Availability
	Nine months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Segment
Solid Fuel	75.3	%	90.1	%	(14.8)	%
Natural Gas	94.6	%	98.0	%	(3.4)	%
Hydroelectric	85.3	%	94.6	%	(9.3)	%
Weighted average	85.0	%	95.8	%	(10.8)	%

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Aggregate power availability for the nine months ended September 30, 2020 decreased 10.8% from the comparable 2019 period primarily due to:

● decreased availability in the Solid Fuel segment primarily due to the fire at Cadillac in September 2019 and outages at Piedmont in the period;

● decreased availability in the Hydroelectric segment primarily due to forced outages at Koma Kulshan in the period; and

● decreased availability in the Natural Gas segment primarily due to planned outages at Kenilworth and Orlando in the period.

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Supplementary Non-GAAP Financial Information

The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. Project Adjusted EBITDA 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 believe that Project Adjusted EBITDA is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project Adjusted EBITDA is Project income. A reconciliation of Net income (loss) to Project income and to Project Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity method investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.

Project Adjusted EBITDA

	Three months ended						Nine months ended
	September 30,				$ change		September 30,				$ change
	2020		2019		2020 vs 2019		2020		2019		2020 vs 2019
Net income	$	17.8	$	14.3	$	3.5	$	37.5	$	19.6	$	17.9
Income tax expense		2.5		0.2		2.3		5.2		2.4		2.8
Income from operations before income taxes		20.3		14.5		5.8		42.7		22.0		20.7
Administration		5.6		5.5		0.1		16.8		17.3		(0.5)
Interest expense, net		10.8		10.9		(0.1)		31.7		33.0		(1.3)
Foreign exchange loss (gain)		5.1		(2.8)		7.9		(6.2)		7.1		(13.3)
Other (income) expense, net		(3.8)		(0.2)		(3.6)		(2.7)		0.7		(3.4)
Project income	$	38.0	$	27.9	$	10.1	$	82.3	$	80.1	$	2.2
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization		18.8		20.2		(1.4)		58.3		60.6		(2.3)
Interest expense, net		0.8		0.8		—		2.1		2.0		0.1
Change in the fair value of derivative instruments		(8.1)		(1.0)		(7.1)		(5.6)		8.3		(13.9)
Insurance loss		—		1.0		(1.0)		—		1.0		(1.0)
Other expense, net		—		—		—		—		1.2		(1.2)
Project Adjusted EBITDA	$	49.5	$	48.9	$	0.6	$	137.1	$	153.2	$	(16.1)
Project Adjusted EBITDA by segment
Solid Fuel		17.1		13.2		3.9		23.3		31.5		(8.2)
Natural Gas		27.1		29.6		(2.5)		79.1		80.6		(1.5)
Hydroelectric		5.6		6.3		(0.7)		35.7		41.2		(5.5)
Corporate		(0.3)		(0.2)		(0.1)		(1.0)		(0.1)		(0.9)
Total	$	49.5	$	48.9	$	0.6	$	137.1	$	153.2	$	(16.1)

Solid Fuel

The following table summarizes Project Adjusted EBITDA for our Solid Fuel segment for the periods indicated:

	Three months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Solid Fuel
Project Adjusted EBITDA	$	17.1	$	13.2	30	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

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Project Adjusted EBITDA for the three months ended September 30, 2020 increased $3.9 million from the comparable 2019 period primarily due to increased Project Adjusted EBITDA of:

● $5.0 million at Cadillac primarily due to insurance proceeds of $6.2 million for business interruption losses, a portion of which related to losses incurred in 2019, as a result of the fire at the project in September 2019;

● $1.2 million at Chambers due to lower fuel consumption and improved heat rate than the comparable 2019 period; and

● $1.1 million at Williams Lake primarily due to the project’s new energy purchase agreement that became effective in October 2019, and higher generation than the comparable 2019 period.

These increases were partially offset by decreases in Project Adjusted EBITDA of:

● $1.1 million at Calstock due to higher biomass fuel prices; and

● $1.1 million at Piedmont due to maintenance outages in the current quarterly period.

	Nine months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Solid Fuel
Project Adjusted EBITDA	$	23.3	$	31.5	(26)	%

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Project Adjusted EBITDA for the nine months ended September 30, 2020 decreased $8.2 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

● $2.6 million at Cadillac, which was non-operational from September 2019 to August 20, 2020 due to a fire at the project. This resulted in a decrease of $8.8 million from the comparable 2019 period, partially offset by insurance proceeds of $6.2 million for business interruption losses, a portion of which related to losses incurred in 2019;

● $1.8 million at Craven, primarily due to rotor repairs at the project during 2020. The project was purchased in August 2019 and therefore had limited impact on project income in the comparable 2019 period;

● $1.7 million at Williams Lake, primarily due to a $2.3 million increase in maintenance expenses from replacement of the cooling tower, and contractual curtailment of the project from April through July 2020;

● $1.5 million at Piedmont primarily due to maintenance outages; and

● $1.4 million at Grayling primarily due to extended rotor and generator repairs at the project during 2020. The project was purchased in August 2019 and therefore had a limited impact on project income in the comparable 2019 period.

These decreases were partially offset by increases in Project Adjusted EBITDA of:

● $1.4 million at Chambers due to lower fuel consumption and improved heat rate than the comparable 2019 period.

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Natural Gas

The following table summarizes Project Adjusted EBITDA for our Natural Gas segment for the periods indicated:

	Three months ended September 30,
					% change
	2020		2019		2020 vs 2019
Natural Gas
Project Adjusted EBITDA	$	27.1	$	29.6	(8)	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

Project Adjusted EBITDA for the three months ended September 30, 2020 decreased $2.5 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

● $3.0 million at Oxnard due to the new RMR contract, effective from June 2020 through December 2020, which provides for lower energy and capacity revenue than the previous contract; and

● $1.9 million at Morris due to increased gas turbine maintenance expense of $1.1 million and a lower gross margin from lower PJM pricing.

These decreases were partially offset by an increase in Project Adjusted EBITDA of:

● $1.6 million at Nipigon due to major maintenance at the project in the comparable period and the project’s savings pool shared by Nipigon and the offtaker.

	Nine months ended September 30,
					% change
	2020		2019		2020 vs 2019
Natural Gas
Project Adjusted EBITDA	$	79.1	$	80.6	(2)	%

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Project Adjusted EBITDA for the nine months ended September 30, 2020 decreased $1.5 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

● $3.2 million at Oxnard due to the new RMR contract, effective from June 2020 through December 2020, which provides for lower energy and capacity revenue than the previous contract;

● $1.7 million at Orlando primarily due to planned major maintenance at the project; and

● $1.5 million at Morris primarily due to increased gas turbine maintenance expense of $1.3 million and a lower gross margin from lower PJM pricing.

These decreases were partially offset by increases in Project Adjusted EBITDA of:

● $3.2 million at Nipigon due to contractual rate escalation and major maintenance at the project in the comparable 2019 period; and

● $1.0 million at Kenilworth primarily due to a steam revenue adjustment.

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Hydroelectric

The following table summarizes Project Adjusted EBITDA for our Hydroelectric segment for the periods indicated:

	Three months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Hydroelectric
Project Adjusted EBITDA	$	5.6	$	6.3	(11)	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

Project Adjusted EBITDA for the three months ended September 30, 2020 decreased $0.7 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

● $1.7 million at Curtis Palmer primarily due to lower water flows than the comparable 2019 period.

	Nine months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Hydroelectric
Project Adjusted EBITDA	$	35.7	$	41.2	(13)	%

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

Project Adjusted EBITDA for the nine months ended September 30, 2020 decreased $5.5 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

● $8.0 million at Curtis Palmer primarily due to lower water flows than the comparable 2019 period.

This decrease was partially offset by an increase in Project Adjusted EBITDA of:

● $1.1 million at Mamquam primarily due to higher water flows than the comparable 2019 period.

Corporate

The following table summarizes Project Adjusted EBITDA for our Corporate segment for the periods indicated:

	Three months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Corporate
Project Adjusted EBITDA	$	(0.3)	$	(0.2)	50	%

Three months ended September 30, 2020 compared with three months ended September 30, 2019

Project Adjusted EBITDA for the three months ended September 30, 2020 did not change materially from the comparable 2019 period.

	Nine months ended September 30,
					% change
	2020		2019		2020 vs. 2019
Corporate
Project Adjusted EBITDA	$	(1.0)	$	(0.1)	NM

Nine months ended September 30, 2020 compared with nine months ended September 30, 2019

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Project Adjusted EBITDA for the nine months ended September 30, 2020 did not change materially from the comparable 2019 period.

Liquidity and Capital Resources

	September 30,		December 31,
	2020		2019
Cash and cash equivalents	$	30.3	$	74.9
Restricted cash		2.6		7.7
Total		32.9		82.6
Revolving credit facility availability (1)		102.0		121.7
Total liquidity	$	134.9	$	204.3

(1) On March 18, 2020, the borrowing capacity under the Revolver was reduced to $180 million under the amendment to extend the Revolver maturity to April 2025.

Overview

Our primary sources of liquidity are distributions from our projects and availability under our Revolver. Our liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from December 16, 2020 (Calstock) to November 2043 (Allendale). Calstock is currently the one project operating under a PPA with an expiration date in 2020. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA, if at all, or the price received by the project for power under subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project distributions and the cash available for further debt reduction, identification of and investment in accretive growth opportunities (both internal and external), to the extent available, and other allocation of available cash. See “Risk Factors—Risks Related to Our Financial Position and Economic and Financial Market Conditions —We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities” in our Annual Report on Form 10-K for the year ended December 31, 2019.

Consolidated Cash Flow Discussion

The following table reflects the changes in cash flows for the periods indicated:

	Nine months ended
	September 30,
	2020		2019		Change
Net cash provided by operating activities	$	72.1	$	104.5	$	(32.4)
Net cash used in investing activities		(9.4)		(28.0)		18.6
Net cash used in financing activities		(112.4)		(87.1)		(25.3)

Operating Activities

Cash flow from our projects may vary from period to period based on working capital requirements and the operating performance of the projects, as well as changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, and the transition to merchant or re-contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

For the nine months ended September 30, 2020, the net decrease in cash provided by operating activities of $32.4 million was primarily the result of the following:

● Cadillac – following the fire in September 2019, the project was non-operational through August 20, 2020, which resulted in an $8.8 million negative impact on cash flows provided by operations. This decrease was partially offset by insurance proceeds. We received insurance proceeds of $19.7 million related to the

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Cadillac fire, of which $7.0 million related to operating activities, including $6.2 million for business interruption losses and $0.8 million for fuel inventory losses;

● Working capital – changes in working capital resulted in a $14.3 million decrease in cash flows from operating activities from the comparable 2019 period. The unfavorable change in working capital is primarily due to the timing of cash disbursements for payables at Cadillac for repair work and at Morris in preparation for a maintenance outage later in 2020;

● Hydrological conditions – lower water flows at our Curtis Palmer project, partially offset by higher water flows at our Mamquam project, had a $5.5 million negative impact on cash flows provided by operating activities;

● Distributions from unconsolidated affiliates – we received $4.1 million less in distributions from our unconsolidated affiliates than the comparable 2019 period, primarily at Chambers which began repaying principal on its project-level debt in the fourth quarter of 2019; and

● New contracts – A $3.2 million negative impact on cash flows provided by operating activities at Oxnard due to the new RMR contract, effective from June 2020 through December 2020, which provides for lower energy and capacity revenue than the previous contract; and a $1.7 million negative impact on cash flows provided by operating activities at Williams Lake, primarily due to contractual curtailment of the project from April through July 2020 in accordance with the project’s new energy purchase agreement that became effective in October 2019 and a $2.3 million increase in maintenance expenses associated with replacement of the cooling tower.

Investing Activities

For the nine months ended September 30, 2020, the net decrease in cash used in investing activities of $18.6 million was primarily the result of the following:

● Insurance proceeds – we received insurance proceeds of $19.7 million related to the Cadillac fire, of which $12.7 million related to property, plant and equipment;

● Investment in unconsolidated affiliates – we paid $18.7 million in the comparable 2019 period to acquire a 50% interest in Craven and a 30% interest in Grayling in August 2019; and

● Acquisitions  – we paid $10.0 million in the comparable 2019 period to complete the acquisition of Dorchester and Allendale in July 2019.

These decreases were partially offset by the following increase in cash used in investing activities:

● Capitalized plant additions – capitalized plant additions were $22.1 million higher in the nine months ended September 30, 2020 than the comparable 2019 period, primarily due to repairs at Cadillac.

Financing Activities

For the nine months ended September 30, 2020, the net increase in cash used in financing activities of $25.3 million was primarily the result of the following:

● Common share repurchases – we paid $41.6 million (which includes $25.8 million for the SIB, including transaction costs) in the nine months ended September 30, 2020 to repurchase and cancel common shares as compared to $0.8 million in the comparative 2019 period;

● Corporate and project-level debt repayments – we made $4.8 million greater principal payments than the comparable 2019 period; and

● Deferred financing costs – we incurred $1.6 million of deferred financing costs related to amending the Term Loan and the Revolver in the nine months ended September 30, 2020.

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These increases were partially offset by the following decreases in cash flows used in financing activities:

● Convertible debenture redemptions – we paid $18.5 million to redeem and cancel the Series D Debentures in the comparable 2019 period;

● Preferred share repurchases – we paid $6.4 million to repurchase and cancel preferred shares as compared to $8.0 million in the comparable 2019 period; and

● Vested LTIP – we made $1.3 million of lower cash payments for vested LTIP tax withholdings than in the comparable 2019 period.

Corporate Debt

The following table summarizes the maturities of our corporate debt at September 30, 2020:

				Remaining
	Maturity	Interest		Principal
	Date	Rates		Repayments		2020		2021		2022		2023		2024		Thereafter
Senior secured term loan facility(1)	April 2025	4.73	%	$	326.0	$	18.5	$	93.0	$	106.0	$	60.0	$	36.0	$	12.5
MTNs	June 2036	5.95	%		157.4		—		—		—		—		—		157.4
Convertible Debenture	January 2025	6.00	%		86.2		—		—		—		—		—		86.2
Total Corporate Debt				$	569.6	$	18.5	$	93.0	$	106.0	$	60.0	$	36.0	$	256.1

(1) The Term Loan Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the Term Loan Facility and the 5.95% MTNs, letters of credit costs to meet the requirements of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Term Loan Facility, and payment on the preferred equity issued by APPEL, a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of the Term Loan Facility outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Note that failing to meet the mandatory amortization requirements is not an event of default, but could result in APLP Holdings being unable to make distributions to Atlantic Power Corporation and APPEL being unable to pay dividends to its shareholders. The amortization profile in the table above is based on principal payments according to the targeted principal amount described in (ii) above through 2022 based on the schedule as amended in January 2020. After 2022, the amortization profile is based on (i) above and is an estimate, subject to change. See Note 5, Long-term debt for more information on our Credit Facilities.
​

Project-Level Debt

Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue-generating contracts of the projects. The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at September 30, 2020. Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. At November 6, 2020, all of our projects except for Cadillac were in compliance with the covenants contained in project-level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but are not callable or subject to acceleration under the terms of their debt agreements.

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

63

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.

The range of interest rates presented represents the rates in effect at September 30, 2020. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.

							Total
							Remaining
	Maturity	Range of					Principal
	Date	Interest Rates					Repayments		2020		2021		2022		2023		2024		Thereafter
Consolidated Projects:
Cadillac	August 2025	6.26	%	-	6.38	%	$	15.6	$	0.8	$	2.7	$	3.3	$	3.3	$	3.7	$	1.8
Total Consolidated Projects								15.6		0.8		2.7		3.3		3.3		3.7		1.8
Equity Method Projects:
Chambers(1)	December 2023	5.00	%					34.6		3.9		8.8		10.1		11.8		—		—
Total Equity Method Projects								34.6		3.9		8.8		10.1		11.8		—		—
Total Project-Level Debt							$	50.2	$	4.7	$	11.5	$	13.4	$	15.1	$	3.7	$	1.8

(1) The above table does not include our $0.8 million proportionate share of issuance premiums.

Uses of Liquidity

Our requirements for liquidity and capital resources, other than operating our projects, consist primarily of principal and interest on our outstanding Series E Debentures, Term Loan Facility, MTNs and other corporate and project-level debt; funding the repurchase of shares of our common stock, our Series E Debentures, and our preferred shares (to the extent we choose to pursue any such repurchases); collateral and investment in our projects through capital expenditures, including major maintenance and business development costs; and dividend payments to preferred shareholders of a subsidiary company.

Capital and Maintenance Expenditures

Capital expenditures and maintenance expenses for the projects are generally paid at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures and maintenance expenditures needed at the projects. The operating projects which we own consist of large capital assets that have established commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most expenditures relate to planned repairs and maintenance and are expensed when incurred.

Excluding reconstruction costs at Cadillac, we expect to reinvest approximately $4.0 million in 2020 (of which $2.6 million was reinvested in the nine months ended September 30, 2020) in our portfolio, including equity method investments, in the form of project capital expenditures, and incur $32.8 million of maintenance expenses (of which $24.4 million was incurred in the nine months ended September 30, 2020). Such investments are generally paid at the project level. See “Liquidity and Capital Resources—Capital and Maintenance Expenditures” in our Annual Report on Form 10-K for the year ended December 31, 2019. We do not expect any other material or unusual requirements for cash outflows for 2020 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

We believe one of the benefits of our diverse fleet is that plant overhauls and other expenditures do not occur in the same year for each facility. Recognized industry guidelines and original equipment manufacturer recommendations provide a source of data to assess maintenance needs. In addition, we utilize predictive and risk-based analysis to refine our expectations, prioritize our spending and balance the funding requirements necessary for these expenditures over time. Future capital expenditures and maintenance expenses may exceed the projected level in 2020 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.

Recently Adopted and Recently Issued Accounting Guidance

See Note 1 to the consolidated financial statements in this Quarterly Report on Form 10-Q.

64

Off-Balance Sheet Arrangements

As of September 30, 2020, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to financial market risk results primarily from fluctuations in interest and currency rates and fuel and electricity prices. There have been no material changes to our market risks as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act as of the end of the period covered by this report, and they have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the three months ended September 30, 2020, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations of Disclosure Controls and Internal Control over Financial Reporting

Because of their inherent limitations, our disclosure controls and procedures and our internal control over financial reporting may not prevent material errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The effectiveness of our disclosure controls and procedures and our internal control over financial reporting are subject to risks, including that the control may become inadequate because of changes in conditions or that the degree of compliance with our policies or procedures may deteriorate.

ITEM 1A. RISK FACTORS

During the quarter ended September 30, 2020, there have been no material changes from the risk factors previously in “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019 except as follows:

Our business, results of operations, financial condition, cash flows and stock price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the recent COVID-19 pandemic.

Our business, results of operations, financial condition, cash flows and stock price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the COVID-19 pandemic which has spread from China to many other countries, including the United States. In March 2020, the World Health Organization characterized COVID-19 as a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic has resulted in governments around the world implementing increasingly stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures, and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of COVID-19. Although certain governments have begun the process of easing their respective restrictions on individuals and businesses, there is material variation in the requirements to lift and reimpose restrictions and the pace at which those restrictions are being lifted and reimposed between jurisdictions. In some jurisdictions, increases in new cases of COVID-19 have led to reinstatement of restrictions on individuals and businesses.

65

The COVID-19 pandemic has caused, and is expected to continue to cause, the global slowdown of economic activity, disruptions in global supply chains and significant volatility and disruption of financial markets. Because the severity, magnitude and duration of the COVID-19 pandemic, including any resurgence in cases, and its economic consequences are uncertain, rapidly changing and difficult to predict, the pandemic’s impact on our business and results of operations, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains uncertain and difficult to predict. Further, the ultimate impact of the COVID-19 pandemic on our business and results of operations depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures) and the need to reimpose restrictions; the impact of the pandemic and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs (or their failure to implement additional stimulus measures); general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery if and when the COVID-19 pandemic subsides.

We are considered a critical infrastructure industry, as defined by the U.S. Department of Homeland Security. Although we have continued to operate our facilities in both the United States and Canada to date consistent with federal guidelines and state, provincial and local orders, the outbreak of COVID-19 and any preventive or protective actions taken by governmental authorities may have a material adverse effect on our operations, supply chain, customers, including business shutdowns or disruptions. The extent to which COVID-19 may adversely impact our business depends on future developments, which are highly uncertain and unpredictable, depending upon the severity and duration of the outbreak and the effectiveness of actions taken globally to contain or mitigate its effects, including the reimposition of restrictions in response to a resurgence in cases. Any resulting financial impact cannot be estimated reasonably at this time, but may materially adversely affect our business, results of operations, financial condition and cash flow. COVID-19 may affect us by (i) reducing economic activity, thereby resulting in lower demand for electricity consumption (with related effects of pricing), (ii) impairing our supply chain (for example, by limiting the manufacturing of materials or the supply of services used in our operations), and (iii) affecting the health of our workforce, rendering employees unable to work or travel. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to any resulting economic recession or depression. While the restrictions and limitations noted above may be relaxed or rolled back if and when COVID-19 abates, the actions may be reinstated as the pandemic continues to evolve. The scope and timing of any such reinstatements is difficult to predict and may materially affect our operations in the future. Additionally, concerns over the economic impact of COVID-19 have caused extreme volatility in financial and other capital markets, which has and may continue to adversely impact our stock price and our ability to access capital markets. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2019, such as those relating to our business and financial performance. We continue to monitor guidelines proposed by federal, state, provincial and local governments with respect to the proposed “reopening” measures, which may change over time depending on public health, safety and other considerations. We are continuing to focus on the safety and protection of our workforce by continuing to implement additional safety protocols in light of COVID-19.

ITEM 2: UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) Purchases of Equity Securities by Atlantic Power Corporation and Affiliated Purchasers

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 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

66

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 NYSE in compliance with Rule 10b-18 under 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.

For 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.

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.

The following table provides purchases of common equity securities by Atlantic Power Corporation and affiliated purchasers for the period of July 1, 2020 through September 30, 2020 under the NCIB:

Common Shares
					Total Number of Shares		Dollar Value of Maximum Number
	Total Number of		Average Price Paid		as Part of a Publicly Announced		of Shares to be Purchased Under
Purchase Period	Shares Purchased		Per Share		Purchase Plan		the Plan
7/1/2020 - 7/30/2020		2,729,780		$2.01		2,729,780
8/1/2020 - 8/31/2020		—		—		—
9/1/2020 - 9/30/2020		—		—		—		$6,077,388	(1)​
Total		2,729,780				2,729,780

(1) Under the NCIB, we may purchase up to a total of 10,578,799 common shares. Through September 30, 2020, we have repurchased a cumulative 7,540,105 shares and we are authorized to purchase up to an additional 3,038,694 common shares under the NCIB. Our plan does not obligate the Company to acquire any specific number of shares. The $6.1 million dollar value of maximum number of shares that may be purchased under the NCIB is based on the $2.00 average share price for the month of September 2020.

(2) The Board authorization permits the Company to repurchase common and preferred shares and convertible debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our convertible debentures and our APPEL preferred shares through open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the 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.

67

Substantial Issuer Bid

On March 25, 2020, we commenced a SIB for the purchase of up to $25 million of 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$1.95 and not more than US$2.20 per common share in increments of US$0.05 per common share, or (ii) purchase price tenders in which they did not specify a price per common share, but rather agreed to have a specified number of common shares purchased at the purchase price determined by auction tenders.

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.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

HIDDEN_ROW
Exhibit No.	Description
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	Inline XBRL Taxonomy Extension Schema
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE* Exhibit 104	Inline XBRL Taxonomy Extension Presentation Linkbase Cover Page Interactive Data File––the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

* Filed herewith.

** Furnished herewith.

69

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: November 9, 2020	Atlantic Power Corporation
	By:	/s/ Terrence Ronan
		Name:	Terrence Ronan
		Title:	Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

70

EX-31.1

Exhibit 31.1

CERTIFICATION

I, James J. Moore, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Atlantic Power Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2020	/s/ James J. Moore, Jr.
	James J. Moore, Jr.
	President and Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Terrence Ronan, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Atlantic Power Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

ay
Date: November 9, 2020	/s/ Terrence Ronan
	Terrence Ronan
	Chief Financial Officer (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

The undersigned officer of Atlantic Power Corporation (the “Company”) hereby certifies to his knowledge that the Company’s Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2020 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 9, 2020	/s/ James J. Moore, Jr.
	James J. Moore, Jr.
	President and Chief Executive Officer (Principal Executive Officer)

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

The undersigned officer of Atlantic Power Corporation (the “Company”) hereby certifies to his knowledge that the Company’s Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2020 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 9, 2020	/s/ Terrence Ronan
	Terrence Ronan
	Chief Financial Officer (Principal Financial Officer)

XML

Document and Entity Information - shares	9 Months Ended
	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

XML

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	4.0	8.9
Accrued interest	3.4	2.6
Other accrued liabilities	19.3	20.8
Current portion of long-term debt (Note 5)	91.0	76.4
Current portion of derivative instruments liability (Notes 6 and 7)	10.6	12.0
Operating lease liabilities (Note 14)	2.0	2.0
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)	(45.0)
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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	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

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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	64.0	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)	(0.9)
Insurance gain (loss) (Note 13)	6.2	(1.0)	6.2	(1.0)
Other expense, net			0.0	(1.2)
Total project other income (loss)	26.0	11.9	42.6	23.0
Project income	38.0	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	33.0
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	22.0
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	$ 40.0	$ 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	38.0	84.8	99.8
Miscellaneous revenue
Project revenue:
Project revenue	$ 5.2	$ 3.9	$ 13.4	$ 12.9

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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)	(4.0)	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	$ 11.0	$ 36.0	$ 25.8

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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)	1.0
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)	0.3
Prepayments and other assets	(0.4)	(0.2)
Accounts payable	(6.1)	(1.3)
Accruals and other liabilities	(3.0)	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		(10.0)
Proceeds from sales of assets	0.9	1.6
Purchase of property, plant and equipment	(23.0)	(0.9)
Cash used in investing activities	(9.4)	(28.0)
Cash used in financing activities:
Common share repurchases	(41.6)	(0.8)
Preferred share repurchases	(6.4)	(8.0)
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)	(2.0)
Deferred financing costs	(1.6)
Dividends paid to preferred shareholders	(5.0)	(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	27.0
Income taxes paid, net	3.8	3.5
Accruals for construction in progress	$ 1.7	$ 0.2

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Nature of business

9 Months Ended

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” in our Annual Report on Form 10-K for the year ended December 31, 2019. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

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. While COVID-19 did not materially adversely affect our financial results and business operations in the nine months ended September 30, 2020, we are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. We will continue to assess the evolving impact of the COVID-19 pandemic and intend to make adjustments accordingly.

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 are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements.

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Revenue from contracts

9 Months Ended

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. Revenue by segment consists of the following:

	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.

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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.

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Equity method investments in unconsolidated affiliates

9 Months Ended

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.

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Long-term debt

9 Months Ended

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

In January 2020, APLP Holdings Limited Partnership (“APLP Holdings”) completed the repricing of the $380 million term loan (the “Term Loan”) and the senior secured revolving credit facility (the “Revolver”). As a result of the repricing, the interest rate margin on the Term Loan and the Revolver was reduced by 0.25% to LIBOR plus 2.50% with no change to the 1.00% LIBOR floor. An additional 0.25% step down in the interest rate margin will become effective in the event the Leverage Ratio (as defined in the Credit Agreement) is 2.75:1.00 or lower. Additionally, APLP Holdings amended its existing Term Loan to extend the maturity date by two years to April 2025. The repricing also adds customary new provisions relating to the replacement of LIBOR as the benchmark for the Eurodollar Rate (as defined in the Credit Agreement). Targeted debt balances were adjusted to reflect the previously announced anticipated closing of the sale of our Manchief power plant in 2022, resulting in lower targeted debt repayment in 2020 and higher targeted debt repayment in 2022 as compared to the previous schedule. During the nine months ended September 30, 2020, we recorded $0.7 million of new deferred financing costs associated with the amendment, which will be amortized over the remaining terms of the Term Loan and the Revolver. Additionally, we wrote off $0.5 million of existing deferred financing costs to interest expense.

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.

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Fair value of financial instruments

9 Months Ended

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 Measurement Using Significant Unobservable Inputs (Level 3)
	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 Measurement Using Significant Unobservable Inputs (Level 3)
	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.

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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 6,500 Gj of natural gas per day is sold at the spot market price. This contract is not accounted for as a derivative.

On 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

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Income taxes

9 Months Ended

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.

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Equity compensation plans

9 Months Ended

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.

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Basic and diluted earnings per share

9 Months Ended

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. Diluted earnings per share is 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 dilutive effect of our Series E Debentures is calculated using the “if-converted method.” Under the if-converted method, the Series E Debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted earnings per share calculation for the entire period being presented. Interest expense, net of any income tax effects, would be added back to the numerator for purposes of the if-converted calculation. The outstanding equity compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator, when dilutive, for purposes of computing diluted earnings per share under the treasury stock method.

The following table sets forth the calculation of basic and diluted earnings 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

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Equity

9 Months Ended

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$1.95 and not more than US$2.20 per common share in increments of US$0.05 per common share, or (ii) purchase price tenders in which they did not specify a price per common share, but rather agreed to have a specified number of common shares purchased at the purchase price determined by auction tenders.

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.

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Segment and geographic information

9 Months Ended

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.

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Guarantees and Contingencies

9 Months Ended

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.

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Leases

9 Months Ended

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⁾ Short-term lease costs and finance lease costs are immaterial to the Company

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⁾ Cash flows from finance leases are immaterial to the Company

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.

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Nature of business (Policies)

9 Months Ended

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” in our Annual Report on Form 10-K for the year ended December 31, 2019. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

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. While COVID-19 did not materially adversely affect our financial results and business operations in the nine months ended September 30, 2020, we are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. We will continue to assess the evolving impact of the COVID-19 pandemic and intend to make adjustments accordingly.

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 are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements.

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Revenue from contracts (Tables)

9 Months Ended

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

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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.

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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.

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Long-term debt (Tables)

9 Months Ended

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

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Fair value of financial instruments (Tables)

9 Months Ended

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 Measurement Using Significant Unobservable Inputs (Level 3)
	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 Measurement Using Significant Unobservable Inputs (Level 3)
	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

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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

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Income taxes (Tables)

9 Months Ended

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

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Equity compensation plans (Tables)

9 Months Ended

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

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Basic and diluted earnings per share (Tables)

9 Months Ended

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

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Equity (Tables)

9 Months Ended

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

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Segment and geographic information (Tables)

9 Months Ended

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

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Leases (Tables)

9 Months Ended

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⁾ Short-term lease costs and finance lease costs are immaterial to the Company

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⁾ Cash flows from finance leases are immaterial to the Company

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

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Nature of business (Details) MW in Thousands	9 Months Ended
	Sep. 30, 2020 region state project MW
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

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Revenue from contracts - Disaggregation of revenue (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) segment	Sep. 30, 2019 USD ($)
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	38.0	84.8	99.8
Total revenue	29.7	38.0	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	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)

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Revenue from contracts - Contract balances (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract assets	$ 0.0	$ 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

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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			$ (45.0)
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	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	0.0
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	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)	0.0
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

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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)	(16.0)	(37.3)	(41.4)
Deficit in earnings of equity method investments, net of distributions	(3.6)	(3.9)	(5.5)	(7.0)
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	20.0
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)	9.0	8.7	25.0	24.9
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Chambers Cogen, LP
Operating results
Revenue	9.4	9.4	29.1	30.0
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	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

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Long-term debt (Details) $ in Millions		1 Months Ended	9 Months Ended
	Aug. 24, 2020 USD ($)	Jan. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2020 CAD ($)	Sep. 30, 2020 USD ($)	Mar. 18, 2020 USD ($)	Mar. 17, 2020 USD ($)	Jan. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
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					(91,000,000.0)					(76,400,000)
Total long-term debt					399,700,000					473,500,000
Current maturities					(91,000,000.0)					(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								$ 380.0
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					78,000,000.0
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					326,000,000.0					380,000,000.0
Current maturities					(88,000,000.0)					(72,500,000)
Long-term debt excluding debentures | Senior unsecured notes, due June 2036
Long-term debt
Long-term Debt, Gross				$ 210.0	$ 157,400,000				$ 210.0	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					$ (3,000,000.0)					$ (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%

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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

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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		$ 1.0

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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

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Accounting for derivative instruments and hedging activities (Details) $ in Millions, J in Billions		1 Months Ended	9 Months Ended	12 Months Ended
	May 15, 2020 MMBTU	Jan. 31, 2020	Sep. 30, 2020 USD ($) J MMBTU item contract $ / J	Dec. 31, 2019 USD ($) 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			$ 700.0
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			326.0
Remaining aggregate principal amount			326.0
Face amount of debt			$ 326.0

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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, 2020 USD ($) kJ MMBTU	Dec. 31, 2019 USD ($) kJ MMBTU
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	6.0	6.4
Interest rate swaps
Derivative instruments
Volume of forecasted transactions, (in dollars) | $	$ 421.6	$ 468.4

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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	18.0	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

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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	0.0	(0.5)	(0.4)
Realized from OCI during the period	0.1	0.0	0.3	0.2
Accumulated OCI balance at end of period	$ 1.4	$ 1.4	$ 1.4	$ 1.4

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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	(1.0)	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

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Income taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	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

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Income taxes - Other (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	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			1.0
Canada
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	0.2	(1.0)	(3.6)	4.4
United States
Reconciliation of income taxes
Increase (decrease) in the valuation allowance	$ (2.9)	$ (3.4)	$ (8.0)	$ (8.9)

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Equity compensation plans (Details) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020 USD ($) $ / shares shares	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) $ / shares shares	Sep. 30, 2019 USD ($)	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	$ 2.0
Compensation expense related to LTIP | $	$ 1.0	$ 1.1	$ 3.0	$ 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

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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	$ 40.0	$ 22.7
Add: convertible debenture interest expense	1.0	1.0	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	0.9	1.0
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

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Equity (Details) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2020 USD ($)	Sep. 30, 2020 $ / shares	Sep. 30, 2019 USD ($)	Sep. 30, 2019 $ / shares	Sep. 30, 2020 USD ($)	Sep. 30, 2020 $ / shares	Sep. 30, 2019 USD ($)	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)		(8.0)
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		202.0		119.3		202.0
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		40.0		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		(45.0)		(6.9)
Net income (loss)	16.2		12.6		40.0		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)		(8.0)
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)

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Equity - Share Repurchase Program (Details) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Apr. 30, 2020 USD ($) shares	Sep. 30, 2020 USD ($) shares	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) shares	Sep. 30, 2019 USD ($)	Dec. 31, 2019 USD ($) shares	Mar. 25, 2020 USD ($) $ / shares shares
Stock Repurchase Program
Payments for Repurchase of Redeemable Preferred Stock | $				$ 6.4	$ 8.0
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				7.0
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 | $							$ 25.0
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

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Segment and geographic information - EBITDA (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) segment	Sep. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)
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)	(1.0)	(5.6)	8.3
Depreciation and amortization	18.8	20.2	58.3	60.6
Interest, net	0.8	0.8	2.1	2.0
Insurance loss	(6.2)	1.0	(6.2)	1.0
Other project (income) expense				1.2
Project income (loss)	38.0	27.9	82.3	80.1
Administration	5.6	5.5	16.8	17.3
Interest expense, net	10.8	10.9	31.7	33.0
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	22.0
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	6.0	16.8	17.9
Interest, net	0.6	0.8	2.0	2.3
Insurance loss		1.0		1.0
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	28.0
Interest, net				(0.3)
Other project (income) expense		(0.1)		1.2
Project income (loss)	25.2	23.0	61.8	51.6
Net income (loss) before income taxes	25.2	23.0	61.8	51.6
Net income (loss)	25.2	23.0	61.8	51.6
Hydroelectric
Segment and geographic information
Project revenues	9.2	9.7	45.5	50.6
Segment assets	353.0	371.6	353.0	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	21.0	26.6
Net income (loss) before income taxes	0.7	1.4	21.0	26.6
Net income (loss)	0.7	1.4	21.0	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)	(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)	(5.0)	(8.4)
Administration	5.6	5.5	16.8	17.3
Interest expense, net	10.8	10.9	31.7	33.0
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)

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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	1.0		1.0		1.5
Assets	$ 173.9		$ 173.9		$ 173.3

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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%

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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)		$ 1.0	$ (6.2)	$ 1.0
Insurance Recoveries				31.0
Minimum | Scenario, Plan [Member]
Contingencies
Estimated additional insurance recoveries related to business interruption losses and property losses							$ 10.0
Maximum | Scenario, Plan [Member]
Contingencies
Estimated additional insurance recoveries related to business interruption losses and property losses							$ 11.0
Cadillac Project
Contingencies
Estimate damages claimed for statutory misrepresentation	1.0			1.0
Business interruption loss period						45 days
Business interruption expected revenue loss						$ 1.4
Impairment					25.0
Write-down of capital spares		$ 0.6	0.3
Insurance receivable	0.0	$ 24.8	$ 24.2	0.0	24.2	24.8
Insurance					$ 1.0
Insurance Recoveries	7.0			$ 19.7		$ 11.3
Gain on business interruption insurance recovery	6.2
Gain on Business Interruption Insurance Recovery	$ 6.2

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Leases - Real estate and equipment (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) 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

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Leases - Lease cost (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	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

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Leases - Operating lease maturities - Topic 842 (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) item
Operating Lease Commitments
Number of lease transactions with related parties | item	0
Future minimum lease commitments
2020	$ 0.6
2021	2.0
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

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Leases - Operating lease maturities - Supplemental Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
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%

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Leases - PPA Leases (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2019 USD ($)	Sep. 30, 2020 USD ($) project agreement	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) project agreement	Sep. 30, 2019 USD ($)
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		19.0	26.1	$ 51.1	64.4
Natural Gas
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		7.0	6.5	19.0	18.4
Hydroelectric
Operating Lease, Lease Income [Abstract]
Rental income from operating leases		$ 9.2	$ 9.7	$ 45.5	$ 50.6