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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
For the quarterly period ended March 31, 2021
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~~May 6, ~~2020~~2021 was 89,~~222~~797,~~568~~798.

Table of Contents

ATLANTIC POWER CORPORATION

FORM 10-Q

THREE ~~AND NINE~~ MONTHS ENDED ~~SEPTEMBER~~MARCH 3031, ~~2020~~2021

Index

	General :		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of ~~September~~March 3031, ~~2020~~2021 (unaudited) and December 31, ~~2019~~2020	4
		Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020~~2021 (unaudited) and ~~September~~March 3031, ~~2019~~2020 (unaudited)	5
		Consolidated Statements of Comprehensive Income for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020~~2021 (unaudited) and ~~September~~March 30, ~~2019~~2020 (unaudited)	6
		Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September~~March 3031, ~~2020~~2021 (unaudited) and ~~September~~March 3031, ~~2019~~2020 (unaudited)	7
		Condensed Notes to Consolidated Financial Statements (unaudited)	8
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3835
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6551
ITEM 4.		CONTROLS AND PROCEDURES	6551
		PART II—OTHER INFORMATION
ITEM 1A.		RISK FACTORS	6551
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	6651
ITEM 6.		EXHIBITS	6953

Table of Contents

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.

For information with respect to the proposed transaction with affiliates of I Squared Capital, see Note 1 to the Condensed Consolidated Financial Statements under “Proposed Transaction with I Squared Capital.”

Table of Contents

ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)


	~~September~~March 3031,		December 31,
	~~2020~~2021		~~2019~~2020
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	3021.36	$	7438.98
Restricted cash		2.6.9		7.71
Accounts receivable		2933.49		3031.43
Insurance recovery receivable (Note 13)		—		13.5
Current portion of derivative instruments asset (Notes 7 and 8)		—		0.4
Current portion of derivative instruments asset (Notes 6 and 7)		—		0.7
Inventory		17.0		18.3
Inventory		19.5		18.6
Prepayments		6.7		7.0
Prepayments		5.5		3.8
Income taxes receivable (Note 9)		2.0		3.2
Income taxes receivable		2.4		1.8
Current assets held for sale (Note 2)		4.6		—
Lease receivable		—		0.9
Other current assets		0.3		0.3
Other current assets		0.2		0.4
Total current assets		93.0		106.4
Total current assets		89.9		152.7
Property, plant, and equipment, net		481.3		491.8
Property, plant, and equipment, net		494.8		502.1
Equity investments in unconsolidated affiliates (Note 5)		91.8		85.0
Equity method investments in unconsolidated affiliates (Note 4)		91.4		96.6
Power purchase agreements and intangible assets, net		114.8		120.3
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
Operating lease right-of-use assets (Note 15)		4.1		4.6
Deferred income taxes (Note 8)		11.7		10.4
Deferred income taxes (Note 9)		17.0		17.2
Other assets		0.6		10.96
Total assets	$	~~840~~823.49	$	~~935~~847.62
Liabilities
Current liabilities:
Accounts payable	$	45.06	$	86.93
Accrued interest		35.49		2.65
Other accrued liabilities		1914.37		2019.83
Current portion of long-term debt (Note 5)		91.0		76.4
Current portion of long-term debt (Note 6)		90.8		95.7
Current portion of derivative instruments liability (Notes 6 and 7)		10.6		12.0
Current portion of derivative instruments liability (Notes 7 and 8)		9.9		11.0
Operating lease liabilities (Note 14)		2.0		2.0
Operating lease liabilities (Note 15)		1.8		1.9
Other current liabilities		0.6		0.2
Current liabilities held for sale (Note 2)		3.2		—
Total current liabilities		130.9		122.9
Other current liabilities		0.4		0.2
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)		399.7		473.5
Total current liabilities		132.3		136.9
Convertible debentures, net of discount and unamortized deferred financing costs		79.8		81.1
Long-term debt, net of unamortized discount and deferred financing costs (Note 6)		368.3		384.1
Derivative instruments liability (Notes 6 and 7)		9.1		15.9
Convertible debentures, net of discount and unamortized deferred financing costs		85.5		84.1
Deferred income taxes (Note 8)		25.8		23.7
Derivative instruments liability (Notes 7 and 8)		5.4		8.1
Power purchase agreements and intangible liabilities, net		1817.16		1918.80
Asset retirement obligations, net		5045.20		5148.51
Operating lease liabilities (Note 14)		3.4		4.8
Operating lease liabilities (Note 15)		2.7		3.1
Other long-term liabilities		46.17		46.72
Total liabilities		~~721~~663.15		~~797~~688.96
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
Common shares, no par value, unlimited authorized shares; 89,797,798 and 89,222,568 issued and outstanding at March 31, 2021 and December 31, 2020 (Note 12)		1,219.8		1,219.7
Accumulated other comprehensive loss (Note 3)		(144.7)		(140.7)
Accumulated other comprehensive loss (Note 4)		(138.1)		(139.9)
Retained deficit		(1,~~124~~090.21)		(1,~~164~~090.20)
Total Atlantic Power Corporation shareholders’ deficit		(498.54)		(4510.02)
Preferred shares issued by a subsidiary company (Note 11)		168.8		182.7
Preferred shares issued by a subsidiary company (Note 12)		168.8		168.8
Total equity		~~119~~160.34		~~137~~158.76
Total liabilities and equity	$	~~840~~823.49	$	~~935~~847.62

See accompanying notes to condensed consolidated financial statements.

Table of Contents

ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)


	Three Months Ended ~~September~~March 3031,				~~Nine Months Ended September 30,~~
	~~2020~~2021		~~2019~~2020		~~2020~~		~~2019~~
Project revenue:
Energy sales (Note 2)	$	30.3	$	29.2	$	102.1	$	102.7
Energy sales (Note 3)	$	36.0	$	40.7
Energy capacity revenue (Note 2)		29.7		38.0		84.8		99.8
Energy capacity revenue (Note 3)		29.8		28.0
Other (Note 2)		5.2		3.9		13.4		12.9
Other (Note 3)		6.2		4.1
		6572.20		7172.18		~~200.3~~		~~215.4~~
Project expenses:
Fuel		1720.57		19.46		~~51.3~~		~~55.2~~
Operations and maintenance		21.21		1920.57		~~64.0~~		~~54.6~~
Depreciation and amortization		14.53		1615.26		~~45.3~~		~~48.5~~
		5356.21		55.19		~~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)
Change in fair value of derivative instruments (Notes 7 and 8)		3.2		(5.6)
Equity in earnings of unconsolidated affiliates (Note 4)		12.1		12.1		31.8		34.4
Equity in earnings of unconsolidated affiliates (Note 5)		13.4		13.7
Interest, net		(0.43)		(0.3)		~~(1.0)~~		~~(0.9)~~
Insurance gain (loss) (Note 13)		6.2		(1.0)		6.2		(1.0)
Other income, net		0.2		—
Other expense, net		—		—		—		(1.2)
		16.5		7.8
		26.0		11.9		42.6		23.0
Project income		32.4		24.7
Project income		38.0		27.9		82.3		80.1
Administrative and other expenses:
Administrative and other expenses:
Administration		14.1		6.7
Administration		5.6		5.5		16.8		17.3
Interest expense, net		11.4		10.8
Interest expense, net		10.8		10.9		31.7		33.0
Foreign exchange loss (gain)		3.2		(20.6)
Foreign exchange loss (gain)		5.1		(2.8)		(6.2)		7.1
Other (income) expense, net (Note 7)		(0.1)		2.6
Other (income) expense, net (Note 6)		(3.8)		(0.2)		(2.7)		0.7
		28.6		(0.5)
		17.7		13.4		39.6		58.1
Income from operations before income taxes		3.8		25.2
Income from operations before income taxes		20.3		14.5		42.7		22.0
Income tax expense (Note 9)		2.2		1.5
Income tax expense (Note 8)		2.5		0.2		5.2		2.4
Net income		1.6		23.7
Net income		17.8		14.3		37.5		19.6
Net income (loss) attributable to preferred shares of a subsidiary company (Note 12)		1.7		(5.8)
Net income (loss) attributable to preferred shares of a subsidiary company (Note 11)		1.6		1.7		(2.5)		(3.1)
Net (loss) income attributable to Atlantic Power Corporation	$	(0.1)	$	29.5
Net income attributable to Atlantic Power Corporation	$	16.2	$	12.6	$	40.0	$	22.7
Net (loss) earnings per share attributable to Atlantic Power Corporation shareholders: (Note 11)
Net earnings per share attributable to Atlantic Power Corporation shareholders: (Note 10)
Basic	$	(0.00)	$	0.28
Basic	$	0.18	$	0.12	$	0.41	$	0.21
Diluted		(0.00)		0.23
Diluted		0.15		0.10		0.34		0.19
Weighted average number of common shares outstanding: (Note 11)
Weighted average number of common shares outstanding: (Note 10)
Basic		89.4		107.2
Basic		89.5		109.4		98.1		109.4
Diluted		89.4		134.8
Diluted		117.8		137.8		126.4		138.3

See accompanying notes to condensed consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions of U.S. dollars)

(Unaudited)


	Three Months Ended ~~September~~March 3031,				~~Nine Months Ended September 30,~~
	~~2020~~2021		~~2019~~2020		~~2020~~		~~2019~~
Net income	$	171.86	$	1423.37	$	~~37.5~~	$	~~19.6~~
Other comprehensive income, net of tax:
Unrealized loss on hedging activities	$	—	$	—	$	(0.5)	$	(0.4)
Unrealized gain (loss) on hedging activities	$	0.1	$	(0.4)
Net amount reclassified to earnings		~~0.1~~—		—0.1		~~0.3~~		~~0.2~~
Net realized and unrealized gain (loss) on derivatives		0.1		—(0.3)		~~(0.2)~~		~~(0.2)~~
Foreign currency translation adjustments		21.57		(111.62)		~~(3.8)~~		~~3.3~~
Other comprehensive income (loss), net of tax		21.68		(111.65)		~~(4.0)~~		~~3.1~~
Comprehensive income		203.4		12.72		~~33.5~~		~~22.7~~
Less: Comprehensive income (loss) attributable to preferred shares of a subsidiary company		1.67		1(5.78)		~~(2.5)~~		~~(3.1)~~
Comprehensive income attributable to Atlantic Power Corporation	$	181.87	$	1118.0	$	~~36.0~~	$	~~25.8~~

See accompanying notes to condensed consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)


	~~Nine~~Three months ended
	~~September~~March 3031,
	~~2020~~2021		~~2019~~2020
Cash provided by operating activities:
Net income	$	371.56	$	1923.67
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4514.3		4815.56
Share-based compensation		10.1		10.24
Other gain		—(0.2)		~~(0.8)~~—
Asset retirement obligations		—		1.4
Equity in earnings from unconsolidated affiliates		(13.4)		(13.7)
Gain on disposal of fixed assets and inventory		(0.8)		(0.1)
Distributions from unconsolidated affiliates		6.9		6.0
Insurance loss		—		1.0
Unrealized foreign exchange loss (gain)		3.1		(20.9)
Equity in earnings from unconsolidated affiliates		(31.8)		(34.4)
Change in fair value of derivative instruments		(3.3)		8.2
Distributions from unconsolidated affiliates		37.3		41.4
Amortization of debt discount and deferred financing costs		1.3		2.0
Unrealized foreign exchange (gain) loss		(6.6)		7.3
Non-cash operating lease expense		0.5		0.5
Change in fair value of derivative instruments		(7.3)		9.8
Deferred income taxes		0.3		0.3
Amortization of debt discount and deferred financing costs		4.7		5.3
Change in other operating balances:
Non-cash operating lease expense		1.4		1.1
Accounts receivable		(3.1)		(2.1)
Deferred income taxes		0.6		(1.8)
Inventory		0.2		2.8
Change in other operating balances
Prepayments and other assets		1.6		(1.7)
Accounts receivable		1.2		4.7
Accounts payable		(0.9)		(5.7)
Inventory		(1.0)		0.3
Accruals and other liabilities		(0.6)		(7.0)
Prepayments and other assets		(0.4)		(0.2)
Cash provided by operating activities		8.4		8.4
Accounts payable		(6.1)		(1.3)
Cash provided by (used in) investing activities:
Accruals and other liabilities		(3.0)		1.5
Insurance proceeds		—		7.4
Cash provided by operating activities		72.1		104.5
Proceeds from sale of equity investment		0.5		—
Cash used in investing activities:
Purchase of property, plant and equipment		(0.3)		(10.0)
Investment in unconsolidated affiliate		—		(18.7)
Cash provided by (used in) investing activities		0.2		(2.6)
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)~~—		(0.8.2)
Preferred share repurchases		~~(6.4)~~—		(86.04)
Repayment of corporate and project-level debt		(5723.17)		(5221.36)
Repayment of convertible debentures		—		(18.5)
Cash payments for vested LTIP withheld for taxes		(0.6)		(0.7)
Cash payments for vested LTIP withheld for taxes		(0.7)		(2.0)
Deferred financing costs		—		(1.5)
Deferred financing costs		(1.6)		—
Dividends paid to preferred shareholders		(1.7)		(1.7)
Dividends paid to preferred shareholders		(5.0)		(5.5)
Cash used in financing activities		(26.0)		(40.1)
Cash used in financing activities		(112.4)		(87.1)
Net decrease in cash, restricted cash and cash equivalents		(17.4)		(34.3)
Net decrease in cash, restricted cash and cash equivalents		(49.7)		(10.6)
Cash, restricted cash and cash equivalents at beginning of period		45.9		82.6
Cash, restricted cash and cash equivalents at beginning of period		82.6		70.4
Cash, restricted cash and cash equivalents at end of period	$	28.5	$	48.3
Cash, restricted cash and cash equivalents at end of period	$	32.9	$	59.8
Supplemental cash flow information
Interest paid	$	~~26.~~6.8	$	278.03
Income taxes paid, net	$	30.87	$	30.57
Accruals for construction in progress	$	~~1.7~~—	$	0.23

See accompanying notes to condensed consolidated financial statements.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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~~March 3031, ~~2020~~2021, 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~~2020. 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~~March 3031, ~~2020~~2021, the results of operations and comprehensive income for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020, and our cash flows for the ~~nine~~three months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020, 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

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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~~2020. 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~~three months ended ~~September~~March 3031, ~~2020~~2021, 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~~Proposed ~~adopted~~Transaction ~~and~~with ~~issued~~I ~~accounting~~Squared ~~standards~~Capital

~~Accounting~~On ~~standards~~January ~~adopted~~14, 2021, Atlantic Power announced that it had entered into a definitive agreement (as amended on April 1, 2021 and April 29, 2021, and as may be further amended from time to time, the “Arrangement Agreement”) with certain affiliates of infrastructure funds managed by I Squared Capital Advisors (US) LLC (“I Squared Capital”), a leading global infrastructure investor (the “Purchasers”), under which the Company's outstanding common shares and 6.00% Series E convertible unsecured subordinated debentures due January 31, 2025 (“Convertible Debentures”), and the outstanding preferred shares and medium term notes of certain of its subsidiaries, would be acquired (the “Transaction”). The total enterprise value of the deal is approximately $961 million and the Transaction was unanimously approved by Atlantic Power's board of directors. The parties are currently targeting May 14, 2021 as the closing date for the Transaction.

In ~~June~~connection ~~2016,~~with the ~~FASB issued ASU 2016-13~~Transaction, ~~“Financial~~and ~~Instruments-Credit~~subject ~~Losses”(Topic~~to ~~326),~~and ~~Measurement~~conditional ofto ~~Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance amends~~ the ~~guidance~~closing ~~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.Transaction:

In● ~~August~~Holders 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~~common ~~disclosures,~~shares ~~such as the amount~~ of ~~and~~Atlantic ~~reasons~~Power ~~for~~will ~~transfers~~receive 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~~.03 ~~The~~per ~~guidance~~common isshare ~~effective~~in ~~for fiscal years beginning after December 15, 2019~~cash. ~~We adopted this guidance on January 1, 2020 and it did not have an impact on the condensed consolidated financial statements.~~

●

Atlantic Power Preferred Equity Ltd.’s (“APPEL’s”) cumulative redeemable preferred shares, Series 1, cumulative rate reset preferred shares, Series 2, and cumulative floating rate preferred shares, Series 3, will be purchased by APPEL for Cdn$22.00 per preferred share in cash.

●

Atlantic Power Limited Partnership’s (“APLP’s”) 5.95% medium term notes due June 23, 2036 (the “MTNs”) will be redeemed for consideration equal to 106.071% of the principal amount of MTNs held as of the closing of the Transaction, plus accrued and unpaid interest on the MTNs up to, but excluding, the closing date of the Transaction. Holders of MTNs that have delivered a valid consent to the proposed amendments to the trust indenture governing the MTNs (as described below) prior to 5:00 p.m. (Toronto time) on March 16, 2021 will also be entitled to a consent fee equal to 0.25% of the principal amount of MTNs held by such holders in respect of which a consent was delivered, conditional on closing of the Transaction.

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ATLANTIC POWER CORPORATION

InNOTES ~~August~~TO ~~2018,~~CONDENSED ~~the~~CONSOLIDATED ~~FASB~~FINANCIAL 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.STATEMENTS

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

9(Unaudited)

●

Holders of Atlantic Power’s Convertible Debentures who deliver a conversion notice prior to 4:00 p.m. (Toronto time) on May 11, 2021 (the “Conversion Deadline”) will receive $3.03 per common share issuable on conversion of the Convertible Debentures in respect of which such conversion notice has been delivered (including common shares issuable on account of the Make Whole Premium (as defined in the Arrangement Agreement), plus accrued and unpaid interest up to, but excluding, the date of conversion, and all other Convertible Debentures will be defeased in accordance with the terms of the trust indenture governing the Convertible Debentures (the “Debenture Indenture”) (as described below)

The Arrangement Agreement was amended on April 1, 2021 to provide for certain administrative and housekeeping amendments to the Arrangement Agreement and to, among other things, clarify the mechanics surrounding the payment of consideration payable pursuant to the Transaction. The amendments also added a step to the Arrangement to, among other things, provide for the creation of a class of non-voting preferred shares in connection with the Pre-Acquisition Reorganization (as defined in the Arrangement Agreement). The creation and issuance of any such shares will not occur until immediately prior to the effective time of the Arrangement and will only occur if the Purchasers have irrevocably waived or confirmed in writing the satisfaction of all conditions to closing in their favor and shall have confirmed in writing that they are prepared, and able, to promptly and without condition proceed to effect the Arrangement (as defined in the Arrangement Agreement).

The Arrangement Agreement was further amended on April 29, 2021 to provide for mutual covenants in connection with the proposed defeasance of the Convertible Debentures (the “Defeasance”), clarify the mechanics surrounding the payment of the amounts required to effect the Defeasance, and effect a waiver of certain conditions precedent in the Arrangement Agreement relating to the approval of the Transaction by holders of the Convertible Debentures. Notwithstanding the Defeasance, any holder of Convertible Debentures who converts their Convertible Debentures during the period beginning 10 trading days (as defined in the Debenture Indenture) prior to the closing of the Transaction (“Closing”) and ending 30 calendar days following the delivery of the change of control notice under the Indenture (the “Make Whole Conversion Period”) will be entitled to receive the Make Whole Premium. Assuming that the Closing occurs on May 14, 2021 and the change of control notice is delivered on Closing as is currently anticipated, the Make Whole Conversion Period opened on April 30, 2021 and will close on June 14, 2021.

In connection with the Defeasance, and if Closing occurs (i) Atlantic Power expects to de-list its Convertible Debentures from the TSX and its common shares from the TSX and the NYSE; (ii) Atlantic Power intends to apply to Canadian securities regulators to cease being a reporting issuer, or to be exempt from its reporting obligations as a Canadian reporting issuer, and also intends to file to deregister under the U.S. Securities Exchange Act of 1934; (iii) the Convertible Debentures will no longer be convertible into common shares and, if converted after the Conversion Deadline, holders will be entitled to receive a cash amount equal to Cdn$3.72 in lieu of each Common Share previously issuable on a conversion (including any common shares otherwise issuable on account of the Make Whole Premium if converted within the Make Whole Conversion Period), plus accrued and unpaid interest paid in Canadian dollars up to, but excluding, the date of conversion; and (iv) except as otherwise provided in the Debenture Indenture, any Convertible Debentures which remain outstanding following the expiry of the Make Whole Conversion Period will continue to receive interest at a rate of 6.00% per annum, payable semi-annually in arrears until, and the repayment of principal upon, the redemption of the Convertible Debentures. Following the Defeasance, the Convertible Debentures will be redeemed at par on January 31, 2023.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

~~Accounting~~The ~~standards~~Transaction tohas bereceived ~~implemented~~approval from the holders of common shares of the Company and the holders of preferred shares and medium term notes of certain of the Company's subsidiaries. The Transaction also has received certain required regulatory approvals, including an advance ruling certificate from the Canadian Commissioner of Competition under the Competition Act (Canada) on February 5, 2021, the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 on March 9, 2021, the approval of the Federal Energy Regulatory Commission on April 2, 2021 and the approval in April 2021 from the Federal Communications Commission (“FCC”) for the transfer of control of certain FCC licenses held by the Company or its subsidiaries.

InThe ~~August~~Transaction ~~2018,~~remains ~~the~~subject ~~FASB issued ASU No. 2018-14, “Changes~~ to the ~~Disclosure~~satisfaction 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~~waiver ~~postretirement plans. Additionally, the amendments in this ASU remove disclosures that no longer are considered cost beneficial, clarify the specific requirements~~ of ~~disclosures,~~certain ~~and~~remaining ~~add~~third-party ~~disclosure~~consents ~~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~~other ~~adoption~~customary isclosing ~~permitted for all entities~~conditions. ~~We are currently evaluating the impact that adoption will have on our disclosures.~~

InRecently ~~December~~adopted ~~2019,~~and ~~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.standards

InAccounting ~~March~~standards ~~2020,~~adopted 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.2021

2In 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.” ~~Revenue~~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 ~~contracts~~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. Adoption of this guidance did not have a material impact on the condensed consolidated financial statements.

~~Disaggregation~~Accounting ofstandards ~~revenue~~not yet adopted

WeIn ~~have~~March ~~four~~2020, ~~reportable~~the ~~segments:~~FASB ~~Solid~~issued ~~Fuel,~~amendments ~~Natural~~to ~~Gas,~~the ~~Hydroelectric~~guidance ~~and~~for ~~Corporate.~~reference Werate ~~revised~~reform ~~our~~through ~~reportable~~ASU ~~business~~2020-04, ~~segments~~“Reference inRate ~~the~~Reform ~~fourth~~(Topic ~~quarter~~848): Facilitation of ~~2019 as~~ the ~~result~~effects of ~~recent~~reference ~~asset~~rate ~~acquisitions,~~reform ~~PPA~~on ~~expirations~~financial ~~and~~reporting.” ~~project~~The ~~decommissioning,~~amendments ~~and~~ in ~~order~~this toupdate ~~align~~provide ~~with~~optional ~~changes~~expedients toand ~~management’s~~exceptions ~~structure~~for applying GAAP to contracts, ~~resource~~hedging ~~allocation~~relationships, and ~~performance~~other ~~assessment~~transactions inaffected ~~making~~by ~~decisions~~reference ~~regarding~~rate ~~our~~reform ~~operations~~if certain criteria are met. ~~Segment~~The ~~information~~amendments ~~for~~apply ~~the~~only ~~comparative~~to ~~2019~~contracts ~~period~~and ~~has~~hedging ~~been~~relationships ~~revised~~that toreference ~~conform~~LIBOR or another reference rate expected to ~~the~~be ~~new~~discontinued ~~segment~~due ~~presentation~~to reference rate reform. ~~Each~~The ~~segment~~expedients ~~contains~~and ~~various~~exceptions ~~power~~provided ~~generation~~by ~~projects~~the amendments do not apply to contract modifications made and ~~performance~~hedging ~~obligations. For~~relationships ~~more~~entered ~~detailed~~into ~~information~~or ~~about~~evaluated ~~reportable~~after ~~segments~~December 31, ~~see~~2022. ~~Note~~The ~~12,~~amendments ~~Segment~~are elective and ~~geographical~~are ~~information~~effective upon issuance for all entities. ~~Revenue~~We byare ~~segment~~in ~~consists~~the process of evaluating the ~~following:~~potential impact of the new guidance on our condensed consolidated financial statements.

2. Assets and liabilities held for sale

North Bay and Kapuskasing projects

Our North Bay and Kapuskasing projects are each 40 MW natural gas plants located in the Province of Ontario. 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. On February 23, 2021, we entered into an agreement with SNS Power Corp. to sell our properties in the City of North Bay, the District of Nipissing (the “North Bay Property”) and in Kapuskasing, Ontario (the “Kapuskasing Property”) for Cdn$3.0 million in cash. We currently expect the sale of the plants to be completed in the second quarter of 2021 subject to customary due diligence procedures.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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

We determined the North Bay Property and Kapuskasing Property asset groups met the criteria for held for sale accounting, as specified by Accounting Standards Codification (“ASC”) 360, “Property, Plant, and Equipment,” as of March 31, 2021. In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. We determined the estimated sales value of the disposal group, less costs to sell, exceeded the carrying value as of March 31, 2021. As a result, no long-lived asset impairment charge was recorded during the three months ended March 31, 2021. The North Bay and Kapuskasing projects are components of our Natural Gas segment.


	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

The amounts classified as assets and liabilities held for sale as of March 31, 2021 include the following:


	~~Nine~~March ~~Months Ended September 30~~31, ~~2020~~
	2021									~~Consolidated~~
	Solid Fuel		Natural Gas		Hydroelectric			Corporate		Total
Assets	(unaudited)
Project revenue:
Inventory	$	1.1
Energy sales	$	40.6	$	18.4	$	43.1	$		—	$	102.1
Property, plant, and equipment, net		3.5
Energy capacity revenue		26.2		58.6		—			—		84.8
Total current assets held for sale	$	4.6
Steam energy and capacity revenue		—		6.8		—			—		6.8
Liabilities
Waste heat revenue		0.5		—		—			—		0.5
Asset retirement obligations	$	3.2
Ancillary and transmission services		—		2.2		2.4			—		4.6
Total current liabilities held for sale	$	3.2
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

3. Revenue from contracts

Revenue, receivables and contract liabilities by segment consists of following:


	Three Months Ended March 31, 2021
										Consolidated
	Solid Fuel		Natural Gas		Hydroelectric			Corporate		Total
Project revenue:
Energy sales	$	18.2	$	5.6	$	12.2	$		—	$	36.0
Energy capacity revenue		8.1		21.7		—			—		29.8
Steam energy and capacity revenue		—		3.2		—			—		3.2
Waste heat revenue		0.6		—		—			—		0.6
Ancillary and transmission services		—		1.0		1.0			—		2.0
Asset management and operation		—		—		—			0.3		0.3
Miscellaneous revenue				0.2		(0.1)			—		0.1
		26.9		31.7		13.1			0.3		72.0

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	~~Nine~~Three Months Ended ~~September~~March 3031, ~~2019~~2020
										Consolidated
		Solid Fuel		Natural Gas		Hydroelectric		Corporate		Total
Project revenue:
Energy sales	$	3016.78	$	~~23.~~6.2	$	4817.47	$	—	$	~~102~~40.7
Energy capacity revenue		336.73		6621.17		—		—		9928.80
Steam energy and capacity revenue		—		02.17		—		—		02.17
Ancillary and transmission services		—		10.3		2.2		—		12.5
Waste heat revenue		0.3		—		—		—		0.3
Asset management and operation		—		—		—		0.7		0.7
Ancillary and transmission services		—		0.7		0.7		—		1.4
Miscellaneous revenue		0.1		(0.5)		—		—		(0.4)
Asset management and operation		—		—		—		0.2		0.2
		64.5		99.6		50.6		0.7		215.4
Miscellaneous revenue		—		(0.5)		—		—		(0.5)
		23.4		30.8		18.4		0.2		72.8

Contract balances

Contract liabilities as of ~~September~~March 3031, ~~2020~~2021 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 $0.43 million water license fee at Mamquam (Hydroelectric segment). Contract liabilities as of December 31, ~~2019~~2020 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~~March ~~30, 2020 and December~~ 31, ~~2019~~2021.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

34. 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~~March 3031,				~~Nine Months Ended September 30,~~
	~~2020~~2021		~~2019~~2020		~~2020~~		~~2019~~
Foreign currency translation
Balance at beginning of period	$	(~~146~~138.94)	$	(~~141~~140.56)	$	~~(140.6)~~	$	~~(146.4)~~
Other comprehensive income (loss):
Other comprehensive income:
Foreign currency translation adjustments(1)		21.57		(111.62)		~~(3.8)~~		~~3.3~~
Balance at end of period	$	(~~144~~136.47)	$	(~~143~~151.18)	$	~~(144.4)~~	$	~~(143.1)~~
Pension
Balance at beginning and end of period (2)	$	(13.71)	$	(1.47)	$	~~(1.7)~~	$	~~(1.4)~~
Cash flow hedges
Balance at beginning of period	$	1.36	$	1.46	$	~~1.6~~	$	~~1.6~~
Other comprehensive (loss) income:
Other comprehensive income (loss):
Net change from periodic revaluations		—0.2		—(0.6)		~~(0.7)~~		~~(0.4)~~
Tax benefit		—		—		0.2		—
Tax (expense) benefit		(0.1)		0.2
Total other comprehensive (loss) income before reclassifications, net of tax		—		—		(0.5)		(0.4)
Total other comprehensive income (loss) before reclassifications, net of tax		0.1		(0.4)
Net amount reclassified to earnings:
Interest rate swaps(3)		~~0.2~~—		—0.1		~~0.4~~		~~0.2~~
Tax expense		~~(0.1)~~—		—		~~(0.1)~~		—
Total amount reclassified from accumulated other comprehensive income, net of tax		~~0.1~~—		—0.1		~~0.3~~		~~0.2~~
Total other comprehensive loss		0.1		—		(0.2)		(0.2)
Total other comprehensive income (loss)		0.1		(0.3)
Balance at end of period	$	1.47	$	1.43	$	~~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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

45. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020, respectively, for our proportional ownership interest in equity method investments:


	~~Three Months Ended September 30,~~	Three Months Ended March 31,					~~Nine Months Ended September 30,~~
Operating results	~~2020~~	2021		~~2019~~	2020		~~2020~~		~~2019~~
Revenue
Frederickson	$	~~8.3~~$	7.3	$	~~10.3~~$	8.0	$	~~22.4~~	$	~~26.4~~
Orlando Cogen, LP		~~15.7~~	15.5		~~15.6~~	14.6		~~44.8~~		~~46.4~~
Chambers Cogen, LP		~~9.4~~	10.8		~~9.4~~	10.6		~~29.1~~		~~30.0~~
Craven County Wood Energy, LP (1)		2.4			1.8			6.2		1.8
Craven County Wood Energy, LP			3.1			3.1
Grayling Generating Station, LP (1)		0.4			0.8			2.0		0.8
Grayling Generating Station, LP			1.6			1.5
		~~36.2~~	38.3		~~37.9~~	37.8		~~104.5~~		~~105.4~~
Project expenses
Frederickson		~~5.8~~	4.8		~~7.5~~	5.4		~~16.3~~		~~20.0~~
Orlando Cogen, LP		~~6.7~~	7.2		~~6.9~~	6.3		~~19.8~~		~~21.5~~
Chambers Cogen, LP		~~7.7~~	8.2		~~8.9~~	8.1		~~23.7~~		~~26.1~~
Craven County Wood Energy, LP (1)		2.6			1.6			8.3		1.6
Craven County Wood Energy, LP			3.0			2.6
Grayling Generating Station, LP (1)		0.9			0.5			3.4		0.5
Grayling Generating Station, LP			1.2			1.4
		~~23.7~~	24.4		~~25.4~~	23.8		~~71.5~~		~~69.7~~
Project other expenses
Project other income
Frederickson		—	—		—	—		—		—
Orlando Cogen, LP		—	—		—	—		—		—
Chambers Cogen, LP		~~(0.3)~~	(0.2)		~~(0.4)~~	(0.3)		~~(1.1)~~		~~(1.3)~~
Craven County Wood Energy, LP (1)		—			—			—		—
Craven County Wood Energy, LP			—			—
Grayling Generating Station, LP (1)		(0.1)			—			(0.1)		—
Grayling Generating Station, LP			—			—
		~~(0.4)~~	(0.2)		~~(0.4)~~	(0.3)		~~(1.2)~~		~~(1.3)~~
Net income (loss)
Net income
Frederickson		~~2.5~~	2.5		~~2.8~~	2.6		~~6.1~~		~~6.4~~
Orlando Cogen, LP		~~9.0~~	8.3		~~8.7~~	8.3		~~25.0~~		~~24.9~~
Chambers Cogen, LP		~~1.4~~	2.4		~~0.1~~	2.2		~~4.3~~		~~2.6~~
Craven County Wood Energy, LP (1)		(0.2)			0.2			(2.1)		0.2
Craven County Wood Energy, LP			0.1			0.5
Grayling Generating Station, LP (1)		(0.6)			0.3			(1.5)		0.3
Grayling Generating Station, LP			0.4			0.1
Equity in earnings of unconsolidated affiliates	$	~~12.1~~$	13.7	$	~~12.1~~$	13.7	$	~~31.8~~	$	~~34.4~~

Distributions from equity method investments		~~(15.7)~~	(6.9)		~~(16.0)~~	(6.0)		~~(37.3)~~		~~(41.4)~~
Deficit in earnings of equity method investments, net of distributions	$	(3.6)		$	(3.9)		$	(5.5)	$	(7.0)
Earnings of equity method investments, net of distributions		$	6.8		$	7.7

(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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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

56. Long-term debt

Long-term debt consists of the following:


	~~September~~March 3031,		December 31,
	~~2020~~2021		~~2019~~2020		Interest Rate
Recourse Debt:
Senior secured term loan facility, due 2025(1)	$	~~326~~284.05	$	~~380~~307.05	LIBOR(2)	plus	2.50	%
Senior unsecured notes, due June 2036 (Cdn$210.0)		~~157~~167.40		~~161~~164.79			5.95	%
Non-Recourse Debt:
Cadillac term loan, due 2025 (3)(4)		15.6		18.7	LIBOR	plus	1.61	%
Cadillac term loan, due 2025 (3)		14.1		14.8	LIBOR	plus	1.61	%
Less: unamortized discount		(43.10)		(53.85)
Less: unamortized deferred financing costs		(43.25)		(43.79)
Less: current maturities		(9190.08)		(7695.47)
Total long-term debt	$	~~399~~368.73	$	~~473~~384.51

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


	March 31,		December 31,
	2021		2020		Interest Rate
Current Maturities:
Senior secured term loan facility, due 2025⁽¹⁾	$	88.0	$	93.0	LIBOR⁽²⁾	plus	2.50	%
Cadillac term loan, due 2025 ⁽³⁾		2.8		2.7	LIBOR	plus	1.61	%
Total current maturities	$	90.8	$	95.7

(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~~284.05 million outstanding aggregate borrowings under our senior secured term loan facility at ~~September~~March 3031, ~~2020~~2021. See Note 78, 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 78, 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.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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~~March 3031, ~~2020~~2021, we had no borrowings under the Revolver and utilized $7881.02 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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

67. 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~~March 3031, ~~2020~~2021 and December 31, ~~2019~~2020. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.


	~~September~~March 3031, ~~2020~~2021
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	3021.36	$	—	$	—	$	3021.36
Restricted cash		2.6.9		—		—		2.6.9
Derivative instruments asset		—		—		—		—
Total	$	3228.95	$	—	$	—	$	3228.95
Liabilities:
Derivative instruments liability	$	—	$	1813.29	$	1.54	$	1915.73
Total	$	—	$	1813.29	$	1.54	$	1915.73


	December 31, ~~2019~~2020
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	7438.98	$	—	$	—	$	7438.98
Restricted cash		7.71		—		—		7.71
Derivative instruments asset		—		0.74		—		0.74
Total	$	8245.69	$	0.74	$	—	$	8346.3
Liabilities:
Derivative instruments liability	$	—	$	2417.76	$	31.25	$	2719.91
Total	$	—	$	2417.76	$	31.25	$	2719.91

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~~March 3031, ~~2020~~2021, the credit valuation adjustments resulted in a $0.53 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $0.42 million gain in change in fair value of derivative instruments. As of December 31, ~~2019~~2020, the credit valuation adjustments resulted in a $10.15 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $1.0.4 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

The following table reconciles, for the ~~nine~~three months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020, 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 valueMeasurementUsing SignificantUnobservableInputs (Level 3)
	~~Nine~~Three Months Ended
	~~September~~March 3031, ~~2020~~2021

Beginning balance of liability at January 1, 2020	$	3.2
Beginning balance of liability at January 1, 2021	$	1.5
Total unrealized gain		(10.81)
Currency transaction loss		0.1
Currency translation (gain) / loss		—
Ending balance of liability at September 30, 2020	$	1.5
Ending balance of liability at March 31, 2021	$	1.4


	Fair valueMeasurementUsing SignificantUnobservableInputs (Level 3)
	~~Nine~~Three Months Ended
	~~September~~March 3031, ~~2019~~2020

Beginning balance of liability at January 1, 2019	$	1.2
Beginning balance of liability at January 1, 2020	$	3.2
Total unrealized loss		12.56
Currency transaction loss		0.1
Currency translation gain		(0.2)
Ending balance of liability at September 30, 2019	$	2.8
Ending balance of liability at March 31, 2020	$	5.6

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.

78. 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

1819

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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 1311.53 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~~2021 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~~March 3031, ~~2020~~2021. 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~~March 3031, ~~2020~~2021, these agreements totaled $~~326~~284.5 million notional amount of the remaining $~~326~~284.5 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 21.2392%, resulting in an all-in rate of approximately 4.7342% for $~~326~~284.5 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~~Convertible ~~debentures~~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 March 31, 2021, we have no foreign currency forward contracts.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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~~March 3031, ~~2020~~2021 and December 31, ~~2019~~2020:


		~~September~~March 3031,	December 31,
	Units	~~2020~~2021	~~2019~~2020
Natural gas swaps	Natural Gas (MMBtu)	1311.53	1612.34
Gas purchase agreements	Natural Gas (Gigajoules)	64.02	6.4.0
Interest rate swaps	Interest (US$)	~~421~~298.67	~~468~~122.43

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~~March 3031, ~~2020~~2021
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.6
Interest rate swaps long-term		—		10.17
Total derivative instruments designated as cash flow hedges		—		1.73
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		4.83
Interest rate swaps long-term		—		~~1.9~~—
Natural gas swaps current		—		~~0.1~~—
Natural gas swaps long-term		—		1.75
Gas purchase agreements current		—		3.6
Gas purchase agreements long-term		—		43.42
Convertible debenture conversion option		—		1.54
Total derivative instruments not designated as cash flow hedges		—		1814.0
Total derivative instruments	$	—	$	1915.73

2021

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	December 31, ~~2019~~2020
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.46
Interest rate swaps long-term		—		1.10
Total derivative instruments designated as cash flow hedges		—		1.56
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		14.91
Interest rate swaps long-term		—		10.19
Natural gas swaps current		—		10.98
Natural gas swaps long-term		—		41.29
Gas purchase agreements current		0.74		4.60
Gas purchase agreements long-term		—		94.53
Convertible debenture conversion option		—		31.25
Total derivative instruments not designated as cash flow hedges		0.74		2617.45
Total derivative instruments	$	0.74	$	2719.91

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
Three Months Ended March 31, 2021	Swaps
Accumulated OCI balance at July 1, 2020	$	1.3
Accumulated OCI balance at January 1, 2021	$	1.6
Change in fair value of cash flow hedges		—0.1
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
Accumulated OCI balance at March 31, 2021	$	1.7

	Interest Rate
Nine Months Ended September 30, 2020	Swaps
Three Months Ended March 31, 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		0.21
Accumulated OCI balance at September 30, 2019	$	1.4
Accumulated OCI balance at March 31, 2020	$	1.3

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Impact of derivative instruments on the condensed 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~~March 3031,

~~Nine Months Ended September 30,~~

recognized in income

~~2020~~2021

~~2019~~2020

~~2020~~

~~2019~~

Gas purchase agreements

Fuel

2.12

~~6.2~~

~~6.1~~

Natural gas swaps

Fuel

0.81

0.67

~~2.4~~

~~0.5~~

Interest rate swaps

Interest, net

10.75

(0.9)3

~~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 gain (loss) ~~gain~~	Three Months Ended ~~September~~March 3031,				~~Nine Months Ended September 30,~~
	recognized in income	~~2020~~2021		~~2019~~2020		~~2020~~		~~2019~~
Natural gas swaps	Change in fair value of ~~derivatives~~derivative instruments	$	31.82	$	(1.0.5)	$	~~4.4~~	$	~~(3.5)~~
Gas purchase agreements	Change in fair value of ~~derivatives~~derivative instruments		21.53		31.70		~~4.9~~		~~3.5~~
Interest rate swaps	Change in fair value of ~~derivatives~~derivative instruments		10.87		(1.6.1)		~~(3.7)~~		~~(8.3)~~
		$	83.12	$	1(5.16)	$	~~5.6~~	$	~~(8.3)~~
Convertible debenture conversion option	Other (income) expense, net	$	(30.81)	$	(02.3)6	$	~~(1.8)~~	$	~~1.5~~

89. Income taxes

The following table summarizes the current and deferred portions of the net income tax expense:


	Three Months Ended ~~September~~March 3031,				~~Nine Months Ended September 30,~~
	~~2020~~2021		~~2019~~2020		~~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)
Current income tax expense	$	1.9	$	1.2
Total income tax expense, net	$	2.5	$	0.2	$	5.2	$	2.4
Deferred income tax expense		0.3		0.3
Total income tax expense, net	$	2.2	$	1.5

For the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020

Income tax expense for the three months ended ~~September~~March 3031, ~~2020~~2021 was $2.52 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $51.50 million. The primary items impacting the tax rate for the three months ended ~~September~~March 3031, ~~2020~~2021 were ~~a net decrease to our valuation allowances of~~ $~~2.7 million, consisting of $~~0.25 million ~~increases~~relating ~~in Canada due~~ to ~~the~~withholding ~~incurrence~~and ofstate ~~operating~~taxes ~~losses~~ and $20.97 million ~~decreases in the United States due to the utilization~~ of ~~net~~other ~~operating~~permanent ~~losses, and $1~~differences.~~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~~March 3031, ~~2019~~2020 was $01.25 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $36.98 million. The primary item impacting the tax rate for the three months ended ~~September~~March 3031, ~~2019~~2020 was a net decrease to our valuation allowances of $48.47 million, consisting of $15.09 million of decreases in Canada and $32.48 million of decreases in the United States due to the utilization of net operating losses. These items were partially offset by $2.0 million relating to foreign exchange and $1.4 million of other permanent differences.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

~~the~~As ~~utilization~~ of ~~net~~March ~~operating~~31, ~~losses~~2021, inwe ~~both~~have ~~jurisdictions.~~recorded ~~This~~a ~~item~~valuation ~~was~~allowance ~~partially~~of ~~offset by~~ $0105.5 million. ~~relating~~The toamount ~~withholding,~~is ~~federal~~comprised ~~and~~primarily ~~state~~of ~~taxes~~provisions against Canadian and $0U.2S. ~~million~~net operating loss carryforwards. In assessing the recoverability of ~~other~~our ~~permanent~~deferred ~~differences~~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 U.S. and in Canada and available tax planning strategies.

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~~10.4 ~~million.~~Equity ~~Expected~~compensation 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.plans

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~~three months ended ~~September~~March 3031, ~~2020~~2021:


				Grant Date
				Weighted-Average
	Notional Shares	~~Notional Shares~~		Fair Value per Notional Share
Outstanding at December 31, 2019		3,578,092	$	2.38
Outstanding at December 31, 2020	3,710,340		$	2.45
Granted		1,866,748		2.49
Vested and redeemed	(1,836,821)			2.36
Vested and redeemed		(1,702,571)		2.34
Forfeitures	(224,678)			2.46
Forfeitures		(31,929)		2.42
Outstanding at March 31, 2021	1,648,841		$	2.56
Outstanding at September 30, 2020		3,710,340	$	2.45

Cash payments made for vested notional shares for the ~~nine~~three months ended ~~September~~March 3031, ~~2020~~2021 and ~~2019~~2020 were $3.35 million and $23.03 million, respectively. ~~Compensation~~Total compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.04 million and $31.0 million for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2020,~~2021 ~~respectively,~~ and ~~$1.1 million and $3.1 million for the three and nine months ended September 30~~2020, ~~2019,~~ respectively.

Transition Equity Participation Agreement

We also have 269,952 transition notional shares outstanding at ~~September~~March 3031, ~~2020~~2021 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 of a change in control or if Mr. Moore is terminated without cause, resigns for good reason, or dies.

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ATLANTIC POWER CORPORATION

~~NOTES~~11. TOBasic ~~CONSOLIDATED~~and ~~FINANCIAL~~diluted ~~STATEMENTS~~earnings per share

(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

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

The following table sets forth the calculation of basic and diluted earnings per share for the three months ended March 31, 2021 and 2020:

11. Equity


	Three Months Ended March 31,
Basic	2021		2020
Numerator:
Net (loss) income attributable to Atlantic Power Corporation	$	(0.1)	$	29.5
Denominator:
Weighted average basic shares outstanding		89.4		107.2
Basic (loss) earnings per share attributable to Atlantic Power Corporation	$	(0.00)	$	0.28
Diluted
Numerator:
Net (loss) income attributable to Atlantic Power Corporation	$	(0.1)	$	29.5
Add: convertible debenture interest expense		—		0.9
		(0.1)		30.4
Denominator:
Weighted average basic shares outstanding		89.4		107.2
Share-based compensation		—		0.2
Convertible debentures		—		27.4
		89.4		134.8
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$	(0.00)	$	0.23

The following ~~tables~~table ~~provide~~summarizes ~~reconciliations~~our ofoutstanding ~~the~~instruments ~~beginning~~that ~~and~~are ~~ending~~anti-dilutive ~~equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company~~ and ~~total~~were ~~equity~~not ~~for~~included in the ~~three~~computation ~~and~~of ~~nine~~our ~~months~~diluted ~~ended~~earnings ~~September~~(loss) ~~30,~~per ~~2020 and 2019~~share:


	Three Months Ended March 31,				~~Accumulated~~		~~Total~~		~~Preferred~~
	2021		2020		~~Other~~		~~Atlantic Power~~		~~Shares of a~~
	Common		Retained		Comprehensive		Corporation		Subsidiary		Total
Share-based compensation		0.6		—
	Shares		Deficit		(loss) income		Shareholders' Deficit		Company		Equity
Convertible debentures		27.4		—
Balance at June 30, 2020	$	1,224.6	$	(1,140.4)	$	(147.3)	$	(63.1)	$	168.8	$	105.7
Total		28.0		—
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

12. 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 months ended March 31, 2021 and 2020:

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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
Balance at January 1, 2021	$	1,219.7	$	(1,090.0)	$	(139.9)	$	(10.2)	$	168.8	$	158.6
Net income (loss)		—		40.0		—		40.0		(2.5)		37.5
Net (loss) income		—		(0.1)		—		(0.1)		1.7		1.6
Share-based compensation		10.1		—		—		10.1		—		10.1
Common share repurchases		(41.6)		—		—		(41.6)		—		(41.6)
Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share)		—		—		—		—		(0.8)		(0.8)
Preferred share repurchases		—		—		—		—		(6.4)		(6.4)
Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.358688 per share)		—		—		—		—		(0.7)		(0.7)
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 3 (Cdn$0.267807 per share)		—		—		—		—		(0.2)		(0.2)
Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$1.076064 per share)		—		—		—		—		(1.9)		(1.9)
Realized and unrealized loss on hedging activities, net of tax		—		—		0.1		0.1		—		0.1
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.013464 per share)		—		—		—		—		(0.7)		(0.7)
Foreign currency translation adjustments		—		—		1.7		1.7		—		1.7
Realized and unrealized loss on hedging activities, net of tax		—		—		(0.2)		(0.2)		—		(0.2)
Balance at March 31, 2021	$	1,219.8	$	(1,090.1)	$	(138.1)	$	(8.4)	$	168.8	$	160.4
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~~Deficit		Company		Equity
Balance at January 1, 2019	$	1,260.9	$	(1,121.6)	$	(146.2)	$	(6.9)	$	199.3	$	192.4
Balance at January 1, 2020	$	1,259.9	$	(1,164.2)	$	(140.7)	$	(45.0)	$	182.7	$	137.7
Net income (loss)		—		2229.75		—		2229.75		(35.18)		1923.67
Share-based compensation		10.24		—		—		10.24		—		10.24
Common share repurchases		(0.8.2)		—		—		(0.8.2)		—		(0.8.2)
Preferred share repurchases		—		—		—		—		(86.04)		(86.04)
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 1 (Cdn$0.303125 per share)		—		—		—		—		(0.8)		(0.8)
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 2 (Cdn$0.358688 per share)		—		—		—		—		(0.6)		(0.6)
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$1.091448 per share)		—		—		—		—		(1.1)		(1.1)
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.363342 per share)		—		—		—		—		(0.3)		(0.3)
Realized and unrealized loss on hedging activities, net of tax		—		—		(0.23)		(0.23)		—		(0.23)
Foreign currency translation adjustments		—		—		3(11.32)		3(11.32)		—		3(11.32)
Balance at September 30, 2019	$	1,261.3	$	(1,098.9)	$	(143.1)	$	19.3	$	182.7	$	202.0
Balance at March 31, 2020	$	1,252.1	$	(1,134.7)	$	(152.2)	$	(34.8)	$	168.8	$	134.0

Share Repurchase ~~Programs~~Program

Normal Course Issuer Bid

On December 31, ~~2019~~2020, 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~~2021 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the ~~NCIBs~~NCIB. Under the ~~NCIB~~NCIBs, we may purchase up to a total of 10 8,~~578~~554,~~799~~ 391 common shares based on 10% of our public float as of December 1718, ~~2019~~2020 and we are limited to daily purchases of 9 10,~~243~~ 420 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. WeAll ~~may~~purchases ~~also~~made ~~purchase~~under upthe toNCIBs ~~Cdn$11.5~~will ~~million~~be made through the facilities of ~~Series~~the ETSX ~~Debentures;~~or ~~384,750~~other ~~shares~~Canadian ofdesignated ~~4.85%~~exchanges ~~Cumulative~~and ~~Redeemable~~published ~~Preferred~~marketplaces ~~Shares,~~and ~~Series~~in 1accordance (with the ~~“Series~~rules 1of ~~Shares”);~~the ~~223,072~~TSX ~~shares~~at market prices prevailing at the time of 7purchase.0% ~~Cumulative~~Common ~~Rate~~share ~~Preferred~~purchases ~~Shares~~under ~~Series~~the 2NCIBs (may also be made on the ~~“Series~~NYSE 2in ~~Shares”);~~compliance ~~and~~with ~~133,031~~Rule ~~shares~~10b-18 ofunder ~~Cumulative~~the ~~Floating~~Securities ~~Rate~~Exchange ~~Preferred~~Act ~~Shares~~of 1934, ~~Series~~as 3amended (the “~~Series~~Exchange ~~3 Shares~~Act”), or other designated exchanges and published marketplaces in the U.S. in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of ~~APPEL~~the NYSE is subject to regulatory approval.

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

~~All~~The ~~purchases~~Board ~~made~~authorization ~~under~~permits the ~~NCIBs~~Company ~~will~~to berepurchase ~~made~~common ~~through~~and ~~the~~preferred ~~facilities~~shares ofand Convertible Debentures. Therefore, in addition to the ~~TSX~~current orNCIBs, ~~other~~from ~~Canadian~~time ~~designated~~to ~~exchanges~~time ~~and~~we ~~published~~may ~~marketplaces~~repurchase ~~and~~our insecurities, ~~accordance~~including ~~with~~our ~~the~~common ~~rules~~shares, ofour ~~the~~Convertible ~~TSX~~Debentures atand our APPEL preferred shares through open market ~~prices~~purchases, ~~prevailing~~including atpursuant ~~the~~to ~~time~~one ofor ~~purchase.~~more ~~Common~~“Rule ~~share~~10b5-1 ~~purchases~~plans” pursuant to such provision under the Exchange Act, NCIBs, ~~may~~issuer ~~also~~self betender ~~made~~or onsubstantial ~~the~~issuer ~~New~~bids, ~~York~~or ~~Stock~~in ~~Exchange~~privately ~~(“NYSE”)~~negotiated intransactions. ~~compliance~~There ~~with~~can ~~Rule~~be ~~10b-18~~no ~~under~~assurances as to the ~~Securities~~amount, ~~Exchange~~timing ~~Act~~or prices of ~~1934~~repurchases, aswhich ~~amended~~may ~~(the~~vary ~~“Exchange~~based ~~Act”),~~on ormarket conditions, other ~~designated~~market ~~exchanges~~opportunities and ~~published~~other ~~marketplaces~~factors. inAny ~~the~~share ~~United~~repurchases ~~States~~outside inof ~~accordance~~previously ~~with~~authorized ~~applicable~~NCIBs ~~regulatory~~would ~~requirements.~~be ~~The~~affected ~~ability~~after totaking ~~make~~into ~~certain~~account ~~purchases~~our ~~through~~then ~~the~~current ~~facilities~~cash ofposition ~~the~~and ~~NYSE~~then isanticipated ~~subject~~cash toobligations ~~regulatory~~or ~~approval~~business opportunities.

~~The~~Atlantic ~~NCIB~~Power ~~permits~~Corporation ~~the Company to repurchase common~~ and ~~preferred~~affiliated ~~shares~~purchasers ~~and~~did ~~Series~~not Emake ~~Debentures.~~any Inrepurchases ~~addition~~of tocommon ~~the~~equity ~~current NCIBs, from time to time we may repurchase our~~ securities, ~~including~~Convertible ~~our common shares, our Series E~~ Debentures ~~and~~or ~~our APPEL~~ preferred shares ~~through~~during ~~open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under~~ the ~~Exchange~~period ~~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,~~January ~~which may vary based on market conditions~~1, ~~other~~2021 ~~market~~through 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 2531, ~~2020, we commenced a Substantial Issuer Bid (“SIB”) (described below) that expired on April 30, 2020~~2021. ~~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.

In13. ~~the~~Segment ~~nine months ended September 30, 2020, we also repurchased~~ and ~~cancelled~~geographic 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. information

~~Substantial~~We ~~Issuer~~have ~~Bid~~four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We analyze the performance of our operating segments based on Project Adjusted EBITDA, which is defined as project income (loss) plus interest, taxes, depreciation and amortization, impairment charges, insurance loss (gain), other (income) expenses and changes in fair value of derivative instruments. 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.

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.

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ATLANTIC POWER CORPORATION

~~NOTES~~A TOreconciliation ~~CONSOLIDATED~~of ~~FINANCIAL~~Project ~~STATEMENTS~~Adjusted EBITDA to net income (loss) for the three months ended March 31, 2021 and 2020 is included in the tables below:

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



	Solid Fuel		Natural Gas		Hydroelectric		Corporate		Consolidated
Three Months Ended March 31, 2021
Project revenues	$	26.9	$	31.7	$	13.1	$	0.3	$	72.0
Segment assets		205.6		190.3		301.4		126.6		823.9
Project Adjusted EBITDA	$	9.7	$	28.7	$	10.3	$	(0.5)	$	48.2
Change in fair value of derivative instruments		—		(2.5)		—		(0.7)		(3.2)
Depreciation and amortization		6.1		7.6		4.9		—		18.6
Interest, net		0.6		—		—		—		0.6
Other project income		—		—		—		(0.2)		(0.2)
Project income		3.0		23.6		5.4		0.4		32.4
Administration		—		—		—		14.1		14.1
Interest expense, net		—		—		—		11.4		11.4
Foreign exchange loss		—		—		—		3.2		3.2
Other income, net		—		—		—		(0.1)		(0.1)
Net income (loss) before income taxes		3.0		23.6		5.4		(28.2)		3.8
Income tax expense		—		—		—		2.2		2.2
Net income (loss)	$	3.0	$	23.6	$	5.4	$	(30.4)	$	1.6

(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.~~ 27

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

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)



	Solid Fuel		Natural Gas		Hydroelectric		Corporate		Consolidated
Three Months Ended March 31, 2020
Project revenues	$	23.4	$	30.8	$	18.4	$	0.2	$	72.8
Segment assets		225.0		230.6		359.5		66.9		882.0
Project Adjusted EBITDA	$	7.8	$	28.2	$	15.3	$	(0.5)	$	50.8
Change in fair value of derivative instruments		—		(0.5)		—		6.1		5.6
Depreciation and amortization		5.6		9.2		4.9		0.1		19.8
Interest, net		0.7		—		—		—		0.7
Other project expense		—		—		—		—		—
Project income (loss)		1.5		19.5		10.4		(6.7)		24.7
Administration		—		—		—		6.7		6.7
Interest expense, net		—		—		—		10.8		10.8
Foreign exchange gain		—		—		—		(20.6)		(20.6)
Other expense, net		—		—		—		2.6		2.6
Net income (loss) before income taxes		1.5		19.5		10.4		(6.2)		25.2
Income tax expense		—		—		—		1.5		1.5
Net income (loss)	$	1.5	$	19.5	$	10.4	$	(7.7)	$	23.7



	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

The tables below provide information, by country, about our consolidated operations for the three months ended March 31, 2021 and 2020 and for Property, Plant and Equipment, PPAs and other intangible assets and total assets as of March 31, 2021 and December 31, 2020, 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
	~~Solid~~Three ~~Fuel~~Months Ended March 31,		~~Natural Gas~~		~~Hydroelectric~~		~~Corporate~~		~~Consolidated~~
Nine Months Ended September 30, 2020
	2021		2020
Project revenues	$	67.4	$	86.7	$	45.5	$	0.7	$	200.3
United States	$	46.1	$	48.2
Segment assets		229.7		208.4		353.0		49.3		840.4
Canada		25.9		24.6
Project Adjusted EBITDA	$	23.3	$	79.1	$	35.7	$	(1.0)	$	137.1
Total	$	72.0	$	72.8
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


	Property, Plant and				PPAs and
	Equipment, net of				other intangible assets, net of
	accumulated depreciation				accumulated amortization				Total assets
	March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
United States	$	345.0	$	351.2	$	114.0	$	119.4	$	644.0	$	666.4
Canada		136.3		140.6		0.8		0.9		179.9		180.8
Total	$	481.3	$	491.8	$	114.8	$	120.3	$	823.9	$	847.2

Table of Contents

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, Niagara Mohawk and Equistar Chemicals, LP, (“Equistar”) provided 1514.58%, 1214.28%, 1113.34%, and 1012.71%, respectively, of total consolidated revenues for the three months ended ~~September~~March 3031, ~~2020~~2021. ~~Georgia~~Niagara ~~Power Company~~Mohawk, IESO, ~~Southern~~BC ~~California~~Hydro ~~Edison~~ and Equistar ~~Chemicals, LP~~ provided 1620.29%, 1114.27%, 1013.5% and 10.43%, respectively, of total consolidated revenues for the three months ended ~~September~~March 3031, ~~2019~~2020.

30IESO purchases electricity from the Calstock, Tunis, and Nipigon projects in the Solid Fuel and Natural Gas segments, 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, Niagara Mohawk purchases electricity from the Curtis Palmer

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

~~Niagara~~project ~~Mohawk,~~in ~~IESO,~~the ~~Georgia~~Hydroelectric ~~Power Company~~segment, ~~BC Hydro,~~ and Equistar ~~Chemicals,~~purchases LPelectricity ~~provided~~from ~~16.1%, 13.5%, 11.6%, 11.2% and 10.8%, respectively, of total consolidated revenues for~~ the ~~nine~~Morris ~~months~~project ~~ended~~in ~~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~~Natural ~~months~~Gas ~~ended September 30, 2019~~segment.

~~Niagara~~14. ~~Mohawk~~Guarantees ~~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.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~~From attime ~~Cadillac~~to ~~project~~time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of March 31, 2021.

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~~15. ~~Damage~~Leases

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.

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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 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.

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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~~March 3031,				~~Nine Months Ended September 30,~~
		~~2020~~2021		~~2019~~2020		~~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.

3329

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED 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	$	1.5		$	(0.8)	$	0.7
2021		2.0			(1.1)		0.9
2022		1.8			(1.1)		0.7
2022		1.7			(1.1)		0.6
2023		1.3			(0.7)		0.6
2023		1.2			(0.7)		0.5
2024		0.2			—		0.2
2024		0.1			—		0.1
2025		—			—		—
Thereafter		—			—		—
Total operating lease payments	$	54.68		$	(3.2.6)	$	2.42
Less: present value discount		(0.23)
Total operating lease liabilities	$	5.4.5

	Lease
	Payments
2020	$	—
2021	$	—
2021		0.1
2022		0.1
2022		0.1
2023		—
Thereafter		—
Total finance lease payments	$	0.21
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.


	March 31,
	2021			2020
Other Information:
Cash paid for amounts included in the measurement of lease liabilities⁽¹⁾:
Operating cash flows from operating leases	$	0.3		$	0.3

Weighted average remaining lease term (in years):
Operating leases		2.5			2.5
Finance leases		1.1			1.4
Weighted average discount rate - operating leases		3.9	%		3.9	%
Weighted average discount rate - finance leases		4.1	%		4.1	%

We have no lease transactions with related parties.

PPA Leases

We have entered into PPAs to sell power at predetermined rates. PPAs were assessed as to whether they contain leases, which convey to the counterparty the right to control the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either operating or finance leases. We recognize lease income consistent with the recognition of energy sales and capacity revenue. When energy is delivered and capacity is provided, we recognize lease income as a component of energy sales and capacity revenue. Finance income related to ~~leases or arrangements accounted for as finance leases is recognized in a manner that produces a constant rate of return~~

3430

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

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~~March 3031, ~~2020~~2021, 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~~one ~~months~~year 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

~~Rental Income from operating leases~~

~~Three Months Ended~~

Three Months Ended

~~Nine Months Ended~~

~~September 30,~~

March 31,

~~September 30,~~

~~2020~~

2021

~~2019~~

2020

~~2020~~

~~2019~~

Solid Fuel

~~19.0~~$

14.8

~~26.1~~$

16.6

~~51.1~~

~~64.4~~

Natural Gas

~~7.0~~

5.6

~~6.5~~

5.9

~~19.0~~

~~18.4~~

Hydroelectric

~~9.2~~

13.1

~~9.7~~

18.4

~~45.5~~

~~50.6~~

~~35.2~~$

33.5

~~42.3~~$

40.9

~~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 expected timing and likelihood of completion of the proposed Transaction with I Squared Capital;

●

the expected impact of the proposed Transaction with I Squared Capital on the price of the Company’s Common Shares;

●

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~~this 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.

36There are a number of risks associated with the proposed Transaction with I Square Capital, including, without limitation:

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These risks include, without limitation:

●

that there can be no certainty that all conditions to the proposed Transaction will be satisfied;

●

the Arrangement Agreement may be terminated in certain circumstances;

●

the termination fee provided under the Arrangement Agreement may discourage other parties from attempting to acquire the Company;

●

even if the Arrangement Agreement is terminated without payment of the termination fee, the Company may, in the future, be required to pay the termination fee in certain circumstances;

●

while the proposed Transaction is pending, the Company is restricted from taking certain actions;

●

the right to match provided under the Arrangement Agreement may discourage other parties from attempting to acquire the Company;

●

prohibition on soliciting other potential purchasers of the Company may reduce the likelihood of other parties attempting to acquire the Company; and

●

the pending Arrangement may divert the attention of the Company’s management.

In addition, 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, more frequent extreme weather conditions arising as a result of climate change, pandemics (including potentially in relation to the coronavirus) or other catastrophic events;

●

increased competition, including for acquisitions;

●

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

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●

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 and uncertain 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;

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●

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~~credit ~~secured term loans~~facilities;

●

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.

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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 management’s discussion ofand ~~the~~analysis of 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 accounting principles generally accepted in the United States of America (“GAAP”) and in accordance with the instructions to Form 10-Q related to smaller reporting companies as promulgated by the SEC. This Item 2 was prepared without regards to potential effects of the Transaction, except where stated otherwise.

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~~March 3031, ~~2020~~2021, 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.

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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~~September ~~16,~~2021 ~~2020~~ (~~Calstock~~Kenilworth) 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.

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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~~Proposed ~~Repair~~Transaction ~~Update~~with I Squared Capital

On ~~September~~January 2214, ~~2019~~2021, ~~the~~Atlantic ~~Cadillac~~Power ~~project~~announced ~~experienced~~that it had entered into a ~~malfunction~~definitive inagreement ~~its~~(as ~~steam~~amended ~~turbine~~on ~~that~~April ~~began~~1, a2021 ~~cascade~~and ofApril ~~events~~29, ~~sparking~~2021, aand ~~fire~~as ~~that~~may ~~resulted~~be infurther ~~significant~~amended ~~damage~~from time to ~~the turbine~~time, ~~generator~~the ~~and~~“Arrangement ~~other~~Agreement”) ~~components~~with incertain ~~that~~affiliates ~~area~~ of ~~the~~infrastructure ~~plant.~~funds ~~The~~managed ~~fire~~by ~~was~~I ~~contained~~Squared byCapital ~~the~~Advisors ~~plant’s~~(US) ~~fire~~LLC ~~protection~~(“I ~~system~~Squared ~~and~~Capital”), ~~the~~a ~~local~~leading ~~fire~~global ~~department~~infrastructure ~~and~~investor ~~did~~(the ~~not~~“Purchasers”), ~~result~~under inwhich ~~any~~the ~~injuries~~Company's oroutstanding ~~known~~common ~~environmental~~shares ~~violations~~and 6.00% ~~Reconstruction~~Series ofE ~~Cadillac~~convertible ~~was~~unsecured ~~completed~~subordinated indebentures ~~late~~due ~~July~~January ~~2020~~31, 2025 (“Convertible Debentures”), and the ~~plant~~outstanding ~~was~~preferred ~~recommissioned,~~shares ~~tested~~ and ~~returned~~medium toterm ~~service~~notes onof ~~August~~certain 20of its subsidiaries, ~~2020.~~would ~~Although~~be acquired (the ~~plant~~“Transaction”). ~~incurred~~The ~~significant~~total ~~damage,~~enterprise value of the ~~financial~~deal ~~impact~~is ~~has~~approximately ~~been~~$961 ~~limited~~million and the Transaction was unanimously approved by ~~our~~Atlantic ~~comprehensive~~Power's ~~insurance~~board ~~coverage~~of directors. The parties are currently targeting May 14, 2021 as the closing date for the Transaction.

WeIn ~~received~~connection ~~insurance~~with ~~proceeds~~the ofTransaction, ~~$7.0 million~~ and ~~$19.7~~subject ~~million~~to ~~for the three~~ and ~~nine~~conditional ~~months ended September 30, 2020, respectively, bringing the total cumulative proceeds received~~ to ~~$31.0 million. Proceeds were applied against~~ the ~~Cadillac~~closing ~~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. Transaction:

As● Holders of ~~November~~common 6,shares ~~2020,~~of weAtlantic ~~estimate~~Power ~~additional~~will ~~insurance~~receive ~~recoveries related to business interruption losses and property losses in the range of~~ $103.003 toper ~~$11.0~~common ~~million~~share in ~~settlement of the claim~~cash. 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.

39● Atlantic Power Preferred Equity Ltd.’s (“APPEL’s”) cumulative redeemable preferred shares, Series 1, cumulative rate reset preferred shares, Series 2, and cumulative floating rate preferred shares, Series 3, will be purchased by APPEL for Cdn$22.00 per preferred share in cash.

~~Table~~● Atlantic Power Limited Partnership’s (“APLP’s”) 5.95% medium term notes due June 23, 2036 (the “MTNs”) will be redeemed for consideration equal to 106.071% of ~~Contents~~the principal amount of MTNs held as of the closing of the Transaction, plus accrued and unpaid interest on the MTNs up to, but excluding, the closing date of the Transaction. Holders of MTNs that have delivered a valid consent to the proposed amendments to the trust indenture governing the MTNs (as described below) prior to 5:00 p.m. (Toronto time) on March 16, 2021 will also entitled to a consent fee equal to 0.25% of the principal amount of MTNs held by such holders in respect of which a consent was delivered, conditional on closing of the Transaction.

●

InThe Arrangement Agreement was amended on April 1, 2021 to provide for certain administrative and housekeeping amendments to the ~~nine~~Arrangement ~~months~~Agreement ~~ended~~and ~~September~~to, 30among other things, ~~2020~~clarify the mechanics surrounding the payment of consideration payable pursuant to the Transaction. The amendments also added a step to the Arrangement to, weamong ~~recorded~~other ~~$21~~things, provide for the creation of a class of non-voting preferred shares in connection with the Pre-Acquisition Reorganization (as defined in the Arrangement Agreement).8 ~~million~~The creation and issuance of ~~capital~~any ~~additions~~such ~~related~~shares will not occur until immediately prior to ~~repairs~~the ateffective ~~Cadillac~~time of the Arrangement and ~~cumulative~~will ~~additions~~only ofoccur ~~$26.8~~if ~~million~~the ~~since~~Purchasers have irrevocably waived or confirmed in writing the ~~inception~~satisfaction of all conditions to closing in their favor and shall have confirmed in writing that they are prepared, and able, to promptly and without condition proceed to effect the ~~reconstruction.~~Arrangement (as defined in the Arrangement Agreement).

~~Substantial~~The ~~Issuer~~Arrangement ~~Bid~~Agreement was further amended on April 29, 2021 to provide for mutual covenants in connection with the proposed defeasance of the Convertible Debentures (the “Defeasance”), clarify the mechanics surrounding the payment of the amounts required to effect the Defeasance, and effect a waiver of certain conditions precedent in the Arrangement Agreement relating to the approval of the Transaction by holders of the Convertible Debentures. Notwithstanding the Defeasance, any holder of Convertible Debentures who converts their Convertible Debentures during the period beginning 10 trading days (as defined in the Debenture Indenture) prior to the closing of the Transaction (“Closing”) and ending 30 calendar days following the delivery of the change of control notice under the Indenture (the “Make Whole Conversion Period”) will be entitled to receive the Make Whole Premium. Assuming that

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the Closing occurs on May 14, 2021 and the change of control notice is delivered on Closing as is currently anticipated, the Make Whole Conversion Period opened on April 30, 2021 and will close on June 14, 2021.

OnIn ~~March~~connection ~~25,~~with ~~2020~~the Defeasance, weand ~~commenced~~if aClosing ~~SIB~~occurs ~~for~~(i) ~~the~~Atlantic ~~purchase~~Power ofexpects up to ~~$25~~de-list ~~million~~its ofConvertible Debentures from the TSX and its common shares. ~~This~~from ~~was~~the ~~equivalent~~TSX and the NYSE; (ii) Atlantic Power intends to ~~12,820,512~~apply ~~common~~to ~~shares~~Canadian securities regulators to cease being a reporting issuer, or ~~approximately~~to ~~12%~~be ofexempt ~~our~~from ~~total~~its ~~issued~~reporting obligations as a Canadian reporting issuer, and ~~outstanding~~also ~~common~~intends ~~shares~~to ~~based~~file onto aderegister $1under the U.~~95 per~~S. ~~share~~Securities ~~purchase~~Exchange ~~price~~Act of 1934; (iii) the ~~minimum~~Convertible ~~price~~Debentures ~~per~~will no longer be convertible into common ~~share~~shares ~~under~~and, if converted after the ~~offer)~~Conversion asDeadline, ~~measured~~holders onwill ~~the~~be ~~date~~entitled ofto ~~commencement~~receive a cash amount equal to Cdn$3.72 ~~The~~in ~~SIB~~lieu ~~expired~~of each Common Share previously issuable on ~~April~~a ~~30,~~conversion ~~2020.~~(including ~~During~~any ~~the~~common ~~time~~shares ~~the~~otherwise ~~SIB~~issuable ~~was~~on ~~active,~~account of the ~~NCIB~~Make ~~was~~Whole ~~suspended~~Premium ~~for~~if converted within the ~~purchase~~Make ofWhole ~~common~~Conversion ~~shares~~Period), plus accrued and ~~Series~~unpaid Einterest ~~Debentures~~paid in Canadian dollars up to, but ~~not~~excluding, ~~for~~ the ~~preferred~~date ~~shares~~ of ~~APPEL.~~conversion; Weand ~~repurchased~~(iv) ~~and~~except ~~cancelled~~as 12otherwise provided in the Debenture Indenture,~~500,000~~ ~~common~~any ~~shares~~Convertible ~~under~~Debentures which remain outstanding following the ~~SIB~~expiry of the Make Whole Conversion Period will continue to receive interest at a ~~total~~rate ~~cost~~ of ~~$25~~6.800% ~~million~~per annum, ~~including~~payable ~~transaction~~semi-annually ~~costs~~in arrears until, and the repayment of principal upon, ~~its~~the ~~expiration~~redemption of the Convertible Debentures. Following the Defeasance, the Convertible Debentures will be redeemed at par on ~~April~~January 3031, ~~2020~~2023.

~~Share~~The ~~buybacks~~Transaction has received approval from the holders of common shares of the Company and the holders of preferred shares and medium term notes of certain of the Company's subsidiaries. The Transaction also has received certain required regulatory approvals, including an advance ruling certificate from the Canadian Commissioner of Competition under the Competition Act (Canada) on February 5, 2021, the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 on March 9, 2021, the approval of the Federal Energy Regulatory Commission on April 2, 2021 and the approval in April 2021 from the Federal Communications Commission (“FCC”) for the transfer of control of certain FCC licenses held by the Company or its subsidiaries.

~~Under~~The ~~the~~Transaction ~~NCIB,~~remains wesubject ~~repurchased~~to ~~and~~the ~~cancelled~~satisfaction ~~7,540,105~~or ~~million~~waiver ~~shares at a cost~~ of ~~$15.8~~certain ~~million~~third-party ~~during~~consents, ~~the~~and ~~nine~~other ~~months~~customary ~~ended~~closing ~~September 30, 2020~~conditions.

WeOxnard ~~also~~PPA 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. Agreement

~~Status~~On March 31, 2021, we executed an agreement to sell Resource Adequacy (RA) capacity from the Oxnard plant effective January 1, 2022 through December 31, 2023. Capacity provided under the agreement will be used to satisfy the load obligations of ~~Calstock~~a ~~and~~community choice aggregator. Under the RA agreement, Oxnard will ~~PPAs~~receive a fixed monthly capacity payment. 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.

InSale 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~~North Bay and ~~biomass generation in the province.~~ Kapuskasing

Our ~~Oxnard~~North ~~project~~Bay isand Kapuskasing projects are each 40 MW natural gas plants located in the Province of Ontario. These plants are currently ~~operating~~being ~~under~~maintained, but do not operate because they do not have PPAs or a ~~Reliability~~merchant ~~Must-Run~~market ~~(RMR)~~where ~~contract~~operations would be profitable. On February 23, 2021, we entered into an agreement with SNS Power Corp. to sell our properties in the ~~California~~City ~~Independent~~of ~~System~~North ~~Operator~~Bay, ~~(CAISO)~~the ~~through December~~District 31of Nipissing and in Kapuskasing, ~~2020~~Ontario for Cdn$3.0 ~~The~~million ~~RMR~~in ~~contract~~cash. isWe ~~based~~determined ~~upon~~the North Bay and Kapuskasing asset groups met the ~~plant’s~~criteria ~~cost~~for held for sale accounting as of ~~service~~March 31, 2021. See Note 2 – Assets and isLiabilities ~~subject~~Held tofor Sale. We currently expect the ~~approval~~sale of the ~~Federal~~plants ~~Energy~~to ~~Regulatory~~be ~~Commission~~completed ~~(FERC),~~in ~~which~~the issecond ~~pending~~quarter of 2021 subject to customary due diligence procedures.

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. 37

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~~May 6, ~~2020~~2021, 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

Economic Interest

Net MW

Primary Electric Purchasers

Power Contract Expiry

Customer Credit Rating (S&P)

Solid Fuel Segment

Allendale

South Carolina

Biomass

100.00

South Carolina Public Service Authority

November 2043

A (1)

Cadillac

Michigan

Biomass

100.00

Consumers Energy

June 2028

A-

Calstock

Ontario

Biomass

100.00

Ontario Electricity Financial Corporation

December ~~2020~~2021 (2)

AA- (1)

Chambers(3)

New Jersey

Coal

262

40.00

Atlantic City Electric (4)

March 2024

A-

Chemours Co.

March 2024

B+

Craven(3)

North Carolina

Biomass

50.00

Duke Energy Carolinas, LLC

December 2027

A-BBB+

Dorchester

South Carolina

Biomass

100.00

South Carolina Public Service Authority

October 2043

A (1)

Grayling(3)

Michigan

Biomass

30.00

Consumers Energy

December 2027

A-

Piedmont

Georgia

Biomass

100.00

Georgia Power

September 2032

A-

Williams Lake

British Columbia

Biomass

100.00

BC Hydro

September 2029

AAA (1)

Natural Gas Segment

Frederickson(3)

Washington

Natural Gas

250

50.15

Benton Co. PUD

August 2022

AA- (1)

Grays Harbor PUD

August 2022

A+ (1)

Franklin Co. PUD

August 2022

A+ (1)

Kenilworth

New Jersey

Natural Gas

100.00

Merck & Co., Inc.

September 2021

AA-

Merchant

N/A

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

Equistar Chemicals, LP (7)

December 2034

BBB- (8)

Nipigon

Ontario

Natural Gas

100.00

Independent Electricity System Operator

December 2022

AA- (1)

Orlando(3)

Florida

Natural Gas

129

50.00

Duke Energy Florida, LLC

December 2023

A-BBB+

Oxnard

California

Natural Gas

100.00

California Independent System Operator

December ~~2020~~2023 (9)

A+

Tunis

Ontario

Natural Gas

100.00

Independent Electricity System Operator

October 2033

AA- (1)

Hydroelectric Segment

Curtis Palmer

New York

Hydro

100.00

Niagara Mohawk Power Corporation

December 2027 (10)

A-BBB+

Koma Kulshan

Washington

Hydro

100.00

Puget Sound Energy

March 2037

BBB

Mamquam(11)

British Columbia

Hydro

100.00

BC Hydro

September 2027

AAA (1)

Moresby Lake

British Columbia

Hydro

100.00

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.

41(2) 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. In December 2020, the Calstock PPA was extended for one year, also under existing terms, and runs to December 16, 2021.

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

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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~~affiliates. ~~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~~On ~~PPA~~August ~~with Southern California Edison expired on May 25~~28, 2020, ~~and~~we ~~was not renewed or extended. The Company~~ executed an ~~RMR~~agreement ~~contract~~to ~~with~~sell ~~the~~RA ~~California~~capacity ~~Independent~~from ~~System~~the ~~Operator~~Oxnard ~~that~~plant ~~became~~ effective ~~June~~January 1, ~~2020~~2021 ~~and~~through ~~will~~to ~~expire~~ December 31, ~~2020~~2021. ~~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~~March 2831, ~~2020~~2021, we executed ana new agreement to sell RA capacity from the Oxnard plant for an additional two years, effective January 1, ~~2021~~2022 through December 31, ~~2021~~2023.

(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~~March 3031, ~~2020~~2021, the facility has generated 8,~~301~~420 GWh under its PPA. Based on cumulative generation to date and assuming average water conditions going forward, we expect the PPA to expire ~~prior~~in tothe ~~December~~first ~~2027~~quarter of 2026.

(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. We anticipate decommissioning will be completed in the second quarter of 2021.

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. On February 23, 2021, we entered into an agreement with SNS Power Corp. to sell our properties in City of North Bay, District of Nipissing and in Kapuskasing, Ontario for Cdn$3.0 million in cash. We determined the North Bay and Kapuskasing asset groups met the criteria for held for sale accounting as of March 31, 2021. See Note 2 – Assets and Liabilities Held for Sale. We currently expect the sale of the plants to be completed in the second quarter of 2021 subject to customary due diligence procedures.

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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~~March 3031, ~~2020~~2021 and ~~2019~~2020, which are analyzed in greater detail below:



	Three months ended				~~Nine months ended~~
	~~September~~March 3031,				~~September 30,~~
(in millions of U.S. dollars, except as otherwise stated)	~~2020~~2021		~~2019~~2020		~~2020~~		~~2019~~

Project revenue	$	6572.20	$	7172.18	$	~~200.3~~	$	~~215.4~~
Project income		3832.04		2724.97		~~82.3~~		~~80.1~~
Net income attributable to Atlantic Power Corporation		16.2		12.6		40.0		22.7
Net (loss) income attributable to Atlantic Power Corporation		(0.1)		29.5
Net cash provided by operating activities		~~27.~~8.4		368.4		~~72.1~~		~~104.5~~
Net cash used in investing activities		(6.5)		(29.1)		(9.4)		(28.0)
Net cash provided by (used in) investing activities		0.2		(2.6)
Net cash used in financing activities		(26.90)		(2040.31)		~~(112.4)~~		~~(87.1)~~
Earnings per share attributable to Atlantic Power Corporation—basic		0.18		0.12		0.41		0.21
(Loss) earnings per share attributable to Atlantic Power Corporation—basic		(0.00)		0.28
Earnings per share attributable to Atlantic Power Corporation—diluted		0.15		0.10		0.34		0.19
(Loss) earnings per share attributable to Atlantic Power Corporation—diluted		(0.00)		0.23
Project Adjusted EBITDA(1)		4948.52		4850.98		~~137.1~~		~~153.2~~

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

Project revenue decreased by $50.98 million to $6572.20 million in the three months ended ~~September~~March 3031, ~~2020~~2021 from $7172.18 million in the three months ended ~~September~~March 3031, ~~2019~~2020. The primary drivers of the decrease are as follows:

● ~~Oxnard~~Curtis Palmer – ~~the new RMR contract, which became effective in June 2020 and will expire in December 2020, provides for~~ lower ~~energy~~water ~~and~~flows ~~capacity~~resulted ~~revenue than the previous contract, resulting~~ in a $5.5 million decrease in ~~project~~ revenue ~~of $6.0 million~~; and

● ~~Cadillac~~Dorchester –a ~~the~~maintenance ~~project~~outage ~~was non-operational through August 20, 2020 following the fire~~ in ~~September~~March ~~2019,~~2021 ~~resulting~~resulted in a $10.67 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~~Cadillac ~~Lake~~ – athe ~~$1.8~~project ~~million~~ceased ~~increase~~operation inafter ~~revenue~~the ~~from~~fire at the ~~comparable~~project in September 2019. ~~period~~The ~~primarily~~project ~~due~~resumed tooperations ~~the~~on ~~project’s~~August ~~new~~20, ~~energy~~2020 ~~purchase~~resulting ~~agreement~~in ~~that~~a ~~became~~$2.9 ~~effective~~million increase in ~~October~~energy ~~2019,~~ and ~~higher~~capacity ~~generation~~revenue ~~than~~in the ~~comparable~~current ~~2019~~ period; ~~and~~

● ~~Allendale~~Morris ~~and Dorchester~~ – ~~the~~a ~~Allendale and Dorchester projects contributed~~ $1.84 million ofincrease ~~revenue~~ in ~~the~~project ~~three~~revenue ~~months~~due ~~ended~~to ~~September~~higher ~~30,~~fuel ~~2020.~~prices ~~The~~than ~~projects were purchased~~ in ~~July~~2020; ~~2019.~~and

~~Consolidated~~● ~~project~~Williams ~~income~~Lake ~~increased~~– bya $100.19 million toincrease ~~$38.0 million~~ in ~~the~~revenue ~~three~~primarily ~~months~~due ~~ended~~to ~~September~~increased ~~30,~~generation ~~2020~~and ~~from $27.9 million in~~ the ~~three~~impact ~~months ended September 30, 2019. The primary drivers~~ of ~~the~~foreign ~~increase~~currency ~~are~~translation ~~as follows:~~adjustments.

●Consolidated ~~Derivative~~project ~~instruments~~income –increased ~~the~~by ~~change~~$7.7 million to $32.4 million in the ~~fair~~three ~~value~~months ofended ~~our~~March ~~derivative~~31, ~~instruments~~2021 ~~increased~~from $724.07 million ~~from~~in the ~~comparable~~three ~~2019~~months ~~period;~~ended March 31, 2020. The primary drivers of the increase are as follows:

43● Derivative instruments – the change in the fair value of our derivative instruments increased $8.8 million from the comparable 2020 period.

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

●The ~~Fuel~~increase ~~expenses~~in –project ~~fuel~~income ~~expenses~~was ~~decreased~~partially offset by ~~$1.9 million from the comparable 2019 period primarily due to~~ a decrease ofin ~~$1.8 million at our Oxnard~~ project, ~~due~~income toresulting ~~the new RMR contract and lower generation for the project.~~from:

~~These~~● ~~increases~~Project inrevenue – project ~~income~~revenue ~~were~~decreased ~~partially~~$0.8 ~~offset~~million byas adiscussed ~~decrease in project income resulting from:~~above.

●A ~~Project~~detailed ~~revenue~~discussion –of project ~~revenue~~income ~~decreased~~by $5segment is provided in Consolidated Overview and Results of Operations below.9 ~~million~~The asdiscussion ~~discussed~~of ~~above~~Project Adjusted EBITDA by segment begins on page 46.

~~Project~~We ~~revenue~~have ~~decreased~~four byreportable ~~$15.1~~segments: ~~million~~Solid toFuel, ~~$200.3~~Natural ~~million in the nine months ended September 30~~Gas, ~~2020~~Hydroelectric ~~from~~and ~~$215~~Corporate.4 ~~million~~Project inincome is the ~~nine~~primary ~~months~~GAAP ~~ended~~measure ~~September~~of ~~30,~~our ~~2019.~~operating ~~The~~results ~~primary~~and ~~drivers~~is ofdiscussed ~~the~~below ~~decrease~~by ~~are~~reportable ~~as follows:~~segment.

● 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;

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Three months ended March 31, 2021 compared to the three months ended March 31, 2020

●The ~~Fuel~~following ~~expenses~~table –provides ~~fuel expenses decreased by $3.9 million from the comparable 2019 period primarily due to a decrease of $6.1 million at~~ our ~~Morris~~consolidated ~~project~~results ~~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; andoperations:

● 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.


	Three months ended March 31,
	2021		2020		$ change		% change
Project revenue:
Energy sales	$	36.0	$	40.7	$	(4.7)	(11.5)	%
Energy capacity revenue		29.8		28.0		1.8	6.4	%
Other		6.2		4.1		2.1	51.2	%
		72.0		72.8		(0.8)	(1.1)	%
Project expenses:
Fuel		20.7		19.6		1.1	5.6	%
Operations and maintenance		21.1		20.7		0.4	1.9	%
Depreciation and amortization		14.3		15.6		(1.3)	(8.3)	%
		56.1		55.9		0.2	0.4	%
Project other income (expense):
Change in fair value of derivative instruments		3.2		(5.6)		8.8	NM
Equity in earnings of unconsolidated affiliates		13.4		13.7		(0.3)	(2.2)	%
Interest expense, net		(0.3)		(0.3)		—	—
Other income, net		0.2		—		0.2	NM
		16.5		7.8		8.7	NM
Project income		32.4		24.7		7.7	31.2	%
Administrative and other expenses:
Administration		14.1		6.7		7.4	NM
Interest expense, net		11.4		10.8		0.6	5.6	%
Foreign exchange loss (gain)		3.2		(20.6)		23.8	NM
Other (income) expense, net		(0.1)		2.6		(2.7)	NM
		28.6		(0.5)		29.1	NM
Income from operations before income taxes		3.8		25.2		(21.4)	(84.9)	%
Income tax expense		2.2		1.5		0.7	46.7	%
Net income		1.6		23.7		(22.1)	(93.2)	%
Net income (loss) attributable to preferred shares of a subsidiary company		1.7		(5.8)		7.5	NM
Net (loss) income attributable to Atlantic Power Corporation	$	(0.1)	$	29.5	$	(29.6)	NM

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

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~~41

● 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.

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


	Three months ended March 31, 2021
									Consolidated
	Solid Fuel		Natural Gas		Hydroelectric		Corporate		Total
Project revenue:
Energy sales	$	18.2	$	5.6	$	12.2	$	—	$	36.0
Energy capacity revenue		8.1		21.7		—		—		29.8
Other		0.6		4.4		0.9		0.3		6.2
		26.9		31.7		13.1		0.3		72.0
Project expenses:
Fuel		12.0		8.7		—		—		20.7
Operations and maintenance		10.9		6.6		2.8		0.8		21.1
Depreciation and amortization		3.6		5.8		4.9		—		14.3
		26.5		21.1		7.7		0.8		56.1
Project other income (loss):
Change in fair value of derivative instruments		—		2.5		—		0.7		3.2
Equity in earnings of unconsolidated affiliates		2.9		10.5		—		—		13.4
Interest expense, net		(0.3)		—		—		—		(0.3)
Other income, net		—		—		—		0.2		0.2
		2.6		13.0		—		0.9		16.5
Project income	$	3.0	$	23.6	$	5.4	$	0.4	$	32.4

The following table provides our consolidated results of operations:


	Three months ended March 31, 2020
									Consolidated
	Solid Fuel		Natural Gas		Hydroelectric		Corporate		Total
Project revenue:
Energy sales	$	16.8	$	6.2	$	17.7	$	—	$	40.7
Energy capacity revenue		6.3		21.7		—		—		28.0
Other		0.3		2.9		0.7		0.2		4.1
		23.4		30.8		18.4		0.2		72.8
Project expenses:
Fuel		10.1		9.5		—		—		19.6
Operations and maintenance		11.2		5.6		3.1		0.8		20.7
Depreciation and amortization		3.2		7.5		4.9		—		15.6
		24.5		22.6		8.0		0.8		55.9
Project other income (expense):
Change in fair value of derivative instruments		—		0.5		—		(6.1)		(5.6)
Equity in earnings of unconsolidated affiliates		2.9		10.8		—		—		13.7
Interest expense, net		(0.3)		—		—		—		(0.3)
		2.6		11.3		—		(6.1)		7.8
Project income (loss)	$	1.5	$	19.5	$	10.4	$	(6.7)	$	24.7


	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%.

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	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~~March 3031, ~~2020~~2021 increased $51.45 million from the comparable ~~2019~~2020 period primarily due to:

● increased project income of $62.38 million at Cadillac primarily due to ~~insurance~~the ~~proceeds~~extended ofoutage ~~$6.2~~following ~~million~~the ~~for~~fire ~~business~~at ~~interruption~~the ~~losses~~plant asin aSeptember ~~result~~2019. ofThe ~~the~~project ~~fire~~was atnon-operational ~~the~~through ~~project~~August in20, ~~September 2019;~~2020.

●This ~~increased~~increase ~~project~~was ~~income~~partially ofoffset ~~$1.3 million at Chambers primarily due to lower fuel consumption and improved heat rate than the comparable 2019 period; and~~by:

● ~~increased~~decreased combined project income of $1.07 million at ~~Williams~~Allendale ~~Lake~~and Dorchester primarily due to ~~the~~maintenance ~~project’s~~outages ~~new energy purchase agreement that became effective~~ in ~~October~~March ~~2019, and higher generation than the comparable 2019 period, which resulted in a $1~~2021.~~8 million increase in project revenue from the comparable 2019 period.~~

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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~~March 3031, ~~2020~~2021 increased $24.21 million from the comparable ~~2019~~2020 ~~period primarily due to:~~

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period primarily due to:

● increased project income of $52.05 million at ~~Orlando~~Oxnard primarily due to the project’s new RA contract that became effective in January 2021 in which the project receives a fixed monthly capacity payment, and decreased depreciation and amortization expense of $41.91 million ~~increase~~as in the ~~fair~~PPA ~~value~~intangibles ofwere ~~natural~~fully ~~gas~~amortized ~~swaps~~in May 2020;

● increased project income of $02.64 million at ~~Nipigon~~Orlando primarily due to a $01.67 million ~~decrease~~increase in ~~maintenance expense due to major maintenance at~~ the ~~project~~fair invalue ~~the~~of ~~comparable~~natural ~~2019~~gas ~~period~~swaps; and

● increased project income of $01.60 million at ~~Manchief~~Kenilworth primarily due to ~~higher~~decreased ~~dispatch~~depreciation ~~than~~and amortization expense of $0.7 million as the ~~comparable~~project’s ~~2019~~property, ~~period~~plant and equipment was fully depreciated as of October 2020.

These increases were partially offset by:

● decreased project income of $2.1.4 million at ~~Morris~~Manchief primarily due to ~~increased gas turbine maintenance expense of $1.1 million and~~ a ~~lower~~forced ~~gross~~outage ~~margin~~in ~~from~~February ~~lower PJM pricing; and~~2021.

● 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~~March 3031, ~~2020~~2021 decreased $05.70 million from the comparable ~~2019~~2020 period primarily due to:

● decreased project income of $15.74 million at Curtis Palmer primarily due to lower water flows than ~~the~~in ~~comparable 2019 period~~2020.

Corporate

Project income for the three months ended ~~September~~March 3031, ~~2020~~2021 increased $37.21 million from the comparable ~~2019~~2020 period primarily due to a $56.48 million increase in the fair value of interest rate swap agreements related to the ~~senior~~Term ~~secured credit facility~~Loan.

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.

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Administration

Administration expense for the three months ended ~~September~~March 3031, ~~2020~~2021 ~~did~~increased ~~not~~by ~~change~~$7.4 ~~materially~~million ~~from~~to $14.1 million in the three months ended ~~September~~March 3031, ~~2019~~2021 from $6.7 million in the comparable period in 2020, primarily due to the costs related to the Transaction including third-party costs and accelerated incentive compensation.

Interest expense, net

Interest expense for the three months ended ~~September~~March 3031, ~~2020~~2021 did not change materially from the three months ended ~~September~~March 3031, ~~2019~~2020.

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