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 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 May 6, 2021 was 89,797,798.

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ATLANTIC POWER CORPORATION

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2021

Index

	General :		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of March 31, 2021 (unaudited) and December 31, 2020	4
		Consolidated Statements of Operations for the three months ended March 31, 2021 (unaudited) and March 31, 2020 (unaudited)	5
		Consolidated Statements of Comprehensive Income for the three months ended March 31, 2021 (unaudited) and March 30, 2020 (unaudited)	6
		Consolidated Statements of Cash Flows for the three months ended March 31, 2021 (unaudited) and March 31, 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	35
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	51
ITEM 4.		CONTROLS AND PROCEDURES	51
		PART II—OTHER INFORMATION
ITEM 1A.		RISK FACTORS	51
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	51
ITEM 6.		EXHIBITS	53

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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.”

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ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)


	March 31,		December 31,
	2021		2020
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	21.6	$	38.8
Restricted cash		6.9		7.1
Accounts receivable		33.9		31.3
Current portion of derivative instruments asset (Notes 7 and 8)		—		0.4
Inventory		17.0		18.3
Prepayments		6.7		7.0
Income taxes receivable (Note 9)		2.0		3.2
Current assets held for sale (Note 2)		4.6		—
Other current assets		0.3		0.3
Total current assets		93.0		106.4
Property, plant, and equipment, net		481.3		491.8
Equity investments in unconsolidated affiliates (Note 5)		91.8		85.0
Power purchase agreements and intangible assets, net		114.8		120.3
Goodwill		21.3		21.3
Operating lease right-of-use assets (Note 15)		4.1		4.6
Deferred income taxes (Note 9)		17.0		17.2
Other assets		0.6		0.6
Total assets	$	823.9	$	847.2
Liabilities
Current liabilities:
Accounts payable	$	5.6	$	6.3
Accrued interest		5.9		2.5
Other accrued liabilities		14.7		19.3
Current portion of long-term debt (Note 6)		90.8		95.7
Current portion of derivative instruments liability (Notes 7 and 8)		9.9		11.0
Operating lease liabilities (Note 15)		1.8		1.9
Current liabilities held for sale (Note 2)		3.2		—
Other current liabilities		0.4		0.2
Total current liabilities		132.3		136.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 6)		368.3		384.1
Convertible debentures, net of discount and unamortized deferred financing costs		85.5		84.1
Derivative instruments liability (Notes 7 and 8)		5.4		8.1
Power purchase agreements and intangible liabilities, net		17.6		18.0
Asset retirement obligations, net		45.0		48.1
Operating lease liabilities (Note 15)		2.7		3.1
Other long-term liabilities		6.7		6.2
Total liabilities		663.5		688.6
Equity
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 4)		(138.1)		(139.9)
Retained deficit		(1,090.1)		(1,090.0)
Total Atlantic Power Corporation shareholders’ deficit		(8.4)		(10.2)
Preferred shares issued by a subsidiary company (Note 12)		168.8		168.8
Total equity		160.4		158.6
Total liabilities and equity	$	823.9	$	847.2

See accompanying notes to condensed consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)


	Three Months Ended March 31,
	2021		2020
Project revenue:
Energy sales (Note 3)	$	36.0	$	40.7
Energy capacity revenue (Note 3)		29.8		28.0
Other (Note 3)		6.2		4.1
		72.0		72.8
Project expenses:
Fuel		20.7		19.6
Operations and maintenance		21.1		20.7
Depreciation and amortization		14.3		15.6
		56.1		55.9
Project other income (loss):
Change in fair value of derivative instruments (Notes 7 and 8)		3.2		(5.6)
Equity in earnings of unconsolidated affiliates (Note 5)		13.4		13.7
Interest, net		(0.3)		(0.3)
Other income, net		0.2		—
		16.5		7.8
Project income		32.4		24.7
Administrative and other expenses:
Administration		14.1		6.7
Interest expense, net		11.4		10.8
Foreign exchange loss (gain)		3.2		(20.6)
Other (income) expense, net (Note 7)		(0.1)		2.6
		28.6		(0.5)
Income from operations before income taxes		3.8		25.2
Income tax expense (Note 9)		2.2		1.5
Net income		1.6		23.7
Net income (loss) attributable to preferred shares of a subsidiary company (Note 12)		1.7		(5.8)
Net (loss) income attributable to Atlantic Power Corporation	$	(0.1)	$	29.5
Net (loss) earnings per share attributable to Atlantic Power Corporation shareholders: (Note 11)
Basic	$	(0.00)	$	0.28
Diluted		(0.00)		0.23
Weighted average number of common shares outstanding: (Note 11)
Basic		89.4		107.2
Diluted		89.4		134.8

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 March 31,
	2021		2020
Net income	$	1.6	$	23.7
Other comprehensive income, net of tax:
Unrealized gain (loss) on hedging activities	$	0.1	$	(0.4)
Net amount reclassified to earnings		—		0.1
Net realized and unrealized gain (loss) on derivatives		0.1		(0.3)
Foreign currency translation adjustments		1.7		(11.2)
Other comprehensive income (loss), net of tax		1.8		(11.5)
Comprehensive income		3.4		12.2
Less: Comprehensive income (loss) attributable to preferred shares of a subsidiary company		1.7		(5.8)
Comprehensive income attributable to Atlantic Power Corporation	$	1.7	$	18.0

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)


	Three months ended
	March 31,
	2021		2020
Cash provided by operating activities:
Net income	$	1.6	$	23.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		14.3		15.6
Share-based compensation		0.1		0.4
Other gain		(0.2)		—
Equity in earnings from unconsolidated affiliates		(13.4)		(13.7)
Distributions from unconsolidated affiliates		6.9		6.0
Unrealized foreign exchange loss (gain)		3.1		(20.9)
Change in fair value of derivative instruments		(3.3)		8.2
Amortization of debt discount and deferred financing costs		1.3		2.0
Non-cash operating lease expense		0.5		0.5
Deferred income taxes		0.3		0.3
Change in other operating balances:
Accounts receivable		(3.1)		(2.1)
Inventory		0.2		2.8
Prepayments and other assets		1.6		(1.7)
Accounts payable		(0.9)		(5.7)
Accruals and other liabilities		(0.6)		(7.0)
Cash provided by operating activities		8.4		8.4
Cash provided by (used in) investing activities:
Insurance proceeds		—		7.4
Proceeds from sale of equity investment		0.5		—
Purchase of property, plant and equipment		(0.3)		(10.0)
Cash provided by (used in) investing activities		0.2		(2.6)
Cash used in financing activities:
Common share repurchases		—		(8.2)
Preferred share repurchases		—		(6.4)
Repayment of corporate and project-level debt		(23.7)		(21.6)
Cash payments for vested LTIP withheld for taxes		(0.6)		(0.7)
Deferred financing costs		—		(1.5)
Dividends paid to preferred shareholders		(1.7)		(1.7)
Cash used in financing activities		(26.0)		(40.1)
Net decrease in cash, restricted cash and cash equivalents		(17.4)		(34.3)
Cash, restricted cash and cash equivalents at beginning of period		45.9		82.6
Cash, restricted cash and cash equivalents at end of period	$	28.5	$	48.3
Supplemental cash flow information
Interest paid	$	6.8	$	8.3
Income taxes paid, net	$	0.7	$	0.7
Accruals for construction in progress	$	—	$	0.3

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 March 31, 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, 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 March 31, 2021, the results of operations and comprehensive income for the three months ended March 31, 2021 and 2020, and our cash flows for the three months ended March 31, 2021 and 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, 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 three months ended March 31, 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.

Proposed Transaction with I Squared Capital

On January 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 connection with the Transaction, and subject to and conditional to the closing of the Transaction:

●

Holders of common shares of Atlantic Power will receive $3.03 per common share in cash.

●

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(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)

The 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.

The Transaction remains subject to the satisfaction or waiver of certain remaining third-party consents and other customary closing conditions.

Recently adopted and issued accounting standards

Accounting standards adopted in 2021

In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. Adoption of this guidance did not have a material impact on the condensed consolidated financial statements.

Accounting standards not yet adopted

In March 2020, the FASB issued amendments to the guidance for reference rate reform through ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the effects of reference rate reform on financial reporting.” The amendments in this update provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022. The amendments are elective and are effective upon issuance for all entities. We are in the process of evaluating the potential impact of the new guidance on our 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)

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.

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


	March 31,
	2021
Assets	(unaudited)
Inventory	$	1.1
Property, plant, and equipment, net		3.5
Total current assets held for sale	$	4.6
Liabilities
Asset retirement obligations	$	3.2
Total current liabilities held for sale	$	3.2

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)


	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
Steam energy and capacity revenue		—		2.7		—		—		2.7
Waste heat revenue		0.3		—		—		—		0.3
Ancillary and transmission services		—		0.7		0.7		—		1.4
Asset management and operation		—		—		—		0.2		0.2
Miscellaneous revenue		—		(0.5)		—		—		(0.5)
		23.4		30.8		18.4		0.2		72.8

Contract balances

Contract liabilities as of March 31, 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 $0.3 million water license fee at Mamquam (Hydroelectric segment). Contract liabilities as of December 31, 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 March 31, 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)

4. Changes in accumulated other comprehensive loss by component

The changes in accumulated other comprehensive (loss) income by component were as follows:


	Three Months Ended March 31,
	2021		2020
Foreign currency translation
Balance at beginning of period	$	(138.4)	$	(140.6)
Other comprehensive income:
Foreign currency translation adjustments⁽¹⁾		1.7		(11.2)
Balance at end of period	$	(136.7)	$	(151.8)
Pension
Balance at beginning and end of period ⁽²⁾	$	(3.1)	$	(1.7)
Cash flow hedges
Balance at beginning of period	$	1.6	$	1.6
Other comprehensive income (loss):
Net change from periodic revaluations		0.2		(0.6)
Tax (expense) benefit		(0.1)		0.2
Total other comprehensive income (loss) before reclassifications, net of tax		0.1		(0.4)
Net amount reclassified to earnings:
Interest rate swaps⁽³⁾		—		0.1
Tax expense		—		—
Total amount reclassified from accumulated other comprehensive income, net of tax		—		0.1
Total other comprehensive income (loss)		0.1		(0.3)
Balance at end of period	$	1.7	$	1.3

(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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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

5. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three months ended March 31, 2021 and 2020, respectively, for our proportional ownership interest in equity method investments:


	Three Months Ended March 31,
Operating results	2021		2020
Revenue
Frederickson	$	7.3	$	8.0
Orlando Cogen, LP		15.5		14.6
Chambers Cogen, LP		10.8		10.6
Craven County Wood Energy, LP		3.1		3.1
Grayling Generating Station, LP		1.6		1.5
		38.3		37.8
Project expenses
Frederickson		4.8		5.4
Orlando Cogen, LP		7.2		6.3
Chambers Cogen, LP		8.2		8.1
Craven County Wood Energy, LP		3.0		2.6
Grayling Generating Station, LP		1.2		1.4
		24.4		23.8
Project other income
Frederickson		—		—
Orlando Cogen, LP		—		—
Chambers Cogen, LP		(0.2)		(0.3)
Craven County Wood Energy, LP		—		—
Grayling Generating Station, LP		—		—
		(0.2)		(0.3)
Net income
Frederickson		2.5		2.6
Orlando Cogen, LP		8.3		8.3
Chambers Cogen, LP		2.4		2.2
Craven County Wood Energy, LP		0.1		0.5
Grayling Generating Station, LP		0.4		0.1
Equity in earnings of unconsolidated affiliates	$	13.7	$	13.7

Distributions from equity method investments		(6.9)		(6.0)
Earnings of equity method investments, net of distributions	$	6.8	$	7.7

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

6. Long-term debt

Long-term debt consists of the following:


	March 31,		December 31,
	2021		2020		Interest Rate
Recourse Debt:
Senior secured term loan facility, due 2025⁽¹⁾	$	284.5	$	307.5	LIBOR⁽²⁾	plus	2.50	%
Senior unsecured notes, due June 2036 (Cdn$210.0)		167.0		164.9			5.95	%
Non-Recourse Debt:
Cadillac term loan, due 2025⁽³⁾		14.1		14.8	LIBOR	plus	1.61	%
Less: unamortized discount		(3.0)		(3.5)
Less: unamortized deferred financing costs		(3.5)		(3.9)
Less: current maturities		(90.8)		(95.7)
Total long-term debt	$	368.3	$	384.1

Current maturities consist of the following:


	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 $284.5 million outstanding aggregate borrowings under our senior secured term loan facility at March 31, 2021. See Note 8, 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 8, Accounting for derivative instruments and hedging activities, for further details.

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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.

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. At March 31, 2021, we had no borrowings under the Revolver and utilized $81.2 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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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

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


	March 31, 2021
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	21.6	$	—	$	—	$	21.6
Restricted cash		6.9		—		—		6.9
Derivative instruments asset		—		—		—		—
Total	$	28.5	$	—	$	—	$	28.5
Liabilities:
Derivative instruments liability	$	—	$	13.9	$	1.4	$	15.3
Total	$	—	$	13.9	$	1.4	$	15.3


	December 31, 2020
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	38.8	$	—	$	—	$	38.8
Restricted cash		7.1		—		—		7.1
Derivative instruments asset		—		0.4		—		0.4
Total	$	45.9	$	0.4	$	—	$	46.3
Liabilities:
Derivative instruments liability	$	—	$	17.6	$	1.5	$	19.1
Total	$	—	$	17.6	$	1.5	$	19.1

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 March 31, 2021, the credit valuation adjustments resulted in a $0.3 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $0.2 million gain in change in fair value of derivative instruments. As of December 31, 2020, the credit valuation adjustments resulted in a $0.5 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $0.4 million gain in change in fair value of derivative instruments.

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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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

The following table reconciles, for the three months ended March 31, 2021 and 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 value Measurement Using Significant Unobservable Inputs (Level 3)
	Three Months Ended
	March 31, 2021

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


	Fair value Measurement Using Significant Unobservable Inputs (Level 3)
	Three Months Ended
	March 31, 2020

Beginning balance of liability at January 1, 2020	$	3.2
Total unrealized loss		2.6
Currency translation gain		(0.2)
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.

8. 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

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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.

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 11.3 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 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 March 31, 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 March 31, 2021, these agreements totaled $284.5 million notional amount of the remaining $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 1.92%, resulting in an all-in rate of approximately 4.42% for $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 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)

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 March 31, 2021 and December 31, 2020:


		March 31,	December 31,
	Units	2021	2020
Natural gas swaps	Natural Gas (MMBtu)	11.3	12.4
Gas purchase agreements	Natural Gas (Gigajoules)	4.2	4.0
Interest rate swaps	Interest (US$)	298.7	122.3

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:


	March 31, 2021
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.6
Interest rate swaps long-term		—		0.7
Total derivative instruments designated as cash flow hedges		—		1.3
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		4.3
Interest rate swaps long-term		—		—
Natural gas swaps current		—		—
Natural gas swaps long-term		—		1.5
Gas purchase agreements current		—		3.6
Gas purchase agreements long-term		—		3.2
Convertible debenture conversion option		—		1.4
Total derivative instruments not designated as cash flow hedges		—		14.0
Total derivative instruments	$	—	$	15.3

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ATLANTIC POWER CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	December 31, 2020
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.6
Interest rate swaps long-term		—		1.0
Total derivative instruments designated as cash flow hedges		—		1.6
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		4.1
Interest rate swaps long-term		—		0.9
Natural gas swaps current		—		0.8
Natural gas swaps long-term		—		1.9
Gas purchase agreements current		0.4		4.0
Gas purchase agreements long-term		—		4.3
Convertible debenture conversion option		—		1.5
Total derivative instruments not designated as cash flow hedges		0.4		17.5
Total derivative instruments	$	0.4	$	19.1

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 March 31, 2021	Swaps
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		—
Accumulated OCI balance at March 31, 2021	$	1.7

	Interest Rate
Three Months Ended March 31, 2020	Swaps
Accumulated OCI balance at January 1, 2020	$	1.6
Change in fair value of cash flow hedges		(0.4)
Realized from OCI during the period		0.1
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	Three Months Ended March 31,
	recognized in income	2021		2020
Gas purchase agreements	Fuel	$	2.2	$	2.2
Natural gas swaps	Fuel		0.1		0.7
Interest rate swaps	Interest, net		0.5		0.3

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)	Three Months Ended March 31,
	recognized in income	2021		2020
Natural gas swaps	Change in fair value of derivative instruments	$	1.2	$	(0.5)
Gas purchase agreements	Change in fair value of derivative instruments		1.3		1.0
Interest rate swaps	Change in fair value of derivative instruments		0.7		(6.1)
		$	3.2	$	(5.6)
Convertible debenture conversion option	Other (income) expense, net	$	(0.1)	$	2.6

9. Income taxes

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


	Three Months Ended March 31,
	2021		2020

Current income tax expense	$	1.9	$	1.2
Deferred income tax expense		0.3		0.3
Total income tax expense, net	$	2.2	$	1.5

For the three months ended March 31, 2021 and 2020

Income tax expense for the three months ended March 31, 2021 was $2.2 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $1.0 million. The primary items impacting the tax rate for the three months ended March 31, 2021 were $0.5 million relating to withholding and state taxes and $0.7 million of other permanent differences.

Income tax expense for the three months ended March 31, 2020 was $1.5 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $6.8 million. The primary item impacting the tax rate for the three months ended March 31, 2020 was a net decrease to our valuation allowances of $8.7 million, consisting of $5.9 million decreases in Canada and $2.8 million 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)

As of March 31, 2021, we have recorded a valuation allowance of $105.5 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the U.S. and in Canada and available tax planning strategies.

10. Equity compensation plans

Long-term incentive plan (“LTIP”)

The following table summarizes the changes in outstanding LTIP notional shares during the three months ended March 31, 2021:


			Grant Date
			Weighted-Average
	Notional Shares		Fair Value per Notional Share
Outstanding at December 31, 2020	3,710,340	$	2.45
Vested and redeemed	(1,836,821)		2.36
Forfeitures	(224,678)		2.46
Outstanding at March 31, 2021	1,648,841	$	2.56

Cash payments made for vested notional shares for the three months ended March 31, 2021 and 2020 were $3.5 million and $3.3 million, respectively. Total compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.4 million and $1.0 million for the three months ended March 31, 2021 and 2020, respectively.

Transition Equity Participation Agreement

We also have 269,952 transition notional shares outstanding at March 31, 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.

11. 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.

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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:


	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 table summarizes our outstanding instruments that are anti-dilutive and were not included in the computation of our diluted earnings (loss) per share:

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, 2021	$	1,219.7	$	(1,090.0)	$	(139.9)	$	(10.2)	$	168.8	$	158.6
Net (loss) income		—		(0.1)		—		(0.1)		1.7		1.6
Share-based compensation		0.1		—		—		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$0.358688 per share)		—		—		—		—		(0.7)		(0.7)
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.267807 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		—		—		1.7		1.7		—		1.7
Balance at March 31, 2021	$	1,219.8	$	(1,090.1)	$	(138.1)	$	(8.4)	$	168.8	$	160.4


					Accumulated		Total		Preferred
					Other		Atlantic Power		Shares of a
	Common		Retained		Comprehensive		Corporation		Subsidiary		Total
	Shares		Deficit		(loss) income		Shareholders' Deficit		Company		Equity
Balance at January 1, 2020	$	1,259.9	$	(1,164.2)	$	(140.7)	$	(45.0)	$	182.7	$	137.7
Net income (loss)		—		29.5		—		29.5		(5.8)		23.7
Share-based compensation		0.4		—		—		0.4		—		0.4
Common share repurchases		(8.2)		—		—		(8.2)		—		(8.2)
Preferred share repurchases		—		—		—		—		(6.4)		(6.4)
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$0.363342 per share)		—		—		—		—		(0.3)		(0.3)
Realized and unrealized loss on hedging activities, net of tax		—		—		(0.3)		(0.3)		—		(0.3)
Foreign currency translation adjustments		—		—		(11.2)		(11.2)		—		(11.2)
Balance at March 31, 2020	$	1,252.1	$	(1,134.7)	$	(152.2)	$	(34.8)	$	168.8	$	134.0

Share Repurchase Program

Normal Course Issuer Bid

On December 31, 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 APPEL, our wholly-owned subsidiary. The NCIBs expire on December 30, 2021 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. Under the NCIBs, we may purchase up to a total of 8,554,391 common shares based on 10% of our public float as of December 18, 2020 and we are limited to daily purchases of 10,420 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. All purchases made under the NCIBs will be made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the NYSE in compliance with Rule 10b-18 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or other designated exchanges and published marketplaces in the U.S. in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval.

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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 Board authorization permits the Company to repurchase common and preferred shares and Convertible Debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our Convertible Debentures and our APPEL preferred shares through open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs, issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and other factors. Any share repurchases outside of previously authorized NCIBs would be affected after taking into account our then current cash position and then anticipated cash obligations or business opportunities.

Atlantic Power Corporation and affiliated purchasers did not make any repurchases of common equity securities, Convertible Debentures or preferred shares during the period of January 1, 2021 through March 31, 2021.

13. Segment and geographic information

We have 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.

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



	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

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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

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
	Three Months Ended March 31,
	2021		2020
United States	$	46.1	$	48.2
Canada		25.9		24.6
Total	$	72.0	$	72.8


	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

Concentration risk

Independent Electricity System Operator (“IESO”), BC Hydro, Niagara Mohawk and Equistar Chemicals, LP (“Equistar”) provided 14.8%, 14.8%, 13.4%, and 12.1%, respectively, of total consolidated revenues for the three months ended March 31, 2021. Niagara Mohawk, IESO, BC Hydro and Equistar provided 20.9%, 14.7%, 13.5% and 10.3%, respectively, of total consolidated revenues for the three months ended March 31, 2020.

IESO 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)

project in the Hydroelectric segment, and Equistar purchases electricity from the Morris project in the Natural Gas segment.

14. Guarantees and Contingencies

Guarantees

We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

Contingencies

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

15. Leases

Real estate leases and equipment leases

We lease our office properties and equipment under operating leases expiring on various dates through 2024. Certain operating lease agreements include provisions for scheduled rent increases over their lease terms. We recognize the effects of these scheduled rent increases on a straight-line basis over the lease term. One of our leased office properties is sub-leased to third parties. The sub-lease is an operating lease and the rental income received is recorded net of rental expense in the condensed consolidated statements of operations.

On January 1, 2019, we implemented FASB ASU No. 2016-02, Leases (Topic 842). To calculate lease liabilities on the implementation date, we utilized an incremental borrowing rate of 3.75%, which was our minimum all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount.

The following table presents the components of lease expense.


	Three Months Ended March 31,
		2021		2020
Lease cost: ⁽¹⁾
Operating lease cost	$	0.5	$	0.5
Sublease income		(0.3)		(0.3)
Total lease cost	$	0.2	$	0.2

⁽¹⁾ Short-term lease costs and finance lease costs are immaterial to the Company.

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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
2021	$	1.5	$	(0.8)	$	0.7
2022		1.8		(1.1)		0.7
2023		1.3		(0.7)		0.6
2024		0.2		—		0.2
2025		—		—		—
Thereafter		—		—		—
Total operating lease payments	$	4.8	$	(2.6)	$	2.2
Less: present value discount		(0.3)
Total operating lease liabilities	$	4.5

	Lease
	Payments
2021	$	—
2022		0.1
2023		—
Thereafter		—
Total finance lease payments	$	0.1
Less: amount representing interest		—
Total finance lease liabilities	$	0.1

⁽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

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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 March 31, 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 one 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
	Three Months Ended
	March 31,
	2021		2020
Solid Fuel	$	14.8	$	16.6

Natural Gas		5.6		5.9

Hydroelectric		13.1		18.4
	$	33.5	$	40.9

For certain of our PPAs accounted for as leases, the lessee has the option to purchase the plant. In May 2019, we entered into an agreement to sell Manchief to Public Service Company of Colorado (“PSCo”) following the expiration of the PPA in April 2022 for $45.2 million subject to working capital and other customary adjustments. BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.

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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, 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, 2020 or in this Quarterly Report on Form 10-Q 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.

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

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●

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;

●

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 credit 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 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

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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 and analysis of financial condition and results of operations 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, 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 March 31, 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.

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 September 2021 (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

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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

Proposed Transaction with I Squared Capital

In connection with the Transaction, and subject to and conditional to the closing of the Transaction:

●

Holders of common shares of Atlantic Power will receive $3.03 per common 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 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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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.

The Transaction remains subject to the satisfaction or waiver of certain third-party consents, and other customary closing conditions.

Oxnard PPA Agreement

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 a community choice aggregator. Under the RA agreement, Oxnard will 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.

Sale of North Bay and Kapuskasing

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 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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OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of May 6, 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 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

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

BBB+

Oxnard

California

Natural Gas

100.00

California Independent System Operator

December 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⁾

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.

(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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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 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, as Equistar is not rated.

(9)

On August 28, 2020, we executed an agreement to sell RA capacity from the Oxnard plant effective January 1, 2021 through to December 31, 2021. On March 31, 2021, we executed a new agreement to sell capacity from the Oxnard plant for an additional two years, effective January 1, 2022 through December 31, 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 March 31, 2021, the facility has generated 8,420 GWh under its PPA. Based on cumulative generation to date and assuming average water conditions going forward, we expect the PPA to expire in the first 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 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 months ended March 31, 2021 and 2020, which are analyzed in greater detail below:



	Three months ended
	March 31,
(in millions of U.S. dollars, except as otherwise stated)	2021		2020

Project revenue	$	72.0	$	72.8
Project income		32.4		24.7
Net (loss) income attributable to Atlantic Power Corporation		(0.1)		29.5
Net cash provided by operating activities		8.4		8.4
Net cash provided by (used in) investing activities		0.2		(2.6)
Net cash used in financing activities		(26.0)		(40.1)
(Loss) earnings per share attributable to Atlantic Power Corporation—basic		(0.00)		0.28
(Loss) earnings per share attributable to Atlantic Power Corporation—diluted		(0.00)		0.23
Project Adjusted EBITDA⁽¹⁾		48.2		50.8

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

Project revenue decreased by $0.8 million to $72.0 million in the three months ended March 31, 2021 from $72.8 million in the three months ended March 31, 2020. The primary drivers of the decrease are as follows:

●

Curtis Palmer – lower water flows resulted in a $5.5 million decrease in revenue; and

●

Dorchester –a maintenance outage in March 2021 resulted in a $0.7 million decrease in revenue.

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

●

Cadillac – the project ceased operation after the fire at the project in September 2019. The project resumed operations on August 20, 2020 resulting in a $2.9 million increase in energy and capacity revenue in the current period;

●

Morris – a $1.4 million increase in project revenue due to higher fuel prices than in 2020; and

●

Williams Lake – a $0.9 million increase in revenue primarily due to increased generation and the impact of foreign currency translation adjustments.

Consolidated project income increased by $7.7 million to $32.4 million in the three months ended March 31, 2021 from $24.7 million in the three months ended March 31, 2020. The primary drivers of the increase are as follows:

●

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

The increase in project income was partially offset by a decrease in project income resulting from:

●

Project revenue – project revenue decreased $0.8 million as discussed above.

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 46.

We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. Project income is the primary GAAP measure of our operating results and is discussed below by reportable segment.

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

The following table provides our consolidated results of operations:


	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%

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	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


	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

Solid Fuel

Project income for the three months ended March 31, 2021 increased $1.5 million from the comparable 2020 period primarily due to:

●

increased project income of $2.8 million at Cadillac primarily due to the extended outage following the fire at the plant in September 2019. The project was non-operational through August 20, 2020.

This increase was partially offset by:

●

decreased combined project income of $1.7 million at Allendale and Dorchester primarily due to maintenance outages in March 2021.

Natural Gas

Project income for the three months ended March 31, 2021 increased $4.1 million from the comparable 2020

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period primarily due to:

●

increased project income of $2.5 million at 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 $1.1 million as the PPA intangibles were fully amortized in May 2020;

●

increased project income of $2.4 million at Orlando primarily due to a $1.7 million increase in the fair value of natural gas swaps; and

●

increased project income of $1.0 million at Kenilworth primarily due to decreased depreciation and amortization expense of $0.7 million as the project’s property, plant and equipment was fully depreciated as of October 2020.

These increases were partially offset by:

●

decreased project income of $1.4 million at Manchief primarily due to a forced outage in February 2021.

Hydroelectric

Project income for the three months ended March 31, 2021 decreased $5.0 million from the comparable 2020 period primarily due to:

●

decreased project income of $5.4 million at Curtis Palmer primarily due to lower water flows than in 2020.

Corporate

Project income for the three months ended March 31, 2021 increased $7.1 million from the comparable 2020 period primarily due to a $6.8 million increase in the fair value of interest rate swap agreements related to the Term 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.

Administration

Administration expense for the three months ended March 31, 2021 increased by $7.4 million to $14.1 million in the three months ended March 31, 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 March 31, 2021 did not change materially from the three months ended March 31, 2020.

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Foreign exchange loss (gain)

Foreign exchange gain decreased by $23.8 million to a $3.2 million loss in the three months ended March 31, 2021 from a $20.6 million gain in the comparable 2020 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and Series E Debentures). The Canadian dollar appreciated 1.2% against the U.S. dollar from December 31, 2020 to March 31, 2021, as compared to a 9.2% depreciation in the comparable 2020 period.

Other (income) expense, net

Other (income) expense, net for the three months ended March 31, 2021 increased by $2.7 million from other expense, net of $2.6 million primarily due to a $2.8 million change in the fair value of the conversion option of the Series E Debentures.

Income tax expense

Project Operating Performance

Two of the primary metrics we utilize to measure the operating performance of our projects are generation and availability. Generation measures the net output of our proportionate project ownership percentage in megawatt hours (“MWh”). Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority of our projects were able to achieve their respective capacity payments. For projects where reduced availability adversely impacted capacity payments, the impact was not material for the three months ended March 31, 2021, with the exception of the Cadillac project. While the reduction in availability at the Cadillac project impacted capacity payments for the period ended March 31, 2021, we recovered these capacity payments through the business interruption insurance recoveries recorded during the year ended December 31, 2020. The terms of our PPAs provide for certain levels of planned and unplanned outages. All references below are denominated in net Gigawatt hours (“net GWh”).

Generation


	Generation
	Three months ended March 31,
			% change
(in Net GWh)	2021	2020	2021 vs. 2020
Segment
Solid Fuel	466.6	423.1	10.3	%
Natural Gas	439.9	581.7	(24.4)	%
Hydroelectric	122.1	172.5	(29.2)	%
Total	1,028.6	1,177.3	(12.6)	%

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Aggregate power generation for the three months ended March 31, 2021 decreased 12.6% from the comparable 2019 period primarily due to:

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●

decreased generation in the Hydroelectric segment, primarily due to a 46.1 net GWh decrease at Curtis Palmer as a result of lower water flows than in 2020; and

●

decreased generation in the Natural Gas segment, primarily due to a 90.0 net GWh decrease in generation at Frederickson due to lower dispatch than the comparable 2020 period, a 35.3 net GWh decrease in generation at Oxnard under the new RA contract, effective from January 2021 through December 2021, as the project runs only when it is called upon to operate, and a 15.9 net GWh decrease in generation at Manchief primarily due to an outage in February 2021.

These decreases in generation were partially offset by:

●

increased generation in the Solid Fuel segment, primarily due to a 34.1 net GWh increase in generation at Cadillac. The project was non-operational through August 20, 2020 due to the extended outage following the fire at the plant in September 2019.

Availability


	Availability
	Three months ended March 31,
					% change
	2021		2020		2021 vs. 2020
Segment
Solid Fuel	91.3	%	83.6	%	7.7	%
Natural Gas	94.3	%	96.0	%	(1.7)	%
Hydroelectric	98.3	%	71.6	%	26.7	%
Weighted average	94.6	%	86.8	%	7.8	%

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Aggregate power availability for the three months ended March 31, 2021 increased 7.8% from the comparable 2019 period primarily due to:

●

increased availability in the Hydroelectric segment, primarily due to forced outages at Moresby Lake and Koma Kulshan in the comparable 2020 period; and

●

increased availability in the Solid Fuel segment, primarily due to the fire at Cadillac in September 2019. The project was non-operational through August 20, 2020 due to the extended outage.

These increases in availability were partially offset by:

●

decreased availability in the Natural Gas segment, primarily due to an outage at Manchief in the current quarterly period.

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Supplementary Non-GAAP Financial Information

The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization, impairment charges, insurance loss (gain), other (income) expenses and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We believe that Project Adjusted EBITDA is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project Adjusted EBITDA is Project income. A reconciliation of Net income (loss) to Project income and to Project Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity method investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.

Project Adjusted EBITDA


	March 31,				$ change
	2021		2020		2021 vs 2020
Net income	$	1.6	$	23.7	$	(22.1)
Income tax expense		2.2		1.5		0.7
Income from operations before income taxes		3.8		25.2		(21.4)
Administration		14.1		6.7		7.4
Interest expense, net		11.4		10.8		0.6
Foreign exchange loss (gain)		3.2		(20.6)		23.8
Other (income) expense, net		(0.1)		2.6		(2.7)
Project income	$	32.4	$	24.7	$	7.7
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization		18.6		19.8		(1.2)
Interest expense, net		0.6		0.7		(0.1)
Change in the fair value of derivative instruments		(3.2)		5.6		(8.8)
Other (income) expense, net		(0.2)		—		(0.2)
Project Adjusted EBITDA	$	48.2	$	50.8	$	(2.6)
Project Adjusted EBITDA by segment
Solid Fuel		9.7		7.8		1.9
Natural Gas		28.7		28.2		0.5
Hydroelectric		10.3		15.3		(5.0)
Corporate		(0.5)		(0.5)		—
Total	$	48.2	$	50.8	$	(2.6)

Solid Fuel

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


	Three months ended March 31,
					% change
	2021		2020		2021 vs. 2020
Solid Fuel
Project Adjusted EBITDA	$	9.7	$	7.8	24	%

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Project Adjusted EBITDA for the three months ended March 31, 2021 increased $1.9 million from the comparable 2020 period primarily due to increased Project Adjusted EBITDA of:

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●

$3.1 million at Cadillac, which was non-operational from September 2019 to August 20, 2020 due to a fire at the project.

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

●

$1.6 million at Allendale and Dorchester primarily due to maintenance outages in March 2021.

Natural Gas

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


	Three months ended March 31,
					% change
	2021		2020		2021 vs 2020
Natural Gas
Project Adjusted EBITDA	$	28.7	$	28.2	2	%

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Project Adjusted EBITDA for the three months ended March 31, 2021 increased $0.5 million from the comparable 2020 period primarily due to increased Project Adjusted EBITDA of:

●

$1.5 million at Oxnard primarily due to the project’s new RA contract that became effective in January 2021 under which the project receives a fixed monthly capacity payment and lower maintenance expense than in the comparable 2020 period.

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

●

$1.4 million at Manchief primarily due to a forced outage in February 2021.

Hydroelectric

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


	Three months ended March 31,
					% change
	2021		2020		2021 vs. 2020
Hydroelectric
Project Adjusted EBITDA	$	10.3	$	15.3	(33)	%

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Project Adjusted EBITDA for the three months ended March 31, 2021 decreased $5.0 million from the comparable 2020 period primarily due to decreased Project Adjusted EBITDA of:

●

$5.4 million at Curtis Palmer primarily due to lower water flows than in 2020.

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Corporate

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


	Three months ended March 31,
					% change
	2021		2020		2021 vs. 2020
Corporate
Project Adjusted EBITDA	$	(0.5)	$	(0.5)	NM

Three months ended March 31, 2021 compared with three months ended March 31, 2020

Project Adjusted EBITDA for the three months ended March 31, 2021 did not change materially from the comparable 2020 period.

Liquidity and Capital Resources


	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	21.6	$	38.8
Restricted cash		6.9		7.1
Total		28.5		45.9
Revolving credit facility availability		98.8		102.9
Total liquidity	$	127.3	$	148.8

Overview

Our primary sources of liquidity are distributions from our projects and availability under our Revolver. Our liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from September 2021 (Kenilworth) to November 2043 (Allendale). Kenilworth is currently the only project operating under a PPA with an expiration date in 2021. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA, at all, or the price received by the project for power under subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project distributions and the cash available for further debt reduction, identification of and investment in accretive growth opportunities (both internal and external), to the extent available, and other allocation of available cash. See “Risk Factors—Risks Related to Our Financial Position and Economic and Financial Market Conditions —We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities” in our Annual Report on Form 10-K for the year ended December 31, 2020.

Consolidated Cash Flow Discussion

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


	Three months ended
	March 31,
	2021		2020		Change
Net cash provided by operating activities	$	8.4	$	8.4	$	—
Net cash provided by (used in) investing activities		0.2		(2.6)		2.8
Net cash used in financing activities		(26.0)		(40.1)		14.1

Operating Activities

Cash flow from our projects may vary from period to period based on working capital requirements and the operating performance of the projects, as well as changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, and the transition to merchant or re-contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of

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distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

For the three months ended March 31, 2021, cash provided by operating activities did not change materially from the comparable 2020 period.

Investing Activities

For the three months ended March 31, 2021, the net decrease in cash used in investing activities of $2.8 million was primarily the result of the following:

●

Capitalized plant additions – capitalized plant additions were $9.7 million lower in the three months ended March 31, 2021 than the comparable 2020 period, primarily due to repairs at Cadillac performed during 2020; and

●

Insurance proceeds – insurance recoveries related to the Cadillac fire were $7.4 million lower than the comparable 2020 period.

Financing Activities

For the three months ended March 31, 2021, the net decrease in cash used in financing activities of $14.1 million was primarily the result of the following:

●

Common share repurchases – we paid $8.2 million to repurchase and cancel common shares in the comparable 2020 period;

●

Preferred share repurchases – we paid $6.4 million to repurchase and cancel preferred shares in the comparable 2020 period; and

●

Deferred financing costs – we incurred $1.6 million of deferred financing costs related to amending the Term Loan and the Revolver in the in the comparable 2020 period.

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

●

Corporate and project-level debt repayments – we made $2.1 million greater principal payments than in the comparable 2020 period.

Corporate Debt

The following table summarizes the maturities of our corporate debt at March 31, 2021:


				Remaining
	Maturity	Interest		Principal
	Date	Rates		Repayments		2021		2022		2023		2024		2025		Thereafter
Senior secured term loan facility⁽¹⁾	April 2025	4.42	%	$	284.5	$	70.0	$	106.0	$	60.0	$	36.0	$	12.5	$	—
MTNs	June 2036	5.95	%		167.0		—		—		—		—		—		167.0
Convertible Debenture	January 2025	6.00	%		91.4		—		—		—		—		91.4		—
Total Corporate Debt				$	542.9	$	70.0	$	106.0	$	60.0	$	36.0	$	103.9	$	167.0

(1)

The Term Loan Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the Term Loan Facility and the 5.95% MTNs, letters of credit costs to meet the requirements of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Term Loan Facility, and payment on the preferred equity issued by APPEL, a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of the Term Loan Facility outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Note that failing to meet the mandatory amortization requirements is not an event of default, but could result in APLP Holdings being unable to make

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distributions to Atlantic Power Corporation and APPEL being unable to pay dividends to its shareholders. The amortization profile in the table above is based on principal payments according to the targeted principal amount described in (ii) above through 2022 based on the schedule as amended in January 2020. After 2022, the amortization profile is based on (i) above and is an estimate, subject to change. See Note 6, Long-term debt for more information on our credit facilities.

Project-Level Debt

Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue-generating contracts of the projects. The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at March 31, 2021. Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. At March 31, 2021, all of our projects were in compliance with the covenants contained in project-level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but are not callable or subject to acceleration under the terms of their debt agreements.

The range of interest rates presented represents the rates in effect at March 31, 2021. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.


							Total
							Remaining
	Maturity	Range of					Principal
	Date	Interest Rates					Repayments		2021		2022		2023		2024		2025		Thereafter
Consolidated Projects:
Cadillac	August 2025	6.26	%	-	6.38	%	$	14.1	$	2.0	$	3.3	$	3.3	$	3.7	$	1.8	$	—
Total Consolidated Projects								14.1		2.0		3.3		3.3		3.7		1.8		—
Equity Method Projects:
Chambers⁽¹⁾	December 2023	5.00	%					30.5		8.8		10.1		11.6		—		—		—
Total Equity Method Projects								30.5		8.8		10.1		11.6		—		—		—
Total Project-Level Debt							$	44.6	$	10.8	$	13.4	$	14.9	$	3.7	$	1.8	$	—

(1)	The above table does not include our $0.6 million proportionate share of issuance premiums.

Uses of Liquidity

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

Capital and Maintenance Expenditures

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

We expect to reinvest approximately $40.0 million in 2021 (of which $6.4 million was reinvested in the three months ended March 31, 2021) in our portfolio in the form of maintenance expenses and project capital expenditures. As explained above, these investments are generally paid at the project level. See “Liquidity and Capital Resources—Capital and Maintenance Expenditures” in our Annual Report on Form 10-K for the year ended December 31, 2020. We believe one of the benefits of our diverse fleet is that plant overhauls and other major expenditures do not occur in the same year for each facility. Recognized industry guidelines and original equipment manufacturer recommendations provide a source of data to assess maintenance needs. In addition, we utilize predictive and risk-based analysis to refine our expectations, prioritize our spending and balance the funding requirements necessary for these expenditures over

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time. Future capital expenditures and maintenance expenses may exceed the projected 2021 level as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

Recently Adopted and Recently Issued Accounting Guidance

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a “smaller reporting company,” as defined in Rule 12b-2 of the Exchange Act, we are electing scaled disclosure reporting obligations and are therefore not required to provide the information called for by this item.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the three months ended March 31, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations of Disclosure Controls and Internal Control over Financial Reporting

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

ITEM 1A. RISK FACTORS

During the quarter ended March 31, 2021, there have been no material changes from the risk factors previously set forth in “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2020.

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

Share Repurchase Program

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purchase. Common share purchases under the NCIBs may also be made on the New York Stock Exchange (“NYSE”) in compliance with Rule 10b-18 under the Exchange Act, or other designated exchanges and published marketplaces in the United States in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval. As of March 31, 2021, we have not made any repurchases under the new NCIBs due to the Transaction. In the event the Transaction does not close, the Company will review its approach on capital allocation.

The Board authorization permits the Company to repurchase common and preferred shares and Convertible Debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our Convertible Debentures and our APPEL preferred shares through open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs, issuer self tenders or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account our then current cash position and then anticipated cash obligations or business opportunities.

Atlantic Power Corporation and affiliated purchasers did not make any repurchases of common equity securities, convertible debentures or preferred shares during the period of January 1, 2021 through March 31, 2021.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

HIDDEN_ROW
Exhibit No.				Description
2.1				Arrangement Agreement dated as of January 14, 2021, among the Company, APPEL and the Purchasers (incorporated by reference to the Company’s Current Report on Form 8-K dated January 15, 2021)
2.2				Second Amendment to Arrangement Agreement dated April 29, 2021, among the Company, APPEL and the Purchasers (incorporated by reference to the Company’s Current Report on Form 8-K dated April 29, 2021)
10.1				Consulting Agreement dated as of January 14, 2021, between Jeffrey S. Levy and the Company (incorporated by reference to the Company’s Current Report on Form 8-K dated January 15, 2021).
31.1*				Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
31.2*				Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
32.1**				Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**				Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1				Amendment to Arrangement Agreement and Plan of Arrangement, dated April 1, 2021 (incorporated by reference to Current Report on Form 8-K dated March 31, 2021).
101.INS*				XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*				Inline XBRL Taxonomy Extension Schema
101.CAL*				Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF*				Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB*				Inline XBRL Taxonomy Extension Label Linkbase
101.PRE* Exhibit 104				Inline XBRL Taxonomy Extension Presentation Linkbase Cover Page Interactive Data File––the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

*	Filed herewith.

**	Furnished herewith.

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SIGNATURES

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


Date: May 6, 2021	Atlantic Power Corporation


	By:	/s/ Terrence Ronan
		Name:	Terrence Ronan
		Title:	Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

Three Months Ended March 31,

Share-based compensation

Convertible debentures