TABLE OF CONTENTS

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PART I

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As used herein, the terms “Atlantic Power,” the “Company,” “we,” “our,” and “us” refer to Atlantic Power Corporation, together with those entities owned or controlled by Atlantic Power Corporation, unless the context indicates otherwise. All 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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 and Canadian securities laws. 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 Annual Report on Form 10-K include, but are not limited to, statements with respect to the following:

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Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Annual Report on Form 10-K. 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.

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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 this Annual Report on Form 10-K. Our business is both highly competitive and subject to various risks.

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

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In addition, risks include, without limitation:

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Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include, without limitation, third-party projections of regional fuel and electric capacity and energy prices based on assumptions about future economic conditions and courses of action, the general conditions of the markets in which the Company operates, revenues, internal and external growth opportunities, the Company’s ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. Although the forward-looking statements contained in this Annual Report on Form 10-K 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 Annual Report on Form 10-K 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 Annual Report on Form 10-K. These forward-looking statements are made as of the date of this Annual Report on Form 10-K and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

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PROPOSED TRANSACTION WITH I SQUARED CAPITAL

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On January 14, 2021, Atlantic Power entered into a definitive agreement (the “Arrangement Agreement”) with Atlantic Power Preferred Equity Ltd. (“APPEL”) Atlantic Power Limited Partnership (“APLP”), Tidal Power Holdings Limited and Tidal Power Aggregator, LP (together with Tidal Power Holdings Limited, the “Purchasers”). The Purchasers were formed solely for the purpose of effecting the transactions contemplated by the Arrangement Agreement (the “Transaction”), and are currently owned and controlled by funds affiliated with I Squared Capital, a private equity investment group.

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In connection with the Transaction:

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The acquisition of Atlantic Power's outstanding common shares and the redemption of the outstanding preferred shares of APPEL would be completed by way of a plan of arrangement (the “Arrangement”) under the Business Corporations Act (British Columbia). In connection with the Arrangement, Atlantic Power's shareholder rights plan would be terminated and all rights to purchase Atlantic Power's common shares issued pursuant to the shareholder rights plan would be cancelled.

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The Arrangement Agreement

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The Arrangement Agreement provides that the Transaction is subject to a number of closing conditions, including court approval of the Arrangement, regulatory approvals (including under the Competition Act (Canada), which approval was obtained by the parties on February 2, 2021, and the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the Communications Act of 1934, as amended, and the Federal Power Act, as amended), as well as the receipt of certain third-party consents.

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The Transaction is also conditional on the approval of two-thirds of the votes cast by holders of Atlantic Power's common shares voting in person or by proxy at a special meeting of Atlantic Power's common shareholders and the approval of two-thirds of the votes cast by holders of APPEL’s preferred shares (voting as a single class) in person or by proxy at a meeting of APPEL’s preferred shareholders in respect of both the Arrangement and the proposed continuance of APPEL under the laws of British Columbia. The Transaction must also be approved by a majority of the votes cast at the special meeting of Atlantic Power’s common shareholders, excluding votes attached to common shares held by persons described in items (a) through (d) of Section 8.1(2) of Multilateral Instrument 61-101 Protection of Minority Security Holders in Special Transactions.

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In addition, the Transaction is conditional upon the approval of the holders of the convertible debentures and the MTNs, respectively (in each case either by way of votes of the holders of the convertible debentures and the MTNs holding at least two-thirds of the principal amount of the convertible debentures and the MTNs, respectively, voted in person or by proxy at separate meetings of the holders of the convertible debentures and the MTNs or by way of separate written consents of the holders of the convertible debentures and the MTNs holding not less than two-thirds of the principal amount of convertible debentures and MTNs outstanding, as applicable), of certain amendments to the trust indentures governing such securities, including to provide for the mandatory conversion of the convertible debentures into common shares; the addition of a redemption obligation of Atlantic Power, conditional on the closing of the Transaction, to redeem all outstanding MTNs for consideration equal to 106.701% of the principal amount of such MTNs; and the modification of the redemption notice period as to the MTNs. Atlantic Power and APLP will seek the approval of the holders of the convertible debentures and MTNs by way of separate meetings and/or consent solicitations.

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A bondholder representing approximately 66% of the principal amount of MTNs and approximately 19% of the principal amount of convertible debentures outstanding has agreed to vote in favor of or otherwise consent to amendments to the trust indentures governing those securities.

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The Arrangement Agreement is subject to customary non-solicitation provisions, including Atlantic Power's right to consider and accept unsolicited superior proposals in certain circumstances, subject to a right to match in favor of the Purchasers. A termination fee of $12.5 million will be payable by Atlantic Power to the Purchasers should the Transaction not close under certain circumstances, including if the Arrangement is not completed as a result of Atlantic Power accepting an unsolicited superior proposal. A reverse termination fee of $15 million will be payable by the Purchasers to Atlantic Power should the Transaction not close as a result of an uncured breach by the Purchasers of the Arrangement Agreement (provided Atlantic Power is not then in breach of the Arrangement Agreement).

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Additional Information

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Atlantic Power has filed a final proxy statement on Form DEF 14A with the United States Securities and Exchange Commission (the “SEC”) in connection with the proposed Arrangement Agreement. This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. WE URGE INVESTORS TO READ THE PROXY STATEMENTS AND ANY OTHER DOCUMENTS TO BE FILED WITH THE SEC IN CONNECTION WITH THE ARRANGEMENT AGREEMENT OR INCORPORATED BY REFERENCE IN THE PROXY STATEMENT BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION.

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Investors may obtain (when available) these documents free of charge at the SEC’s Web site (www.sec.gov). In addition, these documents are available 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. The proxy statement is not incorporated by reference in this Annual Report on Form 10-K and should not be considered a part of the Annual Report.

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Atlantic Power, APPEL, APLP, their directors, and executive officers and other members of management and employees may be considered participants in the solicitation of proxies in connection with the Arrangement Agreement. Information regarding the participants in the proxy solicitation of Atlantic Power and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the proxy statement and other relevant materials to be filed with the SEC.

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BUSINESS STRATEGY

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This section describes our business strategy without regards to potential effects of the Transaction except where stated otherwise.

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Our primary business is the acquisition, operation and ownership of power plants in the United States and Canada. The power generation business is cyclical, capital-intensive, heavily regulated and commodity-priced. In executing our strategy, we are focused on the following priorities:

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ASSET MANAGEMENT

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Our asset management strategy is to manage our physical assets and commercial relationships with the goal of increasing shareholder value. We proactively seek scale opportunities and to establish best practices that result in EBITDA and cash flow growth across all of our twenty-one operating plants. Our asset management group works to ensure that our projects receive appropriate preventative and corrective maintenance and incur capital expenditures to provide for their safety, efficiency, availability, flexibility, longevity, and growth in EBITDA contribution. We also proactively look for opportunities to optimize power purchase, fuel supply, long-term service and other agreements to deliver strong and predictable financial performance. The teams at each of the businesses have extensive experience in managing, operating and maintaining the assets.

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For operations and maintenance services at the five projects in our portfolio which we do not operate, we partner with experienced operators in the independent power business. Examples of our third-party operators include CMS, Heorot and Purenergy, which are experienced, well regarded energy infrastructure management services companies. In addition, employees of Atlantic Power with significant experience managing similar assets are involved in all significant decisions with the objective of proactively identifying value-creating opportunities such as contract renewals or restructurings, asset-level refinancings, add-on acquisitions, divestitures and participation at partnership meetings and calls.

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INDUSTRY AND COMPETITION

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The electric power industry is one of the largest industries in the United States, generating annualized retail electricity sales of approximately $400 billion, based on information published by the Energy Information Administration. A significant portion of the power produced in the United States and Canada is generated by non-utility generators. According to the Energy Information Administration, independent power producers represented approximately 42% of total net generation in 2020. Independent power producers sell the electricity that they generate to electric utilities and other load-serving entities (such as municipalities and electric cooperatives) by way of bilateral contracts or open power exchanges. The electric utilities and other load-serving entities, in turn, generally sell this electricity to industrial, commercial and residential customers. In the independent power generation sector, electricity is generated from a number of energy sources, including natural gas, coal, water, waste products such as biomass (e.g., wood, wood waste, agricultural waste), landfill gas, geothermal, solar and wind. All of our plants are non-utility electric generating facilities in the North American electrical power generation industry.

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The power generation industry is characterized by intense competition, and we compete with utilities, industrial companies, yieldcos and other independent power producers. Historically low crude oil and natural gas prices as well as

decreased rates of demand growth have contributed to reduced capacity and energy prices and increasing competition among generators to obtain power sales agreements. We also compete for acquisition and joint-venture opportunities with numerous private equity, infrastructure and pension funds, Canadian and U.S. independent power firms, utility non-regulated subsidiaries and other strategic and financial players.

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Our competitive strengths

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We believe we have the following competitive strengths:

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OUR ORGANIZATION AND SEGMENTS

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The following tables outline by segment our portfolio of power generating assets in operation as of December 31, 2020, including our interest in each facility. We believe our portfolio is well diversified in terms of electricity and steam customers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.

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We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management's structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for prior periods has been revised to conform to the new segment presentation. The segment classified as Corporate (formally Un-Allocated Corporate) includes activities that support the executive and administrative offices, capital structure and costs of being a public registrant. These costs are not allocated to the operating segments when determining segment profit or loss. We have previously reported our segments on a geographic basis, and consequently the segment information presented herein is significantly different than previous presentations of segment information.

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The sections below provide descriptions of our projects as they are aligned in our segment reporting structure for financial reporting purposes.

matters, including greenhouse gas emissions and green building standards, are subject to federal, provincial and municipal regulation.

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Generating projects

United States

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Thirteen of our power generating projects are QFs under the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”), and FERC regulations. A QF falls into one or both of two primary classes, both of which would facilitate one of PURPA’s goals to more efficiently use fossil fuels to generate electricity than typical utility plants. The first class of QFs includes energy producers that generate power using renewable energy sources such as wind, solar, geothermal, hydro, biomass or waste fuels. The second class of QFs includes cogeneration facilities, which must meet specific fossil fuel efficiency requirements by producing both electricity and steam versus electricity only.

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The generating projects with QF status are currently party to a PPA with a utility or have been granted authority to charge market-based rates or are exempt from FERC rate-making authority. The FERC has granted thirteen of the projects the authority to charge market-based rates based primarily on a finding that the projects lack market power. The projects with QF status are also exempt from state regulation respecting the rates of electric utilities and the financial or organizational regulation of electric utilities. However, state regulators may review the prudency of utilities entering into PPAs with QFs and the siting of the generation facilities. The majority of our generation is sold by QFs under PPAs that required approval by state authorities.

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PURPA, as initially implemented by the FERC, generally required that vertically integrated electric utilities purchase power from QFs at their avoided costs. The Energy Policy Act of 2005 (the “EP Act of 2005”), however, established new limits on PURPA’s requirement that electric utilities buy electricity from QFs to certain markets that lack competitive characteristics. The projects with EWG status are also exempt from state regulation respecting the rates of electric utilities.

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Notwithstanding their status as QFs and EWGs, our projects remain subject to various aspects of FERC regulation, including those relating to power marketer status and to oversight of mergers, acquisitions and investments relating to utilities under the Federal Power Act, as amended by the EP Act of 2005. Nine of our projects are also subject to reliability standards developed and enforced by the North American Electric Reliability Corporation (“NERC”). NERC is a not-for-profit regulatory authority whose mission is to assure the reliability and security of the bulk power system in North America.

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Pursuant to its authority, NERC has issued, and the FERC has approved, a series of mandatory reliability standards. Users, owners and operators of the bulk power system can be penalized significantly for failing to comply with the FERC-approved reliability standards. We have designated our Manager of Operational and Regulatory Compliance to oversee compliance with reliability standards and an outside law firm specializing in this area advises us on FERC and NERC compliance, including annual compliance training for relevant employees.

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British Columbia, Canada

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The vast majority of British Columbia’s power is generated or procured by BC Hydro, which is one of the largest electric utilities in Canada. BC Hydro is owned by the Province of British Columbia and is regulated by the British Columbia Utilities Commission (the “BCUC”), which is governed by the Utilities Commission Act (British Columbia) (the “UCA”). The BCUC is also responsible for the regulation of British Columbia’s public energy utilities including publicly-owned and investor-owned utilities (i.e., independent power producers).

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BC Hydro is generally required to acquire all new power (beyond what it already generates from existing BC Hydro plants) from independent power producers.

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All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed with and approved by the BCUC. In making its determination, the BCUC will examine whether the contract is

in the public interest. The BCUC may hold a hearing in this regard. Furthermore, the BCUC may make rules governing conditions to be contained in agreements entered into by public utilities for electricity.

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Pursuant to the UCA, the BCUC has adopted the standards developed by the NERC and the Western Electricity Coordinating Council (“WECC”) in respect to all generators of electricity in British Columbia, including independent power producers. As a practical matter, the BCUC appointed WECC as Administrator to assist the BCUC in carrying out the registration of parties and compliance monitoring.

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The Clean Energy Act (the “Clean Energy Act”), which became law in 2010, sets out British Columbia’s energy objectives. The Clean Energy Act states, among other things, that British Columbia aims to accelerate and expand the development of clean and renewable energy sources in British Columbia to, among other things, promote economic development and job creation and continue to work toward the reduction of greenhouse gas emissions. The legislation also explicitly states that British Columbia will encourage the use of waste heat, biogas and biomass to reduce waste. Clean Energy Production in B.C.: An Inter-Agency Guidebook for Project Development, which was released by the provincial government in 2016, is consistent with the Clean Energy Act and favors clean and renewable energy sources such as waterpower, windpower and ocean energy generation.

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Other provincial regulators in British Columbia having authority over independent power producers include Technical Safety BC, the Ministry of Environment and Climate Change Strategy, and the Ministry of Energy, Mines and Low Carbon Innovation.

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Ontario, Canada

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In Ontario, the Ontario Energy Board (“OEB”) is an administrative tribunal with overall responsibility for the regulation and supervision of the natural gas and electricity industries in Ontario and with the authority to grant or renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects.

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No person is permitted to own or operate large or medium-scale electricity generation facilities in Ontario without a license from the OEB.

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The OEB’s general functions include:

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The OEB has the authority effectively to modify licenses by adopting “codes” that are deemed to form part of the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result in administrative monetary penalties of up to Cdn$1 million per day of violation, license revocation and other consequences. While the OEB provides reports to the Ontario Minister of Energy, Northern Development and Mines, it generally operates independently from the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives. The law implemented by the OEB has been the subject of relatively frequent change, which has contributed to regulatory uncertainty.

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A number of other regulators and quasi-governmental entities play a role in electricity regulation in Ontario,

including the Independent Electricity System Operator (“IESO”), Hydro One, the Electrical Safety Authority (“ESA”) and the Ontario Electricity Financial Corporation (“OEFC”).

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In 1998, the Legislative Assembly of Ontario passed the Energy Competition Act of 1998, which authorized the establishment of a market in electricity, and reorganized Ontario Hydro into five companies: Ontario Power Generation Inc. (“OPG”), the Ontario Hydro Services Company (later renamed Hydro One), the Independent Electricity Market Operator (later renamed the IESO), the ESA, and OEFC. The two commercial companies, Ontario Power Generation Inc. and Hydro One, were intended to eventually operate as private businesses rather than as crown corporations. The Province currently owns slightly less than half of the equity of Hydro One Inc., a publicly traded corporation. Hydro One has been the subject of intervention by the Province of Ontario, including pressuring the retirement of its former chief executive officer and resignation of its entire board of directors.

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The IESO is responsible for administering the wholesale electricity market and controlling Ontario’s transmission grid. The IESO is a non-profit corporation. Its directors are appointed by the government of Ontario. The IESO’s “Market Rules” form the regulatory framework for the operation of Ontario’s transmission grid and electricity market. The Market Rules require, among other things, that generators meet certain equipment and performance standards and certain system reliability obligations. The IESO may enforce the Market Rules by imposing financial penalties. The IESO may also terminate, suspend or restrict participatory rights, and has an enforcement arm.

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In November 2006, the IESO entered into a memorandum of understanding with NERC, in which it recognized NERC as the “electricity reliability organization” in Ontario. In addition, the IESO has also entered into a similar MOU with both the Northeast Power Coordinating Council (the “NPCC”) and NERC. The IESO is accountable to NERC and NPCC for compliance with NERC and NPCC reliability standards. Although the IESO may impose Ontario-specific reliability standards, such standards must be consistent with, and at least as stringent as, NERC’s and NPCC’s standards. Effective July 1, 2016, the IESO changed the definition of what generating facilities are considered part of the Bulk Electric System (“BES”). Any new facility grouped into the BES, which includes all Ontario sites except Kapuskasing, will have to comply with all NERC reliability standards in effect in Ontario. As of January 1, 2015, the IESO is responsible for procuring new electricity generation. As a result, the IESO enters into electricity generation contracts with electricity generators in Ontario from time to time. The IESO also administers the Ontario Reliability Compliance Program, working with various market participants to ensure they understand and adhere to their obligations to comply with NERC standards and NPCC criteria.

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Although the Green Energy Act became law in Ontario in 2009 for renewable electricity generation technologies, including via a feed-in tariff program, this statute was repealed as of January 1, 2019 with the introduction and proclamation of the Green Energy Repeal Act, 2018. This Act amended provisions of the Electricity Act, 1998, as well as the Environmental Protection Act, and the Planning Act, among others. In particular, amendments to the Environmental Protection Act now provide that, absent a demonstrated demand for the electricity that would be generated by a given renewable energy project, the provincial government is empowered to prohibit the issuance or renewal of energy approvals for any such project. Amendments to the Planning Act now stipulate that there is no appeal route in respect of any refusal or failure to adopt an amendment authorizing a renewable energy undertaking, except by the Minister. Further amendments provide that there is now no appeal route in respect of all or any part of an application for amendment to a by-law if the amendment proposes to permit a renewable energy undertaking, except by the Minister. The provincial government has stated that the repeal of the Green Energy Act will empower individual municipalities to make planning decisions related to the development of new energy projects. In July of 2018, the provincial government cancelled hundreds of renewable energy contracts in the province. In the related Minister’s Directive, the Minister noted that the IESO’s recent system planning work “indicates that Ontario’s current contracted and rate regulated electricity resources are sufficient to satisfy or exceed forecasted provincial needs for the near term and that there are other means of meeting future energy supply and capacity needs at materially lower costs than long-term contracts that lock in the prices paid for these resources.”

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Carbon emissions

United States – regional and state

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In the United States, during the past several years government actions addressing carbon emissions have occurred primarily at the regional and state levels. Beginning in 2009, the Regional Greenhouse Gas Initiative (“RGGI”) was established by certain Northeast and Mid-Atlantic states as the first cap-and-trade program in the United States for CO₂ emissions. CO₂ allowances are now a tradable commodity in the RGGI states. The nine states currently participating in RGGI have varied implementation plans and schedules. RGGI implemented a new, reduced CO₂ cap in 2014, with further reductions of 2.5% each year from 2015 to 2020. On January 1, 2020, New Jersey rejoined RGGI after withdrawing from the compact in 2012. Our Chambers project operates in the state of New Jersey and is subject to RGGI. However, its PPA is grandfathered to provide some cost mitigation under the law. California’s cap-and-trade program governing greenhouse gas emissions became effective for the electricity sector on January 1, 2013. California, along with British Columbia, Nova Scotia and Quebec, is part of the Western Climate Initiative, which supports the implementation of state and provincial greenhouse gas emissions trading programs. Other states and regions in the United States have considered similar regulations, and it is possible that federal climate legislation will be established in the future.

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In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of greenhouse gases. The two laws are more commonly known as AB 32 (the Global Warming Solutions Act) and SB 1368. In 2016, California enacted SB 32, which expanded the requirements of AB 32. Under AB 32 and SB 32, the California Air Resources Board (the “CARB”) is required to adopt a greenhouse gas emissions cap on all major sources (not limited to the electric sector) to achieve goals of reaching (i) 1990 greenhouse gas emissions levels by the year 2020, (ii) 40% below 1990 levels by 2030, and (iii) 80% below 1990 emissions levels by 2050. Under the CARB regulations that took effect on January 1, 2013, electricity generators and certain other facilities are now subject to an allowance for greenhouse gas emissions, with allowances allocated by both formulas set by the CARB and auctions.

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SB 1368 added the requirement that the California Energy Commission, in consultation with the California Public Utilities Commission (the “CPUC”) and the CARB, establish greenhouse gas emission performance standards and implement regulations for PPAs with a term of five or more years entered into prospectively by publicly owned electric utilities. The legislation directs the California Energy Commission to establish the performance standard as one not exceeding the rate of greenhouse gas emitted per megawatt hour (“MWh”) associated with combined-cycle, gas turbine baseload generation.

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United States – Federal

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Over the past several years, the U.S. Environmental Protection Agency (the “EPA”) has taken a number of actions respecting CO₂ emissions. The EPA’s actions include its December 2009 finding of “endangerment” to public health and welfare from greenhouse gases, its issuance in September 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule which required large sources, including power plants, to monitor and report greenhouse gas emissions to the EPA annually beginning in 2011, and its issuance in May 2010 of its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which under a phased-in approach requires large industrial facilities, including power plants, to obtain permits to emit, and to use best available control technology to curb emissions of, greenhouse gases. In addition, in August 2015, the EPA issued its final rule regulating carbon emissions from existing electric generating units, which is referred to as the Clean Power Plan (the “CPP”). As a result of judicial challenge, however, the CPP was not implemented. In June 2019, the EPA issued the final Affordable Clean Energy Rule (“ACE”), which repealed the CPP and established emissions guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. In January 2021, the D.C. Circuit Court of Appeals vacated and remanded ACE. Provided the Supreme Court does not decide to take up the case, the Biden Administration’s EPA will be able to focus on constructing a replacement.

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In January 2021, the Biden Administration signed multiple executive orders related to the climate and environment. These executive orders direct federal agencies to review and reverse more than 100 Trump Administration actions on the environment, instruct the Director of National Intelligence to prepare a national intelligence estimate on the security implications of the climate crisis and direct all agencies to develop strategies for integrating climate considerations into their international work, establish the National Climate Task Force which assembles leaders from across 21 federal agencies and departments, commit to environmental justice and new, clean infrastructure projects, kick off development of emissions reduction target and establish the special presidential envoy for climate on the National

Security Council. At this time, we cannot predict the outcome of any of these executive actions or any legal challenges to these actions.

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Canada - Federal

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In Canada, the federal government has implemented greenhouse gas reporting regulations and is developing additional programs to address greenhouse gas emissions. Under the 2004 federal Greenhouse Gas Emissions Reporting Program (“GHGRP”), all facilities which emit 50,000 tonnes or more of carbon dioxide equivalent (“CO₂eq”) per year are required to submit reports on their emissions to Environment Canada.

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On October 3, 2016, the Government of Canada announced its proposed pan-Canadian approach for the pricing of carbon pollution. On January 15, 2018, the Government of Canada released the draft Greenhouse Gas Pollution Pricing Act, consisting of two mechanisms: (1) a regulatory charge on fuels, and (2) an emissions trading system referred to as the Output-Based Pricing System (“OBPS”). These mechanisms establish a backstop carbon price in provinces that have not implemented, by January 1, 2019, a carbon pricing system that the federal government has determined complies with its carbon pricing requirements. Other policy documents accompanying the Act also included a proposed design of rules to enhance market liquidity. In May 2018, the federal Government published “Carbon pricing: compliance options under the federal output-based pricing system,” a document that describes the proposed rules, and on June 21, 2018 the Greenhouse Gas Pollution Pricing Act went into effect. Since that time the federal government has published several regulations, including the Fuel Charge Regulations and the Output-Based Pricing System Regulations to implement both mechanisms.

British Columbia and Québec have compliant carbon pricing systems in place and are not expected to be subject to the federal backstop regime. Alberta is exempt from parts of the federal backstop regime. Beginning on January 1, 2020, the federal backstop regime imposed a minimum Cdn$30/tonne of CO₂e (“tCO₂e”) carbon price for greenhouse gases that exceed a prescribed emissions limit set out in the Output-Based Pricing System Regulations, increasing by Cdn$10 increments each following year to 2023.

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Although at the beginning of 2017, Ontario had implemented a compliant cap and trade system, there was a change in the provincial government as a result of the election held in June 2018. The then newly elected Ontario government cancelled the cap and trade regulation and prohibited all trading of emission allowances, effective as of July 3, 2018, and on October 31, 2018 formally repealed the cap-and- trade legislation. As a result, our Ontario operations are now currently subject to the federal backstop regime. This means that large industrial emitters in Ontario, such as our operations in Tunis and Nipigon, are currently subject to the federal OBPS provided for in Part 2 of the Greenhouse Gas Pollution Pricing Act. As of July 4, 2019, Ontario has also established its own output-based performance standards for large emitters through Ontario Regulation 241/19: Greenhouse Gas Emissions Performance Standards (“GHGEPS”). The GHGEPS, while currently optional for facilities covered under the federal GHGRP emitting between 10,000 and 50,000 tonnes of CO₂e, appears to be similar to the federal OBPS. On September 20, 2020, the federal government accepted the GHGEPS as an equivalent program, which will exempt Ontario facilities from the federal backstop regime once in force. The implications of the federal OBPS and the GHGEPS for our operations in Ontario, such as Tunis and Nipigon, are discussed below (in the section on Canada – Ontario).

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The validity of the federal backstop regime is being challenged on constitutional grounds by Alberta, Ontario and Saskatchewan. The Courts of Appeal in Ontario and Saskatchewan have held that the federal backstop regime is constitutional, while the Alberta Court of Appeal found that the federal backstop regime was unconstitutional. Canada’s highest court, the Supreme Court of Canada (“SCC”), heard the three provincial challenges in September 2020. The provinces of British Columbia, Manitoba, New Brunswick, and Quebec joined the proceedings as interveners. The SCC reserved judgement after hearing the appeals and, to date, has not rendered a decision. If the SCC finds that the federal backstop regime is constitutional, then the federal backstop regime will continue to apply as described in this section.

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In December 2020, the federal government announced that the OBPS charge will increase by $15 per tonne in each year after 2023 until the charge hits $170 per tonne in 2030. If provincial regimes do not match this price, then they may no longer be deemed to be equivalent and the federal backstop regime could continue to apply.

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Canada – British Columbia

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The Government of British Columbia has enacted a number of significant pieces of climate action legislation that frame British Columbia’s approach to reducing greenhouse gas emissions with the goal of supporting its participation in the emerging low-carbon economy.

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One key piece of legislation is the Greenhouse Gas Reduction Targets Act, which was re-enacted in November 2018 as the Climate Change Accountability Act (British Columbia) (“CCAA”), which sets legislated targets for the reduction of greenhouse gas emissions in British Columbia. Using 2007 as a base year, CCAA (along with related Ministerial Orders) requires that emissions must be reduced by a minimum of 40% by 2030, 60% by 2040 and 80% by 2050. The Province has also introduced an interim target of 16% by 2025 and will set sectoral targets by March 2021. Also required in connection with CCAA are (from 2020 onward) British Columbia Greenhouse Gas Inventory Reports (reports are prepared in even-numbered years and tables are updated in odd-numbered years) and Community Energy and Emissions Inventory Reports (prepared every two years), all of which are designed to provide scientific, comparable and consistent reporting of greenhouse gas sources.

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Other related, key pieces of legislation include the Carbon Tax Act (“CTA”) and the Greenhouse Gas Industrial Reporting and Control Act (“GGIRCA”). CTA operates to put a price on greenhouse gas emissions, providing an incentive for sustainable choices and practices by producers of greenhouse gases. GGIRCA came into force on January 1, 2016 and combined several pieces of British Columbia's existing greenhouse gas legislation into a single legislative framework. It includes the ability to set a greenhouse gas emissions intensity benchmark for regulated industries and enables the benchmark to be met through flexible options, such as purchasing offsets or paying a set price per tonne of greenhouse gas emissions that would be dedicated to a technology fund. Three regulations necessary to implement GGIRCA also came into force on January 1, 2016: the Greenhouse Gas Emission Reporting Regulation (“GGERR”), the Greenhouse Gas Emission Administrative Penalties and Appeals Regulation (“GGEAPAR”) and the Greenhouse Gas Emission Control Regulation (“GGECR”). GGERR establishes compliance reporting requirements and ensures that industrial operations that emit more than 10,000 carbon dioxide equivalent tonnes per year report their greenhouse gas pollution each year. GGEAPAR establishes the process for when, how much, and under what conditions administrative penalties may be levied for non-compliance with GGIRCA or the regulations made under GGIRCA. GGECR establishes the BC Carbon Registry and sets criteria for developing emission offsets issued by the provincial government. GGECR also establishes the price for funded units issued under GGIRCA that would go towards a technology fund. Regulated operations will purchase offsets from the market or funded units from government to meet emission limits. Funded unit revenue that goes to a technology fund will also support the development of clean technologies with significant potential to reduce British Columbia's emissions over the long term.

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Canada - Ontario

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In a news release issued on June 15, 2018, Ontario Premier-designate Doug Ford announced that the first act of his newly formed government would be to cancel Ontario’s cap and trade program (under the Climate Change Mitigation and Low-carbon Economy Act, 2016). Effective as of July 3, 2018, the Ontario government cancelled the cap and trade regulation and prohibited all trading of emissions allowances, and on October 31, 2018 formally repealed the Ontario cap-and-trade legislation. Bill 4: Cap and Trade Cancellation Act, 2018 (the legislation which repealed the former cap-and-trade regime) retired or cancelled outstanding emissions allowances and strictly limited the ability of those holding emissions allowances to bring claims seeking to recover for any damages suffered as a result.

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Under the previous cap-and-trade regime, facilities in Ontario with annual greenhouse gas emissions of 25,000 tonnes or more were generally required by law to participate in the regime by obtaining emissions allowances. However, facilities which primarily generate electricity using natural gas from a local distributor were excluded from the requirement to obtain emission allowances and instead participated in the program through the payment of the carbon price charged by the local natural gas distributor on the natural gas delivered after the end of 2016. As a result, our operations in Ontario were not holding emissions allowances when the Ontario cap and trade program was cancelled and were not adversely affected by the cancellation of that regime.

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As a result of the cancellation of the Ontario cap-and-trade regime, on January 1, 2019 our operations in

Nipigon and Tunis became subject to the federal OBPS. Under the federal “Notice Establishing Criteria Respecting Facilities and Persons and Publishing Measures: SOR/2018-213”, as it read before its repeal, any facility which emitted more than 50kt of CO₂e during any of the 2014, 2015, 2016 or 2017 calendar years, and which carries out, as its primary activity, the generation of electricity using fossil fuels, is a covered facility and subject to the OBPS. Since the Nipigon and Tunis projects are each generating electricity using natural gas and each reported emissions in excess of 50kt of CO₂e for one of the 2014, 2015, 2016 or 2017 calendar years (119,248 tonnes for 2014 in the case of Tunis and 115,725 tonnes for 2016 in the case of Nipigon), each is considered a covered facility and currently subject to the federal OBPS and required to pay fees as described below.

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Our operations in Ontario may also be subject to Ontario’s GHGPE, as it comes into force. Under Ontario’s GHGPE, facilities must register with the Director of the Ministry of the Environment, Conservation and Parks if the facility is required to submit a report under the federal GHGRP and reported emissions of more than 50,000 tonnes of CO₂e. Facilities may also choose to register if the facility submitted a report under the federal GHGRP and emits between 10,000 and 50,000 tonnes of CO₂e. Accordingly, our operations in Tunis and Nipigon are also subject to Ontario’s GHGPE.

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Under the federal OBPS regulations, the Tunis and Nipigon projects are required to either pay an excess emissions charge or remit compliance units as prescribed by the federal backstop regime for each tonne of CO₂e emissions in excess of 370 tonnes of CO₂e / GWh of electricity generated by such operations for the 2021 compliance period, and will receive free emissions allowances if the emissions fall below that measure. The emissions limit for both the Nipigon and Tunis facilities will be reduced to 329 tonnes of CO₂e / GWh in 2022 under the OBPS.

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Facilities in Ontario subject to the GHGPE will be required to pay a similar excess emissions charge or remit compliance units per tonne of CO₂e emissions, in accordance with the GHG Emissions Performance Standards and Methodology for the Determination of the Total Annual Emissions Limit guideline prepared by the Province. The details of arrangements for the possible recovery of these potential additional costs from the IESO will depend on the terms of the applicable PPA. The Province and federal government’s coordination of the transition between the federal OBPS and the provincial GHGPE also adds to some uncertainty in the future.

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Renewable Energy

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More than half of the U.S. states and most Canadian provinces have set mandates requiring the achievement of certain levels of renewable energy production and/or energy efficiency during target timeframes. This includes generation from wind, solar and biomass, and/or renewable fuel mandates. For example, in 2011, California enacted a law requiring retail sellers of electricity to deliver 33% of their customers' electricity requirements from renewable resources, as defined in the statute, by 2020. In 2015, California enacted SB 350, which increases the amount of electricity from renewable resources that California retail sellers must deliver after 2020 to 40% of retail sales by December 2024, 45% of retail sales by December 2027, and 50% of retail sales by December 2030. In order to meet CO₂ reduction goals, changes in the generation fuel mix are forecasted to include a reduction in existing coal resources, higher reliance on natural gas and renewable energy resources and an increase in demand-side resources. Investments in new or upgraded transmission lines will be required to move increasing renewable generation from more remote locations to load centers.

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In December 2015, 195 countries participating in the United Nations Framework Convention on Climate Change (“UNFCC”), at its 21st Conference of the Parties meeting (“COP21”) held in Paris, adopted a new global agreement on the reduction of climate change (the “Paris Agreement”). The Paris Agreement became effective in November 2016, after it had been ratified by a sufficient number of countries. The Paris Agreement sets a goal of holding the increase in global average temperature to well below 2 degrees Celsius and pursuing efforts to limit the increase to 1.5 degrees Celsius, to be achieved by aiming to reach a global peaking of greenhouse gas emissions as soon as possible. The Paris Agreement consists of two elements: a legally binding commitment by each participating country to set an emissions reduction target, referred to as “nationally determined contributions” or “NDCs,” with a review of the NDCs that could lead to updates and enhancements every five years (Article 4) and a transparency commitment requiring participating countries to disclose in full their progress (Article 13). As decided at the 24^th Conference of the Parties meeting in December 2020, countries are expected to submit updated NDCs in 2020. Accordingly, the Paris

Agreement may result in additional regulations to reduce carbon emissions in coming years.

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Canada ratified the Paris Agreement, and submitted an NDC that included a 2030 target of 30% below 2005 levels. The United States also submitted an NDC, which called for reducing its net greenhouse gas emissions by 26-28% below 2005 levels by 2025. In November 2019, the Trump Administration notified the United Nations of the U.S. withdrawal from the Paris Agreement, which became effective in November 2020. On January 21, 2021, the Biden Administration formally rejoined the Paris Agreement through executive order. The return to the agreement takes effect 30 days from the signing of the executive order. Later in 2021, the Biden Administration is expected to submit a new official commitment that pledges domestic reductions in heat-trapping emissions. In light of the legislative, judicial and executive factors influencing regulatory action, significant uncertainty exists as to how greenhouse gas restrictions in the United States will impact our facilities in the future.

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HUMAN CAPITAL

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As of March 3, 2021, we had 261 employees, 200 in the United States and 61 in Canada. Of our Canadian employees, 43 are covered by collective bargaining agreements, which will expire on December 19, 2021 and December 31, 2023. During 2020, we did not experience any labor stoppages or labor disputes at any of our facilities.

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AVAILABLE INFORMATION

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Access to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports filed with or furnished to the SEC 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 Annual Report, information contained on our website or the SEC or CSA websites is not incorporated by reference in the Annual Report on Form 10-K and should not be considered to be a part of the Annual Report. We have included our website address and that of the SEC and CSA only as inactive textual references and do not intend them to be active links to such websites. All statements made in any of our securities filings, including all forward-looking statements or information, are made as of the date of the document in which the statement is included, and we do not assume or undertake any obligation to update any of those statements or documents unless we are required to do so by applicable law. We are not a foreign private issuer, as defined in Rule 3b-4 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

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ITEM 1A. RISK FACTORS

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This section highlights specific risks that could affect our Company. You should carefully consider each of the following risks and all of the other information set forth in this Annual Report on Form 10-K. Based on the information currently known to us, we believe the following information identifies the material risk factors affecting our Company. However, the risks and uncertainties described below are not the only ones related to our business and are not necessarily listed in the order of their importance. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business, results of operations or financial condition.

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If any of the following risks and uncertainties develops into actual events or if the circumstances described in the risks and uncertainties occur or continue to occur, these events or circumstances could have a material adverse effect on our business, results of operations or financial condition. These events could also have a negative effect on the trading price of our securities.

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Summary of Risk Factors

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

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In addition, risks include, without limitation:

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For a more complete discussion of risk factors relevant to our Company, see the risk factors discussion beginning on page 24.

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Risks Related to the Proposed Transaction with I Squared Capital

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There can be no certainty that all conditions to the Transaction will be satisfied. Failure to complete the Transaction could negatively impact the share price of the common shares or preferred shares or otherwise adversely affect the business of the Company

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The completion of the Arrangement is subject to a number of conditions, certain of which are outside our control, including the obtaining of common shareholder approval, the obtaining of preferred shareholder approval, the obtaining of the consents of holders of the MTNs, the obtaining of consents or approvals from holders of convertible debentures, the obtaining of required regulatory approvals, the obtaining of required third-party consents and receipt of a final order from the Supreme Court of British Columbia. There can be no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when. A substantial delay in obtaining satisfactory approvals and/or the imposition of unfavorable terms or conditions in the approvals to be obtained could have an adverse effect on our business, financial condition or results of operations of Atlantic Power or could result in the termination of the Arrangement Agreement. If: (i) common shareholders choose not to approve the Arrangement, (ii) preferred shareholders choose not to approve the continuance of APPEL under the laws of British Columbia and the Arrangement, (iii) holders of the MTNs choose not to amend the MTN indenture (as describe in the Arrangement Agreement), (iv) holders of the convertible debentures choose not to amend the indenture of the convertible debentures (as described in the Arrangement Agreement), (v) we otherwise fail to satisfy, or fail to obtain a waiver of the satisfaction of, the closing conditions to the transaction and the Arrangement is not completed, (vi) a material adverse effect occurs that results in the termination of the Arrangement Agreement, or (vii) any legal proceeding results in enjoining the transactions contemplated by the Arrangement, we could be subject to various adverse consequences, including that we would remain liable for significant costs relating to the Transaction, including, among others, legal, accounting, financial advisory and financial printing expenses.

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If the Transaction is not completed, the market price of the common shares and preferred shares may decline to the extent that the market price reflects a market assumption that the Transaction will be completed. The US$3.03 per share to be paid for each Common Share exceeds Atlantic Power’s 52-week and last five-year-high price, and represents a premium of approximately 48% to the 30-day volume weighted average price per Common Share on the NYSE. If the Transaction is not completed and the Board decides to seek another merger or business combination, there can be no assurance that it will be able to find a party willing to pay an equivalent or more attractive price than the prices offered to holders of common shares and holders of preferred shares to be paid pursuant to the Arrangement.

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In addition, since the completion of the Transaction is subject to uncertainty, our officers and employees may experience uncertainty about their future roles with the Company. This may adversely affect our ability to attract or to retain key management and personnel in the period until the Arrangement is completed or terminated.

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The Arrangement Agreement may be terminated in certain circumstances. 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

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Each of the parties to the Arrangement Agreement has the right to terminate the Arrangement Agreement in certain circumstances. Accordingly, there is no certainty, nor can we provide any assurance, that the Transaction will not be terminated by any of the parties to the Arrangement Agreement before the completion of the Transaction. Failure to complete the Arrangement could negatively impact the trading price of the common shares or preferred shares or otherwise adversely affect our business.

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Under the Arrangement Agreement, we are required to pay a termination fee of $12,500,000 in the event the Arrangement Agreement is terminated following the occurrence of certain events. The termination fee may discourage other parties from attempting to acquire the common shares and preferred shares, even if those parties would otherwise be willing to offer greater value than that offered under the Arrangement.

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Even if the Arrangement Agreement is terminated without payment of the termination fee, we may, in the

future, be required to pay the termination fee in certain circumstances. Under the Arrangement Agreement, we may be required to pay the termination fee to the Purchasers at a date subsequent to the termination of the Arrangement Agreement if the Arrangement Agreement is terminated due (i) to common shareholder approval of the Arrangement by at least two-thirds of the votes cast by common shareholders at a special meeting of the common shareholders or preferred shareholder approval of the continuance of APPEL under the laws of British Columbia and the Arrangement by at least two thirds of the votes cast by preferred shareholders at a special meeting of the preferred shareholders not being obtained, (ii) the closing of the Transaction having not occurred prior to July 14, 2021, or (iii) our breaching certain representations and warranties if (A) prior to such termination an acquisition proposal is publicly announced after the date of the Arrangement Agreement and not withdrawn prior to the special meetings of common and preferred shareholders and (B) within twelve months of such termination, (x) an acquisition proposal (whether or not the same acquisition proposal described in clause (A) above) is consummated or (y) we or one or more of our subsidiaries enters into an agreement with respect to an acquisition proposal and such acquisition proposal is later consummated (whether or not within the twelve month period following such termination).

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Certain features of the Arrangement Agreement may discourage other parties from attempting to acquire the Company

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Under the Arrangement Agreement, as a condition to entering into a definitive agreement in respect of a superior proposal, we and APPEL are required to offer the Purchasers the right to match such superior proposal. This right may discourage other parties from making a superior proposal, even if they would otherwise have been willing to acquire us on more favorable terms than the Transaction.

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Prior to entering into the Arrangement Agreement, we engaged in exclusive negotiations with I Squared Capital and did not solicit expressions of interest from other potential buyers. A special committee of the Board comprised entirely of independent directors and the Board concluded, after receiving advice from their financial and legal advisors, that the risks of soliciting expressions of interest from other potential buyers outweighed the benefits of doing so, particularly having regard to the financial and other terms of the Arrangement Agreement. However, there can be no assurance that, if we had solicited expressions of interest from other potential buyers, that one or more of such potential buyers would not have been willing to acquire us on more favorable terms than I Squared Capital and the Purchasers.

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While the Arrangement is pending, the Company is restricted from taking certain actions

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The Arrangement Agreement restricts us from taking certain specified actions until the Arrangement is completed without the consent of the Purchasers. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Arrangement.

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The pending Transaction may divert the attention of the Company’s management

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The pendency of the Transaction could cause the attention of our management to be diverted from the day-to-day operations and counterparties or suppliers may seek to modify or terminate their business relationships with us. These disruptions could be exacerbated by a delay in the completion of the Arrangement and could have an adverse effect on our business, operating results or prospects.

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Risks Related to the Operation of Our Business

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If the Arrangement is not completed, the Company will continue to face the risks that it currently faces with respect to its affairs, business and operations and future prospects,. Such risk factors are set out below.

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The expiration or termination of our PPAs could have a material adverse impact on our business, results of operations and financial condition

Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our PPAs are scheduled to expire between September 2021 and November 2043. See Item 1. Business—Our Organization and Segments for details about our projects’ PPAs and related expiration dates. In addition, these PPAs may be subject

to termination prior to expiration in certain circumstances, including default by the project. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all; the price received by the project for power under subsequent arrangements may be reduced significantly, or there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA at the project. It is possible that subsequent PPAs may not be available at prices that permit the operation of the project on a profitable basis. For example, our Kapuskasing and North Bay projects formerly had PPAs with the OEFC that expired in December 2017. These plants are currently being maintained, but do not operate because they do not have PPAs or a merchant market where operations would be profitable. When the affected project temporarily or permanently ceases operations, or when we have an expectation that we will be unable to renew or renegotiate the PPA, the value of the project may be impaired such that we would be required to record an impairment loss under applicable accounting rules. See “—Impairment of goodwill, long lived assets or equity method investments could have a material adverse effect on our business, results of operations and financial condition.” Any expiration of our existing PPAs or failure to secure new PPAs could have a material adverse effect on our business, results of operations, financial condition and Adjusted EBITDA.

Three of our projects, representing 8.5% of our operating net MW and 3.5% of our 2020 Project Adjusted EBITDA, have PPAs or other contractual arrangements that will expire in 2021. These projects are Oxnard, Kenilworth and Calstock. Another six of our other projects, representing 48.3% of our operating net MW and 55.8% of our 2020 Project Adjusted EBITDA, have PPAs or other contractual arrangements that will expire within the next five years. These projects are Manchief (2022), Frederickson (2022), Moresby Lake (2022), Nipigon (2022), Orlando (2023) and Chambers (2024). 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 2022.

Our projects depend on their electricity and thermal energy customers and there is no assurance that these customers will perform their obligations or make required payments

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Each of our projects relies on one or more PPAs, steam sales agreements or other agreements with one or more utilities or other customers for a substantial portion of its revenue. At times, we rely on a single customer or a limited number of customers to purchase all or a significant portion of a project’s output. In 2020, the largest customers of our power generation projects, including projects recorded under the equity method of accounting, were Niagara Mohawk Power Corporation, IESO, BC Hydro, Equistar Chemicals L. P. and Georgia Power Company, which account for approximately 14.8%, 13.8%, 12.5%, 10.9% and 10.4%, respectively, of the consolidated revenue of our projects. If a customer stops purchasing output from our power generation projects or purchases less power than anticipated, such customer may be difficult to replace, if at all. Further concentration of our customers would increase our dependence on any one customer. Our cash flows and results of operations, including the amount of cash available to make payments on our indebtedness, are highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance that these customers will perform their contractual obligations or make required payments.

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Further, our customers generally have investment-grade credit ratings, as measured by S&P. Customers that have assigned ratings at the top end of the range have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest capacity. Agency ratings are subject to change, and there can be no assurance that a ratings 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.

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Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of these projects and on our business, results of operations and financial condition

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PPAs that are based on spot market pricing for some or all of their output will be exposed to fluctuations in the wholesale price of electricity. In addition, as PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for electricity will depend on market conditions at the time, which may not be favorable. The open market wholesale prices for electricity are very

volatile. Long and short-term power prices may fluctuate substantially due to other factors outside of our control, including:

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The market price for electricity is affected by changes in demand for electricity. Factors such as economic slowdown, worse than expected economic conditions, milder than normal weather, the growth of energy efficiency and efforts aimed at energy conservation, among others, could reduce energy demand or significantly slow the growth in demand for electricity, thereby reducing the market price for electricity. A reduction in demand could contribute to conditions that no longer support the continued operation of certain power generation projects, which could adversely affect our results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs, among others.

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Both our Chambers and Morris projects are contracted but have some exposure to market prices for power. At Chambers, plant capacity is sold forward pursuant to the PPA with our utility customer but the project is economically dispatched, which impacts variable operating margins. For example, during periods of low demand and low spot electricity prices, the project is dispatched less, which reduces the project’s operating margin. In addition, the utility customer has the right to sell a portion of the output into the spot market if it is economical to do so, and the Chambers project shares in the profit from these sales. This also adds some variability to the project’s financial results.

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At Morris, a portion of the capacity is contracted with the industrial customer through 2034. The remaining capacity has been sold forward into the Pennsylvania New Jersey Maryland (“PJM”) capacity market through annual auctions covering the period through May 2022. The capacity revenues from these auctions generally represent the majority of the operating margin of the uncontracted portion of the project. Energy associated with the capacity sold forward into the PJM market is generally dispatched by PJM when economic to do so or when needed for other reasons.

The project can also offer ancillary services to the grid. The sale of energy and ancillary services from the uncontracted portion of the project is not at a fixed price or margin and therefore can add variability to the project’s financial results.

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Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the results of operations of the projects

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The amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or failure by any supplier to meet its contractual commitments may adversely affect our results.

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