AT Atlantic Power Corporation

 

UNITED STATES
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CONFIDENTIAL Q4 and Year End 2020 Financial Results Supplementary Presentation March 5, 2021

Cautionary Note Regarding Forward - Looking Statements 2 To the extent any statements made in this presentation contain information that is not historical, these statements are forward - looking statements or forward - looking information, as applicable, within the meaning of Section 27 A of the U . S . Securities Act of 1933 , as amended, and Section 21 E of the U . S . Securities Exchange Act of 1934 , as amended, and under Canadian securities law (collectively “forward - looking statements”) . Forward - looking statements can generally be identified by the use of words such as “should,” “intend,” “may,” “expect,” “believe,” “anticipate,” “estimate,” “continue,” “plan,” “project,” “will,” “could,” “would,” “target,” “potential” and other similar expressions . In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward - looking statements . Although Atlantic Power Corporation (“AT”, “Atlantic Power” or the “Company”) believes that the expectations reflected in such forward - looking statements are reasonable, such statements involve risks and uncertainties and 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 . Please refer to the factors discussed under “Risk Factors” and “Forward - Looking Information” in the Company’s periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the effects of the coronavirus pandemic on the Company’s business and results, including the measures taken by governmental authorities to address it, which may precipitate or exacerbate other risks and/or uncertainties ; the outcome or impact of the Company’s business strategy to increase the intrinsic value of the Company on a per - share basis through disciplined management of its balance sheet and cost structure and investment of its discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities ; the Company’s ability to enter into new PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or impact on the Company’s business of any such actions ; the anticipated benefits of the transaction with I Squared Capital and its affiliates ; the receipt of required regulatory, court and securityholder approvals for the transaction with I Squared Capital and its affiliates ; the receipt of third - party consents necessary to satisfy closing conditions to the transaction with I Squared Capital and its affiliates ; the ability of the parties to satisfy the other conditions to, and to complete, the transaction with I Squared Capital and its affiliates ; the Company’s intention to hold securityholder meetings ; and the anticipated timing of the closing of the transaction with I Squared Capital and its affiliates . Although the forward - looking statements contained in this presentation 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 . These forward - looking statements are made as of the date of this presentation and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances . The Company’s ability to achieve its longer - term goals, including those described in this presentation, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions . The Company’s actual results may differ, possibly materially and adversely, from these goals . Disclaimer – Non - GAAP Measures 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 . Investors are cautioned that the Company may calculate this non - GAAP measure in a manner that is different from other companies . The most directly comparable GAAP measure is project income (loss) . Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non - cash impairment charges), and changes in the fair value of derivative instruments . Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors . A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net income (loss) by segment and on a consolidated basis is provided on pages 33 - 35 . All amounts in this presentation are in US $ and approximate unless otherwise stated .

Additional Information About the Arrangement and Where to Find It 3 This presentation is not intended to and does not constitute an offer to sell or the solicitation of an offer to subscribe for or buy or an invitation to purchase or subscribe for any securities or the solicitation of any vote or approval in any jurisdiction, nor shall there be any sale, issuance or transfer of securities in any jurisdiction in contravention of applicable law . In connection with the transaction with I Squared Capital and its affiliates, Atlantic Power has filed a management information circular and proxy statement relating to a special meeting of its common shareholders with the SEC and Canadian Securities Administrators . Additionally, Atlantic Power will file other relevant materials in connection with the transaction with the SEC . Securityholders of Atlantic Power are urged to read the management information circular and proxy statement regarding the transaction and any other relevant materials carefully in their entirety when they become available before making any voting or investment decision with respect to the transaction with I Squared Capital and its affiliates because they contain important information about the transaction with I Squared Capital and its affiliates and the parties to such transaction . Securityholders of Atlantic Power are able to obtain a copy of the management information circular and proxy statement, and the filings with the SEC and Canadian Securities Administrators that will be incorporated by reference into the proxy statement as well as other filings containing information about the transaction with I Squared Capital and its affiliates and the parties to such transaction made by Atlantic Power with the SEC and Canadian Securities Administrators free of charge on EDGAR at www . sec . gov, on SEDAR at www . sedar . com, or on Atlantic Power’s website at www . atlanticpower . com . Information contained on, or that may be accessed through, the websites referenced in this communication is not incorporated into and does not constitute a part of this presentation . We have included these website addresses only as inactive textual references and do not intend them to be active links . Participants in the Solicitation Atlantic Power and its directors and executive officers may be deemed to be participants in the solicitation of proxies from the holders of Atlantic Power’s common shares in respect of the transaction with I Squared Capital and its affiliates . Investors may obtain additional information regarding the interest of such participants by reading the management information circular and proxy statement regarding the transaction when it becomes available .

4 □ 2020 Highlights □ Acquisition Agreement with I Squared Capital □ Financial Results □ Liquidity and Debt Repayment Profile □ Operations Review □ Commercial Update □ Q&A Agenda

2020 Highlights 5 Financial Results □ Project Adjusted EBITDA of $188.7 million near top end of guidance □ Operating cash flow of $107.3 million exceeded our estimate □ Liquidity of $142 million, including approximately $14 million of discretionary cash Balance Sheet □ Repaid $76.4 million of consolidated debt from strong operating cash flow, improving leverage ratio to 3.6 times Capital Allocation □ Invested $48.0 million in repurchases of common and preferred shares □ Average price $2.04 per common share; preferred shares 39% discount to par PPAs □ Calstock PPA extended one year, to December 2021; in discussions on potential five - year contract options □ Oxnard is operating under a Resource Adequacy (RA) agreement through year end; exploring RA opportunities for 2022 and 2023 Operations □ Improved safety outcomes □ Completed reconstruction of Cadillac in August; plant running very well since then □ Williams Lake has been running well; fuel availability continues to improve

Acquisition by I Squared Capital: Investor Questions Why sell now? □ Forward power curves have continued to decline, adversely affecting ability to re - contract expiring PPAs □ Microcap stock in out - of - favor sector with declining Project Adjusted EBITDA profile Why sell at these prices? □ Offer of US$3.03 per common share gives us value today for Project Adjusted EBITDA potentially at risk due to re - contracting □ Without the offer, getting to that price would require a recovery in forward power curves Impact of new green energy policies on Atlantic Power? □ Policies are hurting gas plants by adding supply where it is not needed □ Hydro plants likely to be re - contracted, but at much lower levels of Project Adjusted EBITDA Why is this a good deal structure for all of our securityholders? □ All holders have ability to realize liquidity in near term at premiums to recent and historic trading ranges Why aren’t the preferred shares being redeemed at par? □ Not a redemption; buyer not required to pay par, but is offering fair value □ Significant premium to recent and historic levels, and a 40% premium to average repurchase price (Cdn$15.74) under normal course issuer bid □ Downside risk of Cdn$6 per share to Cdn$7 per share equates to approximately five years of dividends; permanent lost opportunity cost □ In a “Lower for Longer” scenario in power, our ability to continue paying preferred dividends will be challenged over time Is there any chance the prices offered will be raised? □ Offer is firm and final □ No approaches from potential competing bidders since agreement was announced Read the CEO Letter to Shareholders here 6

Q4 2020 Financial Highlights 7 Financial Results □ Project Adjusted EBITDA of $51.7 million vs. $42.9 million in Q4 2019 □ Cash provided by operating activities of $35.2 million vs. $40.2 million in Q4 2019 Balance Sheet □ Repaid $18.5 million of term loan and $0.8 million of project debt □ Consolidated leverage ratio (1) at December 31 of 3.6 times, or 3.4 times net of cash Capital Allocation □ No activity in Q4, pending completion of the I Squared Capital transaction □ Discretionary cash at December 31 of approximately $14 million Cadillac Insurance Recovery □ Final insurance recoveries received in December 2020 totaling $10.1 million (1) Consolidated debt to trailing 12 - month Project Adjusted EBITDA (after Corporate G&A).

Q4 2020 Project Adjusted EBITDA (1) (bridge vs 2019) ($ millions) 8 $42.9 $51.7 Q4 2019 Q4 2020 Cadillac Timing of Business Interruption recoveries (from 2019 and 2021) 12.7 Williams Lake Higher generation due to better fuel availability 1.5 Morris Higher major maintenance expense; lower PJM pricing (4.1) Curtis Palmer Lower water flows (2019 was a near - record year) (7.0) 1.3 Oxnard Lower availability and higher gas prices in prior period 3.0 Moresby Lake Transformer outage in prior period 1.4 All others (1) See Appendix for non - GAAP disclosures Q4 was modestly ahead of our expectations, including a portion of Cadillac business interruption recoveries related to 2021 capacity revenue

FY 2020 Project Adjusted EBITDA (1) (bridge vs 2019) ($ millions) 9 $196.1 $188.7 FY 2019 FY 2020 Cadillac Timing of Business Interruption recoveries (for 2019 and 2021) 10.1 Nipigon Contractual rate escalation; major maintenance in prior period 2.0 Morris Higher major maintenance expense; lower PJM pricing (5.5) Curtis Palmer Lower water flows (2019 was a near - record year) (14.9) (1.7) Mamquam Higher water flows 3.9 Oxnard PPA expiry (May 2020); RMR contract (through 12/31/20) (1.6) Piedmont Maintenance outages (1) See Appendix for non - GAAP disclosures FY 2020 vs FY 2019 Main Drivers: □ Curtis Palmer water flows down 48% vs prior period (2019 was the second - highest year on record) □ Morris CT and control system upgrades in 2020; lower PJM pricing □ Cadillac includes business interruption recoveries related to 2019 and 2021 (1.7) All others Piedmont ( - ) Craven ( - ) Grayling ( - ) Orlando ( - ) Williams Lake (+) Chambers (+) 2.0 Moresby Lake Higher water flows and improved availability

Three months ended December 31, Unaudited 2020 2019 Change Cash provided by operating activities $35.2 $40.2 $(5.0) Significant uses of cash provided by operating activities: Term loan repayments (1) (18.5) (20.0) 1.5 Project debt amortization (0.8) - (0.8) Capital expenditures (1.1) (1.5) 0.4 Preferred dividends (1.8) (1.9) 0.1 Cash Flow Results ($ millions) 10 • ($11.3) million unfavorable change in working capital • +$8.8 million higher Project Adjusted EBITDA (1) Includes 1% mandatory annual amortization and targeted debt repayments . (2) Maintenance capital; excludes Cadillac repairs of $20.8 million in 2020, which were covered by insurance recoveries. Twelve months ended December 31, Unaudited 2020 2019 Change Cash provided by operating activities $107.3 $144.7 $(37.4) Significant uses of cash provided by operating activities: Term loan repayments (1) (72.5) (70.0) (2.5) Project debt amortization (3.9) (2.3) (1.6) Capital expenditures (2) (3.7) (2.3) (1.4) Preferred dividends (6.8) (7.4) 0.6 • ($25.6) million unfavorable change in working capital, mostly due to timing of receipts at Cadillac, Williams Lake and Nipigon, and larger cash disbursements for Cadillac repairs and a maintenance outage at Morris • ($14.9) million due to unfavorable hydrological conditions at Curtis Palmer • ($5.3) million due to lower distributions from unconsolidated affiliates, primarily at Chambers, which began repaying project - level debt in Q4 2019 • +$16.4 million insurance recoveries for Cadillac (portion included in operating cash flow)

Liquidity ($ millions) 11 Dec 31, 2020 Sep 30, 2020 Cash and cash equivalents, parent $21.5 $15.9 Cash and cash equivalents, projects 17.3 14.4 Total cash and cash equivalents 38.8 30.3 Revolving credit facility 180.0 180.0 Letters of credit outstanding (77.1) (78.0) Availability under revolving credit facility 102.9 102.0 Total Liquidity $141.7 $132.3 Excludes restricted cash of (1) : $7.1 $2.6 Consolidated debt (2) $577.6 $585.2 Leverage ratio (3) 3.6 3.9 (1) Includes $6.0 million and $1.2 million, respectively, from Cadillac insurance proceeds for use in reconstruction of the plant . (2) Before unamortized discount and unamortized deferred financing costs (3) Consolidated debt to trailing 12 - month Adjusted EBITDA (after Corporate G&A) Discretionary cash of approximately $14 million at December 31, 2020

$687 $608 $504 $384 $309 $270 $0 $100 $200 $300 $400 $500 $600 $700 $800 YE 2019 YE 2020 YE 2021 YE 2022 YE 2023 YE 2024 $84 $105 $119 $75 $40 $0 $20 $40 $60 $80 $100 $120 $140 2020 2021 2022 2023 2024 Debt Repayment and Projected Debt Balances through 2024 (1) ($ millions) 12 12 (1) Includes Company’s proportional share of debt at Chambers of $30.7 million, which is not consolidated because the project is 40% owned. (2) Public Service Co. of Colorado has executed an agreement to purchase Manchief for $45.2 million following the expiration of the PPA in May 2022. Note: C$ denominated debt was converte d t o US$ using exchange rate of $1.2732 as of 12/31/2020. Detail of debt repayment schedule on pages 21 – 23. ▪ Planned debt repayment would reduce debt approximately 55% by YE 2024 ▪ No bullet maturities prior to January 2025 (Series E convertible debentures) ▪ Expect to repay $307.5 million Term Loan by maturity (April 2025) ▪ Repaid $84.2 million in 2020 ▪ Expect to repay $339 million from 2021 through 2024 ▪ Majority of the debt repayment expected to be from operating cash flows and proceeds from the sale of Manchief (2) ▪ Expect to result in lower cash interest payments and lower leverage ratios Projected Debt Balances Debt Repayment $84 repayment $(5) F/X loss (unrealized)

317.8 456.3 603.6 508.3 166.9 140.2 1,088.3 1,104.8 Q4 2019 Q4 2020 Q4 2019 Q4 2020 Q4 2019 Q4 2020 Q4 2019 Q4 2020 1.67 0.69 1.16 1.65 3.60 1.10 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Q4 2020 Operational Performance: Higher generation: Williams Lake new PPA, Manchief higher dispatch, Cadillac return to service 13 Q4 2020 Q4 2019 Solid Fuel 87.0% 83.0% Natural Gas 93.8% 96.0% Hydro 99.2% 89.8% Total 91.9% 90.4% Aggregate Power Generation Q4 2020 vs. Q4 2019 (Net GWh) Solid Fuel Natural Gas Hydroelectric Total 43.6% (15.8%) (16.0%) 1.5% Higher availability factor: Generation modestly higher due to: + Williams Lake new PPA; rebuilding fuel inventory in prior period + Manchief higher dispatch + Cadillac extended outage in prior period + Mamquam higher water flows - Frederickson lower dispatch (favorable wind and hydro conditions) - Curtis Palmer lower water flows - Oxnard PPA expired (May ‘20); now Resource Adequacy (RA) contract + Cadillac extended outage in prior period + Moresby Lake forced outage in prior period + Kenilworth maintenance outage in prior period - Grayling extended outage for generator rewind - Morris maintenance outage - Allendale extended maintenance outage Safety: Total Recordable Incident Rate TRIR, generation companies (Bureau of Labor Statistics): FY’15 1.4, FY’16 1.0, FY’17 1.5, FY’18 1.1, FY’19 1.1 Industry average Availability (weighted average) Hydro generation Curtis Palmer Mamquam (48%) vs Q4 2019 +42% vs Q4 2019 (33%) vs long - term avg. +34% vs long - term avg.

1.67 0.69 1.16 1.65 3.60 1.10 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 1,439.2 1,506.1 2,475.3 2,226.8 673.2 637.2 4,587.7 4,370.1 FY 2019 FY 2020 FY 2019 FY 2020 FY 2019 FY 2020 FY 2019 FY 2020 FY 2020 Operational Performance: Lower generation: Frederickson lower dispatch, Curtis Palmer lower water flows 14 FY 2020 FY 2019 Solid Fuel 78.2% 92.5% Natural Gas 94.4% 95.8% Hydro 88.8% 92.6% Total 86.7% 94.0% Aggregate Power Generation FY 2020 vs. FY 2019 (Net GWh) Solid Fuel Natural Gas Hydroelectric Total 4.6% (10.0%) (5.3%) (4.7%) Lower availability factor: - Grayling extended rotor and generator outage - Cadillac extended outage and reconstruction - Craven extended rotor outage - Orlando planned major maintenance outage - Morris planned major maintenance outage + Moresby Lake transformer outage prior period Safety: Total Recordable Incident Rate TRIR, generation companies (Bureau of Labor Statistics): FY’15 1.4, FY’16 1.0, FY’17 1.5, FY’18 1.1, FY’19 1.1 Industry average Availability (weighted average) Hydro generation Curtis Palmer Mamquam (27%) vs FY 2019 +22% vs FY 2019 (8%) vs long - term avg. +21% vs long - term avg. Generation lower due to: - Frederickson lower dispatch (favorable wind and hydro conditions) - Curtis Palmer lower water flows (near - record year in 2019) - Oxnard PPA expired (May ‘20); now Resource Adequacy (RA) contract - Piedmont maintenance outages - Cadillac extended outage as a result of the fire - Williams Lake new PPA contractual curtailment (May – July) + Manchief higher dispatch + Allendale, Dorchester and Craven acquired mid - 2019 (benefit of full year) + Mamquam and Moresby Lake higher water flows

Operations Update 15 □ Plant running well □ Has not come offline since return to service on August 20 th □ In the process of scheduling spring outage □ Fuel availability and pricing continue to be stable Cadillac (Michigan) Williams Lake (British Columbia) □ Plant ran well during Q4 □ Improved fuel availability □ Currently five grinders producing fuel in the field. □ Expect to continue operation through end of April (November – February required under contract; contractual curtailment May – July) □ Expect Project Adjusted EBITDA improvement in 2021 Craven (NC) and Grayling (MI) □ Both plants running well since restart □ Craven modifications to pollution control equipment allowing for increased poultry litter burn. San Diego (CA) Demolition □ Expect work to be completed in April and sites to be turned back over to the Navy □ Final cost of approximately $3 million (net of salvage value) for all three sites, compares favorably to our original estimates The company’s continued focus on safety performance resulted in three OSHA recordable incidents during the year, a significant reduction from the nine incidents that occurred in 2019. Safety

Commercial Update 16 Calstock (Ontario) □ PPA extended until December 16, 2021 □ In early February, Ministry instructed IESO to enter discussions with Calstock and report back on potential five - year contract options □ Discussions with IESO commenced mid - February □ Continue to receive strong support from local communities, the Ontario Forest Industries Association, unions and Hearst area mills Oxnard (California) □ Resource Adequacy (RA) agreement in place for 2021 □ Expect modest Project Adjusted EBITDA contribution in 2021 as compared to $1.7 million Project Adjusted EBITDA loss in 2020 □ Exploring RA opportunities for 2022 and 2023

Tax Update NOL Expiration by Year (As of 12/31/20 $ millions) Pre - Tax Reform U.S. Canada 2029 $0.0 $19.9 2030 0.0 0.0 2031 25.4 0.0 2032 13.4 6.0 2033 20.6 24.0 2034 122.3 9.3 2035 154.1 0.0 2036 17.0 20.7 2037 16.7 9.0 2038 0.0 10.3 2039 0.0 7.2 2039 0.0 1.2 Total $369.5 $107.6 • As of December 31, 2020, the Company had U.S. and Canadian NOLs scheduled to expire per the table on the right, that can be utilized to offset future taxable income in their respective tax jurisdictions. • NOLs represent potential future tax savings of approximately $94.9 million in the U.S. under the revised U.S. Federal corporate tax rate of 21% plus State jurisdictions, and $29.1 million in Canada. • Although these NOLs are expected to be available as a future benefit: » Some of the NOLs are subject to limitations on their use » Pre - Tax Reform NOLs, as detailed in the chart, can be used to offset 100% of taxable income and retain a 2 - year carryback and a 20 - year carryforward period » Post - Tax Reform NOLs are limited to offset 80% of taxable income, have no carryback feature but have an unlimited carryforward period. The Company has no Post - Tax Reform NOLs. Net Operating Losses Other Impacts of Recent U.S. Tax Legislation • Repeal of the Alternative Minimum Tax (AMT) will result in cash tax savings » The CARES act allowed the Company to file for the remaining $2.7 million of AMT credit refund on the 2019 federal tax return. The Company expects to receive the $2.7 million in 2021. • Business Interest Expense Limitation » Net business interest deductions in excess of 30% of EBITDA (EBIT after 2021) are disallowed. However, disallowed deductions will be carried forward indefinitely to be used at a future date. 17 Valuation Allowance (VA) • A VA must be established against deferred tax assets (DTAs) when it is more likely than not that the asset will not be realized. During 2020, the Company determined there was enough positive evidence to show it was more likely than not the federal DTAs would be realized. The result was a release of the U.S. federal VA for a reduction of $39.7 million. A small U.S. state NOL and tax credit VA remains in place. In addition, there was a decrease of $0.5 million to the Company’s existing Canadian VAs. • At December 31, 2020, the Company had VAs in the U.S. and Canada of $ 13.5 million and $91.7 million, respectively, totaling $105.2 million. » The Company had disallowed interest expense of $37.9 million in 2018, but utilized $36.3 million in 2019 and remainder in 202 0.

Appendix 18 TABLE OF CONTENTS Page Power Projects and PPA Expiration Dates 19 Coronavirus Update 20 Debt Repayment Schedules 21 - 23 Capital Structure Information 24 - 27 Project Information – Earnings/Cash Flow Diversification and PPA Term 28 - 29 Supplemental Financial Information Project Income by Project 30 Project Adjusted EBITDA by Project 31 Cash Distributions from Projects 32 Non - GAAP Reconciliations 33 - 35

Power Projects and PPA Expiration Dates 19 (1) The PPA with OEFC was extended to December 16, 2021 on existing terms. (2) Executed an agreement to sell RA capacity from the Oxnard plant from January 1, 2021 through December 31, 2021. (3) Public Service Co. of Colorado has executed an agreement to purchase Manchief after the expiration of the PPA in May 2022. (4) BC Hydro has an option to purchase Mamquam that is exercisable in Nov. 2021. (5) Expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on cumulative generation to date, we expect the PPA to expire in the first q uar ter of 2026. (6) Equistar has right to take up to 77 MW but on average takes approx. 50 MW. Balance of 177 MW of capacity is sold to PJM. (7) Equistar has an option to purchase Morris exercisable in December 2027. Economic Net Contract Year Project Location Type Interest MW Expiry Kenilworth New Jersey Nat. Gas 100% 29 9/2021 Calstock Ontario Biomass 100% 35 12/2021 (1) Oxnard California Nat. Gas 100% 49 12/2021 (2) Manchief Colorado Nat. Gas 100% 300 4/2022 (3) Moresby Lake B.C. Hydro 100% 6 8/2022 Frederickson Washington Nat. Gas 50.15% 125 8/2022 Nipigon Ontario Nat. Gas 100% 40 12/2022 2023 Orlando Florida Nat. Gas 50% 65 12/2023 2024 Chambers New Jersey Coal 40% 105 3/2024 Mamquam B.C. Hydro 100% 50 9/2027 (4) Curtis Palmer New York Hydro 100% 60 12/2027 (5) 2025 - 2029 Craven North Carolina Biomass 50% 24 12/2027 Grayling Michigan Biomass 30% 11 12/2027 Cadillac Michigan Biomass 100% 40 6/2028 Williams Lake B.C. Biomass 100% 66 9/2029 Piedmont Georgia Biomass 100% 55 9/2032 Tunis Ontario Nat. Gas 100% 37 10/2033 Morris Illinois Nat. Gas 100% 77 (6) 12/2034 (7) Koma Kulshan Washington Hydro 100% 13 3/2037 Dorchester South Carolina Biomass 100% 20 10/2043 Allendale South Carolina Biomass 100% 20 11/2043 2022 2032 - 2043 2021

Business Model and Proactive Steps have Limited the Impact of Coronavirus Pandemic 20 □ No material impact to date on operations or financial results • Eighteen confirmed cases to date (at various plants) among Atlantic Power employees and plant contractors; followed all recommended guidelines and prevented any further spread of the virus • Continuing to monitor fuel supply at biomass plants; pricing and availability remain stable at each site • Overall, we do not currently anticipate a material impact on operations, financial position or results • Continuing to monitor the evolving situation; ultimate outcome remains uncertain □ Believe we are well positioned overall • Power generation an essential business in the United States and Canada • Substantially contracted business model (capacity payment or contracted energy rate) • Limited financial sensitivity to downturn in demand or spot prices (may hurt re - contracting prospects in near term) • Nearly all of our customers are investment - grade rated (Chemours/Chambers only exception) • Not experiencing any delays in payments • Stable liquidity; no need to access capital markets • Well positioned to withstand extended economic or power market downturn

$45.4 $31.9 $22.8 $22.2 $23.9 $23.9 $24.8 $0 $10 $20 $30 $40 $50 2014 2015 2016 2017 2018 2019 2020 $127 $100 $71 $72 $41 $38 $37 $0 $20 $40 $60 $80 $100 $120 $140 2014 2015 2016 2017 2018 2019 2020 21 (1) Excludes unamortized discounts and deferred financing costs. 2014 – 2020: Significant Debt and Cost Reductions ($ millions) Nearly $1.2 billion net reduction in consolidated debt from YE 2014 to estimated YE 2020 Cash Interest Payments General, Administrative and Development Expense $1,755 $1,019 $997 $846 $727 $649 $578 6.9 5.7 5.6 3.3 4.5 3.8 3.6 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 YE 2014 YE 2015 YE 2016 YE 2017 YE 2018 YE 2019 YE 2020 Consolidated debt (millions) (2) Leverage ratio

0.0 50.0 100.0 150.0 200.0 250.0 300.0 2021 2022 2023 2024 Thereafter Debt Repayment Profile at December 31, 2020 (1) ($ millions) 22 (1) ) Includes Company’s proportional share of debt at Chambers of $30.7 million, which is not consolidated because the project is 40 % owned. (2) Bullet percentage includes medium term notes and Series E convertible debentures. Note: C$ denominated debt was converted to US$ using exchange rate of 1.2732 at 12/31/20. • Project - level non - recourse debt: $45.5, including $30.7 at Chambers (equity method); amortizes over the life of the project PPAs (through 2025) • APLP Holdings Term Loan: $307.5; 1% annual amortization and mandatory prepayment via the greater of a 50% sweep or such other amount that is required to achieve a specified targeted debt balance (combined average annual repayment of ~ $74); projected to fully amo rti ze by maturity • APC Convertible Debentures: $90.3 (US$ equivalent) of Series E convertible debentures (maturing Jan. 2025) • APLP Medium - Term Notes: $164.9 (US$ equivalent) due in June 2036 Total $608 $105 $119 $270 APLP Holdings Term Loan Project - level debt APLP Medium - term Notes (US$ equivalent) APC Convertible Debentures (US$ equivalent) 58% amortizing, 42% bullet (2) $75 $40 Series E (2025) MTNs (2036)

46 34 21 6 2 308 215 109 49 13 90 90 90 90 90 165 165 165 165 165 0 100 200 300 400 500 600 700 12/31/20 12/31/21 12/31/22 12/31/23 12/31/24 23 Expected Debt Repayment (December 31, 2020 – Year End 2024): • APLP Holdings Term Loan: Will fully amortize by maturity (April 2025) • Project Debt: Amortize $44, ending balance $2 (Cadillac) • APC Convertible Debentures: No repayment required prior to 2025 maturity, but callable at par in 2023 • Total Remaining Repayment through 2024: $339 (56%) Projected Debt Balances through 2024 (1) ($ millions) APLP Holdings Term Loan Project - level debt APLP Medium - term Notes (US$ equiv.) APC Convertible Debentures (US$ equiv.) $608 $309 $504 $384 $270 Actual (1) ) Includes Company’s proportional share of debt at Chambers of $30.7 million, which is not consolidated because the project is 40 % owned Note: C$ denominated debt was converted to US$ using exchange rate of 1.2732 at 12/31/20.

Capitalization ($ millions) 24 Dec. 31, 2020 Sep. 30, 2020 Long - term d ebt, incl. current portion (1) APLP Medium - Term Notes (2) $164.9 $157.4 Revolving credit facility - - Term Loan 307.5 326.0 P roject - level debt (non - recourse) 14.8 15.6 Convertible debentures (2) 90.3 86.2 Total long - term debt, incl. current portion $577.5 78% $585.2 83% Preferred shares (3) 168.8 23% 168.8 24% Common equity (4) (10.3) (1)% (49.5) (7)% Total shareholders equity $158.5 22% $119.3 17% Total capitalization $736.0 100% $704.5 100% (1) Debt balances are shown before unamortized discount and unamortized deferred financing costs. (2) Period - over - period change due to F/X impacts. (3) Par value of preferred shares was approximately $135 million and $129 million at December 31, 2020 and September 30, 2020, respectively. (4) Common equity includes other comprehensive income and retained deficit. Note: Table is p resented on a consolidated basis and excludes equity method projects

Capital Summary at December 31, 2020 ($ millions) (1) The interest rate is reduced by 25 basis points if the Company achieves a leverage ratio of 2.75 times or lower. (2) Set on November 30, 2020 for March 31, 2020 dividend payment. Will be reset quarterly based on sum of the Canadian Government 90 - day Treasury Bill yield (using the three - month average result plus 4.18%). Note: C$ denominat ed debt was converted to US$ using exchange rate of $1.2732 at 12/31/20. 25 Atlantic Power Corporation Maturity Amount Outstanding Interest Rate Convertible Debentures (ATP.DB.E) 1/2025 $90.3 (C$115.0) 6.00% APLP Holdings Limited Partnership Maturity Amount Interest Rate Revolving Credit Facility 4/2025 $0 LIBOR + 2.50% (1) Term Loan 4/2025 $307.5 4.70% Atlantic Power Limited Partnership Maturity Amount Interest Rate Medium - term Notes 6/2036 $164.9 (C$210) 5.95% Preferred shares (AZP.PR.A) N/A $68.0 (C$86.6) 4.85% Preferred shares (AZP.PR.B) N/A $47.9 (C$61.0) 5.74% Preferred shares (AZP.PR.C) N/A $18.8 (C$23.9) 4.30% (2) Atlantic Power Transmission & Atlantic Power Generation Maturity Amount Interest Project - level Debt (Cadillac - consolidated) 8/2025 $14.8 6.26% - 6.38% Project - level Debt (Chambers - equity method) 12/2023 $30.7 5.00%

APLP Holdings Term Loan Cash Sweep Calculation 26 APLP Holdings Adjusted EBITDA ( after majority of Atlantic Power G&A expense) Less: Capital expenditures Cash taxes = Cash flow available for debt service Less: APLP Holdings consolidated cash interest (revolver, term loan, MTNs, Cadillac) = Cash flow available for cash sweep Calculate 50% of cash flow available for sweep Compare 50% cash flow sweep to amount required to achieve targeted debt balance Must repay greater of 50% or the amount required to achieve targeted debt balance for that quarter If targeted debt balance is > 50% of cash flow sweep : • Repay amount required to achieve target, up to 100% of cash flow available from sweep • Remaining amount, if any, to Company If targeted debt balance is < 50% of cash flow sweep : • Repay 50% minimum • Remaining 50% to Company Expect loan to be fully repaid by maturity from operating cash flow and Manchief sale proceeds Notes: The cash sweep calculation occurs at each quarter - end. Targeted debt balances are specified in the credit agreement for each qua rter through 2022. Through 2022: After 2022: Repay debt using 50% of cash flow available for sweep

APLP Holdings Credit Facilities – Financial Covenants 27 Leverage ratio : Consolidated debt to Adjusted EBITDA , calculated for the trailing four quarters. Consolidated debt includes both long - term debt and the current portion of long - term debt at APLP Holdings, specifically the amount outstanding under the term loan and the amount borrowed under the revolver, if any, the Medium Term Notes, and consolidated project debt (Cadillac). Adjusted EBITDA is calculated as the Consolidated Net Income of APLP Holdings plus the sum of consolidated interest expense, tax expense, depreciation and amortization expense, and other non - cash charges, minus non - cash gains. The Consolidated Net Income includes an allocation of the majority of Atlantic Power G&A expense. It also excludes earnings attributable to equity - owned projects but includes cash distributions received from those projects. Interest Coverage ratio : Adjusted EBITDA to consolidated cash interest payments , calculated for the trailing four quarters. Adjusted EBITDA is defined above. Consolidated cash interest payments include interest payments on the debt included in the Consolidated debt ratio defined above. Note, the project debt, Project Adjusted EBITDA and cash interest expense for Piedmont are not included in the calculation of these ratios because the project is not included in the collateral package for the credit facilities. Fiscal Quarter Leverage Ratio Interest Coverage Ratio 12/31/2020 4.25:1.00 3.50:1.00 3/31/2021 4.25:1.00 3.50:1.00 6/30/2021 4.25:1.00 3.75:1.00 9/30/2021 4.25:1.00 3.75:1.00 12/31/2021 4.25:1.00 3.75:1.00 3/31/2022 4.25:1.00 3.75:1.00 6/30/2022 4.25:1.00 4.00:1.00 9/30/2022 4.25:1.00 4.00:1.00 12/31/2022 4.25:1.00 4.00:1.00 3/31/2023 4.25:1.00 4.00:1.00

Solid Fuel 21% Natural Gas 55% Hydroelectric 24% Other 2% Curtis Palmer 17% Orlando 16% Nipigon 14% Manchief 8% Chambers 7% Frederickson 8% Cadillac 7% Morris 6% Mamquam 5% Piedmont 4% Calstock 2% Kenilworth 2% Tunis 2% Twelve months ended December 31, 2020 Project Adjusted EBITDA by Project 28 Project Adjusted EBITDA and Cash Flow Diversification by Project (1) Based on Project Adjusted EBITDA for the twelve months ended 12/31/2020, excluding non - operational projects and other projects t hat had negative Project Adjusted EBITDA for the period. (2) Based on $168.5 million in Cash Distributions from Projects for the twelve months ended 12/31/2020. Cash Distributions from Projects by Segment (2) Project Adjusted EBITDA by Segment (1) Solid Fuel 13% Natural Gas 61% Hydroelectric 27%

A - to A+ 64% AA - to AA 22% AAA 7% BBB - to BBB+ 6% B+ 1% NR 1% Less than 1 2% 1 to 5 54% 5 to 10 30% 10 to 15 10% 15+ 2% Remaining PPA Term (years) (1) 29 (1) Weighted by Project Adjusted EBITDA. (2) Primarily merchant energy margin at Morris. (3) Chemours, the smaller of the two offtakers at Chambers, is currently rated B+. Offtaker Credit Rating (1) Contracted projects have an average remaining PPA life of 4.6 years (1) Nearly all PPAs are with investment - grade rated customers (2) Merchant / Market Pricing 2% (2) (3)

Project Income (Loss) by Project ($ millions) 30 (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. Re fle cts new segments adopted in Q4 2019. Prior periods adapted per new segments. Three months ended Twelve months ended December 31, December 31, 2020 2019 2020 2019 Solid Fuel Allendale ($0.3) $0.1 $0.6 $0.8 Cadillac 10.3 (2.8) 10.3 (2.3) Calstock 1.6 (5.1) 4.4 (2.7) Dorchester (0.5) (0.3) (0.2) 0.2 Piedmont (2.2) (2.1) 0.5 2.1 Williams Lake 1.1 (1.9) (1.7) (2.8) Chambers (1) 0.1 (48.6) 4.4 (46.0) Craven (1) 0.3 (0.0) (1.8) 0.2 Grayling (1) 0.3 0.5 (1.1) 0.8 Total 10.8 (60.2) 15.2 (49.8) Natural Gas Kapuskasing (0.1) (0.1) (0.3) (0.3) Kenilworth 0.4 0.1 1.3 (0.1) Manchief 1.3 0.9 5.5 4.6 Morris (0.8) 3.1 3.4 10.2 Naval Station 0.9 (0.1) 0.8 (0.8) Naval Training Center 0.5 (0.1) 0.4 (0.8) Nipigon 7.0 5.7 29.4 22.2 North Bay (0.1) (0.1) (0.3) (0.3) North Island 0.6 (0.0) 0.5 (0.6) Oxnard 0.2 (2.3) (3.5) (4.1) Tunis 0.5 0.5 2.0 2.1 Frederickson (1) 2.1 2.6 8.3 9.1 Orlando (1) 7.0 6.7 34.1 27.5 Total 19.7 16.9 81.7 68.5 Hydroelectric Curtis Palmer 2.6 9.6 17.5 32.4 Koma Kulshan - (0.1) 0.7 (0.1) Mamquam 1.8 0.9 7.5 5.6 Moresby Lake 0.3 (0.9) 0.1 (1.9) Total 4.7 9.4 25.7 36.0 Totals Consolidated projects 25.3 5.0 78.7 63.1 Equity method projects 9.9 (38.8) 43.9 (8.5) Corporate 1.4 0.5 (3.7) (7.9) Total Project Income (loss) $36.6 ($33.4) $118.9 $46.8

31 Project Adjusted EBITDA by Project ($ millions) (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. R efl ects new segments adopted in Q4 2019. Prior periods adapted per new segments. Three months ended December 31, December 31, December 31, 2020 2019 2020 2019 2020 2019 2020 2019 Solid Fuel Allendale ($0.2) $0.2 $0.8 $0.9 Total Project Adjusted EBITDA $51.7 $42.9 $188.7 $196.1 Cadillac 10.8 (1.9) 13.4 3.3 Change in fair value of derivative instruments (1.2) 0.6 (6.8) 8.9 Calstock 1.7 1.2 4.8 5.2 Depreciation and amortization 18.5 20.3 76.6 80.7 Dorchester (0.5) (0.2) (0.1) 0.2 Interest, net 0.7 0.4 2.8 2.5 Piedmont (0.4) (0.3) 7.9 9.4 Impairment - 55.0 - 55.0 Williams Lake 1.6 (1.4) 0.3 (1.0) Insurance (gain) loss (0.7) - (0.7) 1.0 Chambers (1) 2.7 3.0 14.4 13.4 Other project (income) expense (2.2) - (2.1) 1.2 Craven (1) 0.5 0.1 (1.0) 0.4 Project income (loss) $36.6 ($33.4) $118.9 $46.8 Grayling (1) 0.4 0.6 (0.6) 0.9 Administration 8.0 6.6 24.8 23.9 Total 16.6 1.3 39.9 32.7 Interest expense, net 10.7 11.0 42.4 44.0 Natural Gas Foreign exchange loss 11.3 4.8 5.1 11.9 Kapuskasing (0.1) (0.1) (0.3) (0.3) Other expense (income), net - 0.3 (2.7) 1.0 Kenilworth 0.6 0.7 3.5 2.6 Income from operations before income taxes 6.6 (56.1) 49.3 (34.0) Manchief 4.1 3.7 16.5 15.6 Income tax (benefit) expense (29.4) 7.3 (24.2) 9.8 Morris 0.3 4.4 11.1 16.7 Net income (loss) $36.0 ($63.4) $73.5 ($43.8) Naval Station (0.0) (0.1) (0.1) (0.4) Net income (loss) attributable to preferred share Naval Training Center (0.0) (0.0) (0.1) (0.2) dividends of a subsidiary company 1.8 1.9 (0.7) (1.2) Nipigon 8.2 7.5 27.5 23.6 North Bay (0.1) (0.1) (0.3) (0.3) $34.2 ($65.3) $74.2 ($42.6) North Island (0.1) (0.1) (0.3) (0.4) Oxnard 0.2 (1.3) (1.7) (0.0) Tunis 0.8 0.7 3.0 3.1 Frederickson (1) 3.7 4.1 14.4 15.2 Orlando (1) 8.2 8.0 31.7 33.0 Total 25.8 27.6 105.0 108.2 Hydroelectric Curtis Palmer 6.4 13.4 32.9 47.8 Koma Kulshan 0.4 0.3 2.2 1.4 Mamquam 2.2 1.3 9.2 7.2 Moresby Lake 0.6 (0.7) 1.0 (1.0) Total 9.6 14.3 45.3 55.5 Totals Consolidated projects 36.5 27.4 131.2 133.5 Equity method projects 15.5 15.8 58.9 62.9 Corporate (0.3) (0.3) (1.5) (0.3) Total Project Adjusted EBITDA $51.7 $42.9 $188.7 $196.1 Twelve months ended Atlantic Power Corporation Net income (loss) attributable to Three months ended Twelve months ended December 31,

32 Cash Distributions from Projects by Quarter, 2019 - 2020 ($ millions), Unaudited (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. R efl ects new segments adopted in Q4 2019. Prior periods adapted per new segments. Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 YTD 2019 2019 2019 2019 2019 2020 2020 2020 2020 2020 Solid Fuels Allendale - - - $0.8 $0.8 $0.3 ($0.3) $0.4 ($0.6) ($0.2) Cadillac - $1.0 $0.5 - 1.5 - - - 4.3 4.3 Calstock $1.1 1.1 1.8 1.2 5.2 2.9 1.1 1.0 1.6 6.5 Dorchester - - - 0.7 0.7 - (0.3) 0.1 (1.2) (1.4) Piedmont 1.3 0.5 5.5 2.0 9.3 1.0 0.5 5.0 0.8 7.2 Williams Lake 2.5 (0.2) (1.0) (2.6) (1.4) (0.4) 0.9 (5.8) 4.4 (0.8) Chambers (1) - 6.0 - 3.2 9.2 - 2.3 - 3.1 5.4 Craven (1) - - - 0.3 0.3 - - - - - Grayling (1) - - 0.4 0.3 0.6 - - - - - Total 4.8 8.4 7.2 5.8 26.2 3.7 4.3 0.7 12.4 21.1 Natural Gas Kapuskasing (0.1) (0.1) - (0.1) (0.3) - (0.1) (0.1) (0.1) (0.2) Kenilworth 0.9 0.9 1.3 0.5 3.6 0.4 0.8 1.3 0.1 2.6 Manchief 3.4 3.6 2.6 6.0 15.6 3.3 3.2 5.1 4.7 16.3 Morris 5.7 4.0 3.4 4.2 17.3 0.3 7.2 1.7 2.4 11.6 Naval Station 1.2 (0.1) (0.4) (0.1) 0.6 - - 0.2 (0.6) (0.4) Naval Training Center (0.2) (0.1) (0.4) (0.1) (0.7) - (0.1) (1.0) (0.1) (1.3) Nipigon 9.8 5.4 4.7 6.1 26.0 8.3 6.6 5.5 7.0 27.4 North Bay (0.1) (0.1) - (0.1) (0.3) (0.1) (0.1) (0.1) (0.1) (0.3) North Island (0.3) (0.1) (0.2) (0.2) (0.8) (0.1) (0.1) (0.4) (0.6) (1.2) Oxnard (1.1) (1.9) 4.7 0.3 1.9 (0.6) (0.8) (0.1) 0.1 (1.5) Tunis 1.4 0.8 0.8 0.6 3.6 0.8 0.8 0.8 0.6 3.1 Frederickson (1) 3.8 2.8 4.5 4.3 15.4 3.7 3.8 3.1 4.1 14.7 Orlando (1) 1.9 10.1 10.6 10.3 32.9 1.6 8.8 10.9 10.6 31.8 Total 26.2 25.1 31.7 31.8 114.8 17.6 30.0 27.0 28.1 102.6 Hydroelectric Curtis Palmer 14.3 15.2 7.6 10.3 47.4 13.7 13.3 2.6 4.1 33.7 Koma Kulshan 0.3 0.6 0.1 0.4 1.3 0.2 0.7 0.9 0.3 2.1 Mamquam 1.7 2.4 2.1 1.2 7.4 1.4 1.9 3.3 2.1 8.7 Moresby Lake 0.5 (0.3) (0.3) (0.3) (0.4) (0.5) 0.3 0.3 0.2 0.2 Total 16.8 17.8 9.5 11.7 55.7 14.8 16.2 7.0 6.8 44.8 Total Cash Distributions $47.8 $51.3 $48.3 $49.3 $196.7 $36.2 $50.4 $34.7 $47.2 $168.5 Consolidated 42.1 32.4 32.8 31.0 138.3 30.9 35.5 20.6 29.5 116.6 Equity Method 5.7 18.9 15.4 18.3 58.4 5.3 14.9 14.0 17.7 51.9

Non - GAAP Disclosures 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 . The most directly comparable GAAP measure is Project income (loss) . Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non - cash impairment charges) and changes in the fair value of derivative instruments . Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors . A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net income (loss) by segment and on a consolidated basis is provided on pages 34 - 35 . Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies . 33 2020 2019 2020 2019 Net income (loss) attributable to Atlantic Power Corporation $34.2 ($65.3) $74.2 ($42.6) Net income (loss) attributable to preferred share dividends of a subsidiary company 1.8 1.9 (0.7) (1.2) Net income (loss) $36.0 ($63.4) $73.5 ($43.8) Income tax (benefit) expense (29.4) 7.3 (24.2) 9.8 Income (loss) from operations before income taxes 6.6 (56.1) 49.3 (34.0) Administration 8.0 6.6 24.8 23.9 Interest expense, net 10.7 11.0 42.4 44.0 Foreign exchange loss 11.3 4.8 5.1 11.9 Other expense (income), net - 0.3 (2.7) 1.0 Project income $36.6 ($33.4) $118.9 $46.8 Reconciliation to Project Adjusted EBITDA Change in the fair value of derivative instruments ($1.2) $0.6 ($6.8) $8.9 Depreciation and amortization 18.5 20.3 76.6 80.7 Interest, net 0.7 0.4 2.8 2.5 Impairment - 55.0 - 55.0 Insurance (gain) loss (0.7) - (0.7) 1.0 Other project (income) expense (2.2) - (2.1) 1.2 Project Adjusted EBITDA $51.7 $42.9 $188.7 $196.1 December 31, December 31, Three months ended Twelve months ended

34 Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment ($ millions) Three months ended December 31, 2020 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net income (loss) attributable to Atlantic Power Corporation $10.8 $19.7 $4.7 ($1.0) $34.2 Net income attributable to preferred share dividends of a subsidiary company - - - 1.8 1.8 Net income 10.8 19.7 4.7 0.8 36.0 Income tax benefit - - - (29.4) (29.4) Net income (loss) before income taxes 10.8 19.7 4.7 (28.6) 6.6 Administration - - - 8.0 8.0 Interest expense, net - - - 10.7 10.7 Foreign exchange loss - - - 11.3 11.3 Other income, net - - - - - Project income 10.8 19.7 4.7 1.4 36.6 Change in fair value of derivative instruments - 0.5 - (1.7) (1.2) Depreciation and amortization 5.8 7.8 4.9 - 18.5 Interest, net 0.7 - - - 0.7 Insurance gain (0.7) - - - (0.7) Other project income - (2.2) - - (2.2) Project Adjusted EBITDA $16.6 $25.8 $9.6 ($0.3) $51.7 Three months ended December 31, 2019 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($60.2) $16.9 $9.4 ($31.4) ($65.3) Net income attributable to preferred share dividends of a subsidiary company - - - 1.9 1.9 Net (loss) income (60.2) 16.9 9.4 (29.5) (63.4) Income tax expense - - - 7.3 7.3 Net (loss) income before income taxes (60.2) 16.9 9.4 (22.2) (56.1) Administration - - - 6.6 6.6 Interest expense, net - - - 11.0 11.0 Foreign exchange loss - - - 4.8 4.8 Other expense, net - - - 0.3 0.3 Project (loss) income (60.2) 16.9 9.4 0.5 (33.4) Change in fair value of derivative instruments - 1.4 - (0.8) 0.6 Depreciation and amortization 6.1 9.3 4.9 - 20.3 Interest, net 0.4 - - - 0.4 Impairment 55.0 - - - 55.0 Other project income - - - - - Project Adjusted EBITDA $1.3 $27.6 $14.3 ($0.3) $42.9

35 Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment ($ millions) Twelve months ended December 31, 2020 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net income (loss) attributable to Atlantic Power Corporation $15.2 $81.7 $25.7 ($48.4) $74.2 Net loss attributable to preferred share dividends of a subsidiary company - - - (0.7) (0.7) Net income (loss) 15.2 81.7 25.7 (49.1) 73.5 Income tax benefit - - - (24.2) (24.2) Net income (loss) before income taxes 15.2 81.7 25.7 (73.3) 49.3 Administration - - - 24.8 24.8 Interest expense, net - - - 42.4 42.4 Foreign exchange loss - - - 5.1 5.1 Other income, net - - - (2.7) (2.7) Project income (loss) 15.2 81.7 25.7 (3.7) 118.9 Change in fair value of derivative instruments - (8.9) - 2.1 (6.8) Depreciation and amortization 22.7 34.3 19.6 - 76.6 Interest, net 2.7 - - 0.1 2.8 Insurance gain (0.7) - - - (0.7) Other project income - (2.1) - - (2.1) Project Adjusted EBITDA $39.9 $105.0 $45.3 ($1.5) $188.7 Twelve months ended December 31, 2019 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($49.8) $68.5 $36.0 ($97.3) ($42.6) Net loss attributable to preferred share dividends of a subsidiary company - - - (1.2) (1.2) Net (loss) income (49.8) 68.5 36.0 (98.5) (43.8) Income tax expense - - - 9.8 9.8 Net (loss) income before income taxes (49.8) 68.5 36.0 (88.7) (34.0) Administration - - - 23.9 23.9 Interest expense, net - - - 44.0 44.0 Foreign exchange loss - - - 11.9 11.9 Other expense, net - - - 1.0 1.0 Project (loss) income (49.8) 68.5 36.0 (7.9) 46.8 Change in fair value of derivative instruments - 1.4 - 7.5 8.9 Depreciation and amortization 23.9 37.2 19.5 0.1 80.7 Interest, net 2.6 (0.1) - - 2.5 Impairment 55.0 - - - 55.0 Insurance loss 1.0 - - - 1.0 Other project expense - 1.2 - - 1.2 Project Adjusted EBITDA $32.7 $108.2 $55.5 ($0.3) $196.1