2017 Annual and Special Meeting of Shareholders June 20, 2017

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 27A of the U.S. Securities Act of 1933, as amended, and Section 21E 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 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. Although the forward-looking statements contained in this news release 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 news release 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 news release, 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, 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 slides 22 and 23. 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 (Epsilon Power Partners and 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. Reference 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.

Progress on Debt Reduction and Leverage ($ millions) (Unaudited) 3 (a) Assumes $150 million of debt repayments in 2017 (b) Excludes unamortized discounts and deferred financing costs (c) See page 2 of this presentation for definition Net reduction in consolidated debt of $905 million since YE 2013 (48%); cash interest payments reduced $60 million or 46% $1,876 $1,755 $1,019 $997 $971 $847 9.5 6.9 5.7 5.6 5.4 < 4x 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 YE 2013 YE 2014 YE 2015 YE 2016 3/31/2017 Proj. YE 2017 (a) Consolidated debt (b) Leverage ratio (c)

Debt Repayment Profile at March 31, 2017 ($ millions) Includes Company’s share of debt at equity-owned projects 4 Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.3299. Total at March 31, 2017: $1,014 $85 (US$) 43% bullet, 57% amortizing $154 $177 $116 $139 $164 $92 $88 But committed to repaying at least $123 (total of $150 for the year) Total at Year-End 2013: $1,979 75% bullet, 25% amortizing Majority of debt is amortizing (repaid each year from operating cash flows) Remaining amount of term loan to be repaid at maturity 0 20 40 60 80 100 120 140 160 180 200 Rest of 2017 2018 2019 2020 2021 2022 2023 Thereafter Bullet maturity Amortizing debt

5 Q1 2017 – Year-end 2020: Assumes only required debt amortization each year: - Term loan – repayment of $335 million through 2020 - Project debt – amortization of $39 million through 2020 (Company’s proportional share) Results in annual interest cost savings of more than $20 million by 2021 Note, Company is committed to repaying $150 million or more of debt in 2017, or $38 million more than is required. That additional repayment is not reflected in these projected debt balances. Assumes the following bullet maturities are refinanced: Piedmont project debt maturity of $54 million in August 2018 Convertible debenture maturities totaling $103 million (U.S. dollar equivalent) in 2019 Projected Debt Balances through 2020 ($ millions) Includes Company’s share of debt at equity-owned projects Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.3299. Cumulative paydown of debt drives interest cost savings of more than $20 million $1,014 $929 $830 $756 $640 $0 $200 $400 $600 $800 $1,000 $1,200 3/31/17 12/31/17 12/31/18 12/31/19 12/31/20

G&A and Development Expenses ($ millions) 6 2016 level represents a 58% reduction from 2013 $54 $45 $32 $23 $0 $10 $20 $30 $40 $50 $60 2013 2014 2015 2016

Capital Allocation 7 Sources Cash flow remaining after required repayment of project debt and term loan + Net proceeds from refinancings = Discretionary cash available for allocation Uses Optimization investments at attractive cash-on-cash returns Cumulative investment of $27 million through 2017 $8 million cash return in 2016; expected cash return of $12 million in 2017 Repurchases of convertible debentures at discount to par Through normal course issuer bid and substantial issuer bid Total $81.5 million in 2016 Repurchases of common shares at discount to Company’s estimates of intrinsic value Total nearly 8.1 million common shares from Dec. 2015 through YE 2016 Total cost of $19.6 million; average price $2.42 per share 6.6% reduction in shares outstanding

Operations Update 8 FY 2015 FY 2016 Q1 2017 95.2% 93.3% 96.8% Cost Reduction Initiatives Safety: Total Recordable Incident Rate (1) 2014 BLS data, generation companies = 1.1 (2) 2015 BLS data, generation companies = 1.4 Industry avg (1) Availability (weighted average) Industry avg (2) Optimization Initiatives Invested a total of $27 million in 2013 through 2017 Most significant investments were at Nipigon, Morris and Curtis Palmer Cash return of approximately $8 million in 2016 Expect cash return of approximately $12 million in 2017 Assumes normal water flows at Curtis Palmer Future projects to be relatively modest Shifting focus to operating costs and PPA-related investments Eliminated layer of management between SVP Operations and plant managers Analysis and benchmarking of operation and maintenance costs underway Evaluate maintenance intervals, operational parameters, etc. Goal - Improve efficiency and operational performance; implement best practices Expect to have more to say in 2H 2017 1.25 1.67 0.7 0 FY 2014 FY 2015 FY 2016 Q1 2017

Commercial Update: Power Purchase Agreement (PPA) Renewals 9 Mitigating Factors Nine PPAs or similar contracts expiring within next five years (through mid-2022) Represent 25% of capacity and 30% of 2016 Project Adjusted EBITDA Difficult power market environment in which to renew or extend expiring contracts Contracts that are extended are likely to produce lower Project Adjusted EBITDA Challenge Recent Accomplishments Areas of Focus Ongoing efforts to replace or renew expiring PPAs Stronger position to withstand downturn as a result of: Overhead cost reductions Lower debt levels and lower interest payments Improved debt maturity profile (reduced refinancing risk) Impact on cash flow is less than on Project Adjusted EBITDA Debt repayment of $374 million through 2020 > $20 million reduction in annual interest costs Use of discretionary cash for additional debt reduction Other potential offsets to impact on EBITDA Evaluation of operating costs currently underway Review of overhead costs if PPAs expire without renewal Longer term, possible contribution from growth initiatives Expect to make some progress this year on contracts expiring in 2018 These account for the majority of the expirations in the next five years In discussions with San Diego Gas & Electric on PPAs and with Navy on land use licenses at two of the three plants Submitted second-round proposal in Navy solicitation Also considering other contracting options for San Diego plants and Oxnard Discussions with BC Hydro on potential short-term PPA extension at Williams Lake Revised contractual arrangements for three Ontario plants (Kapuskasing, North Bay and Nipigon), whereby plants are currently in lay-up status Economically beneficial to Company, customer and Province Kapuskasing and North Bay contracts expire at YE 2017; plants are currently in lay-up status Reached settlement of Global Adjustment dispute with OEFC Additional revenues in 2017 of Cdn$36 million (US$27 million)

Improved Shareholder Alignment 10 Recent Share Purchases by Insiders Since last year’s Annual Meeting, management and directors have purchased approximately 269,000 shares Average price of $2.46 per share Since May 2015, purchases by insiders have totaled nearly 1.6 million shares Average price of $2.32 per share Increased Share Ownership Requirements CEO: Minimum of 5x base salary, up from 3x EVPs: Minimum of 3x base salary, up from 2x SVPs: Minimum of 2x base salary; no requirement previously Directors: Minimum of 3x total compensation; previously had been 3x base cash compensation Increased share ownership further ensures that interests of Board and management are aligned with shareholders

Appendix 11

Business Model – How We Mitigate Risk 12 Atlantic Power is an Independent Power Producer (IPP), not a utility Long-term Power Purchase Agreements (PPAs) Competitive business – not a monopoly Greater sensitivity to supply/demand for power in those markets where PPAs are expiring Power prices currently quite low How do we mitigate risk? Reduce debt – reduce cash interest payments – improve debt maturity profile Reduce overhead cost structure Significant progress to date on debt and cost reductions Now in a better position if power prices stay low for longer than we expect Continue working on PPA extensions (with a focus on 2018)

Significant Accomplishments in 2016 and Early 2017 Financial Successfully refinanced term loan and revolver, increasing size of loan, gaining flexibility on revolver, and extending maturity dates for both Subsequently repriced both facilities (April 2017), reducing spread by 75 basis points Reduced consolidated debt by approximately $22 million in 2016 and by approximately $905 million cumulatively since 2013 Reduced cash interest payments by approximately $60 million since 2013 (46%) Leverage ratio has improved from 9.5x at year end 2013 to 5.4x at March 31, 2017 Reduced corporate overhead costs another $9 million in 2016 (28%); cumulative reduction of $31 million or 58% since 2013 Reported $112 million of cash from operating activities in 2016, up from $87 million in 2015; increase attributable to lower cash interest payments and lower overheads Improved liquidity to $214 million at March 31, 2017; includes $56 million of discretionary cash Capital allocation Continued to make investments in fleet at attractive returns; cumulative since 2013 of approximately $27 million, generating $8 million of cash flow in 2016 and cumulative cash return of $19.5 million Repurchased 8.1 million shares in 2016 (6.6% of shares outstanding), representing a total investment of $19.6 million (average price $2.42) Significant discount to Company’s estimate of intrinsic value 13

Significant Accomplishments in 2016 and Early 2017 (continued) Culture Improved safety performance; total recordable injury rate for FY 2016 better than industry average Continued to develop a culture of servant leadership throughout the Company Operational Maintained strong plant availability (93%) and operating performance Completed major scheduled outages on time and on budget Commercial Agreed to contract revisions for three plants in Ontario that produced economic benefits for the Company, the customer and the province Continued to pursue extensions or renewals of Power Purchase Agreements (PPAs) expiring in 2018; expect to execute one or more in 2017 Stronger financial position, improved cost profile and increased liquidity put Company in a better position to withstand extended downturn in a highly cyclical business and: Pay down additional debt Repurchase shares at discount to our estimate of intrinsic value Work toward PPA renewals Begin to implement a growth strategy 14

Atlantic Power Corporation Atlantic Power Transmission & Atlantic Power Generation Project Location Type Economic Interest Net MW Contract Expiry Cadillac Michigan Biomass 100% 40 12/2028 Chambers New Jersey Coal 40% 105 12/2024 Orlando Florida Nat. Gas 50% 65 12/2023 Piedmont (1) Georgia Biomass 100% 55 12/2032 Selkirk New York Nat. Gas 17.7% 61 Merchant Koma Kulshan Washington Hydro 49.8% 6 12/2037 Atlantic Power Limited Partnership Project Location Type Economic Interest Net MW Contract Expiry Calstock Ontario Biomass 100% 35 6/2020 Kapuskasing Ontario Nat. Gas 100% 40 12/2017 Mamquam B.C. Hydro 100% 50 9/2027 Morseby Lake B.C. Hydro 100% 6 8/2022 Nipigon Ontario Nat. Gas 100% 40 12/2022 North Bay Ontario Nat. Gas 100% 40 12/2017 Tunis Ontario Nat. Gas 100% 40 11/2032 (2) Williams Lake B.C. Biomass 100% 66 3/2018 Curtis Palmer New York Hydro 100% 60 12/2027 Kenilworth New Jersey Nat. Gas 100% 29 9/2018 Morris Illinois Nat. Gas 100% 177 12/2034 Frederickson Washington Nat. Gas 50.15% 125 8/2022 Manchief Colorado Nat. Gas 100% 300 4/2022 Naval Station California Nat. Gas 100% 47 12/2019(3) Naval Training California Nat. Gas 100% 25 12/2019(3) North Island California Nat. Gas 100% 40 12/2019(3) Oxnard California Nat. Gas 100% 49 5/2020 Power Projects 15 Canada East U.S. West U.S. (1) Excluded from the APLP Holdings collateral package (2) 15-year contract commences between Nov. 2017 and Jun. 2019 (3) May terminate earlier if land use agreements with U.S. Navy expiring in Feb. 2018 are not extended APLP Holdings Limited Partnership

Commercial Update: Power Market Environment 16 Most of our markets (U.S. and Canada) are impacted by an oversupply of generation Low current and projected load growth Public policy preference / subsidy for renewables New gas-fired merchant construction driven by low natural gas prices and low-cost capital Lower spark spreads and low capacity values The Company’s improved financial position enables us to withstand the current down cycle Significant paydown of debt and reshaping of maturity profile More than 50% reduction in overhead costs Current market conditions have modest impact on Company in near term Most output is sold under PPAs with limited exposure to market price sensitivity Exposure to market pricing is currently limited – Selkirk; Morris (in part); some market price sensitivity – Chambers, Kenilworth Market conditions impact plants with expiring PPAs Next five years: PPAs expire for nine projects, 25% of MW, 30% of 2016 Project Adjusted EBITDA Ability to renew expiring PPAs; economic terms of renewal

Liquidity ($ millions) 17 Unaudited 12/31/16 3/31/17 Revolver capacity $200.0 $200.0 Letters of credit outstanding (81.5) (77.5) Revolver availability 118.5 122.5 Unrestricted cash 85.6 91.5 Total Liquidity $204.1 $214.0 Note: Liquidity does not include restricted cash of $10.0 million at March 31, 2017 and $13.3 million at December 31, 2016. Includes ~ $66 at APC (parent) Balance is at the plants or other subsidiaries ~ ($10) Needed for working capital purposes ~ $56 Discretionary cash available

Q1 2017 Project Adjusted EBITDA ($ millions) 18 $62.5 $63.8 Q1 2016 Q1 2017 $(5) Morris Higher fuel prices and lower fuel optimization, non-recurrence of return on a construction project in the year-ago period, and lower PJM capacity price North Bay Fuel savings driven by expiration of out-of-market fuel contract and enhanced dispatch contracts $3 $(2) Mamquam Lower water flows (typical flows in ‘17 versus very high flows in ‘16) Kapuskasing Fuel savings driven by expiration of out-of-market fuel contract and enhanced dispatch contracts $4 $(1) Calstock Lower waste heat and expiration of fuel adder Orlando Favorable fuel swap settlement impact $2 Naval Station Hot gas path overhaul in prior period $1 $(1) Other, net

Three months ended March 31, Unaudited 2017 2016 Change Cash provided by operating activities $34.1 $29.4 $4.7 Significant uses of cash provided by operating activities: Term loan repayments (1) (25.0) (25.3) 0.3) Project debt amortization (2.3) (2.1) (0.2) Capital expenditures (2.0) (0.7) (1.3) Preferred dividends (2.1) (2.0) (0.1) Q1 2017 Cash Flow Results ($ millions) 19 Primary drivers: Deferred revenues under OEFC Settlement +7.9 Kap/N.Bay/Nipigon revised contracts +6.6 Lower results at Morris and Mamquam (6.4) Higher cash interest payments (2.9) (1) Includes 1% mandatory annual amortization and targeted debt repayments.

20 Continuing Operations $209 Actual $202 FY 2015 FY 2016 $(10) Morris Extensive planned maintenance outage in Q3 2016 Mamquam Higher water flows and lower maintenance expense $7 $(3) Curtis Palmer Lower water flows Manchief Lower maintenance expense (2015 scheduled outage) $7 $(9) Other projects, net Higher maintenance at Oxnard; lower waste heat, higher fuel costs due to contracted escalation and severance at Kapuskasing, North Bay and Nipigon $(2) Calstock Contractual price adjustment and lower waste heat Un-allocated Corporate Decreased compensation, development and related expenses $2 Orlando Higher capacity revenue due to contracted escalation and lower fuel costs $2 Guidance was $205 to $215; shortfall attributable to lower water flows at Curtis Palmer and lower waste heat in Ontario FY 2016 Project Adjusted EBITDA ($ millions)

FY 2016 Cash Flow Results ($ millions) 21 Primary drivers: Lower Proj. Adj. EBITDA (6.7) Lower cash interest +29.3 Lower Corporate G&A +6.8 Wind business (Disc. Ops.) (21.9) Changes in other operating +16.9 balances/write off DFC (1) Includes 1% mandatory annual amortization and targeted debt repayments. Three months ended December 31, 2016 2015 Change Cash provided by operating activities $19.9 $19.7 $0.2 Severance and/or restructuring charges included above: - (0.1) 0.1 Significant uses of cash provided by operating activities: Term loan repayments(1) (15.0) (11.8) (3.2) Project debt amortization (3.0) (4.4) 1.4 Capital expenditures (0.7) (1.9) 1.2 Preferred dividends (2.1) (2.1) - Twelve months ended December 31, 2016 2015 Change Cash provided by operating activities $111.8 $87.4 $24.4 Severance and/or restructuring charges included above: (0.2) (3.9) 3.7 Significant uses of cash provided by operating activities: Term loan repayments(1) (85.5) (68.3) (17.2) Project debt amortization (11.1) (14.9) 3.8 Capital expenditures (7.2) (11.3) 4.1 Preferred dividends (8.5) (8.8) 0.3 Distribution to non-controlling interests - (3.8) 3.8 2015 attributable to Wind business

22 Non-GAAP Disclosures (Q1 2017 and Q1 2016) 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 below. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. Unaudited Three months ended March 31 2017 2016 Net loss attributable to Atlantic Power Corporation ($2.7) ($14.9) Net income attributable to preferred share dividends of a subsidiary company 2.1 2.0 Net loss ($0.6) ($12.9) Income tax benefit (0.3) 1.6 Loss from operations before income taxes (0.9) (11.3) Administration 6.4 6.1 Interest expense, net 17.3 16.6 Foreign exchange loss 2.5 19.8 Other income, net - (2.5) Project income $25.3 $28.7 Reconciliation to Project Adjusted EBITDA Depreciation and amortization $34.9 $29.9 Interest expense, net 2.4 2.5 Change in the fair value of derivative instruments 1.2 1.2 Other expense - 0.2 Project Adjusted EBITDA $63.8 $62.5

Non-GAAP Disclosures (FY 2016 and FY 2015) 23 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 below. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. Unaudited Twelve months ended December 31 2016 2015 Net (loss) income attributable to Atlantic Power Corporation ($122.4) ($62.4) Net income attributable to preferred share dividends of a subsidiary company 8.5 8.8 Net (loss) attributable to noncontrolling interests - (11.0) Net loss ($113.9) ($64.6) Net income from discontinued operations, net of tax - (19.5) Net income (loss) from continuing operations (113.9) (84.1) Income tax expense (14.6) (30.4) Income (loss) from continuing operations before income taxes (128.5) (114.5) Administration 22.6 29.4 Interest expense, net 106.0 107.1 Foreign exchange loss 13.9 (60.3) Other income, net (3.9) (3.1) Project income (loss) $10.1 ($41.4) Reconciliation to Project Adjusted EBITDA Depreciation and amortization $133.5 $130.1 Interest expense, net 10.9 9.8 Change in the fair value of derivative instruments (37.9) (15.4) Impairment 85.9 127.8 Other (income) expense (0.3) (2.0) Total Project Adjusted EBITDA $202.2 $208.9