Q1 2018 Financial Results Conference Call May 4, 2018

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 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 slides 32 and 33. Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. It is not a non-GAAP measure. Project Adjusted EBITDA, a non-GAAP measure, is the most comparable measure, but it is before debt service, capital expenditures and working capital requirements. The Company has provided a bridge of Project Adjusted EBITDA to Cash Distributions from Projects on slides 31. All amounts in this presentation are in US$ and approximate unless otherwise stated.

3 Q1 2018 Highlights Operations Review Commercial Update / PPAs Financial Results Liquidity and Debt Repayment Profile 2018 Guidance Q&A Agenda

Q1 2018 Highlights 4 Financial Results PPAs Capital Allocation Repurchased $7.4 million of common and $4 million (US$ equivalent) of preferred shares in March and April 2018 under our normal course issuer bid - Average price $2.10 per common share - Returns of 10-11% on repurchases of preferred shares Expected returns on internal investments and equity repurchases superior to what we see externally Merck exercised first one-year renewal option at Kenilworth (to Sept. 30, 2019) Unable to reach agreement on commercial terms with Navy for site control at three San Diego projects Average remaining contract term 6.75 years; two-thirds of estimated Project Adjusted EBITDA in 2018 is from PPAs that expire after 2022 First quarter results keep us on track to achieve our full year 2018 expectations Balance Sheet Repaid $32.4 million of debt during first quarter - On track to repay $100 million for full year 2018 Convertible debenture issuance and subsequent redemptions addressed all but $19 million (US$ equivalent) of 2019 maturities Leverage ratio 3.2 times at March 31, 2018 - Will increase by year-end, then expect decline in 2019 and beyond Liquidity of $205.1 million at March 31, 2018, including ~ $32 million of discretionary cash - Re-priced credit facilities for third time

Q1 2018 Operational Performance: Lower generation primarily due to San Diego PPA expirations, but availability improved 5 Q1 2018 Q1 2017 East U.S. 98.0% 96.8% West U.S. 97.2% 98.6% Canada 99.7% 91.4% Total 98.3% 96.4% Aggregate Power Generation Q1 2018 vs. Q1 2017 (Net GWh) East U.S. West U.S. Canada Total 11.3% (30.8%) 4.4% (2.8%) Higher availability factor: Generation is down: Naval Station / North Island / NTC ceased operations in February 2018 Frederickson lower demand due to mild ambient temperatures + Manchief higher dispatch Morris and Chambers higher dispatch due to colder ambient temperatures Orlando and Piedmont maintenance outages performed in prior year Mamquam higher river flows + Mamquam outage in prior period + Piedmont outage in prior period - Oxnard forced outage Safety: Total Recordable Incident Rate (1) 2015 BLS data, generation companies = 1.4 (2) 2016 BLS data, generation companies = 1.0 Industry avg (1) Availability (weighted average) Industry avg (2) 590 656 351 243 212 221 1,153 1,121 Q1 2017 Q1 2018 Q1 2017 Q1 2018 Q1 2017 Q1 2018 Q1 2017 Q1 2018 1.67 0.69 1.16 0 FY 2015 FY 2016 FY 2017 Q1 2018

Operations Update 6 Plant is currently mothballed Expected return to service Nov. 1, 2018 under long-term EDC (through Dec. 2022) To return in simple-cycle model and operate on a flexible basis (when needed/economic) LTEDC provides for monthly capacity-type payments Will earn energy revenue when operates, but capacity factor expected to be low Improved economics vs. original PPA Tunis Planned Restart Targeting commercial operation in July 2018 Simple-cycle operation under 15-year PPA Restart maintenance is on track Gas turbine overhaul is complete Generator overhaul is complete Control system upgrade underway Estimated cost of $5 - $6 million; majority to be incurred and expensed in 2018 Significant 2018 Outages Manchief – GT11 overhaul began mid-April; expected completion late-May Kenilworth – Gas turbine modified overhaul underway; expected completion mid-June; continuing to operate on lease engine Mamquam – replacing runners at both units; expected to take a total of six weeks (mid-August through September) Analysis & Benchmarking for Cost Savings Internal benchmarking of plants completed Close to selection of outside consultant for external benchmarking Deployed Predictive Analytic software (PRiSM) at three sites in 2017 Plan to deploy at two to three additional sites in 2018 to improve reliability and to enhance condition-based maintenance Nipigon Long-term Enhanced Dispatch Contract

Commercial Update: PPA Renewal Status 7 Land use agreements with U.S. Navy expired; plant operations ceased Feb. 7, 2018 - Proposal to Navy has not resulted in agreement that would provide us site control - Unlikely to obtain site control at any of the three sites - Proceeding with plans to decommission the sites; in process of defining scope and timing of work with the Navy PPAs with San Diego Gas & Electric (SDG&E) for all three plants were terminated effective March 1, 2018 - California Public Utilities Commission (CPUC) approved early termination of the PPAs - 30-day appeal period has expired - No early termination penalties were incurred Have signed new seven-year contracts with SDG&E (Naval Station, North Island) and Southern California Edison (NTC) - However, further operations are dependent on site control - Naval Station and North Island contracts have been approved by CPUC - NTC contract is pending CPUC approval Naval Station, NTC and North Island (San Diego)

Commercial Update: PPA Renewal Status (continued) 8 Reached agreement for short-term contract extension in December 2017 Short-term extension runs from April 2, 2018 to June 30, 2019 (or Sept. 30, 2019 at BC Hydro’s option) In early April, BC Utilities Commission ordered a written hearing on contract extension - Proceeding commenced in late April - Timeframe for a ruling not determined - Either party has right to terminate if contract does not receive regulatory approval Currently expect de minimis Project Adjusted EBITDA contribution during short-term extension Written hearing regarding appeal of amended air permit (to burn alternative fuels) currently underway - Decision expected Q4 2018 In late April, Merck exercised its first one-year renewal option of the Energy Services Agreement (ESA) ESA now expires Sept. 30, 2019 Substantially similar to original ESA terms Continuing to discuss with Merck what role we might play in meeting its short- and long-term energy requirements Williams Lake (British Columbia) Kenilworth (New Jersey)

Q1 2018 Financial Highlights and Recent Developments 9 Q1 2018 Financial Results Continued Debt Repayment Project Adjusted EBITDA Q1 2018 $53.4 million vs Q1 2017 $63.8 million PPA expirations (Kapuskasing, North Bay, San Diego projects) Tunis restart expenses + Morris (higher generation, energy and capacity prices) Cash Provided by Operating Activities Q1 2018 $50.3 million vs Q1 2017 $34.1 million Lower Project Adjusted EBITDA + Changes in working capital + Lower cash interest payments Amortized $30 million of term loan and $2.4 million of project debt in Q1 2018 Consolidated leverage ratio at 3/31/18 of 3.2 times Liquidity at 3/31/18 of $205.1 million, including ~ $32 million of discretionary cash

Q1 2018 Financial Highlights and Recent Developments (continued) 10 Improved Debt Maturity Profile NCIB Update Managing Interest Costs and Risk March 2018 repurchases 237,500 Series 1 preferred shares at Cdn$15.25/share 83,095 Series 3 preferred shares at Cdn$17.80/share - Total cost Cdn$5.1 million ($4.0 million US$ equivalent) 3.0 million common shares at average price of $2.10/share - Total cost $6.4 million April 2018 repurchases 0.5 million common shares at average price $2.14/share - Total cost $1.1 million In January, issued Cdn$115 million of Series E 6.00% convertible debentures maturing in 2025 In March, used proceeds to redeem: - US$42.5 million of Series C convertible debentures maturing in June 2019 - Cdn$56.2 million of Series D convertible debentures maturing in Dec. 2019 Only 2019 bullet maturity: Cdn$24.7 million remaining Series D convertible debentures No bullet maturities in 2018, 2020 or 2021; revolver matures in April 2022 In April, executed third re-pricing of term loan and revolver - Reduced spread by another 50 bp, to 300 bp over LIBOR - Savings (before transaction cost) of $2.1 million in 2018 and $8.5 million over remaining term Exposure to higher interest rates is modest - At 3/31/18, ~ 81.5% of our debt was fixed rate or swapped (will be ~ 95% in July) - ~$600 thousand impact in remainder 2018 and ~$450 thousand in 2019, per 100 bp change in rates

Q1 2018 Project Adjusted EBITDA ($ millions) 11 $63.8 $53.4 Q1 2017 Q1 2018 Morris Higher PJM energy prices and generation, higher PJM capacity price, steam and ancillary services 3.6 Nipigon Contractual rate increase 1.7 Williams Lake Higher contractual firm energy revenue 1.0 North Bay PPA Expiration 12/31/17 (7.4) Kapuskasing PPA Expiration 12/31/17 (7.5) San Diego PPA Expirations(1) at Naval Station, North Island and NTC/MCRD (2.7) Tunis Maintenance overhauls in preparation for July 2018 restart (2.6) Mamquam Higher river flows, maintenance timing 0.9 All Others 2.7 PPA Expirations = $(17.6) million Plants ceased operations on 2/7/18 and PPA’s were terminated effective 3/1/18

Three months ended March 31, Unaudited 2018 2017 Change Cash provided by operating activities $50.3 $34.1 $16.2 Significant uses of cash provided by operating activities: Term loan repayments (1) (30.0) (25.3) (4.7) Project debt amortization (2.4) (2.1) (0.3) Capital expenditures (1.1) (2.0) 0.9 Preferred dividends (2.2) (2.1) (0.1) Q1 2018 Cash Flow Results ($ millions) 12 Primary drivers: Changes in working capital (primarily related to five PPA expirations) +20.9 Lower cash interest payments +4.5 Lower Project Adjusted EBITDA -10.4 Includes 1% mandatory annual amortization and targeted debt repayments.

Liquidity ($ millions) 13 Mar 31, 2018 Dec 31, 2017 Cash and cash equivalents, parent $39.2 $49.7 Cash and cash equivalents, projects 43.4 29.0 Total cash and cash equivalents 82.6 78.7 Revolving credit facility 200.0 200.0 Letters of credit outstanding (77.5) (80.5) Availability under revolving credit facility 122.5 119.5 Total Liquidity $205.1 $198.2 Excludes restricted cash of: $5.7 $6.2 Consolidated debt (1) $810.2 $845.7 Leverage ratio (2) 3.2 3.3 (1) Before unamortized discount and unamortized deferred financing costs (2) Consolidated gross debt to trailing 12-month Adjusted EBITDA (after Corporate G&A) Reduction of $10.5 mostly attributable to purchases of common and preferred shares under NCIB of $10.4

Debt Repayment Profile at March 31, 2018 Includes Company’s share of debt at equity-owned projects ($ millions) 14 Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.2893. Project-level non-recourse debt totaling $72, including $43 at Chambers (equity method); amortizes over the life of the project PPAs (through 2025) $510 amortizing term loan (maturing in April 2023), which has 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 annual average repayment of ~ $83) $19 (US$ equivalent) of Series D and $89 (US$ equivalent) of Series E convertible debentures (maturing in Dec 2019 and Jan 2025, respectively) $163 (US$ equivalent) APLP Medium-Term Notes due in 2036 Total $853 $67 $93 $116 $258 $92 APLP Holdings Term Loan Project-level debt APLP Medium-term Notes (US$ equivalent) APC Convertible Debentures (US$ equivalent) 55% amortizing, 45% bullet $88 $139 Series D Series E 0 25 50 75 100 125 150 175 200 225 250 275 Rest of 2018 2019 2020 2021 2022 2023 Thereafter

15 Expected Debt Repayment (March 31, 2018 – Year-end 2023): Term loan – Amortize $385; $125 due at maturity in April 2023 Project debt (proportional) – Repay $66, ending balance $6 Series D convertible debentures mature Dec. 2019 ($19 US$ equivalent) Projected Debt Balances through 2023 Includes Company’s share of debt at equity-owned projects ($ millions) APLP Holdings Term Loan Project-level debt APLP Medium-term Notes (US$ equiv.) APC Convertible Debentures (US$ equiv.) Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of 1.2893. $853 $574 $483 $784 $690 $394 $255 Actual 72 65 56 45 33 20 6 510 450 385 280 200 125 108 108 89 89 89 89 89 163 163 163 163 163 163 163 0 100 200 300 400 500 600 700 800 900 3/31/18 12/31/18 12/31/19 12/31/20 12/31/21 12/31/22 12/31/23

2018 Project Adjusted EBITDA Guidance (Bridge vs 2017) ($ millions) 16 16 The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA. $289 FY 2017 Actual $185 $170 FY 2018 Guidance Morris CT upgrades are complete; lower maintenance expense and outage hours; higher PJM capacity prices $5 $(105) PPA Expirations Kapuskasing: EDC/cost savings(1) ($26) OEFC Settlement (11) North Bay: EDC/cost savings(1) (24) OEFC Settlement (11) San Diego (23) Williams Lake (10) Tunis Restart OEFC Settlement in 2017 ($7), GT overhaul and controls upgrade $(7) Manchief Maintenance GT11 major overhaul $(7) Curtis Palmer Assumes average water flows $(3) Other Frederickson Maintenance in 2017 (+3), Kenilworth GT overhaul in 2018 (-2); other projects, net (+4) $5 (1) Enhanced Dispatch Contract (EDC) and fuel, operations and maintenance cost savings No change from Q4/YE 2017 presentation

Bridge of 2018 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities ($ millions) 17 17 The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA. 2018 Guidance (as of 3/1/18) 2017 Actual Project Adjusted EBITDA $170 - $185 $288.8 Adjustment for equity method projects (1) (2) (6.4) Corporate G&A expense (22) (23.6) Cash interest payments (45) (72.0) Cash taxes (4) (4.4) Other - (13.2) Cash provided by operating activities $95 - $110 $169.2 Note: For purposes of providing a reconciliation of Project Adjusted EBITDA guidance, impact on Cash provided by operating activities of changes in working capital is assumed to be nil. (1) Represents difference between Project Adjusted EBITDA and cash distribution from equity method projects 2018 Planned Uses of Cash Provided by Operating Activities: Term loan repayments $90 Project debt repayments ~$10 Preferred dividends ~$8 Capital expenditures ~$1 Previously $(47); $2 benefit from April 2018 repricing of credit facilities

Appendix 18 TABLE OF CONTENTS Page Power Projects and PPA Expiration Dates 19 Capital Structure Information 20-24 Project Information – Earnings/Cash Flow Diversification and PPA Term 25-26 Supplemental Financial Information Q1 Results Summary 27 G&A and Development Expenses 28 Project Income by Project 29 Project Adjusted EBITDA by Project 30 Cash Distributions by Segment 31 Non-GAAP Disclosures 32-33

Year Project Location Type Economic Interest Net MW Contract Expiry 2019 Williams Lake B.C. Biomass 100% 66 6/2019 (1) Kenilworth New Jersey Nat. Gas 100% 29 9/2019 2020 Oxnard California Nat. Gas 100% 49 4/2020 Calstock Ontario Biomass 100% 35 6/2020 2021 none expiring 2022 Manchief Colorado Nat. Gas 100% 300 4/2022 (2) 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 2025 and beyond Mamquam B.C. Hydro 100% 50 9/2027 (3) Curtis Palmer New York Hydro 100% 60 12/2027 (4) Cadillac Michigan Biomass 100% 40 6/2028 Piedmont Georgia Biomass 100% 55 9/2032 Tunis Ontario Nat. Gas 100% 40 (5) Morris Illinois Nat. Gas 100% 177 12/2034 Koma Kulshan Washington Hydro 49.8% 6 12/2037 Power Projects and PPA Expiration Dates 19 (1) May be extended to Sept. 2019 at BC Hydro’s option (2) Public Service Co. of Colorado has option to purchase Manchief in either May 2020 or May 2021. (3) BC Hydro has an option to purchase Mamquam in Nov. 2021 and every five years thereafter. (4) Expires at the earlier of Dec. 2027 or the provision of 10,000 GWh of generation. Based on cumulative generation to date, we expect the PPA to expire prior to Dec. 2027. (5) 15-year contract commences before June 2019.

Capitalization ($ millions) 20 Mar. 31, 2018 Dec. 31, 2017 Long-term debt, incl. current portion (1) APLP Medium-Term Notes (2) $162.9 $167.4 Revolving credit facility - - Term Loan 510.0 540.0 Project-level debt (non-recourse) 28.9 31.2 Convertible debentures (2) 108.4 107.0 Total long-term debt, incl. current portion $810.2 80% $845.5 79% Preferred shares (3) 207.3 21% 215.2 18% Common equity (4) (12.7) (1)% (18.4) 2% Total shareholders equity $194.6 20% $196.8 21% Total capitalization $1,004.8 100% $1,042.2 100% Debt balances are shown before unamortized discount and unamortized deferred financing costs Period-over-period change due to F/X impacts Par value of preferred shares was approximately $163 million and $175 million at March 31, 2018 and December 31, 2017, respectively. Common equity includes other comprehensive income and retained deficit Note: Table is presented on a consolidated basis and excludes equity method projects

Capital Summary at March 31, 2018 ($ millions) (1) As of April 19, 2018, the spread was reduced to 3.00% (2) Includes impact of interest rate swaps (3) Set on Dec.1, 2017 for March 30, 2018 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$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.2893. 21 Atlantic Power Corporation Maturity Amount Interest Rate Convertible Debentures (ATP.DB.D) 12/2019 $19.2 (C$24.7) 6.00% Convertible Debentures (ATP.DB.E) 1/2025 $89.2 (C$115.0) 6.00% APLP Holdings Limited Partnership Maturity Amount Interest Rate Revolving Credit Facility 4/2023 $0 LIBOR + 3.50% (1) Term Loan 4/2023 $510.0 4.40%-5.20% (2) Atlantic Power Limited Partnership Maturity Amount Interest Rate Medium-term Notes 6/2036 $162.9 (C$210) 5.95% Preferred shares (AZP.PR.A) N/A $87.5 (C$112.8) 4.85% Preferred shares (AZP.PR.B) N/A $45.4 (C$58.5) 5.57% Preferred shares (AZP.PR.C) N/A $30.6 (C$39.5) 5.11% (3) Atlantic Power Transmission & Atlantic Power Generation Maturity Amount Interest Project-level Debt (consolidated) Various $28.9 4.91%-6.13% Project-level Debt (equity method) Various $42.9 4.50%-5.00%

Progress on Debt Reduction and Leverage ($ millions, unaudited) 22 Total net reduction in consolidated debt of approximately $1.1 billion since YE 2013; in addition, debt at equity-owned projects has been reduced by approximately $76 million. Leverage ratio (1) 12/31/2013 consolidated debt $1,876 9.5x 12/31/2014 consolidated debt 1,755 6.9x 12/31/2015 consolidated debt 1,019 5.7x 12/31/2016 consolidated debt 997 5.6x 12/31/2017 consolidated debt 846 3.3x Changes Q1 2018: Amortization of new term loan (30) Amortization of project debt (2) Issuance of Series E convertible debenture 92 Redemptions of Series C and D convertible debentures (88) Incremental F/X impact (unrealized gain) (8) 3/31/18 consolidated debt $810 3.2x Note: Consolidated debt excludes unamortized discounts and unamortized deferred financing costs (1) Consolidated gross debt to trailing 12-month Adjusted EBITDA (after Corporate G&A)

APLP Holdings Term Loan Cash Sweep Calculation 23 APLP Holdings Adjusted EBITDA (note: excludes Piedmont; is 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, EPP, 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 cash sweep to average 65% to 70% over the life of the loan, though higher in early years, and with considerable variability from year to year Expect > 80% of principal to be repaid by maturity through mandatory and targeted repayments Notes: The cash sweep calculation occurs at each quarter-end. Targeted debt balances are specified in the credit agreement for each quarter through maturity.

APLP Holdings Credit Facilities – Financial Covenants 24 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. 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 3/31/2018 5.50:1.00 3.00:1.00 6/30/2018 5.00:1.00 3.00:1.00 9/30/2018 5.00:1.00 3.00:1.00 12/31/2018 5.00:1.00 3.00:1.00 3/31/2019 5.00:1.00 3.00:1.00 6/30/2019 5.00:1.00 3.25:1.00 9/30/2019 5.00:1.00 3.25:1.00 12/31/2019 5.00:1.00 3.25:1.00 3/31/2020 5.00:1.00 3.25:1.00 6/30/2020 4.25:1.00 3.50:1.00 9/30/2020 4.25:1.00 3.50:1.00 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

Curtis Palmer is the single largest contributor (21%); next eight projects account for ~75% 25 Earnings and Cash Flow Diversification by Project (1) Based on $53.4 million in Project Adjusted EBITDA for the three months ended March 31, 2018. Un-allocated corporate segment is included in “Other” category for project percentage allocation and allocated equally among segments for three months ended March 31, 2018 Project Adjusted EBITDA by Segment. (2) Based on $63.9 million in Cash Distributions from Projects for the three months ended March 31, 2018. Three months ended March 31, 2018 Cash Distributions from Projects by Segment (2) Three months ended March 31, 2018 Project Adjusted EBITDA by Segment (1) Generation by Segment (MWh): East U.S.: 59% West U.S.: 21% Canada: 20% (9 projects) Other - 6% Curtis Palmer 21% Orlando 14% Nipigon 14% Chambers 11% Williams Lake 11% Morris 8% Manchief 7% Frederickson 6% Cadillac 4% Calstock 3% Mamquam 3% Piedmont 2% Kenilworth 2% East U.S. 34% West U.S. 17% Canada 49% East U.S. 62% West U.S. 11% Canada 26%

Remaining PPA Term (years) (1) 26 (1) Weighted by FY 2018 Project Adjusted EBITDA. PPA’s for San Diego assets terminated in February 2018. (2) Primarily merchant revenues at Morris Pro Forma Offtaker Credit Rating (1) Approximately two-thirds of 2018 Project Adjusted EBITDA generated from PPAs that expire after 2022 Majority of Cash Flows Covered by Contracts with More Than 5 Years Remaining Contracted projects have an average remaining PPA life of 6.75 years (1) (2) Merchant / Market Pricing 4% (2) Less than 5 31% 6 to 10 49% 11 to 15 15% 15+ 2% A - to A+ 50% AA - to AA 17% AAA 9% BBB - to BBB+ 20% BB 1% NR 3%

27 Summary of Financial and Operating Results Segment Results Results Summary, Q1 2018 vs Q1 2017 ($ millions, unaudited) Three months ended March 31, 2018 2017 Financial Results Project revenue $80.0 $98.4 Project income 28.3 25.3 Net income (loss) attributable to Atlantic Power Corp. 15.9 (2.7) Cash provided by operating activities 50.3 34.1 Project Adjusted EBITDA 53.4 63.8 Operating Results Aggregate power generation (net GWh) 1,120.5 1,152.7 Weighted average availability 98.3% 96.4% Three months ended March 31, 2018 2017 Project income (loss) East U.S. $20.8 $12.9 West U.S. (2.0) (0.7) Canada 7.4 10.9 Un-allocated Corporate 2.1 2.2 Total 28.3 25.3 Project Adjusted EBITDA East U.S. $33.2 $27.2 West U.S. 6.1 9.1 Canada 14.2 27.5 Un-allocated Corporate (0.1) - Total 53.4 63.8

2013 Actual 2014 Actual 2015 Actual 2016 Actual 2017 Actual 2018 Estimate Development (1) $7.2 $3.7 $1.1 n/a (1) n/a (1) - Project G&A and Other 11.4 3.8 1.5 $0.2 ($1.4) $1 Corporate G&A (2) 35.2 37.9 29.4 22.6 23.6 21 Total Overhead $53.8 $45.4 $31.9 $22.8 $22.2 $22 G&A and Development Expenses ($ millions) 28 2017 level represents a ~ 59% reduction from 2013; 2018 expected to be in line with 2017 Includes approximately $3 million annual contractual obligation related to Ridgeline acquisition that terminated in the first quarter of 2015. For 2016 and beyond, all Development spend will be recorded in Corporate G&A. Includes $6 severance in 2014; approximately $4 severance and $2 restructuring in 2015 Project G&A and other: Operations & Asset Management Environmental, Health & Safety Project Accounting Corporate G&A: Executive & Financial Management Treasury, Tax, Legal, HR, IT, Commercial activities Corporate Accounting Office & administrative costs Public company costs One-time costs (mostly severance) Included in Project Adj. EBITDA “Administration” expense on Income Statement; not included in Project Adj. EBITDA

Project Income (Loss) by Project, Q1 2018 vs Q1 2017 ($ millions) 29 Project sold in November 2017 Three months ended March 31 2018 2017 East U.S. Accounting Cadillac Consolidated $0.6 $0.6 Curtis Palmer Consolidated 7.4 7.0 Kenilworth Consolidated 0.3 0.1 Morris Consolidated 2.6 0.2 Piedmont Consolidated (0.5) (1.9) Chambers Equity method 3.0 2.5 Orlando Equity method 7.5 5.1 Selkirk (1) Equity method - (0.7) Total 20.8 12.9 West U.S. Manchief Consolidated 0.9 0.6 Naval Station Consolidated (0.9) (0.3) Naval Training Center Consolidated (0.7) (0.3) North Island Consolidated (0.6) 0.3 Oxnard Consolidated (2.6) (1.9) Frederickson Equity method 1.9 0.9 Koma Kulshan Equity method - - Total (2.0) (0.7) Canada Calstock Consolidated 1.3 0.9 Kapuskasing Consolidated (0.1) 3.1 Mamquam Consolidated 1.3 0.4 Nipigon Consolidated 2.2 0.5 North Bay Consolidated - 3.5 Williams Lake Consolidated 5.1 2.5 Other Consolidated (2.5) - Total 7.4 10.9 Totals Consolidated projects 13.8 15.3 Equity method projects 12.4 7.8 Un-allocated corporate 2.1 2.2 Total Project Income $28.3 $25.3

30 Project Adjusted EBITDA by Project, Q1 2018 vs Q1 2017 ($ millions) Three months ended March 31 2018 2017 Three months ended March 31 2018 2017 East U.S. Accounting Cadillac Consolidated $2.0 $1.8 Curtis Palmer Consolidated 11.3 10.9 Kenilworth Consolidated 1.0 0.8 Morris Consolidated 4.4 0.7 Piedmont Consolidated 1.3 1.2 Chambers Equity method 5.8 5.4 Orlando Equity method 7.6 7.1 Selkirk (1) Equity method 0.0 (0.7) Total 33.2 27.2 West U.S. Manchief Consolidated 3.7 3.3 Naval Station Consolidated 0.2 1.3 Naval Training Center Consolidated (0.0) 0.4 North Island Consolidated 0.3 1.4 Oxnard Consolidated (1.5) (0.9) Frederickson Equity method 3.4 3.4 Koma Kulshan Equity method 0.1 0.2 Total 6.1 9.1 Canada Calstock Consolidated 1.8 1.5 Kapuskasing Consolidated (0.1) 7.4 Mamquam Consolidated 1.7 0.8 Moresby Lake Consolidated 0.4 0.2 Nipigon Consolidated 7.4 5.7 North Bay Consolidated 0.0 7.3 Tunis Consolidated (2.7) (0.0) Williams Lake Consolidated 5.6 4.6 Total 14.2 27.5 Totals Consolidated projects 36.7 48.4 Equity method projects 16.8 15.4 Un-allocated corporate (0.1) 0.0 Total Project Adjusted EBITDA $53.4 $63.8 Interest expense, net $1.0 $2.4 Depreciation and amortization 27.8 34.9 Change in fair value of derivative instruments (3.7) 1.2 Project income $28.3 $25.3 Other income, net (2.0) 0.0 Foreign exchange (gain) loss (8.2) 2.5 Interest expense, net 15.1 17.3 Administration 6.0 6.4 Income (loss) from operations before income taxes 17.4 (0.9) Income tax expense (benefit) 3.2 (0.3) Net income (loss) $14.2 ($0.6) (1.7) 2.1 $15.9 ($2.7) Net income (loss) attributable to Atlantic Power Corporation Net (loss) income attributable to preferred share dividends of a subsidiary company

31 Cash Distributions from Projects, Q1 2018 vs Q1 2017 ($ millions), Unaudited Three months ended March 31, 2018 Project Adjusted EBITDA Repayment of long-term debt Interest expense, net Capital expenditures Other, including changes in working capital Cash Distributions from Projects Segment East U.S. Consolidated $19.8 ($2.4) ($0.5) $0.1 $0.4 $17.6 Equity method 13.3 - (0.4) - (8.9) 4.1 Total 33.2 (2.4) (0.9) 0.1 (8.5) 21.6 West U.S. Consolidated 2.6 - - - 4.0 6.6 Equity method 3.5 - - - 1.0 4.5 Total 6.1 - - - 5.0 11.2 Canada Consolidated 14.2 (0.0) - 0.1 16.9 31.1 Equity method - - - - - - Total 14.2 (0.0) - 0.1 16.9 31.1 Total consolidated 36.7 (2.4) (0.5) 0.2 21.3 55.3 Total equity method 16.8 - (0.4) - (7.9) 8.6 Un-allocated corporate (0.1) - - - 0.1 0.0 Total $53.4 ($2.4) ($0.9) $0.2 $13.5 $63.9 Three months ended March 31, 2017 Project Adjusted EBITDA Repayment of long-term debt Interest expense, net Capital expenditures Other, including changes in working capital Cash Distributions from Projects Segment East U.S. Consolidated $15.4 ($2.3) ($2.1) ($1.2) ($0.1) $9.7 Equity method 11.8 - (0.5) (0.0) (4.6) 6.7 Total 27.2 (2.3) (2.5) (1.2) (4.7) 16.4 West U.S. Consolidated 5.5 - - (0.0) 0.0 5.5 Equity method 3.6 - - - (1.3) 2.3 Total 9.1 - - (0.0) (1.3) 7.8 Canada Consolidated 27.5 (0.0) (0.0) (0.3) (4.1) 23.1 Equity method - - - - - - Total 27.5 (0.0) (0.0) (0.3) (4.1) 23.1 Total consolidated 48.4 (2.4) (2.1) (1.5) (4.2) 38.3 Total equity method 15.4 - (0.5) (0.0) (5.9) 9.0 Un-allocated corporate - - - (0.0) 0.0 (0.0) Total $63.8 ($2.4) ($2.5) ($1.5) ($10.1) $47.3

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. 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 slides [32 and 33]. Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. It is not a non-GAAP measure. Project Adjusted EBITDA, a non-GAAP measure, is the most comparable measure, but it is before debt service, capital expenditures and working capital requirements. The Company has provided a bridge of Project Adjusted EBITDA to Cash Distributions from Projects on slide 31. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. 32 $ millions, unaudited Three months ended March 31, 2018 2017 Net income (loss) attributable to Atlantic Power Corporation $15.9 ($2.7) Net (loss) income attributable to preferred share dividends of a subsidiary company (1.7) 2.1 Net income (loss) attributable to Atlantic Power Corporation $14.2 ($0.6) Income tax expense (benefit) 3.2 (0.3) Income (loss) from operations before income taxes 17.4 (0.9) Administration 6.0 6.4 Interest expense, net 15.1 17.3 Foreign exchange (gain) loss (8.2) 2.5 Other income, net (2.0) - Project income $28.3 $25.3 Reconciliation to Project Adjusted EBITDA Depreciation and amortization $27.9 $34.9 Interest expense, net 1.0 2.4 Change in the fair value of derivative instruments (3.8) 1.2 Project Adjusted EBITDA $53.4 $63.8

33 Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment, Q1 2018 vs Q1 2017 ($ millions) Three months ended March 31, 2018 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net income (loss) attributable to Atlantic Power Corporation $20.8 ($2.0) $7.4 ($10.3) $15.9 Net loss attributable to preferred share dividends of a subsidiary company - - - (1.7) (1.7) Net income (loss) 20.8 (2.0) 7.4 (12.0) 14.2 Income tax expense - - - 3.2 3.2 Income (loss) before income taxes 20.8 (2.0) 7.4 (8.8) 17.4 Administration - - - 6.0 6.0 Interest expense, net - - - 15.1 15.1 Foreign exchange gain - - - (8.2) (8.2) Other income, net - - - (2.0) (2.0) Project Income (loss) 20.8 (2.0) 7.4 2.1 28.3 Change in fair value of derivative instruments (0.2) - (1.2) (2.3) (3.7) Depreciation and amortization 11.6 8.1 8.0 0.1 27.8 Interest, net 1.0 - - - 1.0 Project Adjusted EBITDA $33.2 $6.1 $14.2 ($0.1) $53.4 Three months ended March 31, 2017 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net income (loss) attributable to Atlantic Power Corporation $12.9 ($0.7) $10.9 ($25.8) ($2.7) Net income attributable to preferred share dividends of a subsidiary company - - - 2.1 2.1 Net income (loss) 12.9 (0.7) 10.9 (23.7) (0.6) Income tax benefit - - - (0.3) (0.3) Income (loss) before income taxes 12.9 (0.7) 10.9 (24.0) (0.9) Administration - - - 6.4 6.4 Interest expense, net - - - 17.3 17.3 Foreign exchange loss - - - 2.5 2.5 Project income (loss) 12.9 (0.7) 10.9 2.2 25.3 Change in fair value of derivative instruments 0.2 - 3.3 (2.3) 1.2 Depreciation and amortization 11.5 10.0 13.3 0.1 34.9 Interest, net 2.6 (0.2) - - 2.4 Project Adjusted EBITDA $27.2 $9.1 $27.5 $0.0 $63.8