Q2 2017 Financial Results Conference Call August 4, 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 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 36 and 37. 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 33 and 34. All amounts in this presentation are in US$ and approximate unless otherwise stated.

3 Q2 and YTD 2017 Highlights and Recent Developments Operations Review Commercial Review / PPAs Financial Results 2017 Guidance Balance Sheet and Liquidity Update CEO: Concluding Remarks Q&A Agenda

Overview 4 Q2 Financial Highlights Cash Available for Capital Allocation Progress on Expiring PPAs Net loss attributable to APC of $(21.9) million vs. $(18.5) million for Q2 2016 Project Adjusted EBITDA of $85.4 million vs. $46.2 million for Q2 2016 Cash provided by operating activities of $50.9 million vs. $24.3 million for Q2 2016 2017 Guidance Continued Balance Sheet Improvement Repaid $29.5 million term loan and project debt in Q2 / $56.9 million YTD June 2017 Leverage ratio at June 30, 2017 of 4.4 x Liquidity of $227 million at June 30, 2017, including $104 million of unrestricted cash Approximately $69 million of cash available at parent for discretionary purposes Expect this to increase to approximately $105 to $110 million by year-end 2017 Available for discretionary debt reduction ($40 million or more in 2017), repurchases of common and/or preferred shares (NCIB), and internal and external growth On track operationally and financially Reaffirming 2017 Adjusted EBITDA guidance range of $250 to $265 million Estimated cash provided by operating activities of $155 to $170 million Announced new seven-year tolling agreements for Naval Station and North Island projects in San Diego Subject to regulatory approval (California PUC) and retaining site control (U.S. Navy) Continuing to make progress on other projects (Williams Lake, Tunis, Nipigon)

Q2 2017 Operational Performance: Lower generation primarily due to Ontario curtailments; outages reduced availability 5 Q2 2017 Q2 2016 East U.S. 87.8% 92.7% West U.S. 79.6% 90.6% Canada 87.0% 95.1% Total 85.2% 92.7% Aggregate Power Generation Q2 2017 vs. Q2 2016 (Net GWh) East U.S. West U.S. Canada Total (0.4%) (24.9%) (50.7%) (23.5%) Lower availability factor: Generation is down: Kapuskasing/Nipigon/North Bay are not in operation for 2017 under the enhanced dispatch contracts with the IESO In 2016, these plants generated 216 GWh in the period Mamquam forced outage and Frederickson lower merchant demand Morris merchant generation down due to low PJM demand Curtis Palmer higher water flows versus comparable 2016 period Frederickson, Kenilworth and Morris planned maintenance outages in current period Mamquam forced outage in current period 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) 1.25 1.67 0.70 0.73 FY 2014 FY 2015 FY 2016 YTD 2017 615 612 360 271 501 247 1,476 1,129 Q2 2016 Q2 2017 Q2 2016 Q2 2017 Q2 2016 Q2 2017 Q2 2016 Q2 2017

Operations Update 6 Scheduled Maintenance Outages Analysis and Benchmarking for Cost Savings (ABCs) Morris – Third and final combustion turbine upgrade (optimization project) completed Frederickson – Major outage for gas and steam turbines completed Kenilworth – Steam turbine overhaul completed Piedmont – Spring outage completed Goal – improved efficiency and operational performance Held summit to gather equipment data and maintenance practice details Operations summit scheduled mid-November Project-by-project budget reviews underway Predictive analytic software being installed/tested at three plants Third party benchmarking next year

Commercial Update: PPA Renewal Status 7 PPA amendment for Tunis completed in June 2017 provides for simple-cycle operations and reduced operating risk Nipigon expected to return to service under the existing or a revised PPA in November 2018 New seven-year Power Purchase Tolling Agreements (PPTAs) signed with SDG&E for Naval Station and North Island Existing PPAs would terminate as early as February 2018 Estimated annual Project Adjusted EBITDA under the PPTAs of ~ $6 million on a combined basis PPTAs are conditioned upon: Approval of the California Public Utilities Commission; SDG&E filed for approval in late July Positive outcome in the Navy’s solicitation for energy security and resiliency for the two sites (site control); Atlantic Power submitted response in second round in late May Company is continuing to pursue new contractual arrangements for NTC/MCRD and Oxnard Discussions with BC Hydro continue on a potential extension of existing PPA (expires March 2018) Focus is on a short-term extension that would bridge to outcome of BC Hydro’s Integrated Resource Plan (expected in 2019) Would not require investment in a new fuel shredder (to burn railroad ties) Would provide for significantly lower Project Adjusted EBITDA compared to existing PPA Amended air permit allowing for increased burning of railroad ties has been appealed Schedule for addressing the appeals not yet set Investment in new fuel shredder is subject to execution of a new long-term PPA and resolution of permit appeal Ontario San Diego Plants Williams Lake

Q2 and YTD 2017 Financial Update ($ millions) 8 Net Loss Attributable to APC Adjusted EBITDA Operating Cash Flow OEFC settlement Cdn$32.8 million recorded in Q2; US$24.7 million benefit to Project Adjusted EBITDA Includes Cdn$11.0 million (~ US$8 million) received in Q1 but deferred Enhanced dispatch contracts (Kapuskasing, North Bay and Nipigon) Reduced fuel and operation and maintenance expenses more than offset lower revenue under contracts $10.8 million benefit to Project Adjusted EBITDA Impairment (Selkirk and Chambers) Full impairment at Selkirk ($10.6 million) based on operating and financial performance and history of no distributions while operating merchant Partial impairment at Chambers ($47.1 million), based on reduced estimate of discounted cash flows post-PPA expiration (3/24) due to lower long-term forecast for power, coal and gas prices Total $57.7 million impairment recorded in earnings from unconsolidated affiliates No impact on operating cash flow or Project Adjusted EBITDA Operating cash flow Benefited from US$24.7 million OEFC revenues (~$16.4 million in Q2) $4.2 million reduction in cash interest payments (reduced spread on term loan; cumulative debt repayment) Debt repayment / amortization Repayment of term loan – Q2 $27.1 million / YTD $52.1 million Amortization of project debt – Q2 $2.4 million / YTD $4.7 million Repricing of Term Loan (April 17, 2017) Spread reduced to LIBOR + 425 basis points (from L+500) 50.9 24.3 85.0 53.7 Q2 2017 Q2 2016 YTD 2017 YTD 2016 85.4 46.2 149.3 108.7 Q2 2017 Q2 2016 YTD 2017 YTD 2016 (21.9) (18.5) (24.6) (33.5) Q2 2017 Q2 2016 YTD 2017 YTD 2016

Q2 and YTD 2017 Project Adjusted EBITDA ($ millions) 9 $46 $85 Q2 2016 Q2 2017 $(3) Frederickson Major maintenance outage in current period OEFC Settlement Kapuskasing, North Bay and Tunis $25 $(2) Mamquam Lower water flows and forced outage $(1) Calstock Lower waste heat and higher fuel prices Ontario Enhanced Dispatch Contracts Kapuskasing, North Bay and Nipigon $11 Curtis Palmer Higher water flows $7 Other 2016 maintenance at Piedmont and Williams Lake $2 $109 $149 YTD 2016 YTD 2017 $(2) Frederickson Major maintenance outage in current period $(3) Mamquam Lower water flows and forced outage $(3) Calstock Lower waste heat and higher fuel prices OEFC Settlement Kapuskasing, North Bay and Tunis $25 Ontario Enhanced Dispatch Contracts Kapuskasing, North Bay and Nipigon $18 Curtis Palmer Higher water flows $7 Other 2016 maintenance at Williams Lake and Piedmont, Lower fuel expense at Orlando $4 $(5) Morris Lower energy and capacity pricing

Six months ended June 30, Unaudited 2017 2016 Change Cash provided by operating activities $85.0 $53.7 $31.3 Significant uses of cash provided by operating activities: Term loan repayments (1) (52.2) (50.5) (1.7) Project debt amortization (4.7) (4.3) (0.4) Capital expenditures (4.2) (2.0) (2.2) Preferred dividends (4.3) (4.2) (0.1) Three months ended June 30, Unaudited 2017 2016 Change Cash provided by operating activities $50.9 $24.3 $26.6 Significant uses of cash provided by operating activities: Term loan repayments (1) (27.1) (25.0) (2.1) Project debt amortization (2.4) (2.1) (0.3) Capital expenditures (2.2) (1.3) (0.9) Preferred dividends (2.2) (2.2) - Q2 and YTD 2017 Cash Flow Results ($ millions) 10 Primary drivers: OEFC Settlement +16.4 Kap/N.Bay/Nipigon revised contracts +10.8 Higher results at Curtis Palmer +6.5 Lower results at Frederickson and Mamquam (4.4) (1) Includes 1% mandatory annual amortization and targeted debt repayments. Primary drivers: OEFC Settlement +24.7 Kap/N.Bay/Nipigon revised contracts +17.6 Lower cash interest payments +1.3 Lower results at Morris, Frederickson, Mamquam and Calstock (13.4)

2017 Project Adjusted EBITDA Guidance Guidance remains at $250 to $265 (1) ($ millions) 11 11 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. $242 Latest 12 Months $265 $250 FY 2017 Guidance Ontario Gross Margin Impact Expiration of above-market fuel contract, enhanced dispatch agreement, waste heat $18 $6 Maintenance Morris CT upgrades in 2H 2016 (+8); Offset by planned maintenance at Naval Station in 2H 2017 (-2) $(6) Tunis Repowering Repowering costs planned for 2H 2017 $(2) Kenilworth Reimbursement 2H 2016 fuel reimbursement under fuel contract 1H 2017 $149 2H 2016 $93 2017 Project Adjusted EBITDA Guidance(1) $250 - $265 Adjustment for equity method projects(2) (1) Corporate G&A expense (22) Cash interest payments (67) Cash taxes (4) Other - Cash provided by operating activities $155 - $170 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. 2017 expected uses of cash provided by operating activities: Term loan repayments(3) $100 Project debt amortization 12 Capital expenditures 5 Preferred dividend payments 9 (1) Initially provided May 4, 2017. (2) Represents difference between Project Adjusted EBITDA and cash distribution from equity method projects. (3) Includes 1% mandatory annual amortization and targeted debt repayments. Bridge of 2017 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities

Liquidity ($ millions) 12 June 30, 2017 March 31, 2017 Cash and cash equivalents, parent $78.6 $65.6 Cash and cash equivalents, projects 25.8 25.9 Total cash and cash equivalents 104.4 91.5 Revolving credit facility 200.0 200.0 Letters of credit outstanding (77.2) (77.5) Availability under revolving credit facility 122.8 122.5 Total Liquidity 227.2 214.0 Excludes restricted cash of: 14.1 10.0

Progress on Debt Reduction and Leverage ($ millions, unaudited) 13 Total net reduction in consolidated debt of approximately $930 million since YE 2013; in addition, debt at equity-owned projects has been reduced by approximately $91 million. Although term loan refinancing (April 2016) initially resulted in a net increase in debt, by 9/30/16 that impact was fully offset as a result of allocating the majority of the net proceeds to redemption and repurchases of convertible debentures 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 3/31/2016 consolidated debt 994 5.6x Term loan refinancing: Issuance of new term loan (April) 700 Repayment of previous term loan (April) (448) 3/31/16 consolidated debt – pro forma 1,246 7.1x Changes Q2-Q4 2016: Redemption of 2017 convertible debentures (May) (110) Repurchase of 2019 convertible debentures (July) (63) Amortization of term loan (60) Amortization of project debt (9) Incremental F/X impact (unrealized gain) (7) 12/31/16 consolidated debt 997 5.6x Changes Q1-Q2 2017: Amortization of term loan (52) Amortization of project debt (5) Incremental F/X impact (unrealized loss) 7 6/30/17 consolidated debt 947 4.4x By year end 2016, had paid down all but $10 of $252 increase Term loan refinancing: Net increase in debt $252 Note: Consolidated debt excludes unamortized discounts and deferred financing costs (1) Consolidated gross debt to trailing 12-month Adjusted EBITDA (after Corporate G&A)

Debt Repayment Profile at June 30, 2017 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 $1.2977. Project-level non-recourse debt totaling $135.4, including $43.0 at Chambers (equity method); includes Piedmont bullet maturity of $54.2 (August 2018); remainder amortizes over the life of the project PPAs (through 2025) $588 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 of ~ $82) $105 (US$ equivalent) of convertible debentures (maturing in June and December 2019) $162 (US$ equivalent) APLP Medium-Term Notes due in 2036 Total $990 $55 $154 $179 $116 $307 $92 APLP Holdings Term Loan Project-level debt APLP Medium-term Notes (US$) APC Convertible Debentures (US$) $105 $162 55% amortizing, 45% bullet > 80% of initial principal to be repaid by 2023 maturity $88 0 50 100 150 200 250 300 350 Rest of 2017 2018 2019 2020 2021 2022 Thereafter

2017 Capital Allocation ($ millions) 15 Beginning cash at parent, 12/16 $60 Cash reserve (10) Net available at parent, 12/16 50 2017 Cash provided by operating activities 163 Based on midpoint $155 to $170 Amortization of term loan (100) Amortization of project debt (12) Capex (5) Preferred dividends (9) Repurchase of preferred shares (2) Preferred share repurchases under NCIB (Cdn$2.7) (July 2017) Working capital release at projects; other 22 Based on reduced working capital needs for non-operating plants in Ontario and other Projected cash available at parent, 12/17 107 Range $105 to $110 Available for: Discretionary debt repayment – committed to at least $40 Piedmont maturity (Aug. 2018) $54.2 June 2019 convertible debentures $42.5 Term loan Debt repurchases under NCIB Common and preferred share repurchases (NCIB) Internal growth (fleet optimization, PPA-related investments) External growth

16 Restructuring of business and balance sheet past two and a half years Reduced debt by ~ $1 billion (Slide 13) Reduced corporate overheads and cash interest payments by $91 million annually Leverage reduced to ~ 4x (estimated YE 2017) from a peak of 9.5x (YE 2013) Significantly improved liquidity and available cash Liquidity (at 6/30/17) of ~ $227 million, including ~ $69 million available at the parent Expect discretionary cash to increase to ~ $105 to $110 million by YE 2017 (before any potential use) Five-year outlook (2018-2022), based on modest recontracting assumptions Normalizing for PPA expirations in 2018, EBITDA is relatively stable during the period (and mostly contracted) Continued debt repayment results in interest cost savings that partially offset the impact of lower EBITDA Cumulative operating cash flow (1) of $550 to $600 million (net of overheads, interest and cash taxes) Balanced approach to capital allocation currently Term loan repayments, project debt amortization and maturities during this period of ~ $491 million (2) Maximizing use of cash for debt repayment would result in leverage well below 2x by YE 2022 Repurchase of preferred and common shares when price-to-value relationship is compelling Significant available cash compared to current market capitalization of ~ $270 million (1) Assumes for this purpose that changes in working capital are nil. (2) Excludes Chambers debt amortization ($32 million) because as an equity-owned project, this is already reflected in the presentation of operating cash flow. CEO Concluding Remarks

17 2018 – 2022 EBITDA and Cash Flow Outlook Modest recontracting scenario Most of the impact on Project Adjusted EBITDA through 2021 is from PPA expirations in the next 13 months (1) Kapuskasing and North Bay (12/17), San Diego projects (2/18, assuming early termination), Williams Lake (3/18), Kenilworth (9/18) No expirations in 2019 or 2021 Two in 2020 with a combined Project Adjusted EBITDA of ~ $8 million Modest recontracting assumptions No contribution by Kapuskasing or North Bay Assumes Naval Station and North Island contracts are effective 2/18 Assumes recontracting of some but not all other PPAs expiring during this period ~ 95% contracted / 5% recontracted or merchant Assumes no external growth during this period Five-year cumulative operating cash flow (2) of $550 to $600 million Lower interest payments (from continued debt repayment) mitigate the impact on cash flow from lower EBITDA Assumes impact of working capital changes is nil Net of corporate overheads, cash interest payments and cash taxes Before preferred dividends and capital expenditures (including PPA-related capex) Total cash available during this period of approximately $600 million Includes estimated year-end 2017 discretionary cash of $105 to $110 million Term loan repayment, project debt amortization and Piedmont maturity total ~ $491 million (1) See slide 19 for PPA expirations by year (2) Operating cash flow is presented net of Chambers debt amortization because the project is equity-owned ($32 million during the five-year period). Assumes for this purpose that changes in working capital are nil.

Appendix 18 TABLE OF CONTENTS Page Power Projects and PPA Expiration Dates 19 Operational Performance YTD 2017 20 OEFC Settlement 21 Capital Structure Information 22-26 Project Information 27-28 Supplemental Financial Information Q2 and YTD 2017 Results Summary 29 G&A and Development Expenses 30 Project Income by Project 31 Project Adjusted EBITDA by Project 32 Cash Distributions by Segment 33-34 Non-GAAP Disclosures 35-37

Year Project Location Type Economic Interest Net MW Contract Expiry 2017 Kapuskasing Ontario Nat. Gas 100% 40 12/2017 North Bay Ontario Nat. Gas 100% 40 12/2017 2018 Williams Lake B.C. Biomass 100% 66 3/2018 Kenilworth New Jersey Nat. Gas 100% 29 9/2018 Naval Station California Nat. Gas 100% 47 12/2019 (1) Naval Training California Nat. Gas 100% 25 12/2019 (1) North Island California Nat. Gas 100% 40 12/2019 (1) 2019 none expiring 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 Moresby Lake B.C. Hydro 100% 6 8/2022 Frederickson Washington Nat. Gas 50.15% 125 9/2022 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 10/2027 Curtis Palmer New York Hydro 100% 60 12/2027 (2) Cadillac Michigan Biomass 100% 40 7/2028 Piedmont Georgia Biomass 100% 55 9/2032 Tunis Ontario Nat. Gas 100% 40 11/2032 (3) Morris Illinois Nat. Gas 100% 177 12/2034 Koma Kulshan Washington Hydro 49.8% 6 3/2037 n/a Selkirk New York Nat. Gas 17.7% 61 Merchant Power Projects and PPA Expiration Dates 19 (1) Expiration date of existing PPAs but may terminate as early as Feb. 2018, when land use agreements with U.S. Navy expire. New PPTAs for Naval Station and North Island and an RA contract for Naval Training Center have been executed with existing PPA customer but are subject to regulatory approval and site control. (2) 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 prior to December 2027. (3) 15-year contract commences between Nov. 2017 and Jun. 2019

YTD June 2017 Operational Performance: Lower generation primarily due to curtailment of the Ontario gas plants 20 YTD 2017 YTD 2016 East U.S. 91.8% 95.9% West U.S. 87.1% 90.1% Canada 88.9% 97.3% Total 90.1% 94.6% Aggregate Power Generation YTD 2017 vs. YTD 2016 (Net GWh) East U.S. West U.S. Canada Total (5.9%) (11.6%) (56.1%) (24.6%) Availability factor modestly lower: Generation is down: Kapuskasing/Nipigon/North Bay are not in operation for 2017 under the enhanced dispatch contracts with the IESO In 2016, these plants generated 484 GWh in the period Mamquam forced outage and Frederickson lower merchant demand Morris merchant generation down due to low PJM demand Orlando lower availability due to planned maintenance Curtis Palmer higher water flows versus comparable 2016 period Frederickson, Orlando, Kenilworth and Morris planned maintenance outages in current period Mamquam forced outage in current period 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) 1.25 1.67 0.70 0.73 FY 2014 FY 2015 FY 2016 YTD 2017 1,279 1,203 703 621 1,045 458 3,026 2,283 YTD 2016 YTD 2017 YTD 2016 YTD 2017 YTD 2016 YTD 2017 YTD 2016 YTD 2017

OEFC Settlement Amounts in Cdn$ millions, unless otherwise indicated 21 Q1 2017 Q2 2017 1H 2017 Expected 2H 2017 Total FY 2017 Payments related to: 2013 – 2015 0.0 20.3 20.3 0.0 20.3 2016 8.7 0.0 8.7 0.0 8.7 2017 (EDCs) 2.3 1.4 3.7 3.6 7.3 Total 11.0 21.8 32.8 3.6 36.4 Cash received (Cdn$) 11.0 21.8 32.8 Cash received (US$) 8.2 16.4 24.6 Recorded in revenues (Cdn$) 0.0 32.8 32.8 Recorded in revenues (US$) 0.0 24.7 24.7

Capitalization ($ millions) 22 June 30, 2017 December 31, 2016 Long-term debt, incl. current portion (1) APLP Medium-Term Notes (2) $162 $156 Revolving credit facility - - Term Loan 588 640 Project-level debt (non-recourse) 93 97 Convertible debentures (2) 105 103 Total long-term debt, incl. current portion $947 78% $996 78% Preferred shares (3) 221 17% 221 18% Common equity (4) 48 4% 65 5% Total shareholders equity 286 22% 269 22% Total capitalization $1,282 100% $1,216 100% 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 $168 million and $173 million at December 31, 2016 and June 30, 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 June 30, 2017 ($ millions) (1) Includes impact of interest rate swaps. (2) Set on March 1, 2017 for June 30, 2017 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 $1.2977. 23 Atlantic Power Corporation Actual Maturity Amount Interest Rate Convertible Debentures (ATP.DB.U) 6/2019 $42.5 5.75% Convertible Debentures (ATP.DB.D) 12/2019 $62.4 (C$81.0) 6.0% APLP Holdings Limited Partnership Actual Maturity Amount Interest Rate Revolving Credit Facility 4/2021 $0 LIBOR + 3.75% Term Loan 4/2023 $587.7 5.40%-5.50% (1) Atlantic Power Limited Partnership Actual Maturity Amount Interest Rate Medium-term Notes 6/2036 $161.8 (C$210) 5.95% Preferred shares (AZP.PR.A) N/A $96.3 (C$125) 4.85% Preferred shares (AZP.PR.B) N/A $45.1 (C$58.5) 5.57% Preferred shares (AZP.PR.C) N/A $32.0 (C$41.5) 4.70% (2) Atlantic Power Transmission & Atlantic Power Generation Maturity Amount Interest Project-level Debt (consolidated) Various $92.5 4.20%-8.10% Project-level Debt (equity method) Various $42.9 4.50%-5.00%

24 June 30, 2017 – Year-end 2023: Term loan – Repay $463, ending balance $125 – annual interest cost savings $23 by 2023 Assumes Piedmont ($54) is refinanced at maturity in 2018 – if repaid, would have annual interest cost savings of ~ $4 Project debt (proportional) – Repay $61, ending balance $74 (including Piedmont) – annual interest cost savings ~ $3 Assumes 2019 convertible debentures ($105) are refinanced or repaid using revolver (no change in debt) If redeemed or repurchased using cash, annual interest savings of up to $6 in 2020 Projected Debt Balances through 2022 Includes Company’s share of debt at equity-owned projects ($ millions) APLP Holdings Term Loan Project-level debt APLP Medium-term Notes ($US) APC Convertible Debentures ($US) Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.2977. Cumulative paydown of debt reduces interest costs (benefits cash flow) Required 2017 amortization approx. $112 but expect to repay more than $150 in total $990 $761 $645 $466 Assumes convertible debentures are refinanced or repaid using revolver Assumes Piedmont is refinanced $935 $835 $554 135 128 119 110 99 87 74 588 540 450 385 280 200 125 105 105 105 105 105 105 105 162 162 162 162 162 162 162 0 200 400 600 800 1,000 1,200 6/30/17 12/31/17 12/31/18 12/31/19 12/31/20 12/31/21 12/31/22

APLP Holdings Term Loan Cash Sweep Calculation 25 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 26 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 6/30/2017 5.50:1.00 3.00:1.00 9/30/2017 5.50:1.00 3.00:1.00 12/31/2017 5.50:1.00 3.00:1.00 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

No single project contributed more than 17% to Project Adjusted EBITDA for the six months ended June 30, 2017 (1) 27 Earnings and Cash Flow Diversification by Project (1) Based on $149.3 million in Project Adjusted EBITDA for the six months ended June 30, 2017. Un-allocated corporate segment is included in “Other” category for project percentage allocation and allocated equally among segments for six months ended June 30, 2017 Project Adjusted EBITDA by Segment. (2) Based on $123.9 million in Cash Distributions from Projects for the six months ended June 30, 2017. Six months ended June 30, 2017 Cash Distributions from Projects by Segment (2) Six months ended June 30, 2017 Project Adjusted EBITDA by Segment (1) Capacity (MW) by Segment East U.S.: 51% West U.S.: 30% Canada: 18% (8 projects) Other 6% Kapuskasing 15% North Bay 14% Curtis Palmer 16% Tunis 4% Orlando 9% Nipigon 7% Chambers 6% Manchief 4% Williams Lake 5% Cadillac 3% Naval Station 3% Piedmont 2% Morris 2% North Island 2% Calstock 2% East U.S. 38% West U.S. 13% Canada 49% East U.S. 32% West U.S. 13% Canada 56%

PPA Length (years) (1) 28 (1) Weighted by June YTD 2017 Project Adjusted EBITDA (excluding contribution of OEFC / Global Adjustment payments). For the three San Diego assets, PPA expiration assumes Dec. 2019, but they may terminate in Feb. 2018. (2) Includes Selkirk and merchant capacity at Morris Pro Forma Offtaker Credit Rating (1) 64% of 2017 Project Adjusted EBITDA generated from PPAs that expire beyond the next five years Majority of Cash Flows Covered by Contracts with More Than 5 Years Remaining Contracted projects have an average remaining PPA life of 4.9 years (1) (2) Merchant 2% 1 to 5 36% 6 to 10 35% 11 to 15 22% 15+ 4% A - to A+ 47% AA - to AA 32% AAA 9% BBB - to BBB+ , 11% NR 2%

29 Summary of Financial and Operating Results Segment Results Results Summary, Q2/YTD 2017 vs Q2/YTD 2016 ($ millions, unaudited) Atlantic Power Corporation Table 1 – Selected Results (in millions of U.S. dollars, except as otherwise stated) Unaudited Three months ended June 30 Six months ended June 30 2017 2016 2017 2016 Financial Results Project revenue $124.0 $98.2 $222.4 $204.6 Project (loss) income (12.1) 25.2 13.2 53.9 Net loss attributable to Atlantic Power Corp. (21.9) (18.5) (24.6) (33.5) Cash provided by operating activities 50.9 24.3 85.0 53.7 Project Adjusted EBITDA 85.4 46.2 149.3 108.7 Operating Results Aggregate power generation (Net GWh) 1,129.5 1,477.9 2,283.1 3,031.2 Weighted average availability 85.2% 92.7% 90.6% 94.6% updated 7/26 Three months ended June 30 Six months ended June 30 2017 2016 2017 2016 Project income (loss) East U.S. ($43.3) $9.6 ($30.8) $25.6 West U.S. 0.7 4.6 - 2.3 Canada 31.1 12.9 42.3 29.3 Un-allocated Corporate (0.6) (1.9) 1.7 (3.3) Total (12.1) 25.2 13.2 53.9 Project Adjusted EBITDA East U.S. $29.1 $20.9 $56.2 $51.2 West U.S. 10.6 14.5 19.8 22.0 Canada 45.2 10.9 72.8 35.7 Un-allocated Corporate 0.5 (0.1) 0.5 (0.2) Total 85.4 46.2 149.3 108.7

2013 Actual 2014 Actual 2015 Actual 2016 Actual Development (1) $7.2 $3.7 $1.1 n/a (1) Project G&A and Other 11.4 3.8 1.5 0.2 Corporate G&A (2) 35.2 37.9 29.4 22.6 Total Overhead $53.8 $45.4 $31.9 $22.8 G&A and Development Expenses ($ millions) 30 2016 level represents a 57% reduction from 2013 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 ($ millions) 31 Atlantic Power Corporation Table 12 – Project Income by Project (for Selected Projects) F:\Financial\2017\Q1 2017\Footnotes and MD&A\Segments\Project Income Variance QTD (millions) Q2 2017.xlsx (in millions of U.S. dollars) Unaudited Unaudited plug Three months ended Six months ended Three months ended Six months ended June 30 June 30 June 30 June 30 2017 2016 2017 2016 2017 2016 2017 2016 East U.S. Accounting Cadillac Consolidated $1.4 $0.9 $1.8 $1.6 - - - - Curtis Palmer Consolidated 9.2 2.7 16.2 9.7 - - - - Kenilworth Consolidated (0.7) (0.9) (0.6) (1.0) - - - - Morris Consolidated 0.5 0.6 0.7 4.4 - - - (0.03) Piedmont Consolidated (1.3) (3.3) (3.2) (8.3) - - - - Chambers Equity method (46.5) 0.1 (43.9) 3.4 0.05 - 0.10 - Orlando Equity method 5.0 9.9 9.8 16.5 - - - (0.03) Selkirk Equity method (10.9) (0.3) (11.6) (0.6) - - - - Total (43.3) 9.6 (30.8) 25.6 West U.S. Manchief Consolidated 0.5 0.5 1.1 1.0 (0.03) - - - Naval Station Consolidated 1.1 1.9 0.8 0.5 (0.02) - - - Naval Training Center Consolidated 0.9 0.6 0.6 0.3 - - - North Island Consolidated 1.0 1.6 1.3 1.2 - - - - Oxnard Consolidated (0.5) (0.3) (2.5) (2.1) - - - - Frederickson Equity method (2.7) - (1.9) 0.8 (0.01) - - - Koma Kulshan Equity method 0.5 0.5 0.6 0.5 - - - - Total 0.7 4.6 - 2.3 Canada Calstock Consolidated 0.6 1.7 1.5 4.1 - - - - Kapuskasing Consolidated 9.9 2.3 12.9 5.9 - - 0.03 - Mamquam Consolidated 1.9 3.5 2.3 5.8 - - - - Nipigon Consolidated 1.5 3.3 2.0 4.1 - - - - North Bay Consolidated 9.8 2.7 13.4 6.8 - - 0.03 (0.04) Williams Lake Consolidated 1.2 (0.2) 3.7 2.8 - - - - Other Consolidated 6.3 (0.5) 6.4 (0.1) (0.10) - - - Total 31.1 12.9 42.3 29.3 Totals Consolidated projects 43.2 17.0 58.5 36.7 - - - - Equity method projects (54.6) 10.2 (47.0) 20.6 - - - - Un-allocated corporate (0.6) (1.9) 1.7 (3.3) 0.05 0.06 - (0.04) Total Project (Loss) Income ($12.1) $25.2 $13.2 $53.9 Project Income check - East TRUE TRUE TRUE TRUE - - - - Project Income check - West TRUE TRUE TRUE TRUE - - - - Project Income check - Canada TRUE TRUE TRUE TRUE - - - - Project Income check- Unalloc Corp TRUE TRUE TRUE TRUE - - - - Project Income check Total TRUE TRUE TRUE TRUE - - - - updated 7/26

32 Project Adjusted EBITDA by Project ($ millions) (1) Includes Tunis and Moresby Lake Unaudited Three months Six months ended June 30 ended June 30 2017 2016 2017 2016 East U.S. Accounting Cadillac Consolidated $2.7 $2.3 $4.5 $4.4 Curtis Palmer Consolidated 13.1 6.6 24.0 17.5 Kenilworth Consolidated (0.1) (0.3) 0.7 0.2 Morris Consolidated 2.1 2.5 2.9 7.9 Piedmont Consolidated 2.4 1.1 3.5 1.6 Chambers Equity method 3.3 2.8 8.7 8.9 Orlando Equity method 5.8 6.2 12.9 11.2 Selkirk Equity method (0.3) (0.3) (1.0) (0.6) Total 29.1 20.9 56.2 51.2 West U.S. Manchief Consolidated 3.3 3.3 6.7 6.6 Naval Station Consolidated 2.7 3.4 4.0 3.7 Naval Training Center Consolidated 1.7 1.4 2.1 1.9 North Island Consolidated 2.1 2.6 3.5 3.4 Oxnard Consolidated 0.5 0.7 (0.3) 0.1 Frederickson Equity method (0.2) 2.5 3.1 5.5 Koma Kulshan Equity method 0.6 0.6 0.7 0.9 Total 10.6 14.5 19.8 22.0 Canada Calstock Consolidated 1.1 2.3 2.6 5.1 Kapuskasing Consolidated 14.2 (0.7) 21.7 3.1 Mamquam Consolidated 2.3 4.0 3.1 6.7 Nipigon Consolidated 4.2 3.8 9.9 9.6 North Bay Consolidated 13.5 (0.2) 20.8 4.0 Williams Lake Consolidated 3.3 2.0 7.9 7.0 Other (1) Consolidated 6.6 (0.2) 6.8 0.3 Total 45.2 10.9 72.8 35.7 Totals Consolidated projects 75.8 34.5 124.2 82.9 Equity method projects 9.2 11.8 24.5 26.0 Un-allocated corporate 0.4 (0.1) 0.6 (0.2) Total Project Adjusted EBITDA $85.4 $46.2 $149.3 $108.7 Three months Six months ended June 30 ended June 30 2017 2016 2017 2016 Total Project Adjusted EBITDA $85.4 $46.2 $149.3 $108.7 Other project expense $- ($0.1) $- $0.1 Interest expense, net 2.5 2.9 5.3 5.4 Depreciation and amortization 34.7 30.4 69.3 60.3 Impairment 57.7 - 57.7 - Change in fair value of derivative instruments 2.6 (12.2) 3.8 (11.0) Project (loss) income ($12.1) $25.2 $13.2 $53.9 Other expense (income), net - 0.3 - (2.2) Foreign exchange loss 5.9 2.6 8.3 22.5 Interest expense, net 18.4 51.2 35.7 67.8 Administration 5.7 5.8 12.1 11.9 Loss from operations before income taxes (42.1) (34.7) (42.9) (46.1) Income tax (benefit) (22.3) (18.4) (22.6) (16.8) Net loss ($19.8) ($16.3) ($20.3) ($29.3) Net income attributable to preferred share dividends of a subsidiary company - - - - Net (loss) income attributable to Atlantic Power Corporation ($19.8) ($16.3) ($20.3) ($29.3)

33 Cash Distributions from Projects, Q2 2017 vs Q2 2016 ($ millions) Three months ended June 30, 2017 (Unaudited) 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 $20.3 ($2.3) ($1.8) ($3.1) $1.0 $14.0 Equity method 8.8 - (0.5) (0.0) 0.5 8.8 Total 29.1 (2.3) (2.3) (3.1) 1.5 22.8 West U.S. Consolidated 10.3 - - - (5.6) 4.7 Equity method 0.4 - - - 2.8 3.2 Total 10.6 - - - (2.8) 7.8 Canada Consolidated 45.2 (0.0) (0.0) (0.3) 1.1 46.0 Equity method - - - - - - Total 45.2 (0.0) (0.0) (0.3) 1.1 46.0 Total consolidated 75.8 (2.4) (1.8) (3.4) (3.6) 64.6 Total equity method 9.2 - (0.5) (0.0) 3.3 12.0 Un-allocated corporate 0.4 - - (0.0) (0.4) (0.1) Total $85.4 ($2.4) ($2.3) ($3.5) ($0.7) $76.6 Three months ended June 30, 2016 (Unaudited) 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 $12.2 ($2.1) ($2.4) ($1.1) $2.6 $9.1 Equity method 8.7 - (0.5) (0.0) 0.8 9.1 Total 20.9 (2.1) (2.8) (1.2) 3.4 18.2 West U.S. Consolidated 11.4 - - 0.0 (3.3) 8.2 Equity method 3.1 - - - 0.6 3.7 Total 14.5 - - 0.0 (2.7) 11.9 Canada Consolidated 10.9 - (0.0) (0.3) 2.1 12.7 Equity method - - - - - - Total 10.9 - (0.0) (0.3) 2.1 12.7 Total consolidated 34.5 (2.1) (2.4) (1.4) 1.4 30.0 Total equity method 11.8 - (0.5) (0.0) 1.5 12.8 Un-allocated corporate (0.1) - - - 0.1 0.0 Total $46.2 ($2.1) ($2.8) ($1.4) $2.9 $42.8

34 Cash Distributions from Projects, June YTD 2017 vs June YTD 2016 ($ millions) Six months ended June 30, 2017 (Unaudited) Unaudited 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 $35.5 ($4.6) ($3.9) ($4.3) $0.9 $23.6 Equity method 20.6 - (0.8) (0.1) (4.2) 15.5 Total 56.2 (4.6) (4.8) (4.4) (3.3) 39.1 West U.S. Consolidated 15.9 - - (0.0) (5.6) 10.3 Equity method 3.9 - - - 1.5 5.4 Total 19.8 - - (0.0) (4.1) 15.7 Canada Consolidated 72.8 (0.1) (0.0) (0.6) (3.0) 69.1 Equity method - - - - - - Total 72.8 (0.1) (0.0) (0.6) (3.0) 69.1 Total consolidated 124.2 (4.7) (3.9) (4.8) (7.8) 102.9 Total equity method 24.5 - (0.8) (0.1) (2.7) 20.9 Un-allocated corporate 0.6 - - (0.1) (0.4) 0.1 Total $149.3 ($4.7) ($4.8) ($5.0) ($10.9) $123.9 Six months ended June 30, 2016 (Unaudited) 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 $31.6 ($4.3) ($2.9) $2.9 $3.7 $31.0 Equity method 19.6 - (0.9) (0.1) (2.7) 15.9 Total 51.2 (4.3) (3.8) 2.8 1.1 47.0 West U.S. Consolidated 15.6 - - (0.0) (2.0) 13.6 Equity method 6.4 - - - 0.5 6.9 Total 22.0 - - (0.0) (1.4) 20.5 Canada Consolidated 35.7 - (0.0) (0.6) (4.2) 30.9 Equity method - - - - - - Total 35.7 - (0.0) (0.6) (4.2) 30.9 Total consolidated 82.9 (4.3) (2.9) 2.3 (2.5) 75.6 Total equity method 26.0 - (0.9) (0.1) (2.1) 22.9 Un-allocated corporate (0.2) - - 0.3 (0.1) (0.0) Total $108.7 ($4.3) ($3.8) $2.5 ($4.7) $98.4

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 35 and 36. 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 33 and 34. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. 35 Atlantic Power Corporation Table 8 – Reconciliation of Net Loss to Project Adjusted EBITDA $ millions, unaudited Three months ended June 30 Six months ended June 30 2017 2016 2017 2016 Net loss attributable to Atlantic Power Corporation ($21.9) ($18.5) ($24.6) ($33.5) Net income attributable to preferred share dividends of a subsidiary company 2.1 2.2 4.3 4.2 Net loss ($19.8) ($16.3) ($20.3) ($29.3) Income tax benefit (22.3) (18.4) (22.6) (16.8) Loss from operations before income taxes (42.1) (34.7) (42.9) (46.1) Page 47 Administration 5.7 5.8 12.1 11.9 Interest expense, net 18.4 51.2 35.7 67.8 Foreign exchange loss 5.9 2.6 8.3 22.5 Other income, net - 0.3 - (2.2) Project (loss) income ($12.1) $25.2 $13.2 $53.9 Reconciliation to Project Adjusted EBITDA Depreciation and amortization $34.7 $30.4 $69.3 $60.3 Interest expense, net 2.5 2.9 5.3 5.4 Change in the fair value of derivative instruments 2.6 (12.2) 3.8 (11.0) Other expense - (0.1) - 0.1 Impairment 57.7 - 57.7 - Project Adjusted EBITDA $85.4 $46.2 $149.3 $108.7 $39.20 $40.60 1 EBITDA check TRUE TRUE TRUE TRUE Proj Income check TRUE TRUE TRUE TRUE updated 7/26

36 Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment, Q2 2017 vs Q2 2016 ($ millions) Three months ended June 30, 2017 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($43.3) $0.7 $31.1 ($8.3) ($19.8) Net income attributable to preferred share dividends of a subsidiary company - - - - - Net (loss) income (43.3) 0.7 31.1 (8.3) (19.8) Income tax (benefit) expense - - - (22.3) (22.3) Income (loss) from continuing operations before income taxes (43.3) 0.7 31.1 (30.6) (42.1) Administration - - - 5.7 5.7 Interest expense, net - - - 18.4 18.4 Foreign exchange loss (gain) - - - 5.9 5.9 Other income, net - - - - - Project income (loss) (43.3) 0.7 31.1 (0.6) (12.1) Change in fair value of derivative instruments 0.7 - 0.9 1.0 2.6 Depreciation and amortization 11.4 10.0 13.2 0.1 34.7 Interest expense, net 2.6 (0.1) - - 2.5 Other project expense 57.7 - - - 57.7 Project Adjusted EBITDA $29.1 $10.6 $45.2 $0.5 $85.4 Three months ended June 30, 2016 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation $9.6 $4.6 $12.9 ($43.4) ($16.3) Net income attributable to preferred share dividends of a subsidiary company - - - - - Net (loss) income 9.6 4.6 12.9 (43.4) (16.3) Income tax (benefit) expense - - - (18.4) (18.4) Income (loss) from continuing operations before income taxes 9.6 4.6 12.9 (61.8) (34.7) Administration - - - 5.8 5.8 Interest expense, net - - - 51.2 51.2 Foreign exchange loss (gain) - - - 2.6 2.6 Other income, net - - - 0.3 0.3 Project income (loss) 9.6 4.6 12.9 (1.9) 25.2 Change in fair value of derivative instruments (2.5) - (11.6) 1.9 (12.2) Depreciation and amortization 10.9 9.9 9.6 - 30.4 Interest expense, net 2.9 - - - 2.9 Other project expense - - - 0.1 0.1 Project Adjusted EBITDA $20.9 $14.5 $10.9 $0.1 $46.4

37 Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment, June YTD 2017 vs June YTD 2016 ($ millions) Six months ended June 30, 2017 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($30.8) $- $42.3 ($31.8) ($20.3) Net income attributable to preferred share dividends of a subsidiary company - - - - - Net (loss) income (30.8) - 42.3 (31.8) (20.3) Income tax (benefit) - - - (22.6) (22.6) Income (loss) from operations before income taxes (30.8) - 42.3 (54.4) (42.9) Administration - - - 12.1 12.1 Interest expense, net - - - 35.7 35.7 Foreign exchange loss - - - 8.3 8.3 Other income, net - - - - - Project (loss) income (30.8) - 42.3 1.7 13.2 Change in fair value of derivative instruments 1.3 - 0.9 (1.6) 0.6 Depreciation and amortization 22.7 10.0 13.2 0.4 46.3 Interest expense, net 5.3 (0.1) - - 5.2 Impairment 57.7 - - - 57.7 Project Adjusted EBITDA $56.2 $9.9 $56.4 $0.5 $123.0 Six months ended June 30, 2016 East U.S. West U.S. Canada Un-allocated Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation $25.6 $2.3 $29.3 ($86.5) ($29.3) Net income attributable to preferred share dividends of a subsidiary company - - - - - Net (loss) income 25.6 2.3 29.3 (86.5) (29.3) Income tax (benefit) expense - - - (16.8) (16.8) Income (loss) from operations before income taxes 25.6 2.3 29.3 (103.3) (46.1) Administration - - - 11.9 11.9 Interest expense, net - - - 67.8 67.8 Foreign exchange loss - - - 22.5 22.5 Other income, net - - - (2.2) (2.2) Project income (loss) 25.6 2.3 29.3 (3.3) 53.9 Change in fair value of derivative instruments (1.7) - (12.1) 2.8 (11.0) Depreciation and amortization 21.9 19.7 18.5 0.2 60.3 Interest expense, net 5.4 - - - 5.4 Other project expense - - - 0.1 0.1 Project Adjusted EBITDA $51.2 $22.0 $35.7 ($0.2) $108.7