AtlanticPower Corporation Q1 2017 Financial Results Conference Call May 5, 2017

Cautionary Note Regarding Forward-Looking Statements 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 slide 34. 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 32. All amounts in this presentation are in US$ and approximate unless otherwise stated. 2

Agenda CEO:Q1 2017 Highlights and Recent Operations Review Commercial Review / PPAs Q1 2017 Financial Results Developments Balance Sheet and Liquidity 2017 Guidance Update CEO: Q&A Concluding Remarks 3

Q1 2017 Highlights Solid start to the year ̵ ̵ ̵ ̵ Plant operations as expected Spring maintenance outages on track No safety issues Hydro conditions at Curtis Palmer looking better Financial results in line with expectations ̵ Project Adjusted EBITDA of $63.8 million vs. $62.5 million Did not include any benefit from Global Adjustment payments (OEFC) o ̵ Cash provided by operating activities of $34.1 million vs. $29.4 million Included about $8 million of Global Adjustment payments o • Debt reduction on track ̵ ̵ Repaid $27.3 million of term loan and project debt in Q1 Expect to repay $150 million or more of debt this year Improved liquidity $214 million at March 31 vs. $204 million at December 31, 2016 Includes $91.5 million of unrestricted cash (including $66 million at the parent)  Increased 2017 guidance by $25 million for Global Adjustment payments ̵ Now $250 to $265 million 4

Developments Since Q4 / YE 2016 Call In April, finalized settlement for Cdn$36.1 million (approximately US$26 million) Represents revenues that we should have received in April 2013 through the current year for Kapuskasing, North Bay and Tunis plants Received Cdn$10.7 million in Q1 2017 and another Cdn$20.3 million in early May (Q2) Q1 2017 amount recorded as deferred revenue; benefited cash flow but not included in Q1 2017 Project Adjusted EBITDA of $63.8 million • ̵ Q1 and May 2017 payments will be recorded in Q2 2017 EBITDA Expect to receive another Cdn$5.1 million over the balance of the year Adds significantly (~ US$18 million) to our cash at the parent ($66 million) 5 OEFC Settlement Regarding Global Adjustment Dispute

Developments Since Q4 / YE 2016 Call (continued) In April, successfully repriced $615 million term loan and $200 million revolver Reduced spread by 75 bp to LIBOR + 4.25% Results in interest cost savings, net of transaction fees, of $2.4 million in 2017 and $17 million over remaining lives of facilities Resolution of required amendment to air permit expected in next couple of months Evaluating options for 2018 debt maturity - - Sale process expect would result in proceeds in excess of project debt Continue to own pay down or refinance 8.5% debt Disciplined approach: we believe both are good options 6 Piedmont Term Loan / Revolver Repricing

Q1 2017 Operational Performance: Lower generation primarily due to curtailment of the Ontario gas plants 1.67 596 FY 2014 FY 2015 FY 2016 Q1 2017 2.3% (1) 2014 BLS data, generation companies = 1.1 (2) 2015 BLS data, generation companies = 1.4 Q1 2017 East U.S. Q1 2017 West U.S. Q1 2017 Canada Q1 2017 Availability (weighted average) Total Q1 2017 Q1 2016 Generation is down: - Kapuskasing/Nipigon/North Bay are not in operation for 2017 under the enhanced dispatch contracts with the IESO Mamquam lower water flows (compared to record levels in 2016) Morris merchant generation down due to mild weather and low PJM demand Naval Station favorable due to major outage in prior period - - + Total 96.8% 96.6% Availability factor in line: + Naval Station is favorable due to major outage in prior period - Mamquam is unfavorable due to planned outage in current period 7 East U.S. West U.S. Canada 98.8%99.0% 94.7%89.6% 91.4%99.5% 664 343351 544 1,551 (25.3%) 1,159 (10.2%) (61.1%) 212 Q1 2016 Q1 2016 Q1 2016 Q1 2016 1.25 Indu avg Industry avg (2) 0.7 stry (1) 0 Safety: Total Recordable Incident Rate Aggregate Power Generation Q1 2017 vs. Q1 2016 (thousands, Net MWh)

Operations Update Kapuskasing, Nipigon and North Bay in non-operational state Plan to return Tunis to service in 2018 - Work to be done in latter part of 2017 Still in discussions with relevant parties in Ontario on potential initiatives that could affect Tunis and/or Nipigon Morris Work on completing third and final combustion turbine upgrade (optimization project); currently under way; plant continuing to operate on two previously upgraded turbines Frederickson Major outage for gas and steam turbines began in late April Kenilworth Steam turbine overhaul, but plant continues to operate on gas turbine Orlando Major turbine maintenance completed Analysis and benchmarking of operation and maintenance costs under way Goal improved efficiency and operational performance Expect to have more to say in 2H 2017 8 Cost Reduction Initiatives Scheduled Maintenance Outages Ontario Plants

Commercial Update:PPA Renewal Status Continuing discussions with relevant parties on potential initiatives for Nipigon and Tunis that would be mutually beneficial Three plants PPAs with San Diego Gas & Electric (SDG&E) expire Dec. 2019, but Navy steam contracts / leases expire Feb. 2018 Continuing discussions with SDG&E for PPAs at two of three plants Also considering other contracting options for Oxnard and San Diego plants Navy issued solicitation for energy resiliency proposals for Naval Station and North Island We responded in mid-March Notified early May that we have been selected to move into second phase for both Discussions with BC Hydro continuing on potential extension of existing PPA (expires March 2018) - - - Focus is on a short-term extension that would bridge to outcome of Integrated Resource Plan (2019) Would not require investment in a new fuel shredder Would result in significantly lower Project Adjusted EBITDA compared to existing PPA Regarding appeal of amended air permit for new shredder - - - Some of the appeals were dismissed by Environmental Appeal Board Oral hearing likely in toward year-end or early 2018 Final decision could be in first-half 2018 9 Williams Lake San Diego Plants Ontario

Q1 2017 Project Adjusted EBITDA ($ millions) $4 $63.8 $62.5 $(5) $3 $2 $(2) $(1) Kapuskasing Fuel savings driven by expiration of out-of-market fuel contract and enhanced dispatch contracts $1 $(1) Morris North Bay Fuel savings driven by expiration of out-of-market fuel contract and enhanced dispatch contracts 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 Mamquam Lower water flows (typical flows in ‘17 versus very high flows in ‘16) Orlando Favorable fuel swap settlement impact Calstock Lower waste heat and expiration of fuel adder Other, net Naval Station Hot gas path overhaul in prior period Q1 2016 Q1 2017 10

Q1 2017 Cash Flow Results ($ millions) 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) Project debt amortization Capital expenditures Preferred dividends (25.0) (2.3) (2.0) (2.1) (25.3) (2.1) (0.7) (2.0) (1) Includes 1% mandatory annual amortization and targeted debt repayments. 11 0.3 (0.2) (1.3) (0.1) 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)

Liquidity ($ millions) Unaudited 12/31/16 3/31/17 Revolver capacity Letters of credit outstanding Unused borrowing capacity Unrestricted cash $200.0 (81.5) 118.5 85.6 $200.0 (77.5) 122.5 91.5 (4.0) 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. 12 Includes ~ $66 at APC (parent); balance is at the plants or other subsidiaries (10) Need for working capital purposes ~ 56 Discretionary cash available $4 reduction in LCs (debt service LC)

Progress on Debt Reduction (Unaudited) and Leverage ($ millions) Leverage (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) Repayment of previous term loan (April) 3/31/16 consolidated debt pro forma 700 (448) 1,246 7.1x Changes Q2-Q4 2016: Redemption of 2017 convertible debentures (May) Repurchase of 2019 convertible debentures (July) Amortization of new term loan (Q2 Q4) Amortization of project debt (Q2 Q4) Incremental F/X impact (unrealized gain) (Q2 Q4) 12/31/16 consolidated debt (110) (63) (60) (9) (7) 997 5.6x Changes Q1 2017: Amortization of new term loan Amortization of project debt Incremental F/X impact (unrealized loss) 3/31/17 consolidated debt (25) (2) 2 971 5.4x Note: Consolidated debt excludes unamortized discounts and deferred financing costs (1) Consolidated gross debt to trailing 12-month Adjusted EBITDA (after Corporate G&A) 13 Total net reduction in consolidated debt of approximately $905 million since YE 2013; in addition, debt at equity-owned projects has been reduced by approximately $89 million. By year end 2016, had paid down all but $10 of $252 increase Net increase in debt $252

Debt Repayment Profile at March 31, 2017 ($ millions) Includes Company’s share of debt at equity-owned projects 450 $390 400 350 $158 300 250 200 > 80% of initial principal to be 150 repaid by 2023 maturity 100 50 0 (US$) Rest of 2017 2018 2019 APLP Holdings Term Loan 2020 2021 Thereafter Project-level debt APC Convertible Debentures APLP Medium-term Notes Project-level non-recourse debt totaling $138, including $43 at Chambers (equity method); includes Piedmont bullet maturity of $54.1 (2018); remainder amortizes over the life of the project PPAs $615 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) $103 (US$ equivalent) of convertible debentures (maturing in June and December 2019) $158 APLP Medium-term Notes due in 2036 Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.3299. 14 57% amortizing, 43% bullet $177 $154 $103$116 $85$92 Total $1,014

Projected Debt Balances through 2020 ($ millions) Includes Company’s share of debt at equity-owned projects $1,014 $927 $830 $756 $640 (US$) APLP Holdings Term Loan Project-level debt APC Convertible Debentures APLP Medium-term Notes Q1 2017 Year-end 2020: Term loan Repay $335, ending balance $280 annual interest cost savings $18 by 2021 Project debt (proportional) Repay $39, ending balance $99 annual interest cost savings $2 Assumes Piedmont ($54) is refinanced at maturity in 2018 if repaid, would have annual interest cost savings of ~ $5 Assumes 2019 convertible debentures ($103) are refinanced or repaid using revolver (no change in debt) - If redeemed or repurchased using cash, annual interest savings of up to $6 in 2020 Cumulative Paydown of Debt Drives Interest Cost Savings Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.3299. 15 Assumes Piedmont is refinanced Assumes convertible debentures are refinanced or repaid using revolver Required 2017 amortization approx. $112 but expect to repay more than $150 in total

2017 Project Adjusted EBITDA Guidance ($ millions) Guidance revised to $250 to $265 (had been $225 to $240) 5/4/17 Guidance $250 - $265 $26 3/2/17 Guidance $225 - $240 $26 $4 $202 $4 $(3) OEFC/ Global Adjustment Settlement Optimization CT upgrades at Morris; assumed return to average water flows at Curtis Palmer Expiration of above-market fuel contract Other Tunis repowering (-) Morris ‘16 outage (+) Ontario cost savings (+) Frederickson outage (-) Water Return to average: Curtis Palmer (+) Mamquam (-) (2) Kapuskasing and North Bay FY 2016 FY 2017 FY 2017 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. 16 Key drivers include: Kapuskasing & North Bay (see above), higher Optimization returns and assumed average water flows at Curtis Palmer (+) and Mamquam (-) Kapuskasing & North Bay 2016 Project Adjusted EBITDA $10 Gros s m argin (1) + 30 O&M cos t s avings + 7 OEFC / Global Adjus tm ent s ettlem ent + 20 2017 Estimate ~$67 (1) Includes impact o f enhanced dispatch co ntracts and expiratio n o f abo ve-market gas co ntract

Bridge of 2017 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities ($ millions) 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) 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. 17 2017 expected uses of cash provided by operating activities: Term loan repayments(3) $100 Project debt amortization12 Capital expenditures5 Preferred dividend payments9 2017 Project Adjusted EBITDA Guidance(1) $250 - $265 Adjustment for equity method projects(2) Corporate G&A expense Cash interest payments Cash taxes Other (1) (22) (67) (4) - Cash provided by operating activities $155 - $170

CEO: Concluding Remarks Atlantic Power in much better position than three years ago ̵ Lower interest expense and corporate overheads (down $91 million) Significant compared to Project Adjusted EBITDA of $250 to $265 million o ̵ Much lower debt balance; improved liquidity ($214 million) Good options for allocating cash flow and using liquidity ̵ ̵ ̵ ̵ Retain ownership of Piedmont / pay down project-level debt Redeem 2019 convertible debentures Develop new projects for industrial customers Repurchase shares when trading at a discount to our estimates of intrinsic value 18

Appendix TABLE OF CONTENTS Page 20-23 24-26 Capital Structure Information Project Information Supplemental Financial Information Q1 2017 Results Summary G&A and Development Expenses Net Operating Loss Project Income by Project Project Adjusted EBITDA by Project Cash Distributions by Segment Non-GAAP Disclosures 27 28 29 30 31 32 33-34 19

Capitalization ($ millions) 20 December 31, 2016 March 31, 2017 Long-term debt, incl. current portion (1) APLP Medium-Term Notes (2) Revolving credit facility Term Loan Project-level debt (non-recourse) Convertible debentures $156 - 640 97 103 $158 - 615 95 103 Total long-term debt, incl. current portion Preferred shares Common equity (3) $99678% 22117% 655% $97177% 22118% 635% Total shareholders equity Total capitalization 28622% $1,282100% 28423% $1,255100% (1) Debt balances are shown before unamortized discount and unamortized deferred financing costs (2) Period-over-period change due to F/X impacts (3) 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, 2017 ($ millions) (1) As of April 17, 2017, the spread is reduced to 3.75%. (2) Includes impact of interest rate swaps. (3) As of April 17, 2017, the interest rate is 5.25%-5.37%. (4) Set on December 1, 2016 for March 31, 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 $1.3299. 21 Atlantic Power Corporation Maturity Convertible Debentures (ATP.DB.U)6/2019 Convertible Debentures (ATP.DB.D)12/2019 Actual Amount $42.5 $60.9 (C$81.0) Interest Rate 5.75% 6.0% APLP Holdings Limited Partnership Revolving Credit Facility Term Loan Actual MaturityAmountInterest Rate 4/2021$0LIBOR + 5.00% (1) 4/2023$614.96.00%-6.12% (2) (3) Atlantic Power Limited Partnership Medium-term Notes Preferred shares (AZP.PR.A) Preferred shares (AZP.PR.B) Preferred shares (AZP.PR.C) Actual MaturityAmountInterest Rate 6/2036 $157.9 (C$210) 5.95% N/A $93.1 (C$125) 4.85% N/A $45.5 (C$58.5) 5.57% N/A $31.0 (C$41.5) 4.68% (4) Atlantic Power Transmission & Atlantic Power Generation MaturityAmountInterest Project-level Debt (consolidated)Various$94.84.20%-8.47% Project-level Debt (equity method)Various$42.94.50%-5.00%

APLP Holdings Term Loan Cash Sweep Calculation 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 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. 22 If targeted debt balance is < 50% of cash flow sweep: •Repay 50% minimum •Remaining 50% to Company 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

APLP Holdings Credit Facilities Financial Covenants Leverage ratio: Interest Coverage 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. Fiscal Quarter Leverage Ratio 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. 23 3/31/2017 6.00:1.00 2.75:1.00 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 3.5:1.00 9/30/2020 4.25:1.00 3.5:1.00 12/31/2020 4.25:1.00 3.5:1.00 3/31/2021 4.25:1.00 3.5:1.00 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

Power Projects (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 24 Atlantic Power Corporation APLP Holdings Limited Partnership Atlantic Power Limited Partnership Atlantic Power Transmission & Atlantic Power Generation EconomicNetContract ProjectLocationTypeInterestMWExpiry EconomicNetContract ProjectLocationTypeInterestMWExpiry CadillacMichiganBiomass100%4012/2028 ChambersNew JerseyCoal40%10512/2024 OrlandoFloridaNat. Gas50%6512/2023 Piedmont (1) GeorgiaBiomass100%5512/2032 SelkirkNew YorkNat. Gas17.7%61Merchant CalstockOntarioBiomass100%356/2020 KapuskasingOntarioNat. Gas100%4012/2017 MamquamB.C.Hydro100%509/2027 Morseby LakeB.C.Hydro100%68/2022 NipigonOntarioNat. Gas100%4012/2022 North BayOntarioNat. Gas100%4012/2017 TunisOntarioNat. Gas100%4011/2032 (2) Williams LakeB.C.Biomass100%663/2018 Koma KulshanWashingtonHydro49.8%612/2037 Canada East U.S. West U.S. Curtis PalmerNew YorkHydro100%6012/2027 KenilworthNew JerseyNat. Gas100%299/2018 MorrisIllinoisNat. Gas100%17712/2034 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

Earnings and Cash Flow Diversification by Project No single project contributed more than 17% to Project Adjusted EBITDA for the three months ended March 31, 2017 (1) Three months ended March 31, 2017 Project Adjusted EBITDA by Segment (1) Ma nchi ef Other (8 projects) 1% 5% Curti s Pa l mer 17% North Ba y 11% Ka pus ka s ing 12% Orl a ndo 11% Three months ended March 31, 2017 Cash Distributions from Projects by Segment (2) Ca di l l ac 3% North Is l a nd 2% Ca l s tock 2% Pi edmont Cha mbers 8% 2% Na va l Sta ti on Morri s 1% 2% Frederi cks on 5% Ni pi gon 9% Wi l l iams La ke 7% (1) Based on $63.8 million in Project Adjusted EBITDA for the three months ended March 31, 2017. Un-allocated corporate segment is included in “Other” category for project percentage allocation and allocated equally among segments for three months ended March 31, 2017 Project Adjusted EBITDA by Segment. (2) Based on $47.3 million in Cash Distributions from Projects for the three months ended March 31, 2017. 25 Capacity (MW) by Segment East U.S.: 51% West U.S.: 30% Canada: 18%

Majority of Cash Flows Covered by Contracts with More Than 5 Years Remaining Contracted projects have an average remaining PPA life of 5.8 years (1) PPA Length (years) (1) Pro Forma Offtaker Credit Rating (1) (1) Weighted by FY 2017 Project Adjusted EBITDA estimate (excluding contribution of OEFC / Global Adjustment payments). 26 70% of estimated 2017 Project Adjusted EBITDA generated from PPAs that expire beyond the next five years

Results (Unaudited) Summary, Q1 2017 vs Q1 2016 ($ millions) Summary of Financial and Operating Results Thre e m onths e nde d M arch 31 2017 2016 Financial Re s ults Project revenue Project income Net loss attributable to Atlantic Pow er Corp. Cash provided by operating activities Project Adjusted EBITDA $98.4 25.3 (2.7) 34.1 63.8 $106.4 28.7 (14.9) 29.4 62.5 Ope rating Re s ults Aggregate pow er generation (thousands of Net MWh) Weighted average availability 1,158.7 96.8% 1,586.9 96.6% Segment Results Thre e m onths e nde d M arch 31 2017 2016 Proje ct incom e (los s ) East U.S. West U.S. Canada Un-allocated Corporate Total $12.9 (0.7) 10.9 2.2 25.3 $16.1 (2.4) 16.4 (1.4) 28.7 Proje ct Adjus te d EBITDA East U.S. West U.S. Canada Un-allocated Corporate Total $27.2 9.1 27.5 - 63.8 $30.3 7.5 24.8 (0.1) 62.5 27

G&A and Development Expenses ($ millions) Included in Project Adj. EBITDA “Administration” expense on Income Statement; not included in Project Adj. EBITDA (1) 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. (2) Includes $6 severance in 2014; approximately $4 severance and $2 restructuring in 2015 28 2016 level represents a 57% reduction from 2013 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) 2013 Actual 2014 Actual 2015 Actual 2016 Actual Development (1) Project G&A and Other Corporate G&A (2) $7.2 11.4 35.2 $3.7 3.8 37.9 $1.1 1.5 29.4 n/a (1) 0.2 22.6 Total Overhead $53.8 $45.4 $31.9 $22.8

Net Operating Loss Carryforwards (NOLs) ($ millions) As of December 31, 2016, we had NOLs scheduled to expire per the schedule below that we can utilize to offset future taxable income: NOLs represent approximately $216 million in potential future tax savings Although we expect these NOLs will be available to us as a future benefit: - - Some of the NOLs are subject to limitations on their use. Concurrent with closing the term loan refinancing, we implemented a tax restructure by moving APG and APT underneath USGP to form one consolidated tax group. We believe this structure will allow the Company to operate in the most tax-efficient manner going forward. Note: USGP = Atlantic Power (US) GP Holdings Inc.; APG = Atlantic Power Generation; APT = Atlantic Power Transmission 29 2027$43.2 202893.0 202970.8 203025.8 203113.4 203219.0 2033137.7 2034167.0 203517.0 203632.1 Total$619.0

Project Income (Loss) by Project ($ millions) Three months ended March 31 2017 2016 Accounting Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Equity m ethod Equity m ethod Equity m ethod East U.S. Cadillac Curtis Palm er Kenilworth Morris Piedm ont Cham bers Orlando Selkirk Total West U.S. Manchief Naval Station Naval Training Center North Is land Oxnard Fredericks on Kom a Kuls han Total Canada Cals tock Kapus kas ing Mam quam Nipigon North Bay William s Lake Other Total Totals Cons olidated projects Equity m ethod projects Un-allocated corporate $0.6 7.0 0.1 0.2 (1.9) 2.5 5.1 $0.7 7.0 (0.1) 3.8 (5.0) 3.4 6.6 (0.7) (0.3) 12.9 16.1 Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Equity m ethod Equity m ethod 0.6 (0.3) (0.3) 0.3 (1.9) 0.9 0.5 (1.3) (0.2) (0.5) (1.7) 0.6 - 0.2 (0.7) (2.4) Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated 0.9 3.1 0.4 0.5 3.5 2.5 2.3 3.6 2.3 0.8 4.1 3.0 - 0.3 10.9 16.4 15.3 7.8 2.2 19.6 10.5 (1.4) Total Project Income $25.3 $28.7 30

Project Adjusted EBITDA by Project ($ millions) Unaudited Unaudited Three months ended March 31 Three months ended March 31 2017 2016 2017 2016 Accounting Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Equity m ethod Equity m ethod Equity m ethod East U.S. Cadillac Curtis Palm er Kenilworth Morris Piedm ont Cham bers Orlando Selkirk Total West U.S. Manchief Naval Station Naval Training Center North Is land Oxnard Fredericks on Kom a Kuls han Total Canada Cals tock Kapus kas ing Mam quam Nipigon North Bay William s Lake Other (1) Total Totals Cons olidated projects Equity m ethod projects Un-allocated corporate Total Project Adjusted EBITDA $63.8 $62.5 $1.8 10.9 0.8 0.7 1.2 5.4 7.1 (0.7) $2.1 10.9 0.5 5.4 0.6 6.1 5.1 (0.3) Other project expens e Interes t expens e, net Depreciation and am ortization Change in fair value of derivative ins trum ents ($0.0) 2.4 34.9 1.2 $0.2 2.5 29.9 1.2 Project income $25.3 $28.7 Other incom e, net Foreign exchange los s Interes t expens e, net Adm inis tration - 2.5 17.3 6.4 (2.5) 19.8 16.6 6.1 27.2 30.3 Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Equity m ethod Equity m ethod 3.3 1.3 0.4 1.4 (0.9) 3.4 3.3 0.3 0.6 0.7 (0.6) 3.0 Los s from operations before incom e taxes Incom e tax (benefit) expens e (0.9) (0.3) (11.3) 1.6 Net loss ($0.6) ($12.9) 0.1 0.3 9.1 7.5 Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated Cons olidated 1.5 7.4 0.8 5.7 7.3 4.6 2.8 3.8 2.6 5.8 4.2 5.1 0.2 0.5 27.5 24.8 48.5 15.3 0.0 48.5 14.2 (0.1) Total Project Adjusted EBITDA $63.8 $62.5 (1) Includes Tunis and Moresby Lake 31

Cash Distributions from Projects, Q1 2017 vs Q1 2016 ($ millions) Three months ended March 31, 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. Cons olidated Equity m ethod Total West U.S. Cons olidated Equity m ethod Total Canada Cons olidated Equity m ethod Total $15.4 11.8 ($2.3) - ($2.1) (0.5) ($1.2) (0.0) ($0.1) (4.6) $9.7 6.7 27.2 (2.3) (2.5) (1.2) (4.7) 16.4 5.6 3.5 - - - - (0.0) - 0.0 (1.3) 5.6 2.2 9.1 - - (0.0) (1.3) 7.8 27.5 - (0.0) - (0.0) - (0.3) - (4.1) - 23.1 - 27.5 (0.0) (0.0) (0.3) (4.1) 23.1 Total cons olidated Total equity m ethod Un-allocated corporate 48.5 15.3 0.0 (2.4) - - (2.1) (0.5) - (1.5) (0.0) (0.0) (4.2) (5.9) 0.0 38.4 8.9 (0.0) Total $63.8 ($2.4) ($2.5) ($1.5) ($10.1) $47.3 Three months ended March 31, 2016 (Unaudited) Project Adjusted EBITDA Repayment of long-term debt Interest expense, net Capital Other, including changes in Cash Distributions from Projects expenditures working capital Segment East U.S. Cons olidated Equity m ethod Total West U.S. Cons olidated Equity m ethod Total Canada Cons olidated Equity m ethod Total $19.4 10.9 ($0.6) (1.5) ($1.9) (0.6) $4.0 (0.0) $3.2 (3.5) $24.1 5.2 30.3 (2.1) (2.5) 4.0 (0.3) 29.3 4.2 3.3 - - - - - (0.0) 1.3 (0.6) 5.4 2.7 7.5 - - (0.0) 0.6 8.1 24.8 - - - (0.0) - (0.3) - (6.3) - 18.2 - 24.8 - (0.0) (0.3) (6.3) 18.2 Total cons olidated Total equity m ethod Un-allocated corporate 48.5 14.2 (0.1) (0.6) (1.5) - (1.9) (0.6) - 3.7 (0.0) 0.3 (1.8) (4.2) (0.2) 47.8 7.9 (0.0) Total $62.5 ($2.1) ($2.5) $4.0 ($6.1) $55.7 32

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 slide 34. 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 32. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. Una udi ted Thre e m onths e nde d M arch 31 2017 2016 Ne t los s attributable to Atlantic Pow e r Corporation Net income attributable to pref erred share dividends of a subsidiary company ($2.7) 2.1 ($14.9) 2.0 Net loss Income tax benef it Loss f rom operations bef ore income taxes Administration Interest expense, net Foreign exchange loss Other income, net ($0.6) (0.3) ($12.9) 1.6 (0.9) 6.4 17.3 2.5 - (11.3) 6.1 16.6 19.8 (2.5) Proje ct incom e $25.3 $28.7 Re conciliation to Proje ct Adjus te d EBITDA Depreciation and amortization Interest expense, net Change in the f air value of derivative instruments Other expense $34.9 2.4 1.2 - $29.9 2.5 1.2 0.2 Proje ct Adjus te d EBITDA $63.8 $62.5 33

Reconciliation of Net Income (Loss) to Project Adjusted EBITDA by Segment, Q1 2017 vs Q1 2016 ($ millions) Three months ended March 31, 2017 (unaudited) Un-allocated Corporate East U.S. West U.S. Canada Consolidated Net (los s ) incom e attributable to Atlantic Power Corporation Net incom e attributable to preferred s hare dividends of a s ubs idiary com pany $12.9 - ($0.7) - $10.9 - ($25.8) 2.1 ($2.7) 2.1 Net (los s ) incom e Incom e tax (benefit) expens e 12.9 - (0.7) - 10.9 - (23.7) (0.3) (0.6) (0.3) Incom e (los s ) from operations before incom e taxes Adm inis tration Interes t expens e, net Foreign exchange los s Other incom e, net 12.9 - - - - (0.7) - - - - 10.9 - - - - (24.0) 6.4 17.3 2.5 - (0.9) 6.4 17.3 2.5 - Project incom e (los s ) Change in fair value of derivative ins trum ents Depreciation and am ortization Interes t expens e, net Other project expens e 12.9 0.2 11.5 2.6 - (0.7) - 10.0 (0.2) - 10.9 3.3 13.3 - - 2.2 (2.3) 0.1 - - 25.3 1.2 34.9 2.4 - Project Adjus ted EBITDA $27.2 $9.1 $27.5 $-$63.8 Three months ended March 31, 2016 (unaudited) Un-allocated Corporate East U.S. West U.S. Canada Consolidated Net (los s ) incom e attributable to Atlantic Power Corporation Net incom e attributable to preferred s hare dividends of a s ubs idiary com pany $16.1 - ($2.4) - $16.4 - ($45.0) 2.0 ($14.9) 2.0 Net (los s ) incom e Incom e tax (benefit) expens e 16.1 - (2.4) - 16.4 - (43.0) 1.6 (12.9) 1.6 Incom e (los s ) from operations before incom e taxes Adm inis tration Interes t expens e, net Foreign exchange los s Other incom e, net 16.1 - - - - (2.4) - - - - 16.4 - - - - (41.4) 6.1 16.6 19.8 (2.5) (11.3) 6.1 16.6 19.8 (2.5) Project incom e (los s ) Change in fair value of derivative ins trum ents Depreciation and am ortization Interes t expens e, net Other project expens e 16.1 0.7 11.0 2.5 - (2.4) - 9.9 - - 16.4 (0.4) 8.8 - - (1.4) 0.9 0.2 - 0.2 28.7 1.2 29.9 2.5 0.2 Project Adjus ted EBITDA $30.3 $7.5 $24.8 ($0.1) $62.5 34