Exhibit 99.1

PREPARED REMARKS

Q3 2018

NOVEMBER 2, 2018

Ron Bialobrzeski — Atlantic Power Corporation — Director, Finance

Page 2:  Cautionary Note Regarding Forward-Looking Statements

Financial figures that are presented in this document and the presentation are stated in U.S. dollars and are approximate unless otherwise noted.

Management’s prepared remarks presented in this document include forward-looking statements.  As discussed on page 2 of the accompanying presentation, these statements are not guarantees of future performance and involve certain risks and uncertainties that are more fully described in our various securities filings.  Actual results may differ materially from such forward-looking statements.  Please see Atlantic Power Corporation’s Safe Harbor statement, presented on page 2 of the accompanying presentation, which can be found in the Investor Relations section of our website.

In addition, the financial results in the Company’s press release and the presentation include both GAAP and non-GAAP measures, including Project Adjusted EBITDA.  For reconciliations of this measure to the most directly comparable GAAP financial measure to the extent that they are available without unreasonable effort, please refer to the press release, the Appendix of the presentation or our quarterly report on Form 10-Q, all of which are available on our website.

ATLANTIC POWER CORPORATION

Q3 2018

NOVEMBER 2, 2018

For additional information, please refer to our most recent SEC filings, which can be accessed free of charge on our website, www.atlanticpower.com, and on EDGAR and SEDAR.

James J. Moore, Jr. — Atlantic Power Corporation — President & CEO

Page 3:  Agenda

In the third quarter we continued to make progress on a number of fronts.  I will provide highlights of our financial results and recent operational and commercial developments.  The rest of the team will provide more detail.

Page 4:  Q3 2018 Highlights

Third quarter results.  As noted on page 4 of the presentation, third quarter results were generally in line with our expectations.  Our year-to-date results keep us on track to achieve our full year 2018 guidance for Project Adjusted EBITDA of $170 to $185 million.

Debt reduction.  During the third quarter we repaid nearly $21 million of debt and expect to repay a total of $100 million this year, using our strong operating cash flow from our existing businesses.

Interest costs.  We re-priced our term loan this week, reducing the spread by another 25 basis points to 275 basis points over LIBOR, down from 500 over when originally issued in April 2016.  The combination of lower debt levels and a lower rate on the term loan is continuing to reduce our annual interest payments, which benefits our operating cash flow.

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Costs.  Although the majority of the possible cost reductions have been achieved already, we continue to look for incremental cost reduction opportunities.  In September, we completed the move to smaller headquarters space in our existing building, which will reduce our annual rent by approximately $245,000 or more than 40% from the previous level.  Dan Rorabaugh and the asset management team continue to improve the efficiency of our operation and maintenance expenditures and practices.

Capital allocation.  We have allocated most of our free cash flow (as it is typically defined) to debt reduction and would continue to do so even if our term loan did not have a cash sweep.  Given the industry and the cash flow profile of our business, we think it is prudent to do so.

During the third quarter, we allocated approximately $22 million of our discretionary cash to a combination of share repurchases and growth investments.  Our common shares have been priced below our estimates of intrinsic value per share, so we repurchased and canceled $3.1 million in the third quarter (and $12.9 million this year through October).  Similarly, we have been able to buy in preferred shares at cash returns in excess of 10% (dividend plus avoided withholding tax on the dividend) and so we repurchased and canceled Cdn$4.5 million in the third quarter (and Cdn$10.3 million this year through October).

With attractive uses of capital on our own balance sheet, we have not stretched to invest in external growth in an environment marked by low returns and tax-driven investments.  We did reach two deals to acquire assets this year, both with long-dated PPAs.  These are our first external growth investments following our three-year program to improve performance and strengthen our balance sheet.

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In late July, we closed the acquisition of the 50% remaining interest in the Koma Kulshan hydro facility; our total investment was approximately $13 million net of cash received.

In September, we announced an agreement to acquire two 20 megawatt biomass plants in South Carolina for $13 million.  The plants have PPAs that run to 2043.  During the quarter, we paid $2.6 million toward the purchase price; the balance will be paid at closing in the latter part of 2019.  In his prepared remarks Joe Cofelice discusses this acquisition.  We think this investment represents a rare opportunity in the current market to earn attractive returns while adding to our PPA cover.

Even after allocating $22 million of cash for these purposes, we still had strong liquidity at Sept. 30, 2018 of approximately $181 million, including approximately $32 million of discretionary cash.    Our liquidity and the cash flow generated by our existing assets are sufficient for us to continue paying down debt while also investing internally and externally in a disciplined manner.

Tunis and Nipigon.  We returned Tunis to commercial operation under a 15-year PPA in early October.  Nipigon’s Long-Term Enhanced Dispatch Contract became effective this week; that contract runs through the end of 2022.

Commercial.  The most significant news this quarter was on the growth side, with two external acquisitions announced, as previously discussed.  On the PPA side, we were not successful in gaining site control at our San Diego projects and thus

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have begun preparations to decommission them.  We are still awaiting regulatory approval of our short-term contract extension at Williams Lake.

Dan Rorabaugh — Atlantic Power Corporation — SVP, Asset Management

Page 5:  Q3 2018 Operational Performance

Beginning with our safety record, we had no recordable injuries in the third quarter.  We continue to place the highest priority on maintaining a strong culture of safety and regulatory compliance.

Turning to our operating results, generation declined 14.1% in the third quarter, primarily because of the San Diego projects, which have been shut down since February 7 due to early termination of their PPAs.  In addition, generation at Curtis Palmer was down significantly from the year-ago period because of lower water flows, and Piedmont had a maintenance outage in July.  On the positive side, Manchief experienced higher dispatch and Frederickson generation increased due to higher demand resulting from above-average temperatures and lower hydro reserves.

Our availability factor in the third quarter of 2018 decreased to 94.3% from 98.6% in the year-ago period.  The decrease reflects maintenance outages at Morris, Cadillac (fall outage was extended for a turbine control upgrade), Moresby Lake (planned outage for runner replacements) and Koma Kulshan (fall maintenance outage).  Mamquam availability improved as it had no forced outages this quarter.

With respect to our hydro plants, generation at Curtis Palmer was approximately 45% below the third quarter of 2017 (which was a very strong water year) and 30%

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below the long-term average.  Generation at Mamquam was down 9% versus the third quarter of 2017 and 2% compared to the long-term average.

Page 6:  Operations Update

Tunis

On October 4, 2018, we returned the Tunis plant to commercial operation.  It now operates in dispatchable mode under a 15-year PPA with the Ontario Independent Electricity System Operator (IESO) and receives capacity payments for being available.  The capacity payments are based on an annual average capacity of 36.5 MW.  Tunis will also receive energy payments for those periods when it is required to produce power.  Each day the project bids into the market based on its cost of production.  It has not been required to produce any power since returning to service.  We expect its capacity factor to be low.

We expect that Tunis will generate approximately US$2 million of Project Adjusted EBITDA annually, although 2018 results are expected to be negative because of the expenses associated with re-start.  Year to date, its Project Adjusted EBITDA is $(4.3) million.

Nipigon

On November 1, 2018, the long-term enhanced dispatch contract (LTEDC) with the IESO went into effect, replacing the project’s original PPA, which was terminated.  The expiration date of December 2022 is unchanged.  Nipigon will operate as a flexible plant, running only when needed and when it is economic to operate.  It will receive monthly capacity-type payments, with adjustments for operational savings that will be shared with the IESO, and earn energy revenues for those periods when it operates.  We expect the economics of the LTEDC to be

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favorable versus the original PPA, although fairly similar to results under the short-term enhanced dispatch contract that has been in place since January 2017.

Earlier this week, we completed the dispatchable registration process with the IESO.  We expect to undertake capacity and stack testing next week.  We do not need to perform any overhauls of Nipigon’s major equipment prior to its return to service, although we plan to upgrade the plant’s gas turbine control system in 2019, which will enable remote simple cycle operation, as well as undertake other component or system upgrades as necessary.

Maintenance Outages

Most of the major outages this year were conducted in the second quarter.  The gas turbine overhaul at Kenilworth was completed in September, although the plant continued to operate on a leased engine while the work was being done.  We had fall maintenance outages at Cadillac (which was extended for a turbine control upgrade), Morris, Koma Kulshan and Moresby Lake.

Decommissioning of San Diego Sites

As noted in our third quarter press release, we have begun preparations to decommission all three San Diego plant sites, as required by our land use agreements with the Navy.  The scope of the work has not yet been finalized with the Navy, although we have agreement with respect to most issues at the NTC site.  The other two sites are not as far along.  Timing will be a function of reaching determination with the Navy on scope as well as work that must be done by San Diego Gas & Electric (SDG&E) to decommission the gas and electric lines.  At this time we expect that most of the work will be done in the first half of 2019.

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We expect to have a better handle on the estimated cost of this work once we have a determination with the Navy on scope for each of the three sites and we have received bids from contractors, which we expect will occur over the next few months.  We currently anticipate that the final cost may exceed the $1.7 million of decommissioning expense that we have previously accrued.  If necessary, we will record an additional accrual in our fourth quarter results.  This additional expense would reduce net income but would not be included in Project Adjusted EBITDA.  We expect that the substantial majority of the required cash outlays will be incurred in 2019.

Cost Focus

As part of our ongoing initiative to analyze, identify and achieve potential savings in our operation and maintenance costs, earlier this year we retained a consulting firm to perform external benchmarking of our thermal (non-hydro) plants, specifically with respect to cost structure, staffing levels, maintenance intervals and other variables.  We have preliminary results of this study and are working with the consultant to finalize the report.

We don’t expect to make any across-the-board cost cuts as a result of their findings.  That was never our goal.  Our goal is to identify those areas where we may be overspending based on the age, condition, or profile (base load, mid-load, peaking, etc.) of the plants.  We expect to find some areas where we need to spend more for improved reliability, as causes of failures are identified by the analysis.  We expect to realize some cost savings from extension of maintenance intervals (based on equipment condition), procurement policies, and inventory levels.  We are also looking at shift schedules and overtime percentages as possible areas of cost

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savings.  It varies from plant to plant and generalizations about findings and implications are difficult as the makeup of our fleet of plants continues to change.

We look forward to implementing those recommendations from the report that are practical and feasible.  As we’ve indicated in the past, we believe the cost savings potential is quite modest as compared to what we have been able to achieve on the corporate side.  Our current thinking is that we will take a similar look at our hydro plants next year, possibly with the help of an external consultant.

You may recall that one of the steps we took in 2017 as part of this overall effort was to deploy Predictive Analytic software at three plants (Curtis Palmer, Morris and Piedmont), which monitors equipment and systems, with a goal of improving reliability, reducing downtime and achieving fuel and operation and maintenance cost savings.  We are now in the process of rolling out this technology at another three sites (Cadillac, Frederickson and Mamquam).

Joseph E. Cofelice — Atlantic Power Corporation — EVP Commercial Development

Page 7:  Commercial Update

I’ll provide an update on Williams Lake, Ontario and the San Diego projects, and then discuss our recent agreement to acquire two biomass plants in South Carolina.

Williams Lake

The project continues to operate under a short-term contract extension with BC Hydro, which runs to June 30, 2019, or September 30, 2019 at the customer’s option.  The contract extension is subject to the approval of the BC Utilities Commission (BCUC), which in April ordered a written hearing and more recently

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extended the hearing schedule.  The timing of a decision by the BCUC is uncertain but may not occur until close to year-end or in early 2019.  If the BCUC has not approved the contract by February 28, 2019, either BC Hydro or Atlantic Power has the right to terminate the contract at that time.  That date was recently extended from October 31, 2018 in response to the extension of the BCUC schedule.

Separately, final submissions by all parties are due shortly in the written hearing on the appeal of the amended air permit for Williams Lake, which we received in September 2016.  We sought the amended air permit in order to burn a wider range of fuels at Williams Lake, including rail ties (up to 50% of the mix).  A decision on the appeal by the Environmental Appeal Board is now expected in the first quarter of 2019.  We expect the permit to be upheld.

The investment in a new fuel shredder at Williams Lake, which would be required to burn rail ties and certain other types of materials, would be undertaken only if we are successful in reaching agreement on a new long-term contract with BC Hydro for Williams Lake which would provide for recovery of the shredder investment including a return.  The prospects for a new contract will be dependent on the outcome of BC Hydro’s Integrated Resource Plan (IRP) filing, expected next year, and more specifically a determination with respect to the role of biomass in meeting the province’s future energy needs.

Ontario

In September we received notice that the City of North Bay had agreed to re-zone our North Bay site to allow for various industrial uses, including data centers, on land adjacent to the plant that is owned by us.  Our Kapuskasing project is already zoned for light industrial use.  The re-zoning of North Bay is part of our effort to

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market both the Kapuskasing and North Bay projects (which are currently mothballed) to a range of potential customers or alternate users of the sites.  That effort continues, although there is nothing substantive to report at this time.

San Diego Projects

As indicated by Dan Rorabaugh in his prepared remarks, we are preparing to decommission the three plant sites in San Diego.  We terminated discussions with the Navy earlier this fall when it became apparent that we would not be able to achieve site control in time to meet critical deadlines in the PPAs we had signed with SDG&E.

Page 8:  Other Commercial Initiatives

South Carolina Biomass Acquisition

Turning from PPA renewals to other commercial initiatives, in September, we announced an agreement to acquire two contracted biomass plants located in South Carolina from EDF Renewables for $13 million.  Closing is expected late in the third quarter or the fourth quarter of 2019.  The long period to closing is to allow EDF Renewables to restructure the ownership of the plants, which can occur only after the end of the relevant tax credit recapture periods.  The restructuring will permit the plants to be acquired by us without any project debt or tax equity.  Upon signing of the agreement, we made a $2.6 million deposit toward the purchase price, which will be held in escrow until closing.

The Allendale and Dorchester plants are each 20 megawatts and have been in commercial operation since 2013.  All of the output is sold to Santee Cooper, a state-owned utility, under two PPAs which run to 2043.  Under the PPAs, the plants receive energy payments for the power produced.

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We believe that both of the plants are running well and have been well maintained.  However, we see potential to optimize the operational and financial performance of the plants by implementing initiatives similar to those we have undertaken on our own biomass plants over the past few years.  We have developed significant operational and commercial expertise in biomass.  With respect to these two plants specifically, we will focus on improving plant availability and output to be more in line with our other biomass plants.  We also think there are things we can do in the areas of fuel handling and maintenance practices, which may require some modest investment by us.

Even without any of our planned improvements, we believe the return on investment from this acquisition compares favorably to other external growth options while adding long-dated PPA cover to our portfolio.  If we are modestly successful in the implementation of our optimization program, the returns on this investment should be very attractive.

Other Commercial Initiatives

As we have discussed in previous quarterly calls, we remain focused on maximizing the value of our existing assets and sites.  As part of this process, we continue to evaluate our project sites (e.g., land availability, interconnection capacity, and market conditions) for potential competitive advantages for energy storage and other applications.  The project returns required to win competitive tenders for new wind, solar and energy storage PPAs are very low and are well below the returns we can earn from other uses of our cash.  Thus, the probability of success from this effort is low but we will participate on an opportunistic basis when the competitive situation warrants.

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In the area of potential acquisitions, we continue to remain disciplined, focusing on contracted out-of-favor assets, such as biomass plants.  In the current market environment, we believe this is the best strategy to pursue in order to find opportunities that meet our risk/return targets.

Terry Ronan — Atlantic Power Corporation — EVP & CFO

Pages 9-10:  Q3 2018 Financial Highlights

Financial Results — Third Quarter 2018

Project Adjusted EBITDA of $45.4 million declined $32.0 million from the year-ago level of $77.4 million, primarily because of PPA expirations, early terminations and a short-term extension that have occurred since year-end 2017 and non-recurrence of the OEFC Settlement recorded in 2017.  These declines were expected.  We also experienced below-average water flows at Curtis Palmer, which continued from the second quarter.  As we noted in our remarks on the second quarter call, first half results were better than expected in part due to a shift in the timing of maintenance expense.  We believe that third quarter and year-to-date results put us on track to be within our guidance range of $170 to $185 million for the full year.

Cash provided by operating activities decreased $33.4 million to $19.5 million from $52.9 million.  Most of the decline was attributable to lower Project Adjusted EBITDA.  We would note that the September distribution from Orlando (an equity project) was not received until October 1.  Relative to our expectations, this

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resulted in a shift of $3.6 million of operating cash flow from the third quarter into the fourth quarter.

Debt Repayment

During the third quarter we repaid $20.8 million of term loan and project debt; for the year to date, debt repayment totals $79.5 million.  The decline in Project Adjusted EBITDA (for the quarter and on a trailing 12-month basis) resulted in an increase in our leverage ratio at Sept. 30, 2018 to 4.5 times.  This increase was expected and consistent with the decline we anticipated in Project Adjusted EBITDA.  We ended the quarter with liquidity of $180.6 million, including approximately $32 million of discretionary cash.

Interest Costs

As we announced earlier this week, we executed a fourth re-pricing of our term loan and revolver, reducing the spread another 25 basis points, to 275 basis points over LIBOR.  The spread on the facilities when originally issued in April 2016 was LIBOR plus 500.  The interest cost savings (before transaction costs to be recorded in the fourth quarter) are estimated to be $1.2 million in 2019 and $3.25 million over the remaining term of the facilities.

We also continue to manage our exposure to increases in market interest rates.  At Sept. 30, 2018, more than 96% of our debt carried either a fixed rate or a variable rate that has been fixed through interest rate swaps.  Through September 2019, 92% or more of our debt is either fixed rate or swapped.  Our exposure to a 100 basis point change in LIBOR is approximately $450 thousand in 2019.

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Capital Allocation

In the third quarter, we used a portion of our discretionary cash to fund growth initiatives as well as to repurchase common and preferred shares under our normal course issuer bid, or NCIB, as follows:

Acquisitions.  In July, we closed the acquisition of Covanta’s 50% interest in Koma Kulshan and bought out the O&M contract, using $12.5 million of our discretionary cash ($11.7 million net of cash acquired).  With this acquisition we consolidated our ownership of Koma at an attractive valuation level; the acquisition also adds to the stability of our cash flows as the project has a PPA that runs to 2037.

In September, we used $2.6 million of cash to make a deposit in conjunction with our agreement to acquire two contracted biomass plants in South Carolina for $13 million. Closing of this acquisition is not expected until late third quarter or fourth quarter 2019.  In his prepared remarks, Joe Cofelice discussed how we are thinking about potential returns from this investment.

NCIB.  We continued to make share repurchases under our NCIB in the third quarter as we saw opportunities to do so at a discount to our estimates of intrinsic value per share.  We repurchased and canceled approximately 1.4 million common shares at an average price of $2.15 per share (total investment $3.1 million).  We also repurchased 237,500 shares of our preferred Series 1; 5,000 shares of our preferred Series 2, and 41,695 shares of our preferred Series 3, at a total cost of $3.4 million (US$ equivalent).  With these repurchases, we have reached the 10% limit on repurchases of our Series 1 and Series 3 preferred shares under this NCIB.

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Subsequent to the end of the quarter, we repurchased another 288 thousand common shares at an average price of $2.15 per share.

Pages 11 through 13 address the drivers of our third quarter and year-to-date financial results in more detail.

Page 11:  Q3 2018 Project Adjusted EBITDA bridge

The decline in third quarter 2018 Project Adjusted EBITDA was largely expected and primarily attributable to PPA expirations and extensions during the past nine months, as follows:

PPA expirations.  The Kapuskasing and North Bay contracts expired on Dec. 31, 2017 and were not renewed, as expected.  Both projects had received OEFC Settlement revenues in 2017 that did not recur.  Together these accounted for $11.3 million of the decline in Project Adjusted EBITDA from the third quarter of 2017.  Our three projects in San Diego ceased operations in early February and the PPAs were terminated effective March 1st, which resulted in an $11.3 million reduction in Project Adjusted EBITDA from the third quarter of 2017.  The Williams Lake PPA, which was scheduled to expire on April 1, was amended and extended for a short period on less favorable terms; this resulted in a $5.0 million reduction to Project Adjusted EBITDA.  In total, PPA expirations and extensions accounted for $27.6 million of the $32.0 million decline in Project Adjusted EBITDA for the quarter.

Curtis Palmer.  Water flows were well below year-ago levels, which resulted in reduced generation for Curtis Palmer and a $3.3 million reduction to Project

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Adjusted EBITDA from the year-ago level.  We experienced low water flows in the second quarter as well.

Cadillac.  An extended maintenance outage for a turbine control upgrade reduced Project Adjusted EBITDA by $1.2 million from the year-ago level.

Kenilworth.  Increased maintenance expense associated with a gas turbine overhaul reduced Project Adjusted EBITDA by $0.9 million from the year-ago level.

On the positive side, Manchief benefited from higher dispatch and Morris from a higher PJM capacity price.

Page 12:  YTD Sept. 2018 Project Adjusted EBITDA bridge

Project Adjusted EBITDA of $138.5 million for the nine months ended Sept. 2018 decreased $88.1 million from $226.6 million for the nine months ended Sept. 2017.  The decline was expected.  Some of the third quarter drivers that we previously discussed, including the PPA expirations, non-recurrence of the OEFC Settlement and lower water flows at Curtis Palmer, were also factors in the year-to-date decline.  Results also were affected by re-start expenses at Tunis incurred in the first half of 2018 and a gas turbine maintenance outage at Manchief in the second quarter of 2018.  Projects that contributed positively to the comparison included Morris, Frederickson, Nipigon, Orlando and Mamquam, as indicated on page 12.

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Page 13:  Operating Cash Flow and Uses of Cash

Third Quarter 2018

As previously noted, cash provided by operating activities totaled $19.5 million in the third quarter, a decrease of $33.4 million from $52.9 million in the third quarter of 2017.  Most of the reduction in operating cash flow was attributable to lower Project Adjusted EBITDA.

During the quarter, we used operating cash flow to repay $20 million of our term loan and to amortize $0.8 million of project debt.  We also paid $2.1 million of preferred dividends.

Year-to-date Sept. 2018

Cash provided by operating activities for the nine months ended Sept. 2018 of $97.8 million declined $40.9 million from $138.7 million in the comparable 2017 period.  Although Project Adjusted EBITDA declined $88.1 million, the reduction in operating cash flow was significantly less due to $34.6 million of favorable changes in working capital, including $29.2 million related to PPA expirations and plant shutdowns (Kapuskasing, North Bay and the three San Diego projects), and a $13.9 million reduction in cash interest payments resulting from debt repayment and a lower spread on our credit facilities.

In the first nine months of 2018, we used operating cash flow to repay $70 million of our term loan and to amortize $9.5 million of project debt.  We also paid $6.3 million of preferred dividends.

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Page 14:  Liquidity

At Sept. 30, 2018, we had liquidity of $180.6 million, including $57.6 million of unrestricted cash.  These figures are approximately $23 million lower than the June 30th balances of $203.4 million and $80.8 million, respectively.

In the third quarter, we used $6.5 million of discretionary cash for common and preferred share repurchases and another $12.5 million to acquire the 50% interest in Koma Kulshan that we did not previously own and to buy out the project’s O&M contract from Covanta.  We also made a $2.6 million deposit associated with our South Carolina biomass acquisition agreement.  The total of these three uses of cash was $21.6 million.

Cash at the parent of $39.1 million as of Sept. 30 declined only $10.1 million from the June 30th level, because during the quarter there was a release of cash by the projects due to lower working capital needs (at projects no longer in operation).  This release of cash from the projects occurred in the second quarter as well.  Holding aside approximately $7 million for working capital purposes, we had about $32 million of discretionary cash at Sept. 30.

As shown on page 14, we do not currently have any borrowings under the revolver, but we do use it for letters of credit.  Availability under the revolver was $123.0 million at Sept. 30, virtually unchanged from the June 30th level.

Page 15:  Debt Repayment Profile

Over the next several years we expect to repay a significant amount of debt, as shown on page 15.  Approximately half (51%) of our debt is amortizing and repaid from cash flow rather than in the form of a bullet maturity.  Through year-end

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2022, we expect to amortize approximately $390 million of our term loan and project debt, predominantly from operating cash flow.  During this period, we have only one bullet maturity– the remaining $19 million (US$ equivalent) of the Series D debentures, which mature in December 2019.  We can redeem the Series D convertible debentures at par at or before their maturity date, or repurchase a portion of them up to a 10% limit under our NCIB.

With respect to the fourth quarter of 2018 specifically, we plan to repay $20 million of our term loan and amortize $0.8 million of project debt (at Cadillac).  This would bring debt repayment for the year to a total of $100 million.

As previously indicated, our leverage ratio at Sept. 30, 2018 was 4.5 times.  Notwithstanding the substantial amount of debt we have repaid this year, this ratio has increased from year-end 2017 due to the significant reduction in Project Adjusted EBITDA in 2018 to date.  We expect it to move modestly higher in the fourth quarter.  However, our leverage ratio should decline in 2019 as we continue to repay significant amounts of debt (as shown on page 15).  We expect the ratio to move below four times in 2020.

Page 16:  Projected Debt Balances

Page 16 shows the impact of continued debt repayment on our debt balances, projected through year-end 2023.  At Sept. 30, 2018, we had debt of $805 million, including our share of debt at Chambers, which is an equity-owned project.  Assuming that we amortized the term loan per the targeted debt reduction schedule through year-end 2022 and repaid the remaining $125 million of principal at its maturity in April 2023, our projected debt balance at year-end 2023 of $256 million would consist of the $162 million (US$ equivalent) Medium-Term Notes

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(with a 2036 maturity), the $89 million (US$ equivalent) Series E convertible debenture (2025 maturity), and $5 million of project debt.  However, there are alternative paths we could follow with respect to the final balance on the term loan, including refinancing it prior to its maturity date, extending the maturity date or (as page 16 contemplates), paying off the remaining principal with cash in 2023.

We expect that this substantial debt repayment over the next several years will generate significant interest cost savings that would mitigate a portion of the impact of lower Project Adjusted EBITDA (from PPA expirations, or extensions on less favorable terms) on our operating cash flow.

Page 17:  2018 Guidance

We have 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.

Our 2018 Project Adjusted EBITDA guidance remains $170 to $185 million.  Based on this range, we estimate 2018 cash provided by operating activities in the range of $95 to $110 million.  This estimate assumes the impact of changes in working capital on cash flow is nil.  However, given the reduction in working capital attributable to projects no longer in operation (relative to 2017), changes in working capital are more likely to have a positive impact on the 2018 GAAP result ($22.3 million in the first nine months of 2018).

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Our principal planned uses of operating cash flow in 2018 include $90 million amortization of our term loan; $10 million of project debt amortization; $2 million of capital expenditures; and $8 million of preferred dividend payments.  As previously noted, our repurchases under the NCIB and our acquisition of Koma Kulshan have been funded from our discretionary cash balances.

Tax Update

Although we do not anticipate becoming a federal cash taxpayer in either the U.S. or Canada in 2018 or 2019, for the three months ended September 30, 2018, the $19.5 million increase in income tax expense is primarily related to the impact of recent U.S. tax legislation lowering the corporate tax rate from 35% to 21%, which results in a reduction in our U.S. deferred tax assets (primarily U.S. net operating losses) and, in turn, an increase in our U.S. tax expense.  Similarly, for the nine months ended September 30, 2018, tax expense increased by approximately $46 million due to the same U.S. tax law change.

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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, 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) on a consolidated basis is provided in Table 1 below.

Atlantic Power Corporation

Table 1 — Reconciliation of Net (Loss) income to Project Adjusted EBITDA

(in millions of U.S. dollars)

Unaudited

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