Atlantic Power Preferred Equity Ltd. - Call Transcript 2020

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 28, 2020

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia, Canada (State or other jurisdiction of incorporation or organization)

001-34691

(Commission File Number)

55-0886410

(IRS Employer Identification No.)

3 Allied Drive, Suite 155 Dedham, MA

(Address of principal executive offices)

02026 (Zip Code)

(617) 977-2400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Trading Symbol Name of Exchange on which registered Common Shares, no par value, and the associated Rights to AT The New York Stock Exchange Purchase Common Shares

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):

Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
Pre-commencement communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
Pre-commencement communication pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).

Emerging growth company �

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. �

Item 2.02. Results of Operations and Financial Condition.

On February 28, 2020, Atlantic Power Corporation (the “Company”) held its fourth quarter and year end 2019 financial results conference call and webcast. A copy of management’s prepared remarks and a copy of the related presentation are attached hereto as Exhibits 99.1 and 99.2, respectively, and are hereby incorporated by reference.

The information in Item 2.02, including Exhibits 99.1 and 99.2 is being furnished and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”) or otherwise subject to the liability of that Section, nor shall such information be deemed to be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933 or the Exchange Act, except as otherwise stated in that filing.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

Exhibit Number 99.1 99.2	Description
	Atlantic Power Corporation’s management’s prepared remarks with respect to the Atlantic Power Corporation fourth quarter and year end
	2019 financial results conference call and webcast. Presentation prepared with respect to the Atlantic Power Corporation fourth quarter and year end 2019 financial results conference call and webcast.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Atlantic Power Corporation

Dated: February 28, 2020

By: /s/ TERRENCE RONAN Name: Terrence Ronan Title: Chief Financial Officer

Exhibit 99.1

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PREPARED REMARKS Q4 2019 FEBRUARY 28, 2020

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 annual report on Form 10-K, all of which are available on our website.

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

2019 was a good year in terms of progress on business fundamentals. I’ll review our financial results for the year and other highlights. Terry Ronan will cover our fourth quarter results and our 2020 guidance in more detail, and Nick Galotti and Joe Cofelice will provide operational and commercial updates, respectively.

Page 4: 2019 Highlights

Financial results . Project Adjusted EBITDA of $196.1 million exceeded the top end of our guidance range, which we revised upward in the third quarter. Operating cash flow of $144.7 million also exceeded our estimate. We ended the year with $196.5 million of liquidity, including approximately $42 million of discretionary cash.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Balance sheet . We repaid $90.8 million of consolidated debt, using our strong operating cash flow from existing businesses. Our leverage ratio improved from 4.5 times at year-end 2018 to 3.8 times at year-end 2019. We improved the terms of our credit facilities, reducing the cost and extending the maturity date. The combination of lower debt levels and a lower interest rate is continuing to reduce our annual interest payments, which benefits our operating cash flow. Our progress in deleveraging was rewarded with a credit rating upgrade from S&P, the fourth we have received from the two major rating agencies over the past four years.

Capital allocation . It was a very strong year for discretionary cash flow and capital allocation. Partly due to the contribution from above-average water flows at Curtis Palmer and favorable changes in working capital, we generated approximately $63 million of discretionary cash flow (defined as operating cash flow after term loan and project debt amortization, preferred dividends and capex). We allocated this cash approximately evenly between “internal” uses (repurchases of debt and shares) and “external” uses, though not by design. We used $18.5 million to redeem the Series D convertible debentures (which were maturing at year-end 2019) and $10.5 million to repurchase common and preferred shares, at prices we considered attractive. We also had a strong year for external uses, allocating $28.5 million to closing the acquisition of the South Carolina biomass projects and equity interests in two other biomass projects.

PPAs . We had a couple of successes, including a new ten-year contract for our Williams Lake biomass project. At Kenilworth, our customer executed two successive one-year contract extensions.

Costs . We maintained our overhead costs in line with the levels of 2016 through 2018, approximately 56% below the 2013 peak level.

Operations . The Cadillac equipment failure and fire was the most significant negative development of the year, but the financial impact is limited and we are making progress on returning the plant to operation later this year.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Nick Galotti – Atlantic Power Corporation – SVP Operations

Page 5: Q4 2019 Operational Performance

Safety

We had two recordable injuries in the fourth quarter, and nine total for 2019. As a result, our total recordable incident rate (TRIR) was 3.60 for 2019 and three of these incidents were lost time events. At Atlantic Power we take all injuries very seriously. Of the nine recordable incidents, six were associated with pinches and punctures to hands of employees. Due to the number of hand injuries, we have implemented mandatory glove training, evaluated and supplemented existing plant equipment, shared best practices amongst the fleet and shared behavioral-based lessons regarding hand protection. We have also increased the frequency of safety meetings and expanded all safety-related communications throughout the Company. We continue to make the safety of our employees our number one priority.

Generation

Turning to our operating results, generation increased 6.0% in the fourth quarter of 2019 compared to the 2018 period, primarily because of the acquisitions of Allendale and Dorchester and equity interests in Craven and Grayling, higher dispatch at Frederickson, higher dispatch at Manchief, and higher water flows at Curtis Palmer. Generation at Curtis Palmer increased 14% from the year-ago period, and was 28% above the long-term average for the quarter. These increases were partially offset by lower generation at Williams Lake, due to voluntary curtailment resulting from lower wood fuel inventory, at Cadillac due to the outage and at Mamquam due to lower water flows.

Availability

Our availability factor in the fourth quarter of 2019 decreased to 90.4% from 97.5% in the fourth quarter of 2018. Cadillac availability was lower due to the outage following the fire and Moresby Lake availability was affected by a failure of the main transformer last spring. We replaced the transformer earlier this month. Piedmont had a maintenance outage and Kenilworth had its annual fall outage, which occurred in the fourth quarter of 2019 as opposed to the third quarter of 2018. Oxnard availability improved because the year-ago period was reduced by gas turbine repairs.

Page 6: FY 2019 Operational Performance

Generation

For the full year, generation increased 6.0%, driven by the acquisitions of Allendale, Dorchester, Craven and Grayling, higher dispatch at Frederickson and Manchief, and higher water flows at Curtis Palmer. Generation at Curtis Palmer increased 27% from 2018 and 26% versus the long-term average. These increases were partially offset by decreases at Williams Lake and Cadillac, the San Diego projects due to the PPA expirations in 2018 and Mamquam, due to lower water flows. Mamquam generation decreased 17% versus 2018 though it was approximately in line with the long-term average.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Availability

Availability declined modestly to 94.0% from 96.5% in 2018 due to lower availability at Cadillac and Moresby Lake.

Page 7: Operations Update

Cadillac

The Cadillac plant remains out of service following a fire at the plant in September 2019. Although we are still investigating the root cause, we believe that the fire was the result of an overspeed event in the steam turbine. As we indicated on our third quarter conference call, there was extensive damage to the steam turbine and generator as well as other equipment in that area of the plant. We have procured the necessary equipment and components that need to be replaced in order for reconstruction of the plant to proceed. We were successful in sourcing the turbine and generator from an identical biomass plant in Maine, which will allow us to avoid the extended lead time on a new order. Both will be completely overhauled prior to being installed at Cadillac.

Last quarter we indicated that we expected the plant to be offline for at least nine months, and that is still the case. We are targeting a return to operation in the third quarter of this year and we expect to start building fuel inventory again this spring.

We continue to believe that the total cost of new equipment and repairs to the plant will be at least $25 million. Through year end 2019, we had capitalized $5.1 million of equipment purchases and repairs. We have received $11.1 million from our insurers, net of deductibles, and we will be filing another claim shortly. Terry will address insurance recovery and related accounting in his section of the prepared remarks.

Williams Lake

As you know, we signed a new ten-year contract with BC Hydro for Williams Lake last October. Previous to that, the plant had been under a short-term contract that hindered our ability to procure fuel, and so we curtailed the plant due to low fuel inventory.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

We returned Williams Lake to operations in December 2019, earlier than expected, although it is not operating at full capacity. Our current expectation is that it will run into April at a slightly reduced capacity, which is a more efficient level for us in terms of fuel burn. The plant will then be shut down in May through July (during the spring thaw or freshet), as required under the new contract. Our plan during this period is to perform necessary plant maintenance, including a replacement of the cooling tower (which will be expensed), and to rebuild our fuel supply inventory, with a goal of returning the plant to service sometime in the third quarter. The contract requires the plant to operate in November through February of next year.

Fuel procurement remains the major challenge at the plant. Our efforts will continue to be impacted by conditions in the British Columbia timber market, which have adversely affected the availability, cost, and tenor of new fuel supply arrangements. Since signing the new contract with BC Hydro, we have been focused on rebuilding our fuel supply sources, including traditional mill waste and forest and roadside residuals. We have entered into a new fuel supply arrangement with the First Nations, purchased and deployed a new mobile fuel grinder, and entered into other short-term agreements with third parties to extend supplies of mill waste and secure additional forest residuals. The grinder has been helpful in sourcing and transporting wood waste from forest areas. Although fuel costs to date have been mostly in line with the expectations we had when we executed the new contract, we are still early in the process and could experience considerable variability over the course of the year.

We continue to evaluate a potential investment in a new shredder that would allow us to burn rail ties as a source of fuel, but we have not made any commitment or preparations to burn rail ties and we do not expect to undertake such an investment this year. Our current focus is on traditional sources of fiber.

As we noted on the third quarter call, our current estimate is that the plant will generate approximately a breakeven level of EBITDA in 2020.

Decommissioning of San Diego Sites

We recently signed a contract for the demolition of all three San Diego project sites. We expect the work to commence shortly and be completed within about six months. Our cost estimates have not changed. We expect a cash outlay this year to complete the work of approximately $4 million.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Cost Focus

In 2019, we continued to advance our program to improve our operation and maintenance performance. We rolled out Mainsaver (maintenance management system) to Allendale and Dorchester, which we acquired in July, and to Koma Kulshan, in which we acquired the remaining ownership interests in the third quarter of 2018. We also implemented it at Piedmont in the fourth quarter. We have an ongoing focus on optimizing the preventive maintenance programs for all sites.

Another area of focus is avoiding equipment issues that result in unplanned outages. To that end, we have installed predictive analytic software (PRiSM) at six plants over the past two years. To date, the system has had 27 good “catches” (potential equipment problems that were avoided). We are currently installing PRiSM at Williams Lake and plan to roll it at Allendale and Dorchester in the summer of 2020.

In the fourth quarter, we rolled out a new system for testing and evaluating the condition of all plant step-up transformers. All equipment has been base-lined and going forward all plants will use the same lab for testing. Understanding the condition of these critical components will allow us to better predict potential failures and avoid long down time of our facilities.

In 2020, we plan to undertake a benchmarking of our hydro and biomass plants, with a goal of driving further improvements to our cost structure as we add and integrate new assets into our fleet.

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

- Page 8: Re contracting Updates

As you know, we have two projects for which the PPAs are expiring this year, Oxnard in May and Calstock in June. I will review the status of each of these projects and also provide a brief update on our Manchief transaction.

Oxnard (California)

Oxnard has a PPA with Southern California Edison (SCE). As we discussed on our third quarter call, last fall SCE issued a solicitation for incremental system resource adequacy capacity. Another solicitation with slightly different requirements was issued by SCE in December. We participated in both but our bids were not selected.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

As we also noted on our previous call, we are also pursuing other potential paths to continue operations at Oxnard, including reliability must run (RMR), resource adequacy (RA) and community choice aggregation (CCA) off-take structures. We believe recent developments in California, including recognition by the California Public Utilities Commission of near-term reliability challenges and the state’s plans to continue the deployment of renewable generation, highlight the need for reliable and firm capacity. It is too early to know whether these other re-contracting avenues will prove successful. As a reminder, we own the Oxnard site so our efforts are not impacted by site-lease termination risk. We expect to provide a further update on plans for Oxnard post-PPA on our next quarterly call in May.

Calstock (Ontario)

Despite support from the local government, unions, various forestry organizations and Hearst area mills, and our continued engagement with the relevant government ministries to develop a re-contracting path for Calstock, we now expect that the plant will cease operations when its PPA expires in June. Although we continue to pursue all paths, there is no policy or market mechanism currently in place that would compensate biomass plants for the non-power benefits provided, including economic and environmental support to the forestry sector (waste management), general forest management (clearing and use of forest residuals), and firm renewable energy. At this time, we have not determined whether we will mothball the plant (as we have done at Kapuskasing and North Bay, both of which are also in Ontario) or decommission it.

Manchief (Colorado)

As you know, we have an agreement to sell our Manchief plant to Public Service Co. of Colorado (PSCo), the customer under the PPA, for $45.2 million in May 2022 following the expiration of the PPA. The agreement required the approvals of the Federal Energy Regulatory Commission, which was received in October 2019, and the Colorado Public Utilities Commission (PUC), which was received earlier this month. Thus, the required regulatory approvals for the sale have been received.

Terry Ronan – Atlantic Power Corporation – EVP & CFO

Page 9: Q4 2019 Accounting Developments

Before reviewing the results of the fourth quarter, I will first cover a few accounting developments that are discussed in our 10-K:

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

New Business Segments

Effective in the fourth quarter, we have changed our segments from geographic to fuel type. This better aligns with how the projects are managed and evaluated. The biomass project acquisitions, recent and near-term PPA expirations and the decommissioning of the San Diego projects were also factors in the revision. The new segments are Solid Fuel, which includes our biomass plants and our 40% interest in the Chambers coal plant; Natural Gas, Hydroelectric and Corporate. Prior periods in the 10-K have been restated for the change. The organization of projects by segment is detailed on page 30 of the presentation.

Impairment

During the fourth quarter, we recorded non-cash impairment expense of $55.0 million, which is included in Project income (loss) but not Project Adjusted EBITDA. The impairments were at Chambers ($49.2 million) and Calstock ($5.8 million).

Our 40% interest in Chambers is accounted for as an equity investment. The PPA for Chambers expires in March 2024. Based on the continued decline in forward power curves since we partially impaired our investment in 2017, an expectation of a challenging re-contracting environment for a coal plant and a low probability of the plant being able to operate profitably as a merchant facility, we determined that there had been a decline in value in our investment that was other than temporary.

Consistent with our practice, we reviewed Calstock for potential impairment consistent as its PPA is within six months of expiration. As Joe indicated, we believe that it is unlikely the plant will continue to operate beyond 2020. Accordingly, we determined the fair value of the long-lived assets at Calstock based solely on the cash flows remaining under the current contract.

Page 10: Q4 2019 Accounting Developments (cont’d)

Cadillac Insurance Recovery and Accounting

As I indicated last quarter, we expect the cost of repairing Cadillac and returning it to service, as well as lost profits during the extended outage, will be recovered under our property and business interruption insurance. In December, we received initial insurance recoveries totaling $11.3 million, which was net of the $1 million deductible on our property insurance (recorded in Q3) and net of a 45-day deductible on our business interruption insurance, which had an impact of approximately $1.4 million (nearly all in Q4). This $11.3 million payment was not allocated between property and business interruption, but we estimate that approximately $2.0 million was for business interruption losses incurred in the fourth quarter subsequent to the 45-day deductible period.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

We recorded the $11.3 million as a reduction to our insurance receivable and included it as a source of Investing cash flows. During the quarter we incurred $5.1 million of capital expenditures for Cadillac repairs and equipment purchases, and this amount is included as a use of Investing cash flows. At December 31, 2019, our insurance receivable was $13.5 million.

The $2.0 million recovery of business interruption losses was not recorded to income but rather treated as a gain contingency. Thus, the impact of business interruption losses on Project Adjusted EBITDA in the fourth quarter was approximately $3.4 million (the $1.4 million deductible plus a $2.0 million gain contingency). Once final payment is made by our insurers and the claim is settled, after the plant returns to service later this year, the gain contingencies will be recorded to income and included in Project Adjusted EBITDA. From a timing standpoint, we will see an impact on Project income (loss) and Project Adjusted EBITDA from the Cadillac outage until the plant returns to service, but we expect there to be no net impact for the year as a whole.

As I indicated last quarter, we expect that during the outage Cadillac will continue to meet its debt service obligations using the business interruption insurance proceeds. Cash that ordinarily would be distributed from the project will instead remain at the project until it returns to service, although this has no impact on operating cash flow as the results of the project are consolidated.

Page 11: Q4 2019 Financial Highlights

Jim reviewed the results for the full year. I will highlight fourth quarter results and developments:

Financial results. Project Adjusted EBITDA declined $3.7 million. The Cadillac outage ($3.4 million impact) and reduced operations at Williams Lake offset strong performance at Curtis Palmer (generation increased 14% from a year ago due to above-average water flows). Cash provided by operating activities was in line with the year-ago period.

Balance sheet and leverage ratio. We repaid $20.0 million of term loan and project debt during the fourth quarter, and our consolidated leverage ratio at year end 2019 was 3.8 times. This was in line with the Sept. 30[th] level of 3.7 times but significantly improved from 4.5 times at year end 2018.

Capital allocation. During the fourth quarter, we invested $1.6 million in the repurchase of 704,317 thousand common shares at an average price of $2.35 per share.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Credit facilities amendment. In January, we successfully amended our credit facilities and achieved several positive changes, including a 25 basis point reduction in the spread to LIBOR plus 2.50%, a two-year extension of the term loan maturity to April 2025 and a modification of the targeted debt balances to reflect the sale of Manchief in 2022. The amendment also provides for a further reduction in the spread to LIBOR plus 2.25%, should we achieve a leverage ratio of 2.75 times.

I’ll review our financial results for the quarter and full year in more detail on the following pages.

Page 12: Q4 2019 Project Adjusted EBITDA bridge

Project Adjusted EBITDA for the fourth quarter of 2019 decreased $3.7 million to $42.9 million from $46.6 million in the fourth quarter of 2018. Excluding the $3.4 million impact of the Cadillac outage, results would have been generally in line with last year and consistent with our previous expectations. Key drivers of the decrease, as shown in the bridge on page 12, are as follows:

Cadillac declined $3.8 million from the fourth quarter of 2018, although we expect that $2.0 million of the impact will be recovered later in the year, as I discussed previously. Williams Lake was not in operation for most of the quarter due to low fuel inventory following the expiration of the short-term contract extension and additional maintenance. We returned the plant to service in mid-December at reduced load. Mamquam had lower water flows and Moresby Lake continued to be hampered by the May 2019 failure of its main transformer (which was replaced in early February).

On the positive side, Curtis Palmer benefited from higher water flows, Nipigon had a contractual price increase, Oxnard had an outage and repairs to its gas turbine in the 2018 period, and Frederickson had higher dispatch and fewer maintenance projects than in 2018. In addition, we realized $0.7 million of Project Adjusted EBITDA from the acquisitions of Allendale and Dorchester and equity interests in Craven and Grayling (though it was less than a full quarter impact).

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Page 13: FY 2019 Project Adjusted EBITDA bridge

Project Adjusted EBITDA for full year 2019 increased $11.0 million to $196.1 million from $185.1 million. Curtis Palmer accounted for $11.5 million of the increase, as higher water flows resulted in strong increases in generation (+27% vs. 2018 and +26% vs. the historical average). Manchief and Tunis Project Adjusted EBITDA increased $7.4 million and $7.1 million, respectively. Most of the Manchief increase was attributable to the gas turbine overhaul in 2018, but results also benefited from higher dispatch. Tunis incurred start-up maintenance prior to returning to operation under a new PPA in October 2018. The biomass projects acquired in the third quarter of 2019 generated $2.4 million of Project Adjusted EBITDA for the year, while Frederickson improved $2.1 million from 2018 due to higher dispatch and lower operation and maintenance expense.

On the negative side, Williams Lake had a $9.0 million decrease in Project Adjusted EBITDA due to the lower economics of the short-term contract extension that was in effect the first nine months of 2019, and to voluntary curtailment in the latter months of the year. Cadillac had a $4.0 million decrease in EBITDA, including a $3.4 million impact in the fourth quarter due to the extended outage following the fire. Approximately $2.0 million of this should be recovered in the latter part of 2020. Chambers Project Adjusted EBITDA decreased $2.4 million due to lower energy and steam demand as well as lower prices for excess energy. Mamquam Project Adjusted EBITDA decreased $2.2 million due to lower water flows (generation was down 17% vs. a strong 2018, though generally in line with the historical average).

Page 14: Operating Cash Flow and Uses of Cash

Fourth Quarter 2019

Cash provided by operating activities was $40.2 million in the fourth quarter of 2019, an increase of $0.5 million from $39.7 million in the fourth quarter of 2018. The modest increase was primarily attributable to receipt of a tax refund ($2.7 million) and favorable working capital comparison, which were mostly offset by the $3.7 million reduction in Project Adjusted EBITDA, a lower distribution from Orlando due to the timing of 2018 distributions ($3.5 million) and initial project debt repayment at Chambers, which reduced its distribution from the prior-year level.

During the fourth quarter, we used operating cash flow to repay $20.0 million of our term loan. We also paid $1.9 million of dividends on our preferred shares and made $1.5 million of capital expenditures, excluding capital expenditures of $5.1 million for repairs to Cadillac, which were covered by insurance proceeds.

Full Year 2019

Cash provided by operating activities was $144.7 million in 2019, an increase of $7.2 million from $137.5 million in 2018. The improvement was primarily due to the $11.0 million increase in Project Adjusted EBITDA and a $3.7 million reduction in cash interest payments due to lower debt balances and a lower spread on our credit facilities. These positive variances were partially offset by a $4.8 million adverse change in cash flows attributable to changes in working capital and a $2.1 million reduction in distributions from unconsolidated affiliates (Chambers, due to initial debt repayment).

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

In 2019, we used operating cash flow to repay $70.0 million of our term loan and to amortize $2.3 million of project debt. We also paid $7.4 million of preferred dividends and made $2.3 million of capital expenditures, excluding repairs to Cadillac (which were covered by insurance proceeds).

Page 15: Liquidity

During the fourth quarter we generated discretionary cash flow (after debt repayment, preferred dividends and capital expenditures) of $16.8 million. We used $1.65 million for the repurchase of common shares during the quarter. At year-end 2019, we had $48.8 million of unrestricted cash at the parent. After holding aside $7 million of this cash for working capital purposes, we had approximately $42 million of discretionary cash available for general corporate purposes.

Total liquidity at December 31, 2019 was $196.5 million, which included $74.9 million of unrestricted cash ($48.8 million at the parent and $26.1 million at the projects) and $121.7 million of availability under our revolver. Project-level cash of $26.1 million included $4.0 million from Cadillac insurance proceeds for use in reconstruction of the plant.

Page 16: Debt Repayment Profile and Projected Debt Balances

The charts on page 16 of the presentation show our debt repayment in 2019 and our expected debt repayment through 2024. Note that these charts include our share of project debt at Chambers, which is accounted for using the equity method. Repayment of that debt occurs at the project level before we receive cash distributions.

In 2019, we repaid $70.0 million of term loan and $2.3 million of project debt from operating cash flow and redeemed $18.5 million (US$ equivalent) of Series D convertible debentures using available cash, for total consolidated debt repayment of $90.8 million. We ended the year with a consolidated leverage ratio of 3.8 times, in line with the third quarter level. The continuing repayment of debt as shown on the chart and relatively stable levels of EBITDA through 2022 should result in the leverage ratio continuing to move lower in 2020 and beyond. The debt repayment shown on page 16 includes $5.1 million of project debt repaid at Chambers (equity-owned project) in 2019.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

As shown in the chart, we expect to repay a total of $423 million of debt in the years 2020 through 2024, and reduce our debt balances by more than 60% from the year end 2019 level. The total includes $38.5 million of project-level debt repayment at Chambers. Following the amendment to our credit facilities last month, we no longer have any bullet maturities during this period, as the maturity date of our term loan was extended two years to 2025. We expect the loan to be fully repaid by the maturity date from operating cash flow and proceeds from the Manchief sale in 2022 ($45.2 million). Our corporate revolver has an April 2022 maturity, but has no borrowings outstanding.

We expect this substantial debt repayment over the next several years to 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.

Interest Costs

We have very little exposure to fluctuations in interest rates. At December 31, 2019, more than 99% of our debt carried either a fixed rate or a variable rate that has been fixed through interest rate swaps. Through December 2021, approximately 93% of our debt is either fixed rate or swapped. Our exposure to a 100 basis point change in LIBOR is approximately $19,000 over the next 12 months.

Page 17: 2020 Project Adjusted EBITDA 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.

Over the past couple of years we have indicated that we expect Project Adjusted EBITDA to be relatively stable through 2022 as there are very few significant PPA expirations until the second half of that year. A year ago, we initiated 2019 guidance in the range of $175 million to $190 million, which was predicated on average water flows for Curtis Palmer. In the third quarter of 2019, we raised our guidance to a range of $185 million to $195 million, primarily to reflect actual experience of much higher water flows. As noted, Project Adjusted EBITDA came in at $196.1 million, above the high end of the range, with the upside driven predominantly by water flows.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

As you can see from Page 17, we are initiating 2020 guidance at the same level as our initial 2019 guidance – a range of $175 million to $190 million. The decline from the 2019 actual level of $196.1 million primarily reflects an assumption of a return to average water flows for Curtis Palmer (-$12 million). The other significant decreases are at Oxnard and Calstock, due to PPA expirations in midyear (-$8 million), and at Morris, which has a maintenance outage in the spring of this year (-$4 million). These decreases are partially offset by expected modest increases from a full year contribution by the biomass acquisitions (+$4 million), Nipigon, Cadillac and Moresby Lake, as shown on page 17.

Although we are not providing quarterly guidance, we expect the decline in Project Adjusted EBITDA for the year to be concentrated in the first half of the year, for several reasons:

The above-average generation at Curtis Palmer occurred mostly in the first two quarters of 2019, though the fourth quarter also was strong;
Timing of Morris maintenance outage in 2020;
Williams Lake required outage and projected maintenance expense in May through July 2020;
Expected business interruption impact at Cadillac in first half 2020, to be reversed in 2H 2020; and
Cadillac, Oxnard and Williams Lake had negative Project Adjusted EBITDA in Q4 2019.

Page 18: 2020 Cash provided by operating activities and planned capital allocation

Our estimate of 2020 cash provided by operating activities is a range of $100 million to $115 million, as shown on page 18 of the presentation. As is our practice, for purposes of this estimate we have assumed that the impact of changes in working capital on cash flow is nil. Our initial estimate for 2019 cash provided by operating activities was the same – $100 million to $115 million. The actual result for 2019 of $144.7 million benefited from higher Project Adjusted EBITDA and favorable changes in working capital. Note that our projected corporate general and administrative (G&A) outlays and our cash interest payments are generally in line with the 2019 level. Most of the San Diego decommissioning outlays will occur in 2020 and represents a $3 million increase in use of cash. The adjustment for equity method projects reflects higher debt amortization at Chambers ($7.8 million in 2020 vs. $5.1 million in 2019).

Our principal planned uses of operating cash flow in 2020 include $72.5 million amortization of our term loan (up slightly from 2019) and $3.9 million of project debt amortization, for total debt repayment of $76.4 million. In addition, we expect to use cash for $7.4 million of dividend payments on our preferred shares (level with 2019) and $4.0 million of capital expenditures (excluding Cadillac repair costs, which are covered by insurance). Based on these estimates, discretionary cash flow in 2020 is expected to be in the range of approximately $12 million to $27 million.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Capital Allocation

As shown on page 18 of the presentation, in 2019, we allocated $10.5 million to the repurchase of preferred and common shares under our normal course issuer bid (NCIB), $18.5 million (US$ equivalent) to the redemption of the Series D convertible debentures ($18.9 million including accrued interest) and $28.5 million (plus $0.2 million of transaction costs) to fund the closing of the acquisitions of the Allendale and Dorchester biomass plants and equity interests in the Craven and Grayling biomass plants.

NCIB Update

During the fourth quarter, we repurchased and canceled 704,317 common shares at an average price of $2.35 per share, for a total investment of $1.65 million. For the full year, we repurchased and canceled nearly 1.1 million common shares at an average price of $2.31 per share, representing an investment of $2.5 million.

Although we did not repurchase any preferred shares in the fourth quarter, during the year we reached the 10% limit on repurchases of Series 1 and Series 3 preferred shares under the NCIB. We also repurchased approximately 43% of the 10% limit on the Series 2 preferred shares. Our total investment in preferred share repurchases in 2019 was Cdn$10.6 million (US$8.0 million equivalent). Our average repurchase price represented a 38% discount to par value.

We put a new NCIB in place on December 31, 2019 for our Series E convertible unsecured subordinated debentures, common shares and all three series of preferred shares. Under this NCIB, through February 26, 2020, we have repurchased approximately 1.7 million common shares at a total cost of $4.1 million, or an average price of $2.35 per share, and 247,894 shares of the Series 1 preferred at Cdn$16.40 per share, for a total cost of Cdn$4.1 million (US$3.1 million equivalent).

Page 19: Tax Update

On our year end conference calls, we generally have provided an update on our net operating losses (NOLs) and other tax matters. Page 19 contains a schedule of our NOLs by their expiration dates and jurisdiction, as well as an update on the impact of the 2017 U.S. tax legislation.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

We have not been a significant cash taxpayer because of our NOL position. In 2019, our net cash taxes were $2.3 million, consisting of cash payments of $5.0 million, partially offset by a $2.7 million refund. The majority of the $5.0 million in cash taxes paid, or approximately $3.0 million, related to withholding taxes associated with the payment of dividends on the preferred shares in Canada. The remaining $2.0 million is primarily state tax payments. We do not anticipate becoming a significant federal cash taxpayer in either the U.S. or Canada with respect to either 2019 or 2020.

The 2017 tax legislation repealed the corporate alternative minimum tax (AMT), which we expect will save us a modest amount of cash taxes. We received our first refund with respect to AMT credit carryforwards in 2019 in the amount of $2.7 million, and we expect refunds of $1.3 million, $0.7 million and $0.7 million in 2020 through 2022.

Limitations on the deductibility of interest expense under the legislation resulted in $37.9 million of interest expense being disallowed in 2018. However, interest expense deduction limitations are allowed to be carried forward indefinitely and we estimate that we will utilize $1.1 million of the carryforward on the 2019 return and the remainder by 2022.

During 2019, we recorded a reduction of $2.2 million to our existing U.S. Valuation Allowances (VA). Based on initiatives recently completed and various analyses, we determined that sufficient deferred tax liabilities were likely to reverse in a timely manner against certain deferred tax assets, resulting in a reduction of our VA in the United States. We increased the VA in Canada due to an increase in deferred tax assets that are uncertain to be utilized in the future.

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

I’ll close with some comments on capital allocation. Over the past five years, we have reduced our debt by approximately $1.1 billion, utilizing a combination of operating cash flow, asset sale proceeds and refinancings. Debt reduction is not driven by the returns available on our debt, but rather the priority of strengthening our balance sheet.

We also have allocated discretionary cash to purposes other than debt repayment, including internal investments in our fleet, external acquisitions and repurchases of common and preferred securities.

In 2013 through 2016, we invested $25 million in internal investments in our fleet and realized attractive returns.

From 2015 through 2019, we repurchased a total of approximately 17.0 million common shares, representing an investment of $38.8 million and an average price of $2.28 per share. As a result of these repurchases, common shares were reduced approximately 11% during this period.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

We also repurchased nearly 1.6 million preferred shares, representing a total investment of US$19.1 million equivalent. The return on these repurchases has averaged approximately 10% to 11%.

In 2018 and 2019, we completed the acquisition of two biomass projects and equity interests in two others, as well as consolidated our ownership of the Koma Kulshan hydro project, for a total of $44.9 million. These were the first external investments that we have made during current management’s tenure, and they represent a meaningful addition to the level and length of our contracted cash flows.

However, investors are rightly focused on the future, not the past. What can we say about the outlook for the next five years?

First, as we’ve noted previously, our Project Adjusted EBITDA should be fairly stable through 2022, before declining in 2023 and 2024 as PPAs expire. More than 95% of our cumulative EBITDA and operating cash flow through 2024 is contracted with little sensitivity to market conditions. We also have very limited foreign currency or interest rate exposure, and our fuel cost risk is well managed through contracts and other commercial arrangements. Operational performance is the primary risk during this period.

Second, while many investors focus on expiring PPAs and a declining EBITDA outlook, our focus is on the cash generated under those PPAs, which we have been primarily using to delever. As we continue to repay debt, our interest payments decline, which benefits our operating cash flow. Over this period, operating cash flow is somewhat less impacted by PPA expirations than EBITDA. As indicated on page 16 of this presentation, we expect to repay $423 million of debt from operating cash flow and the Manchief sale proceeds by the end of this five-year period. At that time (year-end 2024), remaining debt will total $265 million, consisting of the 2036 Medium-Term Notes ($162 million); the Series E convertible debentures ($88 million), which we expect to refinance ahead of their January 2025 maturity; and $15 million of Term Loan and Cadillac project debt, which will be amortized in 2025. So while our EBITDA will be lower, so will our debt and interest payments.

Another point to make is that with the final repayments of the Term Loan and project debt in 2025, we will have no amortizing debt remaining – only bullet maturities.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Third, during this period we expect to generate meaningful discretionary cash. By discretionary cash we mean cash available to us after debt repayment, preferred dividends and maintenance capex. By year-end 2024, we expect to increase our discretionary cash by an amount equal to slightly more than half our current market capitalization. Since we last discussed our five-year outlook (in August 2017), the proportion of operating cash flow that is “discretionary” has increased as a result of significant debt repayment, lower interest payments on the Term Loan due to multiple re-pricings and cash flow contributions by the acquired biomass projects.

Fourth, adding the expected build of discretionary cash during this period to our starting cash level of approximately $75 million (at year-end 2019), our cash balance should grow to a level that, at some point in 2025, will approximate or exceed our debt of $265 million. In other words, we expect to be net debt neutral by sometime in 2025.

Of course, this assumes that we do nothing with the cash.

More likely than getting to net debt neutral would be allocating some or all of this cash for other purposes, including repurchases of common or preferred shares, external investments or some combination of those options. In addition, we can flex our capacity for external growth by using our revolver (which had availability of $122 million at year-end 2019).

We don’t have a predetermined plan for capital allocation. Our approach is to assess the impact on our estimates of intrinsic value per share, while balancing risk and reward. We would invest externally only when we believe the returns are superior to those we can achieve by investing internally or repurchasing shares.

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

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, impairment charges, insurance loss (gain), other (income) expenses 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 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

	Three months ended December 31, 2019 2018	Three months ended December 31, 2019 2018	Twelve months ended December 31, 2019 2018	Twelve months ended December 31, 2019 2018
	2019		2019
Net (loss) income attributable to Atlantic Power Corporation	($ 65.3)	$ 24.7	($ 42.6)	$ 36.8
Net income (loss) attributable to preferred share dividends of a subsidiary company	1.9	2.0	(1.2)	0.4
Net (loss) income	($ 63.4)	$ 26.7	($ 43.8)	$ 37.2
Income tax expense (benefit)	7.3	(7.5)	9.8	0.2
(Loss) income from operations before income taxes	(56.1)	19.2	(34.0)	37.4
Administration	6.6	5.9	23.9	23.9
Interest expense, net	11.0	12.0	44.0	52.7
Foreign exchange loss (gain)	4.8	(13.7)	11.9	(22.8)
Other expense (income), net	0.3	(3.4)	1.0	(3.0)
Project (loss) income	($ 33.4)	$ 20.1	$ 46.8	$ 88.2

Reconciliation to Project Adjusted EBITDA
Depreciation and amortization	$ 20.3	$ 21.8	$ 80.7	$ 99.7
Interest expense, net	0.4	0.8	2.5	3.4
Change in the fair value of derivative instruments	0.6	1.3	8.9	(2.2)
Impairment	55.0	-	55.0	-
Insurance loss	-	-	1.0	-
Other expense (income), net	-	2.5	1.2	(4.0)
Project Adjusted EBITDA	$ 42.9	$ 46.6	$ 196.1	$ 185.1

Exhibit 99.2

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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 27 A of the U . S . Securities Act of 1933 , as amended, and Section 21 E 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 result s, 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 presentation 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 presentation 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 presentation, 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, impairment charges, insurance loss (gain), other (income) expenses, 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 on page 38 . 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 (Cadillac ) . • Adjusted EBITDA is calculated as the Consolidated Net Income of APLP Holdings plus the sum of consolidated interest expense, tax expense, depreciation and amortization expense, and other non - cash charges, minus non - cash gains . The Consolidated Net Income includes an allocation of the majority of Atlantic Power G&A expense . It also excludes earnings attributable to equity - owned projects but includes cash distributions received from those projects . Reference to “ Cdn $ ” and “Canadian dollars” are to the lawful currency of Canada and references to “ $ ”, “US $ ” and “U . S . dollars” are to the lawful currency of the United States . All dollar amounts herein are in U . S . dollars and approximate, unless otherwise indicated .
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3 • Highlights • Operations Review • Commercial Update • Financial Results • Liquidity and Debt Repayment Profile • 2020 Guidance • Appendix Q4 and Full Year 2019 Supplementary Presentation
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Full Year 2019 Highlights 4 Financial Results • Operating cash flow of $144.7 million exceeded our estimate • Project Adjusted EBITDA of $196.1 million also exceeded top end of guidance • Liquidity of $196.5 million, including approximately $42 million of discretionary cash Balance Sheet • Repaid $90.8 million of consolidated debt, improving leverage ratio to 3.8 times • Improved the terms of our credit facilities, reducing cost and extending maturity date • Received a credit rating upgrade from S&P; have received total of four upgrades from two agencies over the past 4+ years Capital Allocation • Generated $63 million of discretionary cash flow • Used: o $18.5 million to repurchase Series D convertible debentures o $10.5 million to repurchase common and preferred shares o $28.5 million to close acquisition of two biomass projects and two other biomass equity interests PPAs • Executed a new 10 - year PPA for Williams Lake • Kenilworth customer executed two one - year contract extensions Costs • Maintained overhead costs in line with 2016 – 2018 level
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1.67 0.69 1.16 1.65 3.60 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 383.9 317.8 462.3 603.6 180.4 166.9 1,026.6 1,088.3 Q4 2018 Q4 2019 Q4 2018 Q4 2019 Q4 2018 Q4 2019 Q4 2018 Q4 2019 Q4 2019 Operational Performance: Higher generation due to acquisitions and higher dispatch at Frederickson and Manchief 5 Q4 2019 Q4 2018 Solid Fuel 83.0% 94.6% Natural Gas 96.0% 98.3% Hydro 89.8% 98.0% Total 90.4% 97.5% Aggregate Power Generation Q4 2019 vs. Q4 2018 (Net GWh) Solid Fuel Natural Gas Hydroelectric Total (17.2%) 30.6% (7.5)% 6.0% Lower availability factor: Generation drivers: + Acquisitions of Allendale, Dorchester, Craven and Grayling + Frederickson higher dispatch + Manchief higher dispatch + Curtis Palmer higher water flows - Williams Lake voluntary curtailment (rebuilding fuel inventory) - Cadillac fire and extended outage - Mamquam lower water flows - Cadillac fire and extended outage - Moresby Lake extended outage (transformer) - Piedmont maintenance outage - Kenilworth later fall outage in 2019 + Oxnard gas turbine repairs in prior period Safety: Total Recordable Incident Rate TRIR, generation companies (Bureau of Labor Statistics): FY 2015 1.4, FY 2016 1.0, FY 2017 1.5, FY 2018 1.1 Industry average Availability Hydro generation Curtis Palmer Mamquam +14% vs Q4 2018 - 31% vs Q4 2018 +28% vs long - term avg. - 5% vs long - term avg. Note: See new Reportable Segments, pages 9 and 30
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1,517.6 1,439.2 2,206.3 2,475.3 637.7 673.2 4,361.6 4,587.7 FY 2018 FY 2019 FY 2018 FY 2019 FY 2018 FY 2019 FY 2018 FY 2019 FY 2019 Operational Performance: Higher generation due to acquisitions and higher dispatch at Frederickson and Manchief 6 FY 2019 FY 2018 Solid Fuel 92.5% 94.6% Natural Gas 95.8% 96.4% Hydro 92.6% 97.3% Total 94.0% 96.5% Aggregate Power Generation FY 2019 vs. FY 2018 (Net GWh) Solid Fuel Natural Gas Hydroelectric Total (5.2%) 12.2% 5.6% 5.2% Lower availability factor: Generation drivers: + Acquisitions of Allendale, Dorchester, Craven and Grayling + Frederickson higher dispatch + Manchief higher dispatch + Curtis Palmer higher water flows - Williams Lake voluntary curtailment (rebuilding fuel inventory) - San Diego project expirations in prior period (Q1 2018) - Cadillac fire and extended outage - Mamquam lower water flows - Cadillac fire and extended outage - Moresby Lake extended outage (transformer) Safety: Total Recordable Incident Rate TRIR, generation companies (Bureau of Labor Statistics): FY 2015 1.4, FY 2016 1.0, FY 2017 1.5, FY 2018 1.1 Availability Full Year Hydro generation Curtis Palmer Mamquam +27% vs FY 2018 - 17% vs FY 2018 +26% vs long - term avg. - 1% vs long - term avg. 1.67 0.69 1.16 1.65 3.60 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 Industry average Note: See new Reportable Segments, pages 9 and 30
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Operations Update 7 • Work continuing on replacement of damaged components and reconstruction of the plant • Sourced turbine and generator from an identical plant in Maine to reduce lead time • Repairs on track for a targeted return to service in Q3 2020 • Received initial insurance recovery of $11.3 million in December 2019 Cadillac (Michigan) Williams Lake (British Columbia) • Returned to operation in late December; running at ~50MW • Continuing to focus on building fuel inventory o Short - term arrangements for traditional sources of fiber, including with new suppliers o Purchased and deployed new mobile fuel grinder o Availability and cost of fuel challenging, but to date are in line with expectations • Targeting continued operation into April • May – July outage (freshet months) o Replacement of cooling tower o Other maintenance o Continue to build fuel inventory • Estimate breakeven EBITDA in 2020 due to maintenance and reduced level of operations
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Commercial Updates 8 Manchief (Colorado) • May 2019 agreement to sell Manchief to Public Service Co. of Colorado ( PSCo ), the customer under the PPA, for $45.2 million in May 2022 following expiration of the PPA • Federal Energy Regulatory Commission approved the transaction in October 2019 • Earlier this month, the Colorado Public Utilities Commission approved PSCo’s application for a Certificate of Public Convenience and Necessity and cost recovery, which was required for acquisition • All regulatory approvals required for the sale have been received Oxnard (California) • PPA with Southern California Edison (SCE) expires in May 2020 • Oxnard was not selected in recent capacity solicitations • Pursuing alternative offtake structures o Reliability Must Run (RMR) contract with California Independent System Operator (CAISO) o Evaluating potential to sell into Resource Adequacy (RA) market or to Community Choice Aggregators (CCA) • We own and control Oxnard site Calstock (Ontario) • Remain engaged with government but expect plant to cease operations at the end of PPA term (June 2020) • No policy or market mechanism in place to continue biomass operations
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Accounting Developments – Q4 2019 9 • New Reportable Segments (see page 30 in Appendix) o Previously geographic (East, West, Canada) and Unallocated Corporate o Now based on fuel type: Solid Fuel (biomass and coal), Natural Gas, Hydroelectric and Corporate o Better aligns with how projects are managed and evaluated • Impairment o N on - cash expense o Included in Project income (loss), but not included in Project Adjusted EBITDA o Chambers ▪ $49.2 million impairment of investment ▪ Continued decline in forward power curves ▪ Challenging re - contracting environment ▪ Unlikely to operate as a merchant plant post - PPA (March 2024) due to unfavorable spot pricing o Calstock ▪ $5.8 million impairment of long - lived assets ▪ Plant unlikely to operate post - PPA (June 2020)
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Accounting Developments – Q4 2019, continued 10 • Cadillac o Received initial insurance recovery of $11.3 million ▪ Amount was net of $1 million property deductible (recorded in Q3 2019) and 45 - day business interruption deductible of approximately $1.4 million (Q4 2019) ▪ Included in investing cash flows ▪ Not allocated between property and business interruption insurance; we estimate $2.0 million was for business interruption ▪ Entire amount recorded as a reduction to insurance receivable o Recoveries under business interruption insurance considered gain contingencies ▪ Change from what we had expected at time of Q3 2019 call ▪ Q4 2019 EBITDA impact approximately $2.0 million ▪ Expect to record to earnings when claim is settled (after plant returns to operation) ▪ Thus, project income and EBITDA for Cadillac is expected to be shifted into 2H 2020 (after claim is settled)
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Q4 2019 Financial Highlights and 2020 Outlook 11 Financial Results • Cash provided by operating activities of $40.2 million, in line with $39.7 million in Q4 2018 • Project Adjusted EBITDA of $42.9 million, down from $46.6 million in Q4 2018 • Results in line with expectations, with Curtis Palmer upside essentially offset by Cadillac outage and reduced operations at Williams Lake Balance Sheet • Repaid $20.0 million of term loan • Consolidated leverage ratio of 3.8 times Capital Allocation • Invested $1.65 million in repurchase of 704,317 common shares (average price $2.35 per share) Full Year 2019 results exceeded expectations for Project Adjusted EBITDA and Operating Cash Flow Significant progress on growth initiatives and debt repayment 2020 Outlook • Initiating 2020 Project Adjusted EBITDA (1) guidance in range of $175 million to $190 million • Estimating 2020 cash provided by operating activities (2) in range of $100 million to $115 million • Expect to repay approximately $76.4 million in 2020 (expect leverage ratio to continue to improve) (1) The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and project ion s without unreasonable efforts with respect to certain highly variable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These fact ors , which generally do not affect cash flow, are not included in Project Adjusted EBITDA. (2) Assumes for this purpose that changes in working capital are nil . Credit Facilities Amendment (January 2020) • Spread reduced 25 basis points to LIBOR plus 2.50%; would be reduced another 25 basis points if the Company achieves leverage ratio of 2.75 times • Maturity date of the term loan was extended by two years to April 2025 • Targeted debt balances modified to reflect sale of Manchief in 2022
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Q4 2019 Project Adjusted EBITDA (1) (bridge vs 2018 actual) ($ millions) 12 $46.6 $42.9 Q4 2018 Q4 2019 Curtis Palmer Higher water flows 1.4 Nipigon Mostly due to contractual price escalation 0.8 Williams Lake Voluntary curtailment and additional maintenance (2.4) Cadillac Outage impact and deductible; expect to recover business interruption losses once rebuild is complete ($2 million) (3.8) (1.8) Oxnard Outage and GT repairs In prior period 1.3 Mamquam, Moresby Lake Mamquam lower water f lows; Moresby Lake main transformer failure (May 2019) Voluntary curtailment at Williams Lake and insurance deductibles related to the fire at Cadillac, mostly offset by higher water flows at Curtis Palmer and capacity rate escalation at Nipigon 0.7 All others (0.5) Frederickson Higher dispatch and fewer maintenance projects (1) See Appendix for discussion of non - GAAP disclosures. 0.7 Acquisitions Allendale Dorchester Craven Grayling
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FY 2019 Project Adjusted EBITDA (1) (bridge vs 2018 actual) ($ millions) 13 $185.1 $196.1 FY 2018 FY 2019 Curtis Palmer Higher w ater flows 11.5 Manchief Gas turbine major overhaul in Q2 2018 7.1 Chambers Lower energy and steam demand; lower prices for excess energy (2.4) Williams Lake Short - term PPA extension (lower margins) and voluntary curtailment (9.0) (4.0) Tunis Start - up maintenance in 2018; revenue under new PPA (Oct. 2018) 7.4 Cadillac Outage impact and deductible; expect to recover business interruption losses once rebuild is complete ($2.0 million) • Higher water flows at Curtis Palmer drove strong full year results • Manchief and Tunis were also significant contributors • Williams Lake decrease due to lower margins under short - term contract and voluntary curtailment • Cadillac business interruption insurance not recognized as income until rebuild complete (1.9) All others 2.1 Frederickson Higher dispatch, lower O&M (2.2) Mamquam Lower water flows (1) See Appendix for discussion of non - GAAP disclosures. 2.4 Acquisitions Allendale Dorchester Craven Grayling
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Three months ended December 31, Unaudited 2019 2018 Change Cash provided by operating activities $40.2 $39.7 $0.5 Recurring uses of cash provided by operating activities: Term loan repayments (1) (20.0) (20.0) - Project debt amortization - (0.8) 0.8 Capital expenditures (2) (1.5) (0.3) (1.2) Preferred dividends (1.9) (2.0) 0.1 Q4 and FY 2019 Cash Flow Results ($ millions) 14 + Receipt of tax refund ($2.7 million) that reduced cash taxes + Favorable working capital comparison - Lower Project Adjusted EBITDA ($3.7 million) - Orlando lower distributions due to timing of the September 2018 distribution (received in Oct. 2018) - Chambers repaid project debt during the quarter and thus the distribution was reduced (1) Includes 1% mandatory annual amortization and targeted debt repayments. (2) Maintenance capital; excludes Cadillac repairs of $5.1 million in Q4, which were covered by insurance proceeds.. (3) Excludes redemption of Series D convertible debentures ($18.5 million US$ equivalent) in 2019. See Appendix for discussion of non - GAAP disclosures. Twelve months ended December 31, Unaudited 2019 2018 Change Cash provided by operating activities $144.7 $137.5 $7.2 Recurring uses of cash provided by operating activities (3) : Term loan repayments (1) (70.0) ( 9 0.0) 20.0 Project debt amortization (2.3) (10.3) 8.0 Capital expenditures (2) (2.3) (1.8) (0.5) Preferred dividends (7.4) (8.3) 0.9 + $11.0 million increase in Project Adjusted EBITDA + $3.7 million reduction in cash interest payments due to lower debt balances and a lower rate on the credit facilities - $(4.8) million adverse impact from changes in working capital - $(2.1) million of lower distributions from unconsolidated affiliates (Chambers) 2019 Cash provided by operating activities of $144.7 million exceeded the Company’s estimate
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Liquidity ($ millions) 15 Dec 31, 2019 Sep 30, 2019 Cash and cash equivalents, parent $48.8 $31.2 Cash and cash equivalents, projects (1) 26.1 26.9 Total cash and cash equivalents 74.9 58.1 Revolving credit facility 200.0 200.0 Letters of credit outstanding (78.3) (76.9) Availability under revolving credit facility 121.7 123.1 Total Liquidity $196.5 $181.2 Excludes restricted cash of (2) : $7.7 $1.7 Consolidated debt (3) $648.9 $664.2 Leverage ratio (4) 3.8 3.7 (1) Includes $4.0 million from Cadillac insurance proceeds for use in reconstruction of the plant. (2) Includes $7.3 million from Cadillac insurance proceeds for use in reconstruction of the plant. (3) Before unamortized discount and unamortized deferred financing costs (4) Consolidated debt to trailing 12 - month Adjusted EBITDA (after Corporate G&A) Q4 2019 change: $16.8 million + $16.8 million discretionary cash flow after debt repayment, preferred dividends and capex + Reduction of $1.3 million in restricted cash (excluding Cadillac restricted cash ) - Used $1.6 million for the repurchase of common shares Includes approx. $42 million available for discretionary purposes
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$96 $84 $105 $119 $75 $40 $0 $20 $40 $60 $80 $100 $120 $140 2019 2020 2021 2022 2023 2024 $770 $687 $603 $499 $379 $304 $265 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 YE 2018 YE 2019 YE 2020 YE 2021 YE 2022 YE 2023 YE 2024 Debt Repayment and Projected Debt Balances through 2024 (1) ($ millions ) 16 16 (1) Includes Company’s proportional share of debt at Chambers of $38.5 million, which is not consolidated because the project is 40% owned. Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.2994 as of December 31, 2019. • Expect to reduce debt by more than 60% from YE 2019 to YE 2024 • M ajority of the debt repayment expected to be from operating cash flows and proceeds from the sale of Manchief (2022) • Expect to result in lower cash interest payments and lower leverage ratios • Repaid $96 million in 2019 • 2020 - 2024 total $423 million • $380 million Term Loan expected to be fully repaid by maturity (April 2025) • No bullet maturities prior to January 2025 (Series E convertible debentures) Projected Debt Balances Debt Repayment $96 repayment $(12) F/X loss (unrealized)
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2020 Project Adjusted EBITDA (1) Guidance (bridge vs 2019 actual) ($ millions) 17 $196 $190 $175 FY 2019 Actual FY 2020 Guidance Acquisitions Full year impact of: Allendale Dorchester Craven Grayling +4 All others ( 1) Moresby Lake Transformer failure in May 2019 +2 Curtis Palmer Assume average water flows (12) Nipigon Rate escalation +3 Calstock PPA expiry June 2020 (1) The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and pr ojections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments an d f oreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA . See Appendix for discussion of non - GAAP disclosures. (5) Initiating guidance of $175 million to $190 million Morris Major maintenance (4) Oxnard PPA expiry May 2020 (3) 2020 Guidance Consistent with Initial 2019 Guidance ($175 million to $190 million) - Assumes average water flows at Curtis Palmer - PPA expirations at Calstock and Oxnard - Morris maintenance outage + Biomass acquisitions Cadillac Business interruption insurance deductible in Q4 2019; Timing of BI recognition +3
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Acquisitions (3) - 28.5 • Redemption of Series D - 18.5Bridge of 2020 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities ($ millions ) 18 18 The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts an d 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 exchan ge gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA. 2020 Guidance as of 2/27/20 2019 Actual Project Adjusted EBITDA $175 - $190 $196.1 Adjustment for equity method projects (1) (8) (3.5) Corporate G&A (cash) (23) (22.4) Cash interest payments (36) (37.6) Cash taxes (4) (2.3) Decommissioning (San Diego projects) (4) (1.0) Other (including changes in working capital) - 15.4 Cash provided by operating activities $100 - $115 $144.7 Note: For purposes of providing a reconciliation of Project Adjusted EBITDA guidance, impact on Cash provided by operating activities of changes in working capital is assumed to be nil. (1) Represents difference between Project Adjusted EBITDA and cash distribution from equity method projects; in 2020, the $(8) million reflects debt amortization at Chambers of $7.8 million. (2 ) 2019 repurchases include $8.0 million of preferred shares and $2.5 million of common shares; 2020 YTD reflects purchases through February 26, 2020 of $4.1 million of common and $3.1 m ill ion of preferred shares. (3 ) Includes the $10.0 million for the South Carolina biomass acquisition paid at closing July 31, 2019 and $18.5 million for the AltaGas biomass acquisition that closed August 13, 2019. See Appendix for discussion of non - GA AP disclosures. Uses of Cash Provided by Operating Activities: 2020 Plan 2019 Actual • Term loan repayments $72.5 $70.0 • Project debt amortization 3.9 2.3 • Preferred dividends 7.4 7.4 • Capital expenditures 4.0 2.3 Additional Capital Allocation: 2020 YTD 2019 Actual • NCIB repurchases (2) $7.2 $10.5 •

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Tax Update NOL Expiration by Year (As of 12/31/19 $ millions) Pre - Tax Reform U.S. Canada 2029 $0.0 $27.3 2030 41.1 0.0 2031 25.8 0.0 2032 13.4 5.8 2033 20.6 23.5 2034 122.3 9.1 2035 154.1 0.0 2036 17.0 20.3 2037 16.7 8.9 2038 0.0 10.1 2039 0.0 6.9 Total $411.0 $111.9 • As of December 31, 2019, the Company had U.S. and Canadian NOLs scheduled to expire per the table (right) that can be utilized to offset future taxable income in their respective tax jurisdictions. • NOLs represent potential future tax savings of approximately $105.7 million in the U.S. under the revised U.S. Federal corporate tax rate of 21% and $30.2 million in Canada. • Although these NOLs are expected to be available as a future benefit: » Some of the NOLs are subject to limitations on their use » Pre - Tax Reform NOLs, as detailed in the chart, can be used to offset 100% of taxable income and retain a 2 - year carryback and a 20 - year carryforward period » Post - Tax Reform NOLs are limited to offset 80% of taxable income, have no carryback feature but have an unlimited carryforward period. The Company has no Post - Tax Reform NOLs. Net Operating Losses Other Impacts of Recent U.S. Tax Legislation • Repeal of the Alternative Minimum Tax (AMT) will result in cash tax savings » De minimis amount of AMT credits that are 50% refundable in 2018 - 2020; any remaining credits are fully refundable in 2021 » First refund of $2.7 million was received in Q4 2019; we expect to receive $1.3 million in 2020 • Business Interest Expense Limitation » Net business interest deductions in excess of 30% of EBITDA (EBIT after 2021) are disallowed . However, disallowed deductions will be carried forward indefinitely to be used at a future date. 19 Valuation Allowance (VA) • A VA must be established against deferred tax assets when it is more likely than not that the asset will not be realized. During 2019, the Company recorded a reduction of $2.2 million to its existing U.S. VA’s and an increase of $7.9 million to its existing Canadian VA’s. • At December 31, 2019, the Company had VA’s in the U.S. and Canada of $53.2 million and $92.2 million, respectively, totaling $145.4 million. » The Company had disallowed interest expense of $37.9 million in 2018 and estimates utilizing $1.1 million of that carryforward on 2019 return and the remainder by 2022. • The Company does not anticipate paying any significant Federal cash taxes in either the U.S. or Canada for FY 2019 or FY 2020.

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Appendix 20 TABLE OF CONTENTS Page Power Projects, PPA Expiration Dates 21 Capital Structure Information 22 - 29 Project Information – Segments, Earnings/Cash Flow Diversification and PPA Term 30 - 32 Supplemental Financial Information Q4 2019 Results Summary 33 - 34 Project Income by Project 35 Project Adjusted EBITDA by Project 36 Cash Distributions from Projects 37 Non - GAAP Disclosures 38 - 40

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Power Projects and PPA Expiration Dates 21 (1) Public Service Co. of Colorado has executed an agreement to purchase Manchief after the expiration of the PPA in May 2022. (2) BC Hydro has an option to purchase Mamquam that is exercisable in Nov. 2021. (3) Expires at the earlier of Dec. 2027 or the provision of 10,000 GWh of generation . Based on cumulative generation to date, we expect the PPA to expire prior to Dec. 2027 . (4) Equistar has right to take up to 77 MW but on average takes approx. 50 MW. Balance of 177 MW of capacity is sold to PJM. (5) Equistar has an option to purchase Morris exercisable in Dec. 2020 and Dec. 2027. Economic Net Contract Year Project Location Type Interest MW Expiry 2020 Oxnard California Nat. Gas 100% 49 5/2020 Calstock Ontario Biomass 100% 35 6/2020 2021 Kenilworth New Jersey Nat. Gas 100% 29 9/2021 Manchief Colorado Nat. Gas 100% 300 4/2022 (1) Moresby Lake B.C. Hydro 100% 6 8/2022 Frederickson Washington Nat. Gas 50.15% 125 8/2022 Nipigon Ontario Nat. Gas 100% 40 12/2022 2023 Orlando Florida Nat. Gas 50% 65 12/2023 2024 Chambers New Jersey Coal 40% 105 3/2024 Mamquam B.C. Hydro 100% 50 9/2027 (2) Curtis Palmer New York Hydro 100% 60 12/2027 (3) 2025 - 2029 Craven North Carolina Biomass 50% 24 12/2027 Grayling Michigan Biomass 30% 11 12/2027 Cadillac Michigan Biomass 100% 40 6/2028 Williams Lake B.C. Biomass 100% 66 9/2029 Piedmont Georgia Biomass 100% 55 9/2032 Tunis Ontario Nat. Gas 100% 37 10/2033 Morris Illinois Nat. Gas 100% 77 (4) 12/2034 (5) Koma Kulshan Washington Hydro 100% 13 3/2037 Dorchester South Carolina Biomass 100% 20 10/2043 Allendale South Carolina Biomass 100% 20 11/2043 2022 2032 - 2043
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$1,876 $1,755 $1,019 $997 $846 $727 $649 $573 9.5 6.9 5.7 5.6 3.3 4.5 3.8 3.7 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 YE 2013 YE 2014 YE 2015 YE 2016 YE 2017 YE 2018 YE 2019 Proj.YE 2020 (1) Consolidated debt (millions) (2) Leverage ratio 22 (1) Reflects $76.4 million of debt repayments in 2020 (2) Excludes unamortized discounts and deferred financing costs. Strengthening Balance Sheet ($ millions) ~ 3.7 More than $1.2 billion net reduction in consolidated debt since YE 2013 Expect to repay $76.4 million of consolidated debt in 2020 Leverage ratio expected to improve modestly in 2020
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0 50 100 150 200 250 300 2020 2021 2022 2023 2024 Thereafter Debt Repayment Profile at December 31, 2019 (1) ($ millions) 23 (1) ) Includes Company’s proportional share of debt at Chambers of $38.5 million, which is not consolidated because the project is 40% owned. (2) Bullet percentage includes medium term notes and Series E convertible debentures. Note : C$ denominated debt was converted to US$ using US$ to C$ exchange rate of 1.2994 as of December 31, 2019. • Project - level non - recourse debt: $57, including $38 at Chambers (equity method); amortizes over the life of the project PPA (through 2025) • APLP Holdings Term Loan: $380; 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 • APC Convertible Debentures: $88 (US$ equivalent) of Series E convertible debentures (maturing Jan. 2025) • APLP Medium - Term Notes: $162 (US$ equivalent) due in June 2036 Total $687 $84 $105 $265 $119 APLP Holdings Term Loan Project - level debt APLP Medium - term Notes (US$ equivalent) APC Convertible Debentures (US$ equivalent) 64% amortizing, 36% bullet (2) $75 $40 Series E (2025) MTNs (2036)
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57 46 34 21 6 2 380 308 215 109 49 13 89 89 89 89 89 89 162 162 162 162 162 162 0 100 200 300 400 500 600 700 800 12/31/19 12/31/20 12/31/21 12/31/22 12/31/23 12/31/24 24 Expected Debt Repayment (Year End 2019 – Year End 2024): • APLP Holdings Term Loan: Will fully amortize by maturity (April 2025) • Project Debt: Amortize $55, ending balance $2 (Cadillac) • APC Convertible Debentures: No repayment required prior to 2025 maturity • Total Repayment through 2024: $423 (62% of total) Projected Debt Balances through 2024 (1) ($ millions ) APLP Holdings Term Loan Project - level debt APLP Medium - term Notes (US$ equiv.) APC Convertible Debentures (US$ equiv.) $687 $379 $304 $603 $499 Actual (1) Includes Company’s proportional share of debt at Chambers of $38.5 million, which is not consolidated because the project is 40% owned. Note : C$ denominated debt was converted to US$ using US$ to C$ exchange rate of 1.2994 as of December 31, 2019. $265
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$130 $127 $100 $71 $72 $41 $38 $42 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 2013 2014 2015 2016 2017 2018 2019 Refinancing Transaction Costs Cash Interest Payments $53.8 $45.4 $31.9 $22.8 $22.2 $23.9 $23.9 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 2013 2014 2015 2016 2017 2018 2019 25 Reducing Cash Interest Payments and Corporate Overhead ($ millions ) Cash Interest Payments (1) Corporate Overhead Expense Reduction has been driven by debt repayment as well as re - pricings of our term loan and revolver Projected to decline to $36 million in 2020 (1) Includes consolidated debt only Combined interest and overhead reduction of $110 million annually from 2014 levels $89 $21 Overhead expense stable 2016 - 2019
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Capitalization ($ millions) 26 Dec. 31, 2019 Dec. 31, 2018 Long - term d ebt, incl. current portion (1) APLP Medium - Term Notes (2) $161.7 $154.0 Revolving credit facility - - Term Loan 380.0 450.0 P roject - level debt (non - recourse) 18.8 21.0 Convertible debentures (2) 88.5 102.4 Total long - term debt, incl. current portion $649.0 83% $727.4 79% Preferred shares (3) 182.7 23% 199.3 22% Common equity (4) (45.0) (6)% (6.9) (1)% Total shareholders equity $137.7 17% $192.4 21% Total capitalization $786.7 100% $919.8 100% (1) Debt balances are shown before unamortized discount and unamortized deferred financing costs. (2) Period - over - period change due to F/X impacts. (3) Par value of preferred shares was approximately $143 million and $149 million at December 31, 2019 and December 31, 2018, respectively. (4) Common equity includes other comprehensive loss and retained deficit. Note: Table is p resented on a consolidated basis and excludes equity method projects
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Capital Summary at December 31, 2019 ($ millions) (1) The January 2020 repricing of the Term Loan will reduce the rate 0.25% to LIBOR plus 2.50%. (2) Weighted average rate at Dec. 31, 2019 of approximately 4.79%. Range and weighted average include impact of interest rate swaps (3) Set on Dec. 2, 2019 for Mar. 31, 2020 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 $1.2994 as of December 31, 2019. 27 Atlantic Power Corporation Maturity Amount Outstanding Interest Rate Convertible Debentures (ATP.DB.E) 1/2025 $88.5 (C$115.0) 6.00% APLP Holdings Limited Partnership Maturity Amount Interest Rate Revolving Credit Facility 4/2022 $0 LIBOR + 2.75% (1) Term Loan 4/2025 $380.0 4.55% - 4.79% (2) Atlantic Power Limited Partnership Maturity Amount Interest Rate Medium - term Notes 6/2036 $161.7 (C$210) 5.95% Preferred shares (AZP.PR.A) N/A $74.1 (C$96.2) 4.85% Preferred shares (AZP.PR.B) N/A $48.2 (C$62.6) 5.739% Preferred shares (AZP.PR.C) N/A $ 20.7 (C$26.9) 5.83% (3) Atlantic Power Transmission & Atlantic Power Generation Maturity Amount Interest Project - level Debt (Cadillac - consolidated) 8/2025 $18.7 6.26% - 6.38% Project - level Debt (Chambers - equity method) 12/2023 $38.5 5.00%
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APLP Holdings Term Loan Cash Sweep Calculation 28 APLP Holdings Adjusted EBITDA ( 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, 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 loan to be fully repaid by maturity from operating cash flow and Manchief sale proceeds Notes: The cash sweep calculation occurs at each quarter - end. Targeted debt balances are specified in the credit agreement for each qu arter through maturity. Through 2022: After 2022: Repay debt using 50% of cash flow available for sweep
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APLP Holdings Credit Facilities – Financial Covenants 29 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 (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 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
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Allendale Allendale Cadillac Cadillac Chambers Calstock Craven Chambers Curtis Palmer Craven Dorchester Dorchester Grayling Grayling Kenilworth Piedmont Morris Williams Lake Orlando Piedmont Frederickson Kapuskasing Frederickson Kenilworth Koma Kulshan Manchief Manchief Morris Naval Station Naval Station North Island Nipigon NTC / MCRD North Bay Oxnard North Island NTC / MCRD Calstock Orlando Kapuskasing Oxnard Mamquam Tunis Moresby Lake Nipigon Curtis Palmer North Bay Koma Kulshan Tunis Mamquam Williams Lake Moresby Lake Unallocated Corporate Corporate Solid Fuel Natural Gas Hydro East West Canada Previous Segments New Segments Change to Reportable Segments 30
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Solid Fuel 17% Natural Gas 55% Hydroelectric 28% Other 2% Curtis Palmer 23% Orlando 17% Nipigon 12% Morris 8% Manchief 8% Frederickson 8% Chambers 7% Piedmont 5% Mamquam 4% Cadillac 3% Calstock 3% Tunis 2% Kenilworth 1% Twelve months ended December 31, 2019 Project Adjusted EBITDA by Project (1) 31 Project Adjusted EBITDA and Cash Flow Diversification by Project (1) Based on Project Adjusted EBITDA for the twelve months ended December 31, 2019, excluding non - operational projects and projects with negative Project Adjusted EBITDA for the period. See Project Adjusted EBITDA by Project in this Appendix. (2) Based on $196.7 million in Cash Distributions from Projects for the twelve months ended December 31, 2019. Cash Distributions from Projects by Segment (2) Project Adjusted EBITDA by Segment I ncludes four acquired biomass plants (partial year) Solid Fuel 14% Natural Gas 58% Hydroelectric 28%
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Less than 5 52% 5 to 10 32% 10 to 15 13% 15+ 2% 2% A - to A+ 63% AA - to AA 19% AAA 5% BBB - to BBB+ 11% BB 1% NR 1% Remaining PPA Term (years) (1) 32 (1) Weighted by FY 2019 Project Adjusted EBITDA. Includes newly acquired projects. (2) Primarily merchant energy revenue at Morris. Pro Forma Offtaker Credit Rating (1) Approximately Half of EBITDA Covered by Contracts with A t Least 5 Years Remaining Contracted projects have an average remaining PPA life of 6.1 years (1 ) (2) Merchant / Market Pricing (2)
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33 Summary of Financial and Operating Results ($ millions, unaudited) (1) See non - GAAP disclosures in this Appendix. (1) 2019 2018 2019 2018 Project revenue $66.2 $70.7 $281.6 $282.3 Project (loss) income (33.4) 20.1 46.8 88.2 Net (loss) income attributable to Atlantic Power Corporation (65.3) 24.7 (42.6) 36.8 Cash provided by operating activities 40.2 39.7 144.7 137.5 Cash provided by (used in) investing activities 6.3 (0.1) (21.7) (17.0) Cash used in financing activities (23.7) (27.1) (110.8) (135.0) Project Adjusted EBITDA 42.9 46.6 196.1 185.1 Operating Results Aggregate power generation (net GWh) 1,088.3 1,026.6 4,587.7 4,361.6 Weighted average availability 90.4% 97.5% 94.0% 96.5% December 31,December 31, Three months ended Twelve months ended
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34 Segment Results ($ millions, unaudited) 2019 2018 2019 2018 Project (loss) income Solid Fuel ($60.2) $0.2 ($49.8) $19.7 Natural Gas 16.9 12.5 68.5 33.3 Hydroelectric 9.4 10.3 36.0 35.8 Corporate 0.5 (3.0) (7.9) (0.6) Total ($33.4) $20.1 $46.8 $88.2 Project Adjusted EBITDA Solid Fuel $1.3 $6.7 $32.7 $46.7 Natural Gas 27.6 24.9 108.2 90.4 Hydroelectric 14.3 14.8 55.5 47.5 Corporate (0.3) 0.2 (0.3) 0.5 Total $42.9 $46.6 $196.1 $185.1 December 31, December 31, Three months ended Twelve months ended

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Project Income (Loss) by Project ($ millions, unaudited) 35 (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. (2) Consolidated as of July 27, 2018; equity investment prior to that date. Three months ended Twelve months ended December 31, December 31, 2019 2018 2019 2018 Solid Fuel Allendale $0.1 - $0.8 - Cadillac (2.8) $0.6 (2.3) $1.9 Calstock (5.1) 0.2 (2.7) 3.4 Dorchester (0.3) - 0.2 - Piedmont (2.1) (1.3) 2.1 2.9 Williams Lake (1.9) 0.5 (2.8) 6.1 Chambers (1) (48.6) 0.2 (46.0) 5.5 Craven (1) (0.0) - 0.2 - Grayling (1) 0.5 - 0.8 - Total (60.2) 0.2 (49.8) 19.7 Natural Gas Kapuskasing (0.1) 0.0 (0.3) (0.4) Kenilworth 0.1 (0.1) (0.1) (0.7) Manchief 0.9 1.0 4.6 (2.9) Morris 3.1 3.6 10.2 10.5 Naval Station (0.1) (0.9) (0.8) (2.7) Naval Training Center (0.1) (1.3) (0.8) (2.8) Nipigon 5.7 4.8 22.2 5.2 North Bay (0.1) 0.0 (0.3) (0.2) North Island (0.0) (1.7) (0.6) (3.1) Oxnard (2.3) (3.1) (4.1) (2.2) Tunis 0.5 0.0 2.1 (4.3) Frederickson (1) 2.6 1.9 9.1 6.9 Orlando (1) 6.7 8.1 27.5 29.9 Total 16.9 12.5 68.5 33.3 Hydroelectric Curtis Palmer 9.6 8.1 32.4 20.9 Koma Kulshan (2) (0.1) 0.5 (0.1) 7.8 Mamquam 0.9 1.8 5.6 7.8 Moresby Lake (0.9) (0.1) (1.9) (0.7) Total 9.4 10.3 36.0 35.8 Totals Consolidated projects 5.0 12.9 63.1 46.5 Equity method projects (38.8) 10.2 (8.5) 42.3 Corporate 0.5 (3.0) (7.9) (0.6) Total Project (Loss) Income ($33.4) $20.1 $46.8 $88.2
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Equity method projects 15.8 14.2 62.9 60.3 Corporate (0.3) 0.2 (0.3) 0.5 Total Project Adjusted EBITDA $42.9 $46.6 $196.1 $185.1 Twelve months ended Atlantic Power Corporation Net (loss) income attributable to Three months ended Twelve months ended December 31,36 Project Adjusted EBITDA by Project ($ millions, unaudited) (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. (2) Consolidated as of July 27, 2018; equity investment prior to that date. Three months ended December 31, December 31, December 31, 2019 2018 2019 2018 2019 2018 2019 2018 Solid Fuel Allendale $0.2 - $0.9 - Total Project Adjusted EBITDA $42.9 $46.6 $196.1 $185.1 Cadillac (1.9) $1.9 3.3 $7.3 Depreciation and amortization 20.3 21.8 80.7 99.7 Calstock 1.2 0.7 5.2 5.5 Interest expense, net 0.4 0.8 2.5 3.4 Dorchester (0.2) - 0.2 - Change in fair value of derivative instruments 0.6 1.3 8.9 (2.2) Piedmont (0.3) 0.5 9.4 10.2 Impairment 55.0 - 55.0 - Williams Lake (1.4) 1.0 (1.0) 8.0 Insurance loss - - 1.0 - Chambers (1) 3.0 2.6 13.4 15.8 Other expense (income), net - 2.5 1.2 (4.0) Craven (1) 0.1 - 0.4 - Project income ($33.4) $20.1 $46.8 $88.2 Grayling (1) 0.6 - 0.9 - Administration 6.6 5.9 23.9 23.9 Total 1.3 6.7 32.7 46.7 Interest expense, net 11.0 12.0 44.0 52.7 Natural Gas Foreign exchange loss (gain) 4.8 (13.7) 11.9 (22.8) Kapuskasing (0.1) 0.0 (0.3) (0.4) Other expense (income), net 0.3 (3.4) 1.0 (3.0) Kenilworth 0.7 0.6 2.6 2.0 (Loss) income from operations before income taxes (56.1) 19.2 (34.0) 37.4 Manchief 3.7 3.8 15.6 8.2 Income tax expense (benefit) 7.3 (7.5) 9.8 0.2 Morris 4.4 5.2 16.7 17.7 Net (loss) income ($63.4) $26.7 ($43.8) $37.2 Naval Station (0.1) (0.1) (0.4) (0.8) Net income (loss) attributable to preferred share Naval Training Center (0.0) (0.2) (0.2) (1.1) dividends of a subsidiary company 1.9 2.0 (1.2) 0.4 Nipigon 7.5 6.0 23.6 23.2 North Bay (0.1) 0.0 (0.3) (0.2) ($65.3) $24.7 ($42.6) $36.8 North Island (0.1) (0.4) (0.4) (1.0) Oxnard (1.3) (2.0) (0.0) 2.1 Tunis 0.7 0.3 3.1 (4.0) Frederickson (1) 4.1 3.5 15.2 13.1 Orlando (1) 8.0 8.2 33.0 31.4 Total 27.6 24.9 108.2 90.4 Hydroelectric Curtis Palmer 13.4 12.0 47.8 36.3 Koma Kulshan (2) 0.3 0.5 1.4 1.4 Mamquam 1.3 2.2 7.2 9.5 Moresby Lake (0.7) 0.1 (1.0) 0.3 Total 14.3 14.8 55.5 47.5 Totals Consolidated projects 27.4 32.2 133.5 124.3

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37 Cash Distributions from Projects by Quarter, 2018 - 2019 ($ millions, unaudited) (1) Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates. (2) Consolidated as of July 27, 2018; equity investment prior to that date. Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 FY 2018 2018 2018 2018 2018 2019 2019 2019 2019 2019 Solid Fuels Allendale - - - - - - - - $0.8 $0.8 Cadillac $0.3 $1.3 $1.0 $1.0 $3.5 - $1.0 $0.5 - 1.5 Calstock 2.9 1.8 (0.1) 0.7 5.4 $1.1 1.1 1.8 1.2 5.2 Dorchester - - - - - - - - 0.7 0.7 Piedmont 1.3 1.3 6.0 1.5 10.0 1.3 0.5 5.5 2.0 9.3 Williams Lake 4.0 1.2 (0.9) 1.7 5.9 2.5 (0.2) (1.0) (2.6) (1.4) Chambers (1) - 5.9 - 8.0 13.9 - 6.0 - 3.2 9.2 Craven (1) - - - - - - - - 0.3 0.3 Grayling (1) - - - - - - - 0.4 0.3 0.6 Total 8.4 11.4 6.0 12.9 38.7 4.8 8.4 7.2 5.8 26.2 Natural Gas Kapuskasing 6.3 (0.2) (0.1) 0.0 6.0 (0.1) (0.1) 0.0 (0.1) (0.3) Kenilworth 1.4 0.5 (0.0) 0.5 2.3 0.9 0.9 1.3 0.5 3.5 Manchief 3.2 0.6 4.2 4.2 12.2 3.4 3.6 2.6 6.0 15.6 Morris 6.9 3.4 1.5 5.0 16.9 5.7 4.0 3.4 4.2 17.3 Naval Station 1.2 (0.7) (0.4) (0.4) (0.4) 1.2 (0.1) (0.4) (0.1) 0.6 Naval Training Center 0.8 (0.5) (0.4) (0.6) (0.7) (0.2) (0.1) (0.4) (0.1) (0.7) Nipigon 10.0 5.7 2.4 5.2 23.3 9.8 5.4 4.7 6.1 26.0 North Bay 6.6 (0.1) (0.1) 0.0 6.4 (0.1) (0.1) (0.0) (0.1) (0.3) North Island 1.4 (0.7) (0.4) (0.6) (0.3) (0.3) (0.1) (0.2) (0.2) (0.8) Oxnard (0.2) (0.2) 5.3 1.3 6.2 (1.1) (1.9) 4.7 0.3 1.9 Tunis (0.5) (3.1) (0.5) (0.5) (4.5) 1.4 0.8 0.8 0.6 3.6 Frederickson (1) 4.0 3.0 3.4 3.7 14.1 3.8 2.8 4.5 4.3 15.4 Orlando (1) 2.6 9.7 6.4 13.7 32.3 1.9 10.1 10.6 10.3 32.9 Total 43.5 17.5 21.4 31.6 114.0 26.2 25.1 31.7 31.8 114.8 Hydroelectric Curtis Palmer 9.5 13.0 2.7 9.0 34.1 14.3 15.2 7.6 10.3 47.4 Koma Kulshan (2) 0.6 0.1 0.4 0.8 1.8 0.3 0.6 0.1 0.4 1.3 Mamquam 1.9 2.7 2.6 1.8 9.0 1.7 2.4 2.1 1.2 7.4 Moresby Lake 0.6 (0.1) (0.2) 0.1 0.4 0.5 (0.3) (0.3) (0.3) (0.4) Total 12.5 15.8 5.4 11.6 45.4 16.8 17.8 9.5 11.7 55.7 Total Cash Distributions $64.5 $44.7 $32.8 $56.1 $198.0 $47.8 $51.3 $48.3 $49.3 $196.7 Consolidated 57.4 26.0 23.0 30.7 137.7 42.1 32.4 32.8 31.0 138.3 Equity Method 7.1 18.8 9.8 25.4 60.3
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5.7 18.9 15.4 18.3 58.4
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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 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 pages 39 - 40 . 38 2019 2018 2019 2018 Net (loss) income attributable to Atlantic Power Corporation ($65.3) $24.7 ($42.6) $36.8 Net income (loss) attributable to preferred share dividends of a subsidiary company 1.9 2.0 (1.2) 0.4 Net (loss) income ($63.4) $26.7 ($43.8) $37.2 Income tax expense (benefit) 7.3 (7.5) 9.8 0.2 (Loss) income from operations before income taxes (56.1) 19.2 (34.0) 37.4 Administration 6.6 5.9 23.9 23.9 Interest expense, net 11.0 12.0 44.0 52.7 Foreign exchange loss (gain) 4.8 (13.7) 11.9 (22.8) Other expense (income), net 0.3 (3.4) 1.0 (3.0) Project (loss) income ($33.4) $20.1 $46.8 $88.2 Reconciliation to Project Adjusted EBITDA Depreciation and amortization $20.3 $21.8 $80.7 $99.7 Interest expense, net 0.4 0.8 2.5 3.4 Change in the fair value of derivative instruments 0.6 1.3 8.9 (2.2) Impairment 55.0 - 55.0 - Insurance loss - - 1.0 - Other expense (income), net - 2.5 1.2 (4.0) Project Adjusted EBITDA $42.9 $46.6 $196.1 $185.1 December 31, December 31, Three months ended Twelve months ended
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39 Reconciliation of Net Income ( L oss) to Project Adjusted EBITDA by Segment ($ millions) Three months ended December 31, 2019 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($60.2) $16.9 $9.4 ($31.4) ($65.3) Net income attributable to preferred share dividends of a subsidiary company - - - 1.9 1.9 Net (loss) income (60.2) 16.9 9.4 (29.5) (63.4) Income tax expense - - - 7.3 7.3 Net (loss) income before income taxes (60.2) 16.9 9.4 (22.2) (56.1) Administration - - - 6.6 6.6 Interest expense, net - - - 11.0 11.0 Foreign exchange loss - - - 4.8 4.8 Other expense, net - - - 0.3 0.3 Project (loss) income (60.2) 16.9 9.4 0.5 (33.4) Depreciation and amortization 6.1 9.3 4.9 - 20.3 Interest expense, net 0.4 - - - 0.4 Change in fair value of derivative instruments - 1.4 - (0.8) 0.6 Impairment 55.0 - - - 55.0 Insurance loss - - - - - Other expense, net - - - - - Project Adjusted EBITDA $1.3 $27.6 $14.3 ($0.3) $42.9 Three months ended December 31, 2018 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net income attributable to Atlantic Power Corporation $0.2 $12.5 $10.3 $1.7 $24.7 Net income attributable to preferred share dividends of a subsidiary company - - - 2.0 2.0 Net income 0.2 12.5 10.3 3.7 26.7 Income tax benefit - - - (7.5) (7.5) Income (loss) before income taxes 0.2 12.5 10.3 (3.8) 19.2 Administration - - - 5.9 5.9 Interest expense, net - - - 12.0 12.0 Foreign exchange gain - - - (13.7) (13.7) Other income, net - - - (3.4) (3.4) Project income (loss) 0.2 12.5 10.3 (3.0) 20.1 Depreciation and amortization 5.8 11.1 5.0 0.0 21.8 Interest expense, net 0.8 - - 0.0 0.8 Change in fair value of derivative instruments - (1.8) - 3.1 1.3 Other expense (income), net - 3.1 (0.5) (0.1) 2.5 Project Adjusted EBITDA $6.7 $24.9 $14.8 $0.2 $46.6
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40 Reconciliation of Net Income ( L oss) to Project Adjusted EBITDA by Segment ($ millions) Twelve months ended December 31, 2019 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net (loss) income attributable to Atlantic Power Corporation ($49.8) $68.5 $36.0 ($97.3) ($42.6) Net loss attributable to preferred share dividends of a subsidiary company - - - (1.2) (1.2) Net (loss) income (49.8) 68.5 36.0 (98.5) (43.8) Income tax expense - - - 9.8 9.8 Net (loss) income before income taxes (49.8) 68.5 36.0 (88.7) (34.0) Administration - - - 23.9 23.9 Interest expense, net - - - 44.0 44.0 Foreign exchange loss - - - 11.9 11.9 Other expense, net - - - 1.0 1.0 Project (loss) income (49.8) 68.5 36.0 (7.9) 46.8 Depreciation and amortization 23.9 37.2 19.5 0.1 80.7 Interest expense, net 2.6 (0.1) - - 2.5 Change in fair value of derivative instruments - 1.4 - 7.5 8.9 Impairment 55.0 - - - 55.0 Insurance loss 1.0 - - - 1.0 Other expense, net - 1.2 - - 1.2 Project Adjusted EBITDA $32.7 $108.2 $55.5 ($0.3) $196.1 Twelve months ended December 31, 2018 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Net income (loss) attributable to Atlantic Power Corporation $19.7 $33.3 $35.8 ($52.0) $36.8 Net income attributable to preferred share dividends of a subsidiary company - - - 0.4 0.4 Net income (loss) 19.7 33.3 35.8 (51.6) 37.2 Income tax expense - - - 0.2 0.2 Net income (loss) before income taxes 19.7 33.3 35.8 (51.4) 37.4 Administration - - - 23.9 23.9 Interest expense, net - - - 52.7 52.7 Foreign exchange gain - - - (22.8) (22.8) Other income, net - - - (3.0) (3.0) Project income (loss) 19.7 33.3 35.8 (0.6) 88.2 Depreciation and amortization 23.7 57.0 18.9 0.1 99.7 Interest expense, net 3.3 0.1 - - 3.4 Change in fair value of derivative instruments - (3.2) - 1.0 (2.2) Other expense, net - 3.2 (7.2) - (4.0) Project Adjusted EBITDA $46.7 $90.4 $47.5 $0.5 $185.1
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Atlantic Power Preferred Equity Ltd. — Call Transcript 2020

46023_rns_2020-02-28_2d83c9f5-205d-49c3-abdd-6373b4665057.pdf

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 8-K

ATLANTIC POWER CORPORATION

Item 2.02. Results of Operations and Financial Condition.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

SIGNATURES

PREPARED REMARKS Q4 2019 FEBRUARY 28, 2020

Ron Bialobrzeski – Atlantic Power Corporation – Director, Finance

- Page 2: Cautionary Note Regarding Forward Looking Statements

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

Page 4: 2019 Highlights

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Page 5: Q4 2019 Operational Performance

Safety

Generation

Availability

Page 6: FY 2019 Operational Performance

Generation

Availability

Page 7: Operations Update

Cadillac

Williams Lake

Decommissioning of San Diego Sites

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Cost Focus

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

- Page 8: Re contracting Updates

Oxnard (California)

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Calstock (Ontario)

Manchief (Colorado)

Terry Ronan – Atlantic Power Corporation – EVP & CFO

Page 9: Q4 2019 Accounting Developments

New Business Segments

Impairment

Page 10: Q4 2019 Accounting Developments (cont’d)

Cadillac Insurance Recovery and Accounting

Page 11: Q4 2019 Financial Highlights

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Page 12: Q4 2019 Project Adjusted EBITDA bridge

Page 13: FY 2019 Project Adjusted EBITDA bridge

Page 14: Operating Cash Flow and Uses of Cash

Fourth Quarter 2019

Full Year 2019

Page 15: Liquidity

Page 16: Debt Repayment Profile and Projected Debt Balances

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Interest Costs

Page 17: 2020 Project Adjusted EBITDA Guidance

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Page 18: 2020 Cash provided by operating activities and planned capital allocation

Capital Allocation

NCIB Update

Page 19: Tax Update

ATLANTIC POWER CORPORATION Q4 2019 FEBRUARY 28, 2020

Non-GAAP Disclosures

Atlantic Power Corporation

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Atlantic Power Preferred Equity Ltd. Call Transcript 2020