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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2020
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

COMMISSION FILE NUMBER 001‑34691

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia, Canada (State or other jurisdiction of incorporation or organization) | 55‑0886410 (I.R.S. 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 Purchase Common Shares | AT | The New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act:

Large accelerated filer ☐ | Accelerated filer ☒ | Non‑accelerated filer ☐ | Smaller reporting company ☐
Emerging growth company ☐ |  |  |

If an emerging 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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐ No ☒

The number of shares outstanding of the registrant’s Common Stock as of May 6, 2020 was 93,002,338.

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ATLANTIC POWER CORPORATION

FORM 10‑Q

THREE MONTHS ENDED MARCH 31, 2020

Index

| General : |  | 3
| PART I—FINANCIAL INFORMATION |  |
ITEM 1. | CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES |  |
| Consolidated Balance Sheets as of March 31, 2020 (unaudited) and December 31, 2019 |  | 4
| Consolidated Statements of Operations for the three months ended March 31, 2020 (unaudited) and March 31, 2019 (unaudited) |  | 5
| Consolidated Statements of Comprehensive Income for the three months ended March 31, 2020 (unaudited) and March 31, 2019 (unaudited) |  | 6
| Consolidated Statements of Cash Flows for the three months ended March 31, 2020 (unaudited) and March 31, 2019 (unaudited) |  | 7
| Condensed Notes to Consolidated Financial Statements (unaudited) |  | 8
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  | 35
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |  | 51
ITEM 4. | CONTROLS AND PROCEDURES |  | 51
| PART II—OTHER INFORMATION |  |
ITEM 1A. | RISK FACTORS |  | 51
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |  | 52
ITEM 6. | EXHIBITS |  | 55

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GENERAL

In this Quarterly Report on Form 10‑Q, references 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, unless otherwise indicated.

Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10‑Q to “we,” “us,” “our,” “Atlantic Power” and the “Company” refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

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ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)

|  | March 31, |  | December 31, |
|  | 2020 |  | 2019 |
Assets |  | (unaudited) |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 47.8 |  | $ | 74.9 |
Restricted cash |  |  | 0.5 |  |  | 7.7 |
Accounts receivable |  |  | 32.6 |  |  | 30.4 |
Insurance recovery receivable (Note 13) |  |  | 6.1 |  |  | 13.5 |
Current portion of derivative instruments asset (Notes 6 and 7) |  |  | — |  |  | 0.7 |
Inventory |  |  | 15.8 |  |  | 18.6 |
Prepayments |  |  | 6.7 |  |  | 3.8 |
Income taxes receivable (Note 8) |  |  | 2.5 |  |  | 1.8 |
Lease receivable (Note 14) |  |  | 0.4 |  |  | 0.9 |
Other current assets |  |  | 0.3 |  |  | 0.4 |
Total current assets |  |  | 112.7 |  |  | 152.7 |
Property, plant, and equipment, net |  |  | 490.5 |  |  | 502.1 |
Equity investments in unconsolidated affiliates (Note 4) |  |  | 103.7 |  |  | 96.6 |
Power purchase agreements and intangible assets, net |  |  | 137.5 |  |  | 144.3 |
Goodwill |  |  | 21.3 |  |  | 21.3 |
Operating lease right-of-use assets (Note 14) |  |  | 5.9 |  |  | 6.3 |
Deferred income taxes (Note 8) |  |  | 9.8 |  |  | 10.4 |
Other assets |  |  | 0.6 |  |  | 1.9 |
Total assets |  | $ | 882.0 |  | $ | 935.6 |
Liabilities |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable |  | $ | 4.7 |  | $ | 8.9 |
Accrued interest |  |  | 3.2 |  |  | 2.6 |
Other accrued liabilities |  |  | 13.6 |  |  | 20.8 |
Current portion of long-term debt (Note 5) |  |  | 78.5 |  |  | 76.4 |
Current portion of derivative instruments liability (Notes 6 and 7) |  |  | 18.0 |  |  | 12.0 |
Operating lease liabilities (Note 14) |  |  | 2.0 |  |  | 2.0 |
Other current liabilities |  |  | 0.2 |  |  | 0.2 |
Total current liabilities |  |  | 120.2 |  |  | 122.9 |
Long-term debt, net of unamortized discount and deferred financing costs (Note 5) |  |  | 436.3 |  |  | 473.5 |
Convertible debentures, net of discount and unamortized deferred financing costs |  |  | 74.2 |  |  | 81.1 |
Derivative instruments liability (Notes 6 and 7) |  |  | 16.5 |  |  | 15.9 |
Deferred income taxes (Note 8) |  |  | 24.1 |  |  | 23.7 |
Power purchase agreements and intangible liabilities, net |  |  | 18.5 |  |  | 19.8 |
Asset retirement obligations, net |  |  | 49.8 |  |  | 51.5 |
Operating lease liabilities (Note 14) |  |  | 4.3 |  |  | 4.8 |
Other long-term liabilities |  |  | 4.1 |  |  | 4.7 |
Total liabilities |  |  | 748.0 |  |  | 797.9 |
Equity |  |  |  |  |  |  |
Common shares, no par value, unlimited authorized shares; 105,502,338 and 108,675,294 issued and outstanding at March 31, 2020 and December 31, 2019 (Note 11) |  |  | 1,252.1 |  |  | 1,259.9 |
Accumulated other comprehensive loss (Note 3) |  |  | (152.2) |  |  | (140.7) |
Retained deficit |  |  | (1,134.7) |  |  | (1,164.2) |
Total Atlantic Power Corporation shareholders’ equity |  |  | (34.8) |  |  | (45.0) |
Preferred shares issued by a subsidiary company (Note 11) |  |  | 168.8 |  |  | 182.7 |
Total equity |  |  | 134.0 |  |  | 137.7 |
Total liabilities and equity |  | $ | 882.0 |  | $ | 935.6 |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions of U.S. dollars, except per share amounts)

(Unaudited)

|  | Three Months Ended March 31, |
|  | 2020 |  | 2019 |
Project revenue: |  |  |  |  |  |  |
Energy sales (Note 2) |  | $ | 40.7 |  | $ | 37.0 |
Energy capacity revenue (Note 2) |  |  | 28.0 |  |  | 30.2 |
Other (Note 2) |  |  | 4.1 |  |  | 5.8 |
|  |  | 72.8 |  |  | 73.0 |
Project expenses: |  |  |  |  |  |  |
Fuel |  |  | 19.6 |  |  | 20.0 |
Operations and maintenance |  |  | 20.7 |  |  | 16.5 |
Depreciation and amortization |  |  | 15.6 |  |  | 16.2 |
|  |  | 55.9 |  |  | 52.7 |
Project other income (loss): |  |  |  |  |  |  |
Change in fair value of derivative instruments (Notes 6 and 7) |  |  | (5.6) |  |  | (2.4) |
Equity in earnings of unconsolidated affiliates (Note 4) |  |  | 13.7 |  |  | 12.9 |
Interest, net |  |  | (0.3) |  |  | (0.3) |
Other income, net |  |  | — |  |  | 0.1 |
|  |  | 7.8 |  |  | 10.3 |
Project income |  |  | 24.7 |  |  | 30.6 |
Administrative and other expenses: |  |  |  |  |  |  |
Administration |  |  | 6.7 |  |  | 6.8 |
Interest expense, net |  |  | 10.8 |  |  | 11.1 |
Foreign exchange (gain) loss |  |  | (20.6) |  |  | 5.0 |
Other expense, net (Note 6) |  |  | 2.6 |  |  | 4.7 |
|  |  | (0.5) |  |  | 27.6 |
Income from operations before income taxes |  |  | 25.2 |  |  | 3.0 |
Income tax expense (Note 8) |  |  | 1.5 |  |  | 0.6 |
Net income |  |  | 23.7 |  |  | 2.4 |
Net loss attributable to preferred shares of a subsidiary company (Note 11) |  |  | (5.8) |  |  | (6.5) |
Net income attributable to Atlantic Power Corporation |  | $ | 29.5 |  | $ | 8.9 |
Net earnings per share attributable to Atlantic Power Corporation shareholders: (Note 10) |  |  |  |  |  |  |
Basic |  | $ | 0.28 |  | $ | 0.08 |
Diluted |  |  | 0.23 |  |  | 0.07 |
Weighted average number of common shares outstanding: (Note 10) |  |  |  |  |  |  |
Basic |  |  | 107.2 |  |  | 108.9 |
Diluted |  |  | 134.8 |  |  | 138.6 |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions of U.S. dollars)

(Unaudited)

|  | Three Months Ended March 31, |
|  | 2020 |  | 2019 |
Net income |  | $ | 23.7 |  | $ | 2.4 |
Other comprehensive income, net of tax: |  |  |  |  |  |  |
Unrealized loss on hedging activities |  | $ | (0.4) |  | $ | (0.2) |
Net amount reclassified to earnings |  |  | 0.1 |  |  | 0.1 |
Net realized and unrealized loss on derivatives |  |  | (0.3) |  |  | (0.1) |
Foreign currency translation adjustments |  |  | (11.2) |  |  | 2.2 |
Other comprehensive (loss) income, net of tax |  |  | (11.5) |  |  | 2.1 |
Comprehensive income |  |  | 12.2 |  |  | 4.5 |
Less: Comprehensive loss attributable to preferred shares of a subsidiary company |  |  | (5.8) |  |  | (6.5) |
Comprehensive income attributable to Atlantic Power Corporation |  | $ | 18.0 |  | $ | 11.0 |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)

|  | Three months ended |
|  | March 31, |
|  | 2020 |  | 2019 |
Cash provided by operating activities: |  |  |  |  |  |  |
Net income |  | $ | 23.7 |  | $ | 2.4 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |
Depreciation and amortization |  |  | 15.6 |  |  | 16.2 |
Share-based compensation |  |  | 0.4 |  |  | 0.6 |
Equity in earnings from unconsolidated affiliates |  |  | (13.7) |  |  | (12.9) |
Distributions from unconsolidated affiliates |  |  | 6.0 |  |  | 5.8 |
Unrealized foreign exchange (gain) loss |  |  | (20.9) |  |  | 5.3 |
Change in fair value of derivative instruments |  |  | 8.2 |  |  | 7.1 |
Amortization of debt discount and deferred financing costs |  |  | 2.0 |  |  | 1.9 |
Non-cash operating lease expense |  |  | 0.5 |  |  | 0.4 |
Deferred income taxes |  |  | 0.3 |  |  | (0.7) |
Change in other operating balances |  |  |  |  |  |  |
Accounts receivable |  |  | (2.1) |  |  | 5.1 |
Inventory |  |  | 2.8 |  |  | 2.7 |
Prepayments and other assets |  |  | (1.7) |  |  | (1.4) |
Accounts payable |  |  | (5.7) |  |  | 1.9 |
Accruals and other liabilities |  |  | (7.0) |  |  | (5.2) |
Cash provided by operating activities |  |  | 8.4 |  |  | 29.2 |
Cash (used in) provided by investing activities: |  |  |  |  |  |  |
Insurance proceeds |  |  | 7.4 |  |  | — |
Proceeds from sales of assets and equity investments, net |  |  | — |  |  | 1.5 |
Purchase of property, plant and equipment |  |  | (10.0) |  |  | (0.3) |
Cash (used in) provided by investing activities |  |  | (2.6) |  |  | 1.2 |
Cash used in financing activities: |  |  |  |  |  |  |
Common share repurchases |  |  | (8.2) |  |  | (0.1) |
Preferred share repurchases |  |  | (6.4) |  |  | (7.7) |
Repayment of corporate and project-level debt |  |  | (21.6) |  |  | (15.8) |
Cash payments for vested LTIP withheld for taxes |  |  | (0.7) |  |  | — |
Deferred financing costs |  |  | (1.5) |  |  | — |
Dividends paid to preferred shareholders |  |  | (1.7) |  |  | (1.9) |
Cash used in financing activities |  |  | (40.1) |  |  | (25.5) |
Net (decrease) increase in cash, restricted cash and cash equivalents |  |  | (34.3) |  |  | 4.9 |
Cash, restricted cash and cash equivalents at beginning of period |  |  | 82.6 |  |  | 70.4 |
Cash, restricted cash and cash equivalents at end of period |  | $ | 48.3 |  | $ | 75.3 |
Supplemental cash flow information |  |  |  |  |  |  |
Interest paid |  | $ | 8.3 |  | $ | 8.2 |
Income taxes paid, net |  | $ | 0.7 |  | $ | 0.8 |
Accruals for construction in progress |  | $ | 0.3 |  | $ | — |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

1. Nature of business

General

Atlantic Power is an independent power producer that owns power generation assets in eleven states in the United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of March 31, 2020, our portfolio consisted of twenty-one operating projects with an aggregate electric generating capacity of approximately 1,723 megawatts (“MW”) on a gross ownership basis and approximately 1,327 MW on a net ownership basis. Sixteen of the projects are majority‑owned by the Company.

Atlantic Power is a corporation established under the laws of the Province of Ontario on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange (“TSX”) under the symbol “ATP” and on the New York Stock Exchange (“NYSE”) under the symbol “AT.” Our registered office is located at 1066 West Hastings Street, Suite 2600, Vancouver, British Columbia V6E 3X1, Canada and our headquarters is located at 3 Allied Drive, Suite 155, Dedham, Massachusetts 02026, USA. Our telephone number in Dedham is (617) 977‑2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power’s website or that can be accessed through its website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10‑Q. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website.

Basis of presentation

The interim condensed consolidated financial statements included in this Quarterly Report on Form 10‑Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10‑Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10‑K for the year ended December 31, 2019. Interim results are not necessarily indicative of results for the full year.

In our opinion, the accompanying unaudited interim condensed consolidated financial statements present fairly our consolidated financial position as of March 31, 2020, the results of operations and comprehensive income for the three months ended March 31, 2020 and 2019, and our cash flows for the three months ended March 31, 2020 and 2019, in accordance with U.S. generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.

Use of estimates

The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair value of assets acquired and liabilities assumed in purchase accounting, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, recovery of expected insurance proceeds, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2019. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Recently adopted and issued accounting standards

Accounting standards adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance amends the guidance on measuring credit losses on financial assets held at amortized cost. ASU 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. This guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted ASU 2016-13 on January 1, 2020 and it did not have a material impact on the condensed consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, “Changes to Fair value Measurement Disclosures” to modify the disclosure requirements on fair value measurement disclosures. The guidance requires removals of certain disclosures, such as the amount of and reasons for transfers between level 1 and level 2 of fair value hierarchy and the policy for timing of transfers between levels. The guidance further requires modifications and additions surrounding the disclosures of level 3 fair value measurements and related unrealized gains and losses. The guidance is effective for fiscal years beginning after December 15, 2019. We adopted this guidance on January 1, 2020 and it did not have an impact on the condensed consolidated financial statements.

In August 2018, the FASB issued ASU 2018-09, “Codification Improvements” to remove disclosures that no longer are considered cost-beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The scope of the guidance is broad and includes reporting comprehensive income, debt modifications and extinguishments and other sub topics. The guidance is effective for fiscal years beginning after December 15, 2019. We adopted this guidance on January 1, 2020 and it did not have an impact on the condensed consolidated financial statements.

Accounting standards to be implemented

In August 2018, the FASB issued ASU No. 2018-14, “Compensation -Retirement Benefits -Defined Benefit Plans -General (Subtopic 715-20)”, to improve the effectiveness of benefit plan disclosures in the notes to financial statements by facilitating clear communication of the information required by generally accepted accounting principles (“GAAP”) that is most important to users of each entity’s financial statements. The amendments in this ASU modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Additionally, the amendments in this ASU remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures, and add disclosure requirements identified as relevant. The amendments in this ASU are effective for fiscal years ending after December 15, 2020, for public business entities and early adoption is permitted for all entities. We are currently evaluating the impact that adoption will have on our disclosures.

In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. We are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements.

In March 2020, the FASB issued amendments to the guidance for reference rate reform through ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the effects of reference rate reform on financial reporting.” The amendments in this update provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022. The amendments are elective and are effective upon issuance for all entities. We are in the process of evaluating the potential impact of the new guidance on our consolidated financial statements.

2. Revenue from contracts

Disaggregation of revenue

We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management’s structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for the comparative 2019 period has been revised to conform to the new segment presentation. Each segment contains various power generation projects and performance obligations as described above. For more detailed information about reportable segments, see Note 12, Segment and geographical information. Revenue by segment consists of the following:

|  | Three Months Ended March 31, 2020
|  |  |  |  |  |  |  |  |  |  |  |  | Consolidated
|  | Solid Fuel |  | Natural Gas |  | Hydroelectric |  | Corporate |  | Total
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 16.8 |  | $ | 6.2 |  | $ | 17.7 | $ |  | — |  | $ | 40.7
Energy capacity revenue |  |  | 6.3 |  |  | 21.7 |  |  | — |  |  | — |  |  | 28.0
Steam energy and capacity revenue |  |  | — |  |  | 2.7 |  |  | — |  |  | — |  |  | 2.7
Waste heat revenue |  |  | 0.3 |  |  | — |  |  | — |  |  | — |  |  | 0.3
Ancillary and transmission services |  |  | — |  |  | 0.7 |  |  | 0.7 |  |  | — |  |  | 1.4
Asset management and operation |  |  | — |  |  | — |  |  | — |  |  | 0.2 |  |  | 0.2
Miscellaneous revenue |  |  | — |  |  | (0.5) |  |  | — |  |  | — |  |  | (0.5)
|  |  | 23.4 |  |  | 30.8 |  |  | 18.4 |  |  | 0.2 |  |  | 72.8

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

|  | Three Months Ended March 31, 2019
|  |  |  |  |  |  |  |  |  |  |  |  |  |  | Consolidated
|  |  | Solid Fuel |  |  | Natural Gas |  |  | Hydroelectric |  |  | Corporate |  |  | Total
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 10.4 |  | $ | 9.0 |  | $ | 17.6 |  | $ | — |  | $ | 37.0
Energy capacity revenue |  |  | 9.3 |  |  | 20.9 |  |  | — |  |  | — |  |  | 30.2
Steam energy and capacity revenue |  |  | — |  |  | 0.6 |  |  | — |  |  | — |  |  | 0.6
Ancillary and transmission services |  |  | — |  |  | 4.3 |  |  | 0.8 |  |  | — |  |  | 5.1
Asset management and operation |  |  | 0.1 |  |  | (0.1) |  |  | — |  |  | 0.2 |  |  | 0.2
Miscellaneous revenue |  |  | — |  |  | (0.1) |  |  | — |  |  | — |  |  | (0.1)
|  |  | 19.8 |  |  | 34.6 |  |  | 18.4 |  |  | 0.2 |  |  | 73.0

Contract balances

Contract liabilities as of March 31, 2020 include a $0.1 million fuel reserve fund at Dorchester (Solid Fuel segment) and a $0.1 million steam sale credit at the San Diego plants (Natural Gas segment). Contract liabilities as of December 31, 2019 include a $0.2 million fuel reserve fund at Dorchester and a $0.1 million steam sale credit at the San Diego plants. We had no contract assets at March 31, 2020 and December 31, 2019.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

3. Changes in accumulated other comprehensive loss by component

The changes in accumulated other comprehensive (loss) income by component were as follows:

|  | Three Months Ended March 31,
|  | 2020 |  | 2019
Foreign currency translation |  |  |  |  |  |
Balance at beginning of period |  | $ | (140.6) |  | $ | (146.4)
Other comprehensive (loss) income: |  |  |  |  |  |
Foreign currency translation adjustments(1) |  |  | (11.2) |  |  | 2.2
Balance at end of period |  | $ | (151.8) |  | $ | (144.2)
Pension |  |  |  |  |  |
Balance at beginning and end of period (2) |  | $ | (1.7) |  | $ | (1.4)
Cash flow hedges |  |  |  |  |  |
Balance at beginning of period |  | $ | 1.6 |  | $ | 1.6
Other comprehensive (loss) income: |  |  |  |  |  |
Net change from periodic revaluations |  |  | (0.6) |  |  | (0.2)
Tax benefit |  |  | 0.2 |  |  | —
Total other comprehensive (loss) income before reclassifications, net of tax |  |  | (0.4) |  |  | (0.2)
Net amount reclassified to earnings: |  |  |  |  |  |
Interest rate swaps(3) |  |  | 0.1 |  |  | 0.1
Tax expense |  |  | — |  |  | —
Total amount reclassified from accumulated other comprehensive loss, net of tax |  |  | 0.1 |  |  | 0.1
Total other comprehensive loss |  |  | (0.3) |  |  | (0.1)
Balance at end of period |  | $ | 1.3 |  | $ | 1.5

| (1) |  | In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings.

| (2) |  | Quarterly activity was immaterial.

| (3) |  | This amount was included in interest expense, net on the accompanying consolidated statements of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

| (4) |  |

4. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three months ended March 31, 2020 and 2019, respectively, for our proportional ownership interest in equity method investments:

|  | Three Months Ended March 31,
Operating results |  | 2020 |  | 2019
Revenue |  |  |  |  |  |
Frederickson |  | $ | 8.0 |  | $ | 5.8
Orlando Cogen, LP |  |  | 14.6 |  |  | 15.5
Chambers Cogen, LP |  |  | 10.6 |  |  | 11.5
Craven County Wood Energy, LP (1) |  |  | 3.1 |  |  | —
Grayling Generating Station, LP (1) |  |  | 1.5 |  |  | —
|  |  | 37.8 |  |  | 32.8
Project expenses |  |  |  |  |  |
Frederickson |  |  | 5.4 |  |  | 3.4
Orlando Cogen, LP |  |  | 6.3 |  |  | 7.5
Chambers Cogen, LP |  |  | 8.1 |  |  | 8.6
Craven County Wood Energy, LP (1) |  |  | 2.6 |  |  | —
Grayling Generating Station, LP (1) |  |  | 1.4 |  |  | —
|  |  | 23.8 |  |  | 19.5
Project other expenses |  |  |  |  |  |
Frederickson |  |  | — |  |  | —
Orlando Cogen, LP |  |  | — |  |  | —
Chambers Cogen, LP |  |  | (0.3) |  |  | (0.4)
Craven County Wood Energy, LP (1) |  |  | — |  |  | —
Grayling Generating Station, LP (1) |  |  | — |  |  | —
|  |  | (0.3) |  |  | (0.4)
Net income |  |  |  |  |  |
Frederickson |  |  | 2.6 |  |  | 2.4
Orlando Cogen, LP |  |  | 8.3 |  |  | 8.0
Chambers Cogen, LP |  |  | 2.2 |  |  | 2.5
Craven County Wood Energy, LP (1) |  |  | 0.5 |  |  | —
Grayling Generating Station, LP (1) |  |  | 0.1 |  |  | —
Equity in earnings of unconsolidated affiliates |  | $ | 13.7 |  | $ | 12.9
Distributions from equity method investments |  |  | (6.0) |  |  | (5.8)
Surplus of earnings of equity method investments, net of distributions |  | $ | 7.7 |  | $ | 7.1

| (1) |  | We acquired our equity interests in Craven Country Wood Energy, LP and Grayling Generating Station, LP on August 13, 2019.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

5. Long‑term debt

Long‑term debt consists of the following:

|  | March 31, |  | December 31, |  |  |  |  |
|  | 2020 |  | 2019 |  | Interest Rate |
Recourse Debt: |  |  |  |  |  |  |  |  |  |  |
Senior secured term loan facility, due 2025(1) |  | $ | 360.0 |  | $ | 380.0 |  | LIBOR(2) | plus | 2.50 | %
Senior unsecured notes, due June 2036 (Cdn$210.0) |  |  | 148.0 |  |  | 161.7 |  |  |  | 5.95 | %
Non-Recourse Debt: |  |  |  |  |  |  |  |  |  |  |
Cadillac term loan, due 2025 (3)(4) |  |  | 17.2 |  |  | 18.7 |  | LIBOR | plus | 1.61 | %
Less: unamortized discount |  |  | (5.2) |  |  | (5.8) |  |  |  |  |
Less: unamortized deferred financing costs |  |  | (5.2) |  |  | (4.7) |  |  |  |  |
Less: current maturities |  |  | (78.5) |  |  | (76.4) |  |  |  |  |
Total long-term debt |  | $ | 436.3 |  | $ | 473.5 |  |  |  |  |

Current maturities consist of the following:

|  | March 31, |  | December 31, |  |  |  |  |
|  | 2020 |  | 2019 |  | Interest Rate |
Current Maturities: |  |  |  |  |  |  |  |  |  |  |
Senior secured term loan facility, due 2025(1) |  | $ | 75.5 |  | $ | 72.5 |  | LIBOR(2) | plus | 2.50 | %
Cadillac term loan, due 2025 (3) |  |  | 3.0 |  |  | 3.9 |  | LIBOR | plus | 1.61 | %
Total current maturities |  | $ | 78.5 |  | $ | 76.4 |  |  |  |  |

| (1) |  | On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the term loan credit agreement. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of senior secured term loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule.

| (2) |  | London Interbank Offered Rate (“LIBOR”) cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR of the $360.0 million outstanding aggregate borrowings under our senior secured term loan facility at March 31, 2020. See Note 7, Accounting for derivative instruments and hedging activities for further details.

| (3) |  | We have entered into interest rate swap agreements to economically fix our exposure to changes in interest rates for this non-recourse debt. See Note 7, Accounting for derivative instruments and hedging activities, for further details.

| (4) |  | The Cadillac term loan credit agreement (the “Cadillac Term Loan”) contains various affirmative and negative covenants, including, among other things, the operation of the Cadillac plant, compliance with laws, incurrence of additional debt and restricted payments (as defined in the Cadillac Term Loan). One of the negative covenants requires the Cadillac project to meet certain key financial ratios, including a debt service coverage ratio (as defined in the Cadillac Term Loan). As of March 31, 2020, we determined that the Cadillac project did not fulfill the debt service coverage ratio as required by the Cadillac Term Loan. Due to the breach of the covenant clause, the Cadillac project is prevented from making restricted payments (as defined in the Cadillac Term Loan) until several conditions are met, including, among other things, (i) the debt service coverage ratio for the most-recently ended period of four consecutive fiscal quarters is at least 1.2 to 1.0 and (ii) the projected debt service coverage ratio for the four consecutive fiscal quarters immediately following the period described in (i) is at least 1.2 to 1.0. We have not made any restricted payments (as defined in the Cadillac Term Loan) since July 31, 2019.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

Term Loan Amendment and Repricing

In January 2020, Atlantic Power Limited Partnership Holdings (“APLP Holdings”) completed the repricing of the $380 million Term Loan and revolving credit facility (“Revolver”). As a result of the repricing, the interest rate margin on the Term Loan and the Revolver was reduced by 0.25% to LIBOR plus 2.50% with no change to the 1.00% LIBOR floor. An additional 0.25% step down in the interest rate margin will become effective in the event the Leverage Ratio (as defined in the Credit Agreement) is 2.75:1.00 or lower. Additionally, APLP Holdings amended its existing Term Loan to extend the maturity date by two years to April 2025. The repricing also adds customary new provisions relating to the replacement of LIBOR as the benchmark for the Eurodollar Rate (as defined in the Credit Agreement). Targeted debt balances were adjusted to reflect the previously announced anticipated closing of the sale of our Manchief power plant in 2022, resulting in lower targeted debt repayment in 2020 and higher targeted debt repayment in 2022 as compared to the previous schedule. We recorded $0.6 million of new deferred financing costs associated with the amendment, which will be amortized over the remaining terms of the Term Loan and Revolver. Additionally, we wrote off $0.5 million of existing deferred financing costs to interest expense in the three months ended March 31, 2020.

Extension of Revolving Credit Facility

On March 18, 2020, we executed an amendment to our senior secured revolving credit facility. The amendment provides for an extension of the Revolver maturity date to April 2025, to coincide with the maturity date of the senior Term Loan. Both the Revolver and the Term Loan are at our APLP Holdings subsidiary. At March 31, 2020, we had no borrowings under the Revolver and utilized $78.1 million of borrowing capacity for letters of credit.

In conjunction with the extension, the Revolver capacity was reduced to $180 million from $200 million previously. The amendment allows an upsizing of the Revolver capacity by up to $30 million, to a maximum aggregate amount of $210 million, subject to approval of the two letter of credit issuer banks and increased commitments by existing or new lenders. Such an upsizing would not require a further amendment. There were no other significant changes to the terms of the Revolver. As a result of the extension, we recorded $0.9 million of new deferred financing costs, which will be amortized over the remaining term of the Revolver.

6. Fair value of financial instruments

The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of March 31, 2020 and December 31, 2019. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

|  | March 31, 2020 |
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 47.8 |  | $ | — |  | $ | — |  | $ | 47.8 |
Restricted cash |  |  | 0.5 |  |  | — |  |  | — |  |  | 0.5 |
Derivative instruments asset |  |  | — |  |  | — |  |  | — |  |  | — |
Total |  | $ | 48.3 |  | $ | — |  | $ | — |  | $ | 48.3 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative instruments liability |  | $ | — |  | $ | 28.9 |  | $ | 5.6 |  | $ | 34.5 |
Total |  | $ | — |  | $ | 28.9 |  | $ | 5.6 |  | $ | 34.5 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

|  | December 31, 2019 |
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 74.9 |  | $ | — |  | $ | — |  | $ | 74.9 |
Restricted cash |  |  | 7.7 |  |  | — |  |  | — |  |  | 7.7 |
Derivative instruments asset |  |  | — |  |  | 0.7 |  |  | — |  |  | 0.7 |
Total |  | $ | 82.6 |  | $ | 0.7 |  | $ | — |  | $ | 83.3 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative instruments liability |  | $ | — |  | $ | 24.7 |  | $ | 3.2 |  | $ | 27.9 |
Total |  | $ | — |  | $ | 24.7 |  | $ | 3.2 |  | $ | 27.9 |

The fair values of our interest rate swaps, foreign exchange forward contracts, natural gas swaps and gas purchase agreements are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk-free interest rate.

We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of March 31, 2020, the credit valuation adjustments resulted in a $1.0 million net increase in fair value, which consists of a $0.1 million pre‑tax gain in other comprehensive income and a $0.9 million gain in change in fair value of derivative instruments. As of December 31, 2019, the credit valuation adjustments resulted in a $1.1 million net increase in fair value, which consists of a $0.1 million pre‑tax gain in other comprehensive income and a $1.0 million gain in change in fair value of derivative instruments.

The conversion option derivative for the Series E Debentures is classified within Level 3 of the fair value hierarchy. The significant unobservable inputs used in developing fair value include the volatility of our common shares and the fair value of the host contract, which is derived from recent similar convertible debenture offerings from peer companies. A discounted cash flow valuation technique is utilized to calculate the fair value of the conversion option derivative.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

The following table reconciles, for the three months ended March 31, 2020 and 2019, the beginning and ending balances for the conversion option derivative that is recognized at fair value in the consolidated financial statements, using significant unobservable inputs:

|  | Fair value Measurement Using Significant Unobservable Inputs (Level 3)
|  | Three Months Ended
|  | March 31, 2020
Beginning balance of liability at January 1, 2020 |  | $ | 3.2
Total unrealized loss |  |  | 2.6
Currency transaction gain |  |  | (0.2)
Ending balance of liability at March 31, 2020 |  | $ | 5.6

|  | Fair value Measurement Using Significant Unobservable Inputs (Level 3)
|  | Three Months Ended
|  | March 31, 2019
Beginning balance of liability at January 1, 2019 |  | $ | 1.2
Total unrealized loss |  |  | 4.7
Currency transaction loss |  |  | 0.1
Ending balance of liability at March 31, 2019 |  | $ | 6.0

For cash and cash equivalents, accounts and other receivables, accounts payable and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments and is classified as Level 1 within the fair value hierarchy.

7. Accounting for derivative instruments and hedging activities

We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.

Gas purchase and sale agreements

We have a gas purchase agreement at our Nipigon project that expires on December 31, 2022 under which we purchase a minimum of 6,500 Gigajoules (“Gj”) of natural gas per day at a price of Cdn$4.57 per Gj. This agreement does not qualify for the normal purchase normal sales (“NPNS”) exemption and is accounted for as a derivative financial instrument because we could not conclude that it is probable that this contract will not settle net and will result in physical delivery. This derivative financial instrument is recorded in the condensed consolidated balance sheets at fair value and the changes in its fair market value are recorded in the condensed consolidated statements of operations. We

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

also have a corresponding gas sales agreement at Nipigon, whereby 6,500 Gj of natural gas per day is sold at the spot market price. This contract is not accounted for as a derivative.

Natural gas swaps

Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the condensed consolidated balance sheets at fair value and the changes in their fair market value are recorded in the condensed consolidated statements of operations.

We have entered into various natural gas swaps to effectively fix the price of 15.4 million Mmbtu of future natural gas purchases at our Orlando project, which is approximately 100% of our share of the expected natural gas purchases in 2020 through 2023. These contracts are accounted for as derivative financial instruments and are recorded in the condensed consolidated balance sheet at fair value at March 31, 2020. Changes in the fair market value of these contracts are recorded in the condensed consolidated statement of operations.

Interest rate swaps

APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in interest at the Adjusted Eurodollar Rate. At March 31, 2020, these agreements totaled $3 29.4 million notional amount of the remaining $360 million aggregate principal amount of borrowings under the senior secured term loan facility (“Term Loan Facility”). These interest rate swap agreements expire at various dates through March 31, 2022. Borrowings under the $700.0 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 2.50%. Based on the terms of the Term Loan Facility, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 3.50% all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount. The weighted average rate of these swap agreements is 2.03%, resulting in an all-in rate of approximately 4.53% for $360.0 million of the Term Loan Facility. In February 2020, APLP Holdings entered into additional interest rate swap agreements. For the period beginning March 31, 2020 through December 31, 2021, we mitigated exposure to changes in interest rates a one-month LIBOR fixed rate of 1.39%. The notional amount of these interest rate swap agreements range between $3.1 million and $100.0 million and are sized to the targeted debt balance payments over that period.

The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.3% through February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of the Cadillac Term Loan. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).

Foreign currency forward contracts

We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our Medium Term Notes due June 23, 2036 (“MTNs”). Principal and interest payments for our senior secured term loans are made in U.S. dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the future interest and principal payments, preferred dividends and other working capital requirements. Foreign currency forward contracts are not designated as hedges, and changes in their market value are recorded in foreign exchange on the condensed consolidated statements of operations. As of March 31, 2020, we have no foreign currency forward contracts.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

Volume of forecasted transactions

We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for NPNS exemption at March 31, 2020 and December 31, 2019:

|  |  |  | March 31, |  | December 31, |
|  | Units |  | 2020 |  | 2019 |
Natural gas swaps |  | Natural Gas (MMbtu) |  | 15.4 |  | 16.3 |
Gas purchase agreements |  | Natural Gas (Gigajoules) |  | 6.5 |  | 6.4 |
Interest rate swaps |  | Interest (US$) |  | 346.6 |  | 468.4 |

Fair value of derivative instruments

We disclose derivative instrument assets and liabilities on a trade‑by‑trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:

|  | March 31, 2020 |
|  | Derivative |  | Derivative |
|  | Assets |  | Liabilities |
Derivative instruments designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  | $ | — |  | $ | 0.6 |
Interest rate swaps long-term |  |  | — |  |  | 1.3 |
Total derivative instruments designated as cash flow hedges |  |  | — |  |  | 1.9 |
Derivative instruments not designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  |  | — |  |  | 5.2 |
Interest rate swaps long-term |  |  | — |  |  | 3.9 |
Natural gas swaps current |  |  | — |  |  | 2.4 |
Natural gas swaps long-term |  |  | — |  |  | 4.2 |
Gas purchase agreements current |  |  | — |  |  | 4.2 |
Gas purchase agreements long-term |  |  | — |  |  | 7.1 |
Convertible debenture conversion option |  |  | — |  |  | 5.6 |
Total derivative instruments not designated as cash flow hedges |  |  | — |  |  | 32.6 |
Total derivative instruments |  | $ | — |  | $ | 34.5 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

|  | December 31, 2019 |
|  | Derivative |  | Derivative |
|  | Assets |  | Liabilities |
Derivative instruments designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  | $ | — |  | $ | 0.4 |
Interest rate swaps long-term |  |  | — |  |  | 1.1 |
Total derivative instruments designated as cash flow hedges |  |  | — |  |  | 1.5 |
Derivative instruments not designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  |  |  |  |  | 1.9 |
Interest rate swaps long-term |  |  | — |  |  | 1.1 |
Natural gas swaps current |  |  | — |  |  | 1.9 |
Natural gas swaps long-term |  |  | — |  |  | 4.2 |
Gas purchase agreements current |  |  | 0.7 |  |  | 4.6 |
Gas purchase agreements long-term |  |  | — |  |  | 9.5 |
Convertible debenture conversion option |  |  | — |  |  | 3.2 |
Total derivative instruments not designated as cash flow hedges |  |  | 0.7 |  |  | 26.4 |
Total derivative instruments |  | $ | 0.7 |  | $ | 27.9 |

Accumulated other comprehensive income

The following table summarizes the changes in the accumulated other comprehensive income (loss) (“OCI”) balance attributable to derivative financial instruments designated as a hedge, net of tax:

|  | Interest Rate
Three Months Ended March 31, 2020 |  | Swaps
Accumulated OCI balance at January 1, 2020 |  | $ | 1.6
Change in fair value of cash flow hedges |  |  | (0.4)
Realized from OCI during the period |  |  | 0.1
Accumulated OCI balance at March 31, 2020 |  | $ | 1.3
|  | Interest Rate
Three Months Ended March 31, 2019 |  | Swaps
Accumulated OCI balance at January 1, 2019 |  | $ | 1.6
Change in fair value of cash flow hedges |  |  | (0.2)
Realized from OCI during the period |  |  | 0.1
Accumulated OCI balance at March 31, 2019 |  | $ | 1.5

Impact of derivative instruments on the consolidated statements of operations

The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges:

|  | Classification of loss (gain) |  | Three Months Ended March 31,
|  | recognized in income |  | 2020 |  | 2019
Gas purchase agreements |  | Fuel |  | $ | 2.2 |  | $ | 2.0
Natural gas swaps |  | Fuel |  |  | 0.7 |  |  | (0.3)
Interest rate swaps |  | Interest, net |  |  | 0.3 |  |  | (1.3)

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

The following table summarizes the unrealized (loss) gain resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

|  | Classification of (loss) gain |  |  | Three Months Ended March 31, |  |
|  | recognized in income |  |  | 2020 |  | 2019 |  |
Natural gas swaps |  | Change in fair value of derivatives |  |  | $ | (0.5) |  | $ | 0.2 |  |
Gas purchase agreements |  | Change in fair value of derivatives |  |  |  | 1.0 |  |  | (0.4) |  |
Interest rate swaps |  | Change in fair value of derivatives |  |  |  | (6.1) |  |  | (2.2) |  |
|  |  |  |  |  | (5.6) |  |  | (2.4) |  |
Convertible debenture conversion option |  | Other expense (income), net |  |  | $ | 2.6 |  |  | 4.7 |  |

X

8. Income taxes

The following table summarizes the current and deferred portions of the net income tax expense:

|  | Three Months Ended March 31, |  |
|  | 2020 |  | 2019 |  |
Current income tax expense |  | $ | 1.2 |  | $ | 1.3 |  |
Deferred income tax expense (benefit) |  |  | 0.3 |  |  | (0.7) |  |
Total income tax expense, net |  | $ | 1.5 |  | $ | 0.6 |  |

For the three months ended March 31, 2020 and 2019

Income tax expense for the three months ended March 31, 2020 was $1.5 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $6.8 million. The primary item impacting the tax rate for the three months ended March 31, 2020 was a net decrease to our valuation allowances of $8.7 million, consisting of $5.9 million decreases in Canada and $2.8 million decreases in the United States due to the utilization of net operating losses. These items were partially offset by $2.0 million relating to foreign exchange and $1.4 million of other permanent differences.

Income tax expense for the three months ended March 31, 2019 was $0.6 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $0.8 million. The primary item impacting the tax rate for the three months ended March 31, 2019 was a net decrease to our valuation allowances of $1.6 million, consisting of $1.7 million increase in Canada and $3.3 million decreases in the United States due to income. These items were partially offset by $0.7 million relating to foreign exchange, $0.4 million relating to withholding state taxes and $0.3 million of other permanent differences.

As of March 31, 2020, we have recorded a valuation allowance of $136.7 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected timing on the reversal of deferred tax liabilities and future taxable income in the United States and in Canada and available tax planning strategies.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

9. Equity compensation plans

Long‑term incentive plan (“LTIP”)

The following table summarizes the changes in outstanding LTIP notional shares during the three months ended March 31, 2020:

|  |  |  |  |  |  | Grant Date |
|  |  |  |  |  |  | Weighted-Average |
|  | Notional Shares |  |  |  |  | Fair Value per Notional Share |
Outstanding at December 31, 2019 |  | 3,578,092 |  |  |  | $ | 2.38 |
Granted |  | 1,866,748 |  |  |  |  | 2.49 |
Vested and redeemed |  | (1,702,571) |  |  |  |  | 2.34 |
Forfeitures |  | (23,388) |  |  |  |  | 2.40 |
Outstanding at March 31, 2020 |  | 3,718,881 |  |  |  | $ | 2.45 |

Cash payments made for vested notional shares for the three months ended March 31, 2020 were $3.3 million and no payments were made in the comparable 2019 period. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.0 million for the three months ended March 31, 2020 and $1.4 million for the three months ended March 31, 2019.

Transition Equity Participation Agreement

We also have 269,952 transition notional shares outstanding at March 31, 2020 under the Transition Equity Participation Agreement with James J. Moore, Jr. These notional shares will vest if the weighted average Canadian dollar closing price of our common shares on the Toronto Stock Exchange exceeds Cdn$4.77 for at least three consecutive calendar months.

10. Basic and diluted earnings per share

Basic earnings per share is calculated by dividing net income attributable to Atlantic Power Corporation by weighted average common shares outstanding during their respective periods. Shares issued and shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of our Series E Debentures is calculated using the “if-converted method.” Under the if-converted method, the Series E Debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted earnings per share calculation for the entire period being presented. Interest expense, net of any income tax effects, would be added back to the numerator for purposes of the if-converted calculation. The outstanding equity compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator, when dilutive, for purposes of computing diluted earnings per share under the treasury stock method.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

The following table sets forth the calculation of basic and diluted earnings per share for the three months ended March 31, 2020 and 2019:

Basic |  | 2020 |  | 2019
Numerator: |  |  |  |  |  |
Income attributable to Atlantic Power Corporation |  | $ | 29.5 |  | $ | 8.9
Denominator: |  |  |  |  |  |
Weighted average basic shares outstanding |  |  | 107.2 |  |  | 108.9
Basic earnings per share attributable to Atlantic Power Corporation |  | $ | 0.28 |  | $ | 0.08
Diluted |  |  |  |  |  |
Numerator: |  |  |  |  |  |
Net income attributable to Atlantic Power Corporation |  | $ | 29.5 |  | $ | 8.9
Add: convertible debenture interest expense |  |  | 0.9 |  |  | 1.3
|  |  | 30.4 |  |  | 10.2
Denominator: |  |  |  |  |  |
Weighted average basic shares outstanding |  |  | 107.2 |  |  | 108.9
Convertible debentures |  |  | 27.4 |  |  | 29.1
Share-based compensation |  |  | 0.2 |  |  | 0.6
|  |  | 134.8 |  |  | 138.6
Diluted earnings per share attributable to Atlantic Power Corporation |  | $ | 0.23 |  | $ | 0.07

11. Equity

The following tables provide reconciliations of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company and total equity for the three months ended March 31, 2020 and 2019:

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

|  |  |  |  |  |  |  | Accumulated |  | Preferred |  |  |  |
|  |  |  |  |  |  | Other |  | Shares of a |  | Total |
|  | Common |  | Retained |  | Comprehensive |  | Subsidiary |  | Shareholders’ |
|  | Shares |  | Deficit |  | (loss) income |  | Company |  | Equity |
Balance at January 1, 2020 |  | $ | 1,259.9 |  | $ | (1,164.2) |  | $ | (140.7) |  | $ | 182.7 |  | $ | 137.7 |
Net income (loss) |  |  | — |  |  | 29.5 |  |  | — |  |  | (5.8) |  |  | 23.7 |
Share-based compensation |  |  | 0.4 |  |  | — |  |  | — |  |  | — |  |  | 0.4 |
Common share repurchases |  |  | (8.2) |  |  | — |  |  | — |  |  | — |  |  | (8.2) |
Preferred share repurchases |  |  | — |  |  | — |  |  | — |  |  | (6.4) |  |  | (6.4) |
Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.8) |  |  | (0.8) |
Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.358688 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.6) |  |  | (0.6) |
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.363342 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.3) |  |  | (0.3) |
Realized and unrealized loss on hedging activities, net of tax |  |  | — |  |  | — |  |  | (0.3) |  |  | — |  |  | (0.3) |
Foreign currency translation adjustments |  |  | — |  |  | — |  |  | (11.2) |  |  | — |  |  | (11.2) |
Balance at March 31, 2020 |  | $ | 1,252.1 |  | $ | (1,134.7) |  | $ | (152.2) |  | $ | 168.8 |  | $ | 134.0 |

|  |  |  |  |  |  |  | Accumulated |  | Preferred |  |  |  |
|  |  |  |  |  |  | Other |  | Shares of a |  | Total |
|  | Common |  | Retained |  | Comprehensive |  | Subsidiary |  | Shareholders’ |
|  | Shares |  | Deficit |  | (loss) income |  | Company |  | Equity |
Balance at January 1, 2019 |  | $ | 1,260.9 |  | $ | (1,121.6) |  | $ | (146.2) |  | $ | 199.3 |  | $ | 192.4 |
Net income (loss) |  |  | — |  |  | 8.9 |  |  | — |  |  | (6.5) |  |  | 2.4 |
Share-based compensation |  |  | 0.6 |  |  | — |  |  | — |  |  | — |  |  | 0.6 |
Common share repurchases |  |  | (0.1) |  |  | — |  |  | — |  |  | — |  |  | (0.1) |
Preferred share repurchases |  |  | — |  |  | — |  |  | — |  |  | (7.7) |  |  | (7.7) |
Dividends on preferred shares of a subsidiary company - Series 1 (Cdn$0.303125 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.9) |  |  | (0.9) |
Dividends on preferred shares of a subsidiary company - Series 2 (Cdn$0.348125 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.6) |  |  | (0.6) |
Dividends on preferred shares of a subsidiary company - Series 3 (Cdn$0.362893 per share) |  |  | — |  |  | — |  |  | — |  |  | (0.4) |  |  | (0.4) |
Realized and unrealized gain on hedging activities, net of tax |  |  | — |  |  | — |  |  | (0.1) |  |  | — |  |  | (0.1) |
Foreign currency translation adjustments |  |  | — |  |  | — |  |  | 2.2 |  |  | — |  |  | 2.2 |
Balance at March 31, 2019 |  | $ | 1,261.4 |  | $ | (1,112.7) |  | $ | (144.1) |  | $ | 183.2 |  | $ | 187.8 |

Share Repurchase Programs

Normal Course Issuer Bid

On December 31, 2019, we commenced a new Normal Course Issuer Bid (“NCIB”) for our Series E Debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd. (“APPEL”), our wholly-owned subsidiary. The NCIBs expire on December 30, 2020 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the new NCIBs. Under the NCIB, we may purchase up to a total of 10,578,799 common shares based on 10% of our public float as of December 17, 2019 and we are limited to daily purchases of 9,243 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. We may also purchase up to Cdn$11.5 million of Series E Debentures; 384,750 shares of 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”); 223,072 shares of 7.0% Cumulative Rate Preferred Shares Series 2 (the “Series 2 Shares”); and 133,031 shares of Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of APPEL.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

All purchases made under the NCIBs will be made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the New York Stock Exchange (“NYSE”) in compliance with Rule 10b-18 under the Exchange Act, as amended, or other designated exchanges and published marketplaces in the United States in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval.

The NCIB permits the Company to repurchase common and preferred shares and Series E Debentures. In addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our Series E Debentures and our APPEL preferred shares through open market purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs, issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account our then current cash position and then anticipated cash obligations or business opportunities. Beginning on March 25, 2020, we commenced a Substantial Issuer Bid (“SIB”) described below that expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL

In the three months ended March 31, 2020, we repurchased and cancelled 3,760,335 common shares under the NCIB at a total cost of $8.2 million.

In the three months ended March 31, 2020, we also repurchased and cancelled 381,794 Series 1 Shares, 62,365 Series 2 Shares and 120,000 Series 3 Shares of APPEL at a total cost of $6.4 million. As a result of the repurchase, a $7.4 million loss was attributed to the preferred shares of a subsi diary company in the consolidated statements of operations for the three months ended March 31, 2020.

Substantial Issuer Bid

On March 25, 2020, we commenced a SIB for the purchase of up to $25 million common shares. This was equivalent to 12,820,512 common shares, or approximately 12% of our total issued and outstanding common shares based on a $1.95 per share purchase price (the minimum price per common share under the offer) as measured on the date of commencement. The SIB expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL.

The SIB proceeded by way of a “modified Dutch auction”. Holders of common shares were able to tender to the offer by: (i) auction tenders in which they specified the number of common shares being tendered at a price of not less than US$1.95 and not more than US$2.20 per common share in increments of US$0.05 per common share, or (ii) purchase price tenders in which they did not specify a price per Common Share, but rather agreed to have a specified number of common shares purchased at the purchase price determined by auction tenders.

The purchase price paid by the Company for each validly deposited common share was based on the number of common shares validly deposited pursuant to auction tenders and purchase price tenders, and the prices specified by shareholders making auction tenders. The purchase price was the lowest price which enabled the Company to purchase common shares up to the maximum amount available for auction tenders and purchase price tenders, determined in accordance with the terms of the offer. Common shares that were deposited at or below the final determined purchase price were purchased at such purchase price. Common shares that were not taken up in connection with the offer, including common shares deposited pursuant to auction tenders at prices above the purchase price, were returned to the shareholders.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

We repurchased and cancelled 12,500,00 common shares under the SIB at a total cost of $25 million upon its expiration on April 30, 2020. All common shares repurchased and cancelled under the SIB occurred subsequent to March 31, 2020. A fter giving effect to the cancellation of the common shares purchased under the SIB, 93,002,338 common shares were issued and outstanding at May 6, 2020.

12. Segment and geographic information

We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management’s structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for the comparative 2019 period has been revised to conform to the new segment presentation. We analyze the performance of our operating segments based on Project Adjusted EBITDA, which is defined as project income (loss) plus interest, taxes, depreciation and amortization, impairment charges, insurance loss (gain), other (income) expenses and changes in fair value of derivative instruments. 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. We use Project Adjusted EBITDA to provide comparative information about segment performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented as proportionately consolidated based on our ownership percentage in the reconciliation of Project Adjusted EBITDA to project income.

A reconciliation of Project Adjusted EBITDA to net income for the three months ended March 31, 2020 and 2019 is included in the tables below:

|  | Solid Fuel |  | Natural Gas |  | Hydroelectric |  | Corporate |  | Consolidated |
Three Months Ended March 31, 2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 23.4 |  | $ | 30.8 |  | $ | 18.4 |  | $ | 0.2 |  | $ | 72.8 |
Segment assets |  |  | 225.0 |  |  | 230.6 |  |  | 359.5 |  |  | 66.9 |  |  | 882.0 |
Project Adjusted EBITDA |  | $ | 7.8 |  | $ | 28.2 |  | $ | 15.3 |  | $ | (0.5) |  | $ | 50.8 |
Change in fair value of derivative instruments |  |  | — |  |  | (0.5) |  |  | — |  |  | 6.1 |  |  | 5.6 |
Depreciation and amortization |  |  | 5.6 |  |  | 9.2 |  |  | 4.9 |  |  | 0.1 |  |  | 19.8 |
Interest, net |  |  | 0.7 |  |  | — |  |  | — |  |  | — |  |  | 0.7 |
Other project expense |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Project income (loss) |  |  | 1.5 |  |  | 19.5 |  |  | 10.4 |  |  | (6.7) |  |  | 24.7 |
Administration |  |  | — |  |  | — |  |  | — |  |  | 6.7 |  |  | 6.7 |
Interest expense, net |  |  | — |  |  | — |  |  | — |  |  | 10.8 |  |  | 10.8 |
Foreign exchange gain |  |  | — |  |  | — |  |  | — |  |  | (20.6) |  |  | (20.6) |
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | 2.6 |  |  | 2.6 |
Net income (loss) before income taxes |  |  | 1.5 |  |  | 19.5 |  |  | 10.4 |  |  | (6.2) |  |  | 25.2 |
Income tax expense |  |  | — |  |  | — |  |  | — |  |  | 1.5 |  |  | 1.5 |
Net income (loss) |  | $ | 1.5 |  | $ | 19.5 |  | $ | 10.4 |  | $ | (7.7) |  | $ | 23.7 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

|  | Solid Fuel |  | Natural Gas |  | Hydroelectric |  | Corporate |  | Consolidated |
Three Months Ended March 31, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 19.8 |  | $ | 34.6 |  | $ | 18.4 |  | $ | 0.2 |  | $ | 73.0 |
Segment assets |  |  | 267.7 |  |  | 275.9 |  |  | 384.0 |  |  | 99.4 |  |  | 1,027.0 |
Project Adjusted EBITDA |  | $ | 10.1 |  | $ | 28.1 |  | $ | 15.6 |  | $ | (0.1) |  | $ | 53.7 |
Change in fair value of derivative instruments |  |  | — |  |  | 0.6 |  |  | — |  |  | 1.8 |  |  | 2.4 |
Depreciation and amortization |  |  | 5.9 |  |  | 9.3 |  |  | 4.9 |  |  | 0.1 |  |  | 20.2 |
Interest, net |  |  | 0.7 |  |  | — |  |  | — |  |  | — |  |  | 0.7 |
Other project income |  |  | — |  |  | (0.2) |  |  | — |  |  | — |  |  | (0.2) |
Project income (loss) |  |  | 3.5 |  |  | 18.4 |  |  | 10.7 |  |  | (2.0) |  |  | 30.6 |
Administration |  |  | — |  |  | — |  |  | — |  |  | 6.8 |  |  | 6.8 |
Interest expense, net |  |  | — |  |  | — |  |  | — |  |  | 11.1 |  |  | 11.1 |
Foreign exchange loss |  |  | — |  |  | — |  |  | — |  |  | 5.0 |  |  | 5.0 |
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | 4.7 |  |  | 4.7 |
Net income (loss) before income taxes |  |  | 3.5 |  |  | 18.4 |  |  | 10.7 |  |  | (29.6) |  |  | 3.0 |
Income tax expense |  |  | — |  |  | — |  |  | — |  |  | 0.6 |  |  | 0.6 |
Net income (loss) |  | $ | 3.5 |  | $ | 18.4 |  | $ | 10.7 |  | $ | (30.2) |  | $ | 2.4 |

The tables below provide information, by country, about our consolidated operations for each of the three months ended March 31, 2020 and 2019 and Property, Plant & Equipment, PPAs and other Intangible and total assets as of March 31, 2020 and December 31, 2019, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.

|  | Project revenue
|  | Three Months Ended
|  | March 31,
|  | 2020 |  | 2019
United States |  | $ | 48.2 |  | $ | 52.1
Canada |  |  | 24.6 |  |  | 20.9
Total |  | $ | 72.8 |  | $ | 73.0

|  | Property, Plant and |  | PPAs and |  |
|  | Equipment, net of |  | other intangible assets, net of |  |
|  | accumulated depreciation |  | accumulated amortization |  | Total assets
|  | March 31, 2020 |  | December 31, 2019 |  | March 31, 2020 |  | December 31, 2019 |  | March 31, 2020 |  | December 31, 2019
United States |  | $ | 357.1 |  | $ | 353.9 |  | $ | 136.3 |  | $ | 142.8 |  | $ | 715.9 |  | $ | 762.3
Canada |  |  | 133.4 |  |  | 148.2 |  |  | 1.2 |  |  | 1.5 |  |  | 166.1 |  |  | 173.3
Total |  | $ | 490.5 |  | $ | 502.1 |  | $ | 137.5 |  | $ | 144.3 |  | $ | 882.0 |  | $ | 935.6

Concentration risk

Niagara Mohawk, Independent Electricity System Operator (“IESO”), BC Hydro and Equistar Chemicals, LP provided 20.9%, 14.7%, 13.5% and 10.3%, respectively, of total consolidated revenues for the three months ended March 31, 2020. Niagara Mohawk, IESO, BC Hydro and Equistar Chemicals, LP provided 20.1%, 15.2%, 12.7% and 12.5%, respectively, of total consolidated revenues for the three months ended March 31, 2019.

Niagara Mohawk purchases electricity from the Curtis Palmer project in the Hydroelectric segment, IESO purchases electricity from the Calstock, Tunis and Nipigon projects in the Solid Fuel and Natural Gas segments, Equistar Chemicals, LP purchases electricity from the Morris project in the Natural Gas segment, and BC Hydro purchases

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

electricity from the Mamquam and Moresby Lake projects in the Hydroelectric segment and Williams Lake project in the Solid Fuel segment.

13. Guarantees and Contingencies

Guarantees

We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

Contingencies

Fire at Cadillac project

On September 22, 2019, the Cadillac project experienced a malfunction in its steam turbine that began a cascade of events, sparking a fire. The fire was contained by the local fire department and did not result in any injuries or known environmental violations.

Physical Damage

The biomass plant suffered significant damage to the turbine, generator and other components in that area of the plant as a result of the fire. The boiler, cooling tower, fuel pile and fuel handling equipment were not affected. Cadillac is expected to be offline for an extended period. Our insurance covers the repair or replacement of the assets that experienced loss or damage. The property damage deductible under the policies insuring the Cadillac assets is $1.0 million. Losses have exceeded the deductible under these insurance policies.

Business Interruption

Our insurance policies also provide coverage for interruption to Cadillac’s business, including lost profits. The policies also reimburse for other expenses and costs it has incurred relating to the damages and loss it has suffered. The policies provide for coverage during the reconstruction period. At this time, we are unable to determine the Cadillac plant’s expected return to service date. The business interruption deductible under the policies insuring the Cadillac assets is 45 days of lost production, which we estimate had an approximate $1.4 million impact to cash flows from operations in the year ended December 31, 2019, the period when the deductible was fulfilled.

Impact

The fire resulted in a triggering event to test the Cadillac’s asset group for long-lived asset impairment. Based on our expectation of insurance recoveries and a full repair of the plant, we did not record an impairment at Cadillac because its estimated undiscounted future cash flows exceed the carrying value of the asset group at the date of the incident.

Because the plant experienced significant damage and it is probable that insurance proceeds will be received in order to repair the facility, we applied accounting for gains and losses on involuntary conversions. Based on loss estimates and expenses incurred through third quarter of 2019, we recorded a $25 million write-down of Cadillac’s property, plant and equipment and a $0.3 million write-down of capital spares inventory in the three months ended

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

September 30, 2019. This was our best estimate at the time the loss was incurred, but may be subject to future adjustments based on actual experience of replacement cost. We also recorded a corresponding insurance receivable ($24.2 million), a component of other current assets, less the $1.0 million property damage deductible, which was recorded as a charge to other project income, because we believe that it is probable we will receive insurance recoveries up to our estimated plant write-down. As the plant is repaired, any costs incurred will be capitalized to property, plant and equipment. During the three months ended December 31, 2019, we recorded an additional $0.6 million write-down of fuel inventory, with a corresponding increase to the insurance receivable. In the three months ended March 31, 2020, we recorded $9.7 million of capital additions related to repairs at Cadillac and cumulative additions of $14.8 million since the inception of repairs. Insurance proceeds in excess of the net book value of the property, plant and equipment write-down, if any, would be recorded as a gain in the period those proceeds are received.

During the year ended December 31, 2019, we received $11.3 million of insurance proceeds with respect to the fire at Cadillac, which were applied against the September 30, 2019 insurance receivable of $24.2 million. Additionally, in the three months ended March 31, 2020 we received $7.4 million of insurance proceeds bringing the total cumulative proceeds received to $18.6 million. As of March 31, 2020, the insurance receivable balance totals $6.1 million. Additionally, we estimated anticipated insurance recoveries related to business interruption losses of $2.0 million for the three months ended December 31, 2019 and $3.2 million for the three months ended March 31, 2020. Anticipated reimbursements for lost profits, or business interruption losses, are accounted for as a gain contingency because lost profits are not considered an incurred loss. Anticipated reimbursements for business interruption losses were not recorded as of March 31, 2020 as all contingencies related to these claims had not been resolved as of period end. We expect all contingencies related to business interruption losses to be resolved once final payment is received from the insurers, which is when we will recognize the reimbursements in earnings. The Cadillac biomass plant is a component of our Solid Fuel segment.

General

From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of March 31, 2020.

14. Leases

Real estate leases and equipment leases

We lease our office properties and equipment under operating leases expiring on various dates through 2024. Certain operating lease agreements include provisions for scheduled rent increases over their lease terms. We recognize the effects of these scheduled rent increases on a straight-line basis over the lease term. One of our leased office properties is sub-leased to third parties. The sub-lease is an operating lease and the rental income received is recorded net of rental expense in the condensed consolidated statements of operations.

On January 1, 2019, we implemented FASB ASU No. 2016-02, Leases (Topic 842). To calculate lease liabilities on the implementation date, we utilized an incremental borrowing rate of 3.75%, which was our minimum all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

The following table presents the components of lease expense.

|  | Three Months Ended March 31,
|  | 2020
Lease cost: (1) |  |  |
Operating lease cost |  | $ | 0.5
Sublease income |  |  | (0.3)
Total lease cost |  | $ | 0.2

| (1) |  | Short-term lease costs and finance lease costs are immaterial to the Company.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

The following table presents operating and finance lease maturities and a reconciliation of the undiscounted cash flows to operating lease liabilities.

|  | Lease |  | Income from |  | Net lease |
|  | Payments |  | subleasing |  | payments |
2020 |  | $ | 1.7 |  | $ | (0.8) |  | $ | 0.9 |
2021 |  |  | 1.9 |  |  | (1.1) |  |  | 0.8 |
2022 |  |  | 1.7 |  |  | (1.1) |  |  | 0.6 |
2023 |  |  | 1.2 |  |  | (0.7) |  |  | 0.5 |
2024 |  |  | 0.1 |  |  | — |  |  | 0.1 |
Thereafter |  |  | — |  |  | — |  |  | — |
Total operating lease payments |  | $ | 6.6 |  | $ | (3.7) |  | $ | 2.9 |
Less: present value discount |  |  | (0.3) |  |  |  |  |  |  |
Total operating lease liabilities |  | $ | 6.3 |  |  |  |  |  |  |
|  | Lease |  |  |  |  |  |  |
|  | Payments |  |  |  |  |  |  |
2020 |  | $ | 0.1 |  |  |  |  |  |  |
2021 |  |  | 0.1 |  |  |  |  |  |  |
2022 |  |  | 0.1 |  |  |  |  |  |  |
Thereafter |  |  | — |  |  |  |  |  |  |
Total finance lease payments |  | $ | 0.3 |  |  |  |  |  |  |
Less: amount representing interest |  |  | (0.1) |  |  |  |  |  |  |
Total finance lease liabilities |  | $ | 0.2 |  |  |  |  |  |  |
Other Information: |  |  |  |  |  |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities (1): |  |  |  |  |  |  |
Operating cash flows from operating leases |  | $ | 0.3 |  |  |  |  |  |  |
Weighted average remaining lease term (in years): |
Operating leases |  |  | 2.5 |  |  |  |  |  |  |
Finance leases |  |  | 1.4 |  |  |  |  |  |  |
Weighted average discount rate - operating leases |  |  | 3.91 | % |  |  |  |  |  |
Weighted average discount rate - finance leases |  |  | 4.08 | % |  |  |  |  |  |

(1) Cash flows from finance leases are immaterial to the Company

We have no lease transactions with related parties.

PPA Leases

We have entered into PPAs to sell power at predetermined rates. PPAs were assessed as to whether they contain leases, which convey to the counterparty the right to control the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either operating or finance leases. We recognize lease income consistent with the recognition of energy sales and capacity revenue. When energy is delivered and capacity is provided, we recognize lease income as a component of energy sales and capacity revenue. Finance income related to

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U.S. dollars, except per‑share amounts)

(Unaudited)

leases or arrangements accounted for as finance leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income (loss) over the lease term. We elected the practical expedient that permits us to retain our existing lease assessment and classification.

As of March 31, 2020, we have eleven PPAs accounted for as operating leases and one PPA accounted as a direct financing lease among our twenty-one projects in operation. No extension terms exist for our PPAs accounted for as leases and the remaining lease term varies from two months to twenty-four years. At March 31, 2020, a net investment in lease of $0.4 million is recorded in current assets on the consolidated balance sheets for our direct financing lease. The following table provides lease income recorded as energy and capacity sales by segment from PPAs accounted for as operating leases:

|  | Rental Income from operating leases |
|  | Three Months Ended |
|  | March 31, |
|  | 2020 |  | 2019 |
Solid Fuel |  | $ | 16.6 |  | $ | 19.7 |
Natural Gas |  |  | 5.9 |  |  | 6.3 |
Hydroelectric |  |  | 18.3 |  |  | 18.4 |
|  | $ | 40.8 |  | $ | 44.4 |

For certain of our PPAs accounted for as leases, the lessee has the option to purchase the plant. In May 2019, we entered into an agreement to sell Manchief to Public Service Company of Colorado (“PSCo”) following the expiration of the PPA in April 2022 for $45.2 million subject to working capital and other customary adjustments. BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.

15. Subsequent events

There are many uncertainties regarding the current coronavirus ("COVID-19") pandemic, and we are closely monitoring the impact of the pandemic on all aspects of our business, including how it will impact our customers, employees, suppliers, vendors and business partners. While the pandemic did not materially adversely affect our financial results and business operations in the three months ended March 31, 2020, we are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. We will continue to assess the evolving impact of the COVID-19 pandemic and intend to make adjustments accordingly.

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FORWARD‑LOOKING INFORMATION

Certain statements in this Quarterly Report on Form 10‑Q constitute “forward‑looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward‑looking statements generally can be identified by the use of forward‑looking terminology such as “outlook,” “objective,” “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “should,” “plans,” “continue,” or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10‑Q include, but are not limited to, statements with respect to the following:

| · |  | the impact of COVID-19 on the economy and our operations, including the measures taken by governmental authorities to address it, which may precipitate or exacerbate other risks and/or uncertainties;

| · |  | our ability to generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities;

| · |  | the outcome or impact of our business strategy to increase our intrinsic value on a per-share basis through disciplined management of our balance sheet and cost structure and internal investments in our fleet, external acquisitions and repurchases of debt, common and preferred securities;

| · |  | our ability to renew or enter into new PPAs on favorable terms or at all after the expiration of our current agreements;

| · |  | our ability to meet the financial covenants under our senior secured term loans and other indebtedness;

| · |  | our ability to ensure that our plants operate safely and effectively;

| · |  | expectations regarding maintenance and capital expenditures;

| · |  | our belief that it is probable that insurance proceeds will cover the estimated plant write-down for the damage to the Cadillac project; and

| · |  | the impact of legislative, regulatory, competitive and technological changes.

Such forward‑looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10‑Q. Such forward‑looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward‑looking statement made by us or on our behalf.

Forward‑looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. In addition, a number of factors could cause actual results to differ materially from the results discussed in the forward‑looking statements, including, but not limited to, the factors included in the filings Atlantic Power makes from time to time with the SEC and the risk factors described under “Item 1A. Risk Factors” in our Annual Report on Form 10‑K for the year ended December 31, 2019 and in this Quarterly Report on Form 10‑Q. To the extent any risk factors in our Annual Report on Form 10‑K for the year ended December 31, 2019 relate to the factual information disclosed elsewhere in this Quarterly Report on Form 10‑Q, including with respect to our business plan and any updates to our business strategy, such risk factors should be read in light of such information. Our business is both highly competitive and subject to various risks.

These risks include, without limitation:

| · |  | deterioration in global economic and financial market conditions generally, including as a result of pandemic health issues (including coronavirus and its effects, among other things, on global supply, demand, and distribution disruptions as the coronavirus outbreak continues and results in an increasingly

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prolonged period of travel, commercial and/or other similar restrictions and limitations) and the effects on electricity demand;

| · |  | the expiration or termination of PPAs and our ability to renew or enter into new PPAs on favorable terms or at all;

| · |  | the dependence of our projects on their electricity and thermal energy customers;

| · |  | exposure of certain of our projects to fluctuations in the price of electricity or natural gas;

| · |  | the dependence of our projects on third-party suppliers;

| · |  | projects not operating according to plan;

| · |  | risks inherent in the use of derivative instruments;

| · |  | the effects of weather, which affects demand for electricity and fuel as well as operating conditions;

| · |  | revenues from hydropower plants are highly dependent on precipitation and associated weather events;

| · |  | the adequacy of our insurance coverage, the timeliness of our insurance payouts, and our estimates of insurance coverage;

| · |  | risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events;

| · |  | increased competition, including for acquisitions;

| · |  | our limited control over the operation of certain minority‑owned projects;

| · |  | transfer restrictions on our equity interests in certain projects;

| · |  | the impact of hostile cyber intrusions;

| · |  | labor disruptions;

| · |  | our pension plan may require additional future contributions;

| · |  | our ability to retain, motivate and recruit executives and other key employees;

| · |  | the impact of significant energy, environmental and other regulations on our projects;

| · |  | noncompliance with federal reliability standards may subject us and our projects to penalties;

| · |  | additional regulatory requirements mandating limitations on greenhouse gas emissions or requiring efficiency improvements;

| · |  | the impact of Canadian and U.S. federal income tax laws on our business;

| · |  | the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian Corruption of Foreign Public Officials Act;

| · |  | the impact of failure to fully comply with Section 404 of the Sarbanes-Oxley Act of 2002;

| · |  | our ability to service our debt obligations or generate sufficient cash flow to pay preferred dividends;

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| · |  | our indebtedness and financing arrangements and the terms, covenants and restrictions included in our senior secured term loans;

| · |  | the discontinuation, reform or replacement of LIBOR;

| · |  | exchange rate fluctuations;

| · |  | the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and changes in our creditworthiness;

| · |  | our ability to access liquidity for the ongoing operation of our business and the execution of our business plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately‑placed bank or institutional non‑recourse operating level debt;

| · |  | unstable capital and credit markets;

| · |  | the anti-takeover protections in the British Columbia Business Corporations Act (the “BCBCA”) and our Articles of Continuance;

| · |  | U.S., Canadian and/or global economic conditions and uncertainty;

| · |  | the impact of impairment of goodwill, long‑lived assets or equity method investments; and

| · |  | increasing competition.

Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward‑looking information include third-party projections of regional fuel and electric capacity and energy prices that are based on assumptions about future economic conditions and courses of action. Although the forward‑looking statements contained in this Quarterly Report on Form 10‑Q 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. Certain statements included in this Quarterly Report on Form 10‑Q may be considered “financial outlook” for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10‑Q. These forward‑looking statements are made as of the date of this Quarterly Report on Form 10‑Q and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and results of operations of Atlantic Power should be read in conjunction with the interim consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10‑Q. All dollar amounts discussed below are in millions of U.S. dollars except per share amounts, or unless otherwise stated. The interim financial statements have been prepared in accordance with GAAP.

OVERVIEW

Atlantic Power is an independent power producer that owns power generation assets in eleven states in the United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long‑term PPAs, which seek to minimize exposure to changes in commodity prices. As of March 31, 2020, our portfolio consisted of twenty-one operating projects with an aggregate electric generating capacity of approximately 1,723 megawatts (“MW”) on a gross ownership basis and approximately 1,327 MW on a net ownership basis. Sixteen of the projects are majority‑owned by the Company.

We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, we receive payments for electric energy sold to our customers (known as

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energy payments), in addition to payments for electric generation capacity (known as capacity payments). Our PPAs have expiration dates ranging from May 24, 2020 (Oxnard) to November 2043 (Allendale). We also sell steam from a number of our projects to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.

We directly operate and maintain sixteen of our operating power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

Available Information

Access to our Quarterly Reports on Form 10-Q, Annual Reports on Form 10-K, Current Reports on Form 8-K, and amendments to these reports filed with or furnished to the Securities and Exchange Commission (“SEC”) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) may be obtained free of charge through the Investors section of our website at https://investors.atlanticpower.com/corporate-profile as soon as is reasonably practical after we electronically file or furnish these reports. In addition, our filings with the SEC may be accessed through the SEC’s website at www.sec.gov and our filings with the Canadian Securities Administrators (CSA) may be accessed through the CSA's System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com. Except for the documents specifically incorporated by reference into this Form 10-Q, information contained on our website or the SEC or CSA websites is not incorporated by reference in the Form 10-Q and should not be considered to be a part of the Form 10-Q. We have included our website address and that of the SEC and CSA only as inactive textual references and do not intend them to be active links to such websites. All statements made in any of our securities filings, including all forward-looking statements or information, are made as of the date of the document in which the statement is included, and we do not assume or undertake any obligation to update any of those statements or documents unless we are required to do so by applicable law. We are not a foreign private issuer, as defined in Rule 3b‑4 under the Exchange Act.

RECENT DEVELOPMENTS

Substantial Issuer Bid

On March 25, 2020, we commenced a SIB for the purchase of up to $25 million common shares. This was equivalent to 12,820,512 common shares, or approximately 12% of our total issued and outstanding common shares based on a $1.95 per share purchase price (the minimum price per common share under the offer) as measured on the date of commencement. The SIB expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL. We repurchased and cancelled 12,500,000 common shares under the SIB at a total cost of $25 million upon its expiration on April 30, 2020. All common shares repurchased and cancelled under the SIB occurred subsequent to March 31, 2020. A fter giving effect to the cancellation of the common shares purchased under the SIB, 93,002,338 common shares were issued and outstanding at May 6, 2020.

Extension of Revolving Credit Facility

On March 18, 2020, we executed an amendment to our senior secured revolving credit facility. The amendment provides for an extension of the Revolver maturity date to April 2025, to coincide with the maturity date of the Term Loan Facility. Both the Revolver and the Term Loan Facility are at our APLP Holdings subsidiary. At March 31, 2020, we had no borrowings under the Revolver and utilized $78.1 million of borrowing capacity for letters of credit.

In conjunction with the extension, the Revolver capacity was reduced to $180 million from $200 million. The amendment allows an upsizing of the Revolver capacity by up to $30 million, to a maximum aggregate amount of $210 million, subject to approval of the two letter of credit issuer banks and increased commitments by existing or new lenders. Such an upsizing would not require a further amendment. There were no other significant changes to the terms of the Revolver.

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COVID-19 Pandemic

We are one of many companies providing essential services during this national emergency related to the COVID-19 pandemic. We have taken extra precautions for our employees who continue to work at our facilities and have implemented work-from-home policies where appropriate. Currently, we do not anticipate any employee layoffs and are continuing to maintain our high level of reliability and availability of our plants. We continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to serve our operational needs with a remote workforce and to keep our operations running to ensure uninterrupted service to our offtakers.

This is a rapidly evolving situation that could lead to extended disruption of economic activity. To date, we have not experienced significant issues to our business related to COVID-19. Nonetheless, as a result of the spread of COVID-19 in the United States and Canada, it is difficult to assess the impact on our customers, which may impact our financial results going forward. In addition, while we have not experienced significant supply chain issues so far, we continue to closely manage and monitor developments in our supply chain, particularly as it relates to fuel procurement and management of the repairs at Cadillac. An extended slowdown of the U.S. economy, demand for commodities and/or material changes in governmental policy could result in lower demand for electricity and natural gas as well as adversely affect the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and prospects.

OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of May 6, 2020, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region. Our customers are generally large utilities and other parties with investment‑grade credit ratings, as measured by Standard & Poor’s (“S&P”). For customers rated by Moody’s, we substitute the corresponding S&P rating in the table below. Customers that have assigned ratings at the top end of the range of investment‑grade have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the lower end of the range of investment‑grade have weaker capacity. Agency ratings are subject to change, and there can be no assurance that a rating agency will continue to rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other obligations.

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Project |  | Location |  | Type |  |  | MW |  | Economic Interest | Net MW |  | Primary Electric Purchasers |  | Power Contract Expiry | Customer Credit Rating (S&P)
Solid Fuel Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Allendale |  |  | South Carolina |  |  | Biomass |  |  | 20 |  |  | 100.00 | % |  | 20 |  |  | South Carolina Public Service Authority |  |  | November 2043 |  |  | A |
Cadillac |  |  | Michigan |  |  | Biomass |  |  | 40 |  |  | 100.00 | % |  | 40 |  |  | Consumers Energy |  |  | June 2028 |  |  | A- |
Calstock |  |  | Ontario |  |  | Biomass |  |  | 35 |  |  | 100.00 | % |  | 35 |  |  | Ontario Electricity Financial Corporation |  |  | June 2020 (1) |  |  | AA |
Chambers(2) |  |  | New Jersey |  |  | Coal |  |  | 262 |  |  | 40.00 | % |  | 89 |  |  | Atlantic City Electric (3) |  |  | March 2024 |  |  | A- |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  | 16 |  |  | Chemours Co. |  |  | March 2024 |  |  | B+ |
Craven(2) |  |  | North Carolina |  |  | Biomass |  |  | 48 |  |  | 50.00 | % |  | 24 |  |  | Duke Energy Carolinas, LLC |  |  | December 2027 |  |  | A- |
Dorchester |  |  | South Carolina |  |  | Biomass |  |  | 20 |  |  | 100.00 | % |  | 20 |  |  | South Carolina Public Service Authority |  |  | October 2043 |  |  | A |
Grayling(2) |  |  | Michigan |  |  | Biomass |  |  | 37 |  |  | 30.00 | % |  | 11 |  |  | Consumers Energy |  |  | December 2027 |  |  | A- |
Piedmont |  |  | Georgia |  |  | Biomass |  |  | 55 |  |  | 100.00 | % |  | 55 |  |  | Georgia Power |  |  | September 2032 |  |  | A- |
Williams Lake |  |  | British Columbia |  |  | Biomass |  |  | 66 |  |  | 100.00 | % |  | 66 |  |  | BC Hydro |  |  | September 2029 |  |  | AAA |
Natural Gas Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Frederickson(2) |  |  | Washington |  |  | Natural Gas |  |  | 250 |  |  | 50.15 | % |  | 50 |  |  | Benton Co. PUD |  |  | August 2022 |  |  | AA- |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  | 45 |  |  | Grays Harbor PUD |  |  | August 2022 |  |  | A+ |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  | 30 |  |  | Franklin Co. PUD |  |  | August 2022 |  |  | A+ |
Kenilworth |  |  | New Jersey |  |  | Natural Gas |  |  | 29 |  |  | 100.00 | % |  | 29 |  |  | Merck & Co., Inc. |  |  | September 2021 |  |  | AA- |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Merchant |  |  | N/A |  |  | NR |
Manchief (4) |  |  | Colorado |  |  | Natural Gas |  |  | 300 |  |  | 100.00 | % |  | 300 |  |  | Public Service Company of Colorado |  |  | April 2022 |  |  | A- |
Morris (5) |  |  | Illinois |  |  | Natural Gas |  |  | 177 |  |  | 100.00 | % |  | 100 |  |  | Merchant |  |  | N/A |  |  | NR |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  | 77 |  |  | Equistar Chemicals, LP (6) |  |  | December 2034 |  |  | BBB (7) |
Nipigon |  |  | Ontario |  |  | Natural Gas |  |  | 40 |  |  | 100.00 | % |  | 40 |  |  | Independent Electricity System Operator |  |  | December 2022 |  |  | A- |
Orlando(2) |  |  | Florida |  |  | Natural Gas |  |  | 129 |  |  | 50.00 | % |  | 65 |  |  | Duke Energy Florida, LLC |  |  | December 2023 |  |  | A- |
Oxnard |  |  | California |  |  | Natural Gas |  |  | 49 |  |  | 100.00 | % |  | 49 |  |  | Southern California Edison |  |  | May 2020 (8) |  |  | BBB |
Tunis |  |  | Ontario |  |  | Natural Gas |  |  | 37 |  |  | 100.00 | % |  | 37 |  |  | Independent Electricity System Operator |  |  | October 2033 |  |  | AA |
Hydroelectric Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Curtis Palmer |  |  | New York |  |  | Hydro |  |  | 60 |  |  | 100.00 | % |  | 60 |  |  | Niagara Mohawk Power Corporation |  |  | December 2027 (9) |  |  | A- |
Koma Kulshan |  |  | Washington |  |  | Hydro |  |  | 13 |  |  | 100.00 | % |  | 13 |  |  | Puget Sound Energy |  |  | March 2037 |  |  | BBB |
Mamquam(10) |  |  | British Columbia |  |  | Hydro |  |  | 50 |  |  | 100.00 | % |  | 50 |  |  | BC Hydro |  |  | September 2027 |  |  | AAA |
Moresby Lake |  |  | British Columbia |  |  | Hydro |  |  | 6 |  |  | 100.00 | % |  | 6 |  |  | BC Hydro |  |  | August 2022 |  |  | AAA |

| (1) |  | In May 2020, the provincial government advised that it intends to extend Calstock’s PPA by six months to provide time to evaluate the future role of biomass generation in the province. The extension has not yet been executed.

| (2) |  | Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

| (3) |  | The base PPA with Atlantic City Electric (“ACE”) makes up the majority of the revenue from the 89 Net MW. For sales of energy and capacity not purchased by ACE under the base PPA and sold to the spot market, profits are shared with ACE under a separate power sales agreement.

| (4) |  | In May 2019, we entered into an agreement to sell Manchief to PSCo following the expiration of the PPA in April 2022 for $45.2 million subject to working capital and other customary adjustments.

| (5) |  | Equistar has an option to purchase Morris that is exercisable in December 2020 and in December 2027.

| (6) |  | Equistar has the right under the PPA to take up to 77 MW, but on average has taken approximately 50 MW.

| (7) |  | Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.

| (8) |  | Depending on outcome of re-contracting efforts, Oxnard may be mothballed following the expiration of its PPA.

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| (9) |  | The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. From January 6, 1995 through March 31, 2020, the facility has generated 8,175 GWh under its PPA. Based on cumulative generation to date, we expect the PPA to expire prior to December 2027.

| (10) |  | BC Hydro has an option to purchase Mamquam that is exercisable in November 2021 and every five-year anniversary thereafter.

Non-operating Natural Gas Plants

In August 2018, we terminated discussions with the Navy regarding site control for our Naval Station, Naval Training Center (“NTC”) and North Island projects located in San Diego, California. We are in the process of decommissioning all three sites, which is a requirement of our land use agreements with the Navy.

Our Kapuskasing and North Bay projects are both 40 MW natural gas plants located in the Province of Ontario. These projects formerly had PPAs with the OEFC that expired in December 2017. These plants are currently being maintained, but do not operate because they do not have PPAs or a merchant market where operations would be profitable.

Consolidated Overview and Results of Operations

Performance highlights

The following table provides a summary of our consolidated results of operations for the three months ended March 31, 2020 and 2019, which are analyzed in greater detail below:

|  | Three months ended |
|  | March 31, |
(in millions of U.S. dollars, except as otherwise stated) |  | 2020 |  | 2019 |
Project revenue |  | $ | 72.8 |  | $ | 73.0 |
Project income |  |  | 24.7 |  |  | 30.6 |
Net income attributable to Atlantic Power Corporation |  |  | 29.5 |  |  | 8.9 |
Net cash provided by operating activities |  |  | 8.4 |  |  | 29.2 |
Net cash (used in) provided by investing activities |  |  | (2.6) |  |  | 1.2 |
Net cash used in financing activities |  |  | (40.1) |  |  | (25.5) |
Earnings per share attributable to Atlantic Power Corporation—basic |  |  | 0.28 |  |  | 0.08 |
Earnings per share attributable to Atlantic Power Corporation—diluted |  |  | 0.23 |  |  | 0.07 |
Project Adjusted EBITDA(1) |  |  | 50.8 |  |  | 53.7 |

| (1) |  | See reconciliation and definition in Supplementary Non‑GAAP Financial Information.

Project revenue decreased by $0.2 million to $72.8 million in the three months ended March 31, 2020 from $73.0 million in the three months ended March 31, 2019. The primary drivers of the decrease are as follows:

| · |  | Cadillac – the project ceased operation after the fire in September 2019, resulting in a $4.5 million decrease in energy and capacity revenue; and

| · |  | Morris – there was a $3.2 million decrease in project revenue at our Morris project due to lower fuel index prices than in 2019.

These decreases in project revenue were partially offset by increases in project revenue resulting from:

| · |  | Allendale and Dorchester – the Allendale and Dorchester projects contributed $6.6 million of revenue in the three months ended March 31, 2020. The projects were purchased in July 2019 and therefore had no impact on revenue in the comparative 2019 period; and

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| · |  | Williams Lake – a $1.8 million increase of revenue from the comparable 2019 period primarily due to the project’s new energy purchase agreement that became effective in October 2019.

Consolidated project income decreased by $5.9 million to $24.7 million in the three months ended March 31, 2020 from $30.6 million in the three months ended March 31, 2019. The primary drivers of the decrease are as follows:

| · |  | Project revenue – project revenue decreased $0.2 million as discussed above;

| · |  | Operation and maintenance expenses – operation and maintenance expenses increased by $4.2 million from the comparable 2019 period primarily due to an increase of $2.5 million at Allendale and Dorchester, which were acquired in July 2019, an increase of $0.8 million at our Cadillac project due to accelerated maintenance performed during the project’s repair outage, an increase of $0.7 million at our Williams Lake project due to planned electrical work costs and an increase of $0.3 million at Morris due to boiler maintenance. These increases were partially offset by a $1.3 million decease at our Oxnard project, which underwent a maintenance outage in the comparable 2019 period; and

| · |  | Derivative instruments – the change in the fair value of our derivative instruments decreased $3.2 million from the comparable 2019 period.

These decreases in project income were partially offset by an increase in project income resulting from:

| · |  | Equity in earnings from unconsolidated affiliates – equity earnings increased $0.8 million in the three months ended March 31, 2020 from the comparative 2019 period due to $0.6 million of equity earnings from Craven and Grayling, which were acquired in August 2019.

A detailed discussion of project income by segment is provided in Consolidated Overview and Results of Operations below. The discussion of Project Adjusted EBITDA by segment begins on page 45.

We have four reportable segments: Solid Fuel, Natural Gas, Hydroelectric and Corporate. We revised our reportable business segments in the fourth quarter of 2019 as the result of recent asset acquisitions, PPA expirations and project decommissioning, and in order to align with changes to management's structure, resource allocation and performance assessment in making decisions regarding our operations. Segment information for comparative 2019 period has been revised to conform to the new segment presentation. The segment classified as Corporate (formerly Un-Allocated Corporate) includes activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects and intercompany eliminations. These costs are not allocated to the operating segments when determining segment profit or loss. Project income is the primary GAAP measure of our operating results and is discussed below by reportable segment.

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Three months ended March 31, 2020 compared to the three months ended March 31, 2019

The following table provides our consolidated results of operations:

|  | Three months ended March 31, |  |
|  | 2020 |  | 2019 |  | $ change |  | % change |  |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 40.7 |  | $ | 37.0 |  | $ | 3.7 |  | 10.0 | % |
Energy capacity revenue |  |  | 28.0 |  |  | 30.2 |  |  | (2.2) |  | (7.3) | % |
Other |  |  | 4.1 |  |  | 5.8 |  |  | (1.7) |  | (29.3) | % |
|  |  | 72.8 |  |  | 73.0 |  |  | (0.2) |  | (0.3) | % |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 19.6 |  |  | 20.0 |  |  | (0.4) |  | (2.0) | % |
Operations and maintenance |  |  | 20.7 |  |  | 16.5 |  |  | 4.2 |  | 25.5 | % |
Depreciation and amortization |  |  | 15.6 |  |  | 16.2 |  |  | (0.6) |  | (3.7) | % |
|  |  | 55.9 |  |  | 52.7 |  |  | 3.2 |  | 6.1 | % |
Project other : |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | (5.6) |  |  | (2.4) |  |  | (3.2) |  | NM |  |
Equity in earnings of unconsolidated affiliates |  |  | 13.7 |  |  | 12.9 |  |  | 0.8 |  | 6.2 | % |
Interest expense, net |  |  | (0.3) |  |  | (0.3) |  |  | — |  | — | % |
Other income, net |  |  | — |  |  | 0.1 |  |  | (0.1) |  | (100.0) | % |
|  |  | 7.8 |  |  | 10.3 |  |  | (2.5) |  | (24.3) | % |
Project income |  |  | 24.7 |  |  | 30.6 |  |  | (5.9) |  | (19.3) | % |
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |
Administration |  |  | 6.7 |  |  | 6.8 |  |  | (0.1) |  | (1.5) | % |
Interest expense, net |  |  | 10.8 |  |  | 11.1 |  |  | (0.3) |  | (2.7) | % |
Foreign exchange (gain) loss |  |  | (20.6) |  |  | 5.0 |  |  | (25.6) |  | NM |  |
Other expense, net |  |  | 2.6 |  |  | 4.7 |  |  | (2.1) |  | (44.7) | % |
|  |  | (0.5) |  |  | 27.6 |  |  | (28.1) |  | NM |  |
Income from operations before income taxes |  |  | 25.2 |  |  | 3.0 |  |  | 22.2 |  | NM |  |
Income tax expense |  |  | 1.5 |  |  | 0.6 |  |  | 0.9 |  | NM |  |
Net income |  |  | 23.7 |  |  | 2.4 |  |  | 21.3 |  | NM |  |
Net loss attributable to preferred shares of a subsidiary company |  |  | (5.8) |  |  | (6.5) |  |  | 0.7 |  | (10.8) | % |
Net income attributable to Atlantic Power Corporation |  | $ | 29.5 |  | $ | 8.9 |  | $ | 20.6 |  | NM |  |

|  | Three months ended March 31, 2020 |
|  |  |  |  |  |  |  |  |  |  |  |  | Consolidated |
|  | Solid Fuel |  | Natural Gas |  | Hydroelectric |  | Corporate |  | Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 16.8 |  | $ | 6.2 |  | $ | 17.7 |  | $ | — |  | $ | 40.7 |
Energy capacity revenue |  |  | 6.3 |  |  | 21.7 |  |  | — |  |  | — |  |  | 28.0 |
Other |  |  | 0.3 |  |  | 2.9 |  |  | 0.7 |  |  | 0.2 |  |  | 4.1 |
|  |  | 23.4 |  |  | 30.8 |  |  | 18.4 |  |  | 0.2 |  |  | 72.8 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 10.1 |  |  | 9.5 |  |  | — |  |  | — |  |  | 19.6 |
Operations and maintenance |  |  | 11.2 |  |  | 5.6 |  |  | 3.1 |  |  | 0.8 |  |  | 20.7 |
Depreciation and amortization |  |  | 3.2 |  |  | 7.5 |  |  | 4.9 |  |  | — |  |  | 15.6 |
|  |  | 24.5 |  |  | 22.6 |  |  | 8.0 |  |  | 0.8 |  |  | 55.9 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | — |  |  | 0.5 |  |  | — |  |  | (6.1) |  |  | (5.6) |
Equity in earnings of unconsolidated affiliates |  |  | 2.9 |  |  | 10.8 |  |  | — |  |  | — |  |  | 13.7 |
Interest expense, net |  |  | (0.3) |  |  | — |  |  | — |  |  | — |  |  | (0.3) |
|  |  | 2.6 |  |  | 11.3 |  |  | — |  |  | (6.1) |  |  | 7.8 |
Project income (loss) |  | $ | 1.5 |  | $ | 19.5 |  | $ | 10.4 |  | $ | (6.7) |  | $ | 24.7 |

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|  | Three months ended March 31, 2019 |
|  |  |  |  |  |  |  |  |  |  |  |  | Consolidated |
|  | Solid Fuel |  | Natural Gas |  | Hydroelectric |  | Corporate |  | Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 10.4 |  | $ | 9.0 |  | $ | 17.6 |  | $ | — |  | $ | 37.0 |
Energy capacity revenue |  |  | 9.3 |  |  | 20.9 |  |  | — |  |  | — |  |  | 30.2 |
Other |  |  | 0.1 |  |  | 4.7 |  |  | 0.8 |  |  | 0.2 |  |  | 5.8 |
|  |  | 19.8 |  |  | 34.6 |  |  | 18.4 |  |  | 0.2 |  |  | 73.0 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 8.0 |  |  | 12.0 |  |  | — |  |  | — |  |  | 20.0 |
Operations and maintenance |  |  | 6.8 |  |  | 6.5 |  |  | 2.8 |  |  | 0.4 |  |  | 16.5 |
Depreciation and amortization |  |  | 3.7 |  |  | 7.6 |  |  | 4.9 |  |  | — |  |  | 16.2 |
|  |  | 18.5 |  |  | 26.1 |  |  | 7.7 |  |  | 0.4 |  |  | 52.7 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | — |  |  | (0.6) |  |  | — |  |  | (1.8) |  |  | (2.4) |
Equity in earnings of unconsolidated affiliates |  |  | 2.5 |  |  | 10.4 |  |  | — |  |  | — |  |  | 12.9 |
Interest expense, net |  |  | (0.3) |  |  | — |  |  | — |  |  | — |  |  | (0.3) |
Other income, net |  |  | — |  |  | 0.1 |  |  | — |  |  | — |  |  | 0.1 |
|  |  | 2.2 |  |  | 9.9 |  |  | — |  |  | (1.8) |  |  | 10.3 |
Project income (loss) |  | $ | 3.5 |  | $ | 18.4 |  | $ | 10.7 |  | $ | (2.0) |  | $ | 30.6 |

Solid Fuel

Project income for the three months ended March 31, 2020 decreased $2.0 million from the comparable 2019 period primarily due to:

| · |  | decreased project income of $3.9 million at Cadillac primarily due to the fire in September 2019.

This decrease was partially offset by:

| · |  | increased project income of $0.7 million at Williams Lake primarily due to a new energy purchase agreement that became effective in October 2019, which resulted in a $1.8 million increase in project revenue from the comparable 2019 period;

| · |  | increased project income of $0.4 million and $0.4 million at Allendale and Dorchester, respectively, which were acquired in July 2019; and

| · |  | increased project income of $0.5 million and $0.1 million at Craven and Grayling, respectively, which were acquired in August 2019.

Natural Gas

Project income for the three months ended March 31, 2020 increased $1.1 million from the comparable 2019 period primarily due to:

| · |  | increased project income of $2.7 million at Nipigon primarily due to a $2.1 million gain in fair value on the fuel agreement accounted as a derivative and a $0.8 million increase in capacity revenue due to favorable fuel index prices.

This increase was partially offset by:

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| · |  | decreased project income of $1.0 million at Orlando primarily due to a planned outage in March 2020; and

| · |  | decreased project income of $0.9 million at Morris primarily due to a $0.8 million decrease in fair value of fuel purchase agreements.

Hydroelectric

Project income for the three months ended March 31, 2020 did not change materially from the three months ended March 31, 2019.

Corporate

Project income for the three months ended March 31, 2020 decreased $4.7 million to a project loss from the comparable 2019 period primarily due to a $4.3 million decrease in the fair value of interest rate swap agreements related to the senior secured credit facility.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to any specific project and are allocated to the corporate segment. These costs include the activities that support the executive and administrative offices, treasury function, costs of being a public registrant, costs to develop or acquire future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate taxes. Significant non‑cash items that impact Administrative and other expenses (income), and that are subject to potentially significant fluctuations include the non‑cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar‑denominated obligations and the related deferred income tax expense (benefit) associated with these non‑cash items.

Administration

Administration expense for the three months ended March 31, 2020 did not change materially from the three months ended March 31, 2019.

Interest expense, net

Interest expense for the three months ended March 31, 2020 did not change materially from the three months ended March 31, 2019.

Foreign exchange (gain) loss

Foreign exchange gain increased by $25.6 million to a $20.6 million gain in the three months ended March 31, 2020 from a $5.0 million loss in the comparable 2019 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and Series E Debentures). The Canadian dollar depreciated 9.2% against the U.S. dollar from December 31, 2019 to March 31, 2020, as compared to a 2.0% appreciation in the comparable 2019 period.

Other expense, net

Other expense, net decreased by $2.1 million for the three months ended March 31, 2020 from the comparative 2019 period primarily due to a $2.1 million change in the fair value of the conversion option of the Series E Debentures.

Income tax expense

Income tax expense for the three months ended March 31, 2020 was $1.5 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $6.8 million. The primary items impacting the tax rate for the three months ended March 31, 2020 was a net decrease to our valuation allowances of $8.7 million, consisting of $5.9 million decreases in Canada and $2.8 million decreases in the United States due to the utilization of

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net operating losses. These items were partially offset by $2.0 million relating to foreign exchange and $1.4 million of other permanent differences.

Income tax expense for the three months ended March 31, 2019 was $0.6 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $0.8 million. The primary item impacting the tax rate for the three months ended March 31, 2019 was a net decrease to our valuation allowances of $1.6 million, consisting of $1.7 million increase in Canada and $3.3 million decreases in the United States due to income. These items were partially offset by $0.7 million relating to foreign exchange, $0.4 million relating to withholding state taxes and $0.3 million of other permanent differences.

Project Operating Performance

Two of the primary metrics we utilize to measure the operating performance of our projects are generation and availability. Generation measures the net output of our proportionate project ownership percentage in megawatt hours (“MWh”). Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority of our projects were able to achieve their respective capacity payments. For projects where reduced availability adversely impacted capacity payments, the impact was not material for the three months ended March 31, 2020 with the exception of the Cadillac project. While the reduction in availability at the Cadillac project impacted capacity payments for the period ended March 31, 2020, we believe we will recover these capacity payments through the anticipated business interruption insurance recoveries for the period. The terms of our PPAs provide for certain levels of planned and unplanned outages. All references below are denominated in net Gigawatt hours (“net GWh”).

Generation

|  | Generation |
|  | Three months ended March 31, |
|  |  |  |  |  | % change |
(in Net GWh) |  | 2020 |  | 2019 |  | 2020 vs. 2019 |
Segment |  |  |  |  |  |  |
Solid Fuel |  | 423.1 |  | 379.7 |  | 11.4 | %
Natural Gas |  | 581.7 |  | 628.6 |  | (7.5) | %
Hydroelectric |  | 172.5 |  | 163.7 |  | 5.4 | %
Total |  | 1,177.3 |  | 1,172.0 |  | 0.5 | %

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Aggregate power generation for the three months ended March 31, 2020 increased 0.5% from the comparable 2019 period primarily due to:

| · |  | increased generation in the Solid Fuel segment primarily due to a combined 130.6 net GWh increase in generation at Allendale, Dorchester, Craven and Grayling, which were acquired in 2019, partially offset by a 34.1 net GWh decrease at Cadillac due to the fire in September 2019 and a 28.6 net GWh decrease in generation at Williams Lake due to lower fuel inventory; and

| · |  | increased generation in the Hydroelectric segment primarily due to a 11.7 net GWh increase in generation at Mamquam due to higher water flows than the comparable 2019 period.

These increases were partially offset by:

| · |  | decreased generation in the Natural Gas segment primarily due to a 33.8 net GWh decrease in generation at Manchief due to lower dispatch than the comparable 2019 period and a 20.5 net GWh decrease in generation at Orlando due to a planned outage, partially offset by a 15.1 net GWh increase in generation at Fredrickson due to higher dispatch than the comparable 2019 period.

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Availability

|  | Availability |
|  | Three months ended March 31, |
|  |  |  |  |  | % change |
|  | 2020 |  | 2019 |  | 2020 vs. 2019 |
Segment |  |  |  |  |  |  |
Solid Fuel |  | 83.6 | % | 99.2 | % | (15.6) | %
Natural Gas (1) |  | 96.0 | % | 96.9 | % | (0.9) | %
Hydroelectric |  | 71.6 | % | 98.6 | % | (27.0) | %
Weighted average |  | 86.8 | % | 97.9 | % | (11.1) | %

| (1) |  | The San Diego projects, which ceased operations in February 2018, have been excluded from availability in both 2020 and 2019.

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Aggregate power availability for the three months ended March 31, 2020 decreased 11.1% from the comparable 2019 period primarily due to:

| · |  | Decreased availability in the Hydroelectric segment primarily due to forced outages at Moresby Lake and Koma in the current quarterly period; and

| · |  | decreased availability in the Solid Fuel segment primarily due to the fire at Cadillac in September 2019 and the outage at Piedmont in the current quarterly period.

Supplementary Non‑GAAP Financial Information

The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. 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 fair value of derivative instruments. 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. We believe that Project Adjusted EBITDA is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project Adjusted EBITDA is Project income. A reconciliation of Net income (loss) to Project income and to Project Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.

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Project Adjusted EBITDA

|  | Three months ended |  |  |  |
|  | March 31, |  | $ change |
|  | 2020 |  | 2019 |  | 2020 vs 2019 |
Net income |  | $ | 23.7 |  | $ | 2.4 |  | $ | 21.3 |
Income tax expense |  |  | 1.5 |  |  | 0.6 |  |  | 0.9 |
Income from operations before income taxes |  |  | 25.2 |  |  | 3.0 |  |  | 22.2 |
Administration |  |  | 6.7 |  |  | 6.8 |  |  | (0.1) |
Interest expense, net |  |  | 10.8 |  |  | 11.1 |  |  | (0.3) |
Foreign exchange (gain) loss |  |  | (20.6) |  |  | 5.0 |  |  | (25.6) |
Other expense, net |  |  | 2.6 |  |  | 4.7 |  |  | (2.1) |
Project income |  | $ | 24.7 |  | $ | 30.6 |  | $ | (5.9) |
Reconciliation to Project Adjusted EBITDA |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 19.8 |  |  | 20.2 |  |  | (0.4) |
Interest expense, net |  |  | 0.7 |  |  | 0.7 |  |  | — |
Change in the fair value of derivative instruments |  |  | 5.6 |  |  | 2.4 |  |  | 3.2 |
Other income, net |  |  | — |  |  | (0.2) |  |  | 0.2 |
Project Adjusted EBITDA |  | $ | 50.8 |  | $ | 53.7 |  | $ | (2.9) |
Project Adjusted EBITDA by segment |  |  |  |  |  |  |  |  |  |
Solid Fuel |  |  | 7.8 |  |  | 10.1 |  |  | (2.3) |
Natural Gas |  |  | 28.2 |  |  | 28.1 |  |  | 0.1 |
Hydroelectric |  |  | 15.3 |  |  | 15.6 |  |  | (0.3) |
Corporate |  |  | (0.5) |  |  | (0.1) |  |  | (0.4) |
Total |  | $ | 50.8 |  | $ | 53.7 |  | $ | (2.9) |

Solid Fuel

The following table summarizes Project Adjusted EBITDA for our Solid Fuel segment for the periods indicated:

|  | Three months ended March 31, |
|  |  |  |  |  |  |  | % change |
|  | 2020 |  | 2019 |  | 2020 vs. 2019 |
Solid Fuel |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 7.8 |  | $ | 10.1 |  | (23) | %

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Project Adjusted EBITDA for the three months ended March 31, 2020 decreased $2.3 million from the comparable 2019 period primarily due to decreased Project Adjusted EBITDA of:

| · |  | $4.3 million at Cadillac, which has been non-operational since the fire in September 2019.

This decrease was partially offset by increases in Project Adjusted EBITDA of:

| · |  | $0.9 million at Allendale and Dorchester, which were acquired in July 2019;

| · |  | $0.8 million at Craven and Grayling, which were acquired in August 2019; and

| · |  | $0.8 million at Williams Lake, primarily due to increase of revenue from the comparable 2019 period primarily due to the project’s new energy purchase agreement that became effective in October 2019.

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Natural Gas

The following table summarizes Project Adjusted EBITDA for our Natural Gas segment for the periods indicated:

|  | Three months ended March 31, |
|  |  |  |  |  |  |  | % change |
|  | 2020 |  | 2019 |  | 2020 vs 2019 |
Natural Gas |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 28.2 |  | $ | 28.1 |  | NM |

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Project Adjusted EBITDA for the three months ended March 31, 2020 did not change materially from the comparable 2019 period.

Hydroelectric

The following table summarizes Project Adjusted EBITDA for our Hydroelectric segment for the periods indicated:

|  | Three months ended March 31, |
|  |  |  |  |  |  |  | % change |
|  | 2020 |  | 2019 |  | 2020 vs. 2019 |
Hydroelectric |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 15.3 |  | $ | 15.6 |  | NM |

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Project Adjusted EBITDA for the three months ended March 31, 2020 did not change materially from the comparable 2019 period.

Corporate

The following table summarizes Project Adjusted EBITDA for our Corporate segment for the periods indicated:

|  | Three months ended March 31, |
|  |  |  |  |  |  |  | % change |
|  | 2020 |  | 2019 |  | 2020 vs. 2019 |
Corporate |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | (0.5) |  | $ | (0.1) |  | NM |

Three months ended March 31, 2020 compared with three months ended March 31, 2019

Project Adjusted EBITDA for the three months ended March 31, 2020 did not change materially from the comparable 2019 period.

Liquidity and Capital Resources

|  | March 31, |  | December 31, |
|  | 2020 |  | 2019 |
Cash and cash equivalents (1) |  | $ | 47.8 |  | $ | 74.9 |
Restricted cash |  |  | 0.5 |  |  | 7.7 |
Total |  |  | 48.3 |  |  | 82.6 |
Revolving credit facility availability (2) |  |  | 101.9 |  |  | 121.7 |
Total liquidity |  | $ | 150.2 |  | $ | 204.3 |

| (1) |  | On May 1, 2020, we utilized $25 million of cash to repurchase and cancel 12.5 million shares under the SIB.

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| (2) |  | On March 18, 2020, the borrowing capacity under the Revolver was reduced to $180 million under the amendment to extend the Revolver maturity to April 2025

Overview

Our primary sources of liquidity are distributions from our projects and availability under our Revolver. Our liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from May 24, 2020 (Oxnard) to November 2043 (Allendale). We currently have two projects with PPAs with expiration dates in 2020, Calstock and Oxnard. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA, if at all, or the price received by the project for power under subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project distributions and the cash available for further debt reduction, identification of and investment in accretive growth opportunities (both internal and external), to the extent available, and other allocation of available cash. See “Risk Factors—Risks Related to Our Financial Position and Economic and Financial Market Conditions —We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities” in our Annual Report on Form 10‑K for the year ended December 31, 2019.

Consolidated Cash Flow Discussion

The following table reflects the changes in cash flows for the periods indicated:

|  | Three months ended |  |  |  |
|  | March 31, |  |  |  |
|  | 2020 |  | 2019 |  | Change |
Net cash provided by operating activities |  | $ | 8.4 |  | $ | 29.2 |  | $ | (20.8) |
Net cash (used in) provided by investing activities |  |  | (2.6) |  |  | 1.2 |  |  | (3.8) |
Net cash used in financing activities |  |  | (40.1) |  |  | (25.5) |  |  | (14.6) |

Operating Activities

Cash flow from our projects may vary from period to period based on working capital requirements and the operating performance of the projects, as well as changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, and the transition to merchant or re‑contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

For the three months ended March 31, 2020, the net decrease in cash provided by operating activities of $20.8 million was primarily the result of the following:

| · |  | Working capital – changes in working capital resulted in a $16.8 million decrease in cash flows from operating activities from the comparable 2019 period. The unfavorable change in working capital is primarily due to the timing of cash receipts at Williams Lake, Morris, and Nipigon, as well as larger cash disbursements for payables at Cadillac for repair work and at Morris in preparation for a maintenance outage later in 2020; and

| · |  | Cadillac – deferral of the recognition of business interruption proceeds had a $3.2 million impact on cash flows from operations. We expect that these insurance recovery proceeds will be recognized as income upon finalization of the plant rebuild and receipt of all insurance proceeds.

Investing Activities

For the three months ended March 31, 2020, the net increase in cash used in investing activities of $3.8 million was primarily the result of the following:

| · |  | Capitalized plant additions – capitalized plant additions were $9.7 million higher in the three months ended March 31, 2020 than the comparable 2019 period primarily due to repairs at Cadillac; and

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| · |  | Proceeds from asset sales – we received $1.5 million of cash proceeds from the sale of equipment at our San Diego projects in the comparable 2019 period.

These increases were partially offset by the following decrease to cash used in investing activities:

| · |  | Insurance proceeds – we received $7.4 million of insurance proceeds related to the Cadillac fire.

Financing Activities

For the three months ended March 31, 2020, the net increase in cash used in financing activities of $14.6 million was primarily the result of the following:

| · |  | Common share repurchases – we paid $8.2 million in the three months ended March 31, 2020 to repurchase and cancel common shares as compared to $0.1 million in the comparative 2019 period;

| · |  | Corporate and project-level debt repayments – we made $5.8 million greater principal payments than the comparable 2019 period;

| · |  | Deferred financing costs – we incurred $1.5 million of deferred financing costs related to amending the Term Loan Facility and Revolver in the three months ended March 31, 2020; and

| · |  | Vested LTIP – we made $0.7 million of higher cash payments for vested LTIP tax withholdings than the comparable 2019 period.

These increases were partially offset by the following decrease to cash flows used in financing activities:

| · |  | Preferred share repurchases – we repurchased and cancelled $1.3 million less preferred shares than in the comparable 2019 period.

Corporate Debt

The following table summarizes the maturities of our corporate debt at March 31, 2020:

|  |  |  |  |  |  |  |  | Remaining |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Maturity |  | Interest |  | Principal |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Date |  | Rates |  | Repayments |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | Thereafter |
Senior secured term loan facility(1) |  | April 2025 |  | 4.53 | % |  |  |  | $ | 360.0 |  | $ | 52.5 |  | $ | 93.0 |  | $ | 106.0 |  | $ | 60.0 |  | $ | 36.0 |  | $ | 12.5 |
MTNs |  | June 2036 |  | 5.95 | % |  |  |  |  | 148.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 148.0 |
Convertible Debenture |  | January 2025 |  | 6.00 | % |  |  |  |  | 81.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 81.1 |
Total Corporate Debt |  |  |  |  |  |  |  |  | $ | 589.1 |  | $ | 52.5 |  | $ | 93.0 |  | $ | 106.0 |  | $ | 60.0 |  | $ | 36.0 |  | $ | 241.6 |

| (1) |  | The Term Loan Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the Term Loan Facility and the 5.95% MTNs, letters of credit costs to meet the requirements of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Term Loan Facility, and payment on the preferred equity issued by APPEL, a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of the Term Loan Facility outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Note that failing to meet the mandatory amortization requirements is not an event of default, but could result in APLP Holdings being unable to make distributions to Atlantic Power Corporation and APPEL being unable to pay dividends to its shareholders. The amortization profile in the table above is based on principal payments according to the targeted principal amount described in (ii) above through 2022 based on the schedule as amended in January 2020. After 2022, the amortization profile is based on (i) above and is an estimate, subject to change. See Note 5, Long-term debt for more

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information on our Credit Facilities.

Project‑Level Debt

Project‑level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project‑level debt generally amortizes during the term of the respective revenue‑generating contracts of the projects. The following table summarizes the maturities of project‑level debt. The amounts represent our share of the non‑recourse project‑level debt balances at March 31, 2020. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project‑level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. At May 6, 2020, all of our projects except for Cadillac were in compliance with the covenants contained in project‑level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but are not callable or subject to acceleration under the terms of their debt agreements.

The range of interest rates presented represents the rates in effect at March 31, 2020. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.

|  |  |  |  |  |  |  |  | Total |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  | Remaining |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Maturity |  | Range of |  | Principal |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Date |  | Interest Rates |  | Repayments |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | Thereafter |
Consolidated Projects: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cadillac |  | August 2025 |  | 6.26 | % | - | 6.38 | % | $ | 17.2 |  | $ | 2.3 |  | $ | 2.7 |  | $ | 3.3 |  | $ | 3.3 |  | $ | 3.7 |  | $ | 1.9 |
Total Consolidated Projects |  |  |  |  |  |  |  |  |  | 17.2 |  |  | 2.3 |  |  | 2.7 |  |  | 3.3 |  |  | 3.3 |  |  | 3.7 |  |  | 1.9 |
Equity Method Projects: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers(1) |  | December 2023 |  | 5.00 | % |  |  |  |  | 38.5 |  |  | 7.8 |  |  | 8.8 |  |  | 10.1 |  |  | 11.8 |  |  | — |  |  | — |
Total Equity Method Projects |  |  |  |  |  |  |  |  |  | 38.5 |  |  | 7.8 |  |  | 8.8 |  |  | 10.1 |  |  | 11.8 |  |  | — |  |  | — |
Total Project-Level Debt |  |  |  |  |  |  |  |  | $ | 55.7 |  | $ | 10.1 |  | $ | 11.5 |  | $ | 13.4 |  | $ | 15.1 |  | $ | 3.7 |  | $ | 1.9 |

| (1) |  | The above table does not include our $1.0 million proportionate share of issuance premiums.

Uses of Liquidity

Our requirements for liquidity and capital resources, other than operating our projects, consist primarily of principal and interest on our outstanding Series E Debentures, Term Loan Facility, MTNs and other corporate and project-level debt; funding the repurchase of shares of our common stock, our Series E Debentures, and our preferred shares (to the extent we choose to pursue any such repurchases); collateral and investment in our projects through capital expenditures, including major maintenance and business development costs; and dividend payments to preferred shareholders of a subsidiary company.

Capital and Maintenance Expenditures

Capital expenditures and maintenance expenses for the projects are generally paid at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures and maintenance expenditures needed at the projects. The operating projects which we own consist of large capital assets that have established commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most expenditures relate to planned repairs and maintenance and are expensed when incurred.

Excluding reconstruction costs at Cadillac, we expect to reinvest approximately $4.0 million in 2020 (of which $0.3 million was reinvested in the three months ended March 31, 2020) in our portfolio, including equity method investments, in the form of project capital expenditures, and incur $32.8 million of maintenance expenses (of which $5.5 million was incurred in the three months ended March 31, 2020). Such investments are generally paid at the project level. See “Liquidity and Capital Resources—Capital and Maintenance Expenditures” in our Annual Report on Form 10‑K for the year ended December 31, 2019. We do not expect any other material or unusual requirements for cash outflows for 2020 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months. All remaining costs for the repair and reconstruction of our Cadillac plant are expected to be

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paid with insurance proceeds. Repair costs exceeded the $1 million deductible in 2019. There may be timing differences between the period of when costs are accumulated, cash is disbursed and insurance proceeds are received.

We believe one of the benefits of our diverse fleet is that plant overhauls and other expenditures do not occur in the same year for each facility. Recognized industry guidelines and original equipment manufacturer recommendations provide a source of data to assess maintenance needs. In addition, we utilize predictive and risk‑based analysis to refine our expectations, prioritize our spending and balance the funding requirements necessary for these expenditures over time. Future capital expenditures and maintenance expenses may exceed the projected level in 2020 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.

Recently Adopted and Recently Issued Accounting Guidance

See Note 1 to the consolidated financial statements in this Quarterly Report on Form 10‑Q.

Off‑Balance Sheet Arrangements

As of March 31, 2020, we had no off‑balance sheet arrangements as defined in Item 303(a)(4) of Regulation S‑K.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to financial market risk results primarily from fluctuations in interest and currency rates and fuel and electricity prices. There have been no material changes to our market risks as disclosed in our Annual Report on Form 10‑K for the fiscal year ended December 31, 2019.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act as of the end of the period covered by this report, and they have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the three months ended March 31, 2020, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations of Disclosure Controls and Internal Control over Financial Reporting

Because of their inherent limitations, our disclosure controls and procedures and our internal control over financial reporting may not prevent material errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The effectiveness of our disclosure controls and procedures and our internal control over financial reporting are subject to risks, including that the control may become inadequate because of changes in conditions or that the degree of compliance with our policies or procedures may deteriorate.

ITEM 1A. RISK FACTORS

During the quarter ended March 31, 2020, there have been no material changes from the risk factors previously in “Item 1A. Risk Factors” of our Annual Report on Form 10‑K for the year ended December 31, 2019 except as follows:

Our business, results of operations, financial condition, cash flows and stock price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the recent outbreak of COVID-19.

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Our business, results of operations, financial condition, cash flows and stock price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the recent outbreak of COVID-19 which has spread from China to many other countries, including the United States. In March 2020, the World Health Organization characterized COVID-19 as a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The outbreak has resulted in governments around the world implementing increasingly stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures, and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of COVID-19.

The COVID-19 pandemic has caused, and is expected to continue to cause, the global slowdown of economic activity, disruptions in global supply chains and significant volatility and disruption of financial markets. Because the severity, magnitude and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly changing and difficult to predict, the pandemic’s impact on our business and results of operations, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains uncertain and difficult to predict. Further, the ultimate impact of the COVID-19 pandemic on our business and results of operations depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of the pandemic and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs; general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery if and when the COVID-19 pandemic subsides.

We are considered a critical infrastructure industry, as defined by the U.S. Department of Homeland Security. Although we have continued to operate our facilities in both the United States and Canada to date consistent with federal guidelines and state, provincial and local orders, the outbreak of COVID-19 and any preventive or protective actions taken by governmental authorities may have a material adverse effect on our operations, supply chain, customers, including business shutdowns or disruptions. The extent to which COVID-19 may adversely impact our business depends on future developments, which are highly uncertain and unpredictable, depending upon the severity and duration of the outbreak and the effectiveness of actions taken globally to contain or mitigate its effects. Any resulting financial impact cannot be estimated reasonably at this time, but may materially adversely affect our business, results of operations, financial condition and cash flow. COVID-19 may affect us by (i) reducing economic activity thereby resulting in lower demand for electricity consumption (with related effects of pricing), (ii) impairing our supply chain (for example, by limiting the manufacturing of materials or the supply of services used in our operations), and (iii) affecting the health of our workforce, rendering employees unable to work or travel. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to any resulting economic recession or depression. While the restrictions and limitations noted above may be relaxed or rolled back if and when COVID-19 abates, the actions may be reinstated as the pandemic continues to evolve. The scope and timing of any such reinstatements is difficult to predict and may materially affect our operations in the future. Additionally, concerns over the economic impact of COVID-19 have caused extreme volatility in financial and other capital markets which has and may continue to adversely impact our stock price and our ability to access capital markets. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2019, such as those relating to our business and financial performance. We continue to monitor guidelines proposed by federal, state and local governments with respect to the proposed “reopening” measures, which may change over time depending on public health, safety and other considerations. We are continuing to focus on the safety and protection of our workforce by continuing to implement additional safety protocols in light of COVID-19.

ITEM 2: UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) Purchases of Equity Securities by Atlantic Power Corporation and Affiliated Purchasers

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Share Repurchase Programs

Normal Course Issuer Bid

On December 31, 2019, we commenced a new Normal Course Issuer Bid (“NCIB”) for our Series E Debentures, our common shares and for each series of the preferred shares of APPEL, our wholly-owned subsidiary. The NCIBs expire on December 30, 2020 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the new NCIBs. Under the NCIB, we may purchase up to a total of 10,578,799 common shares based on 10% of our public float as of December 17, 2019 and we are limited to daily purchases of 9,243 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. We may also purchase up to Cdn$11.5 million of Series E Debentures; 384,750 shares of 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”); 223,072 shares of 7.0% Cumulative Rate Preferred Shares Series 2 (the “Series 2 Shares”); and 133,031 shares of Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of APPEL.

All purchases made under the NCIBs will be made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the NYSE in compliance with Rule 10b-18 under the Exchange Act, as amended, or other designated exchanges and published marketplaces in the United States in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval.

Beginning on January 1, 2020 and through March 24, 2020, we repurchased and cancelled 3,760,335 common shares under the NCIB at a total cost of $8.2 million.

In the three months ended March 31, 2020, we also repurchased and cancelled 381,794 Series 1 Shares, 62,365 Series 2 Shares and 120,000 Series 3 Shares of APPEL at a total cost of $6.4 million. As a result of the repurchase, a $7.4 million loss was attributed to the preferred shares of a subsi diary company in the consolidated statements of operations for the three months ended March 31, 2020.

Beginning on March 25, 2020, we commenced a Substantial Issuer Bid (“SIB”) (described below) that expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL.

The following table provides purchases of common equity securities by Atlantic Power Corporation and affiliated purchasers for the period of January 1, 2020 through March 31, 2020 under the NCIB:

Common Shares |
|  |  |  |  |  | Total Number of Shares |  | Dollar Value of Maximum Number |
|  | Total Number of |  | Average Price Paid |  | as Part of a Publicly Announced |  | of Shares to be Purchased Under |
Purchase Period |  | Shares Purchased |  | Per Share |  | Purchase Plan |  | the Plan |
1/1/2020 - 1/31/2020 |  |  | 1,703,870 |  |  | $ 2.35 |  |  | 1,703,870 |  |  |  |
2/1/2020 - 2/29/2020 |  |  | 39,049 |  |  | $ 2.36 |  |  | 39,049 |  |  |  |
3/1/2020 - 3/31/2020 |  |  | 2,017,416 |  |  | $ 2.01 |  |  | 2,017,416 |  |  | $ 13,568,743 | (1)
Total |  |  | 3,760,335 |  |  |  |  |  | 3,760,335 |  |  |  |

| (1) |  | Under the NCIB, we may purchase up to a total of 10,578,799 common shares. Through March 31, 2020, we have repurchased a cumulative 3,760,335 shares and we are authorized to purchase up to an additional 6,818,464 common shares under the NCIB. Our plan does not obligate the Company to acquire any specific number of shares. The $13.6 million dollar value of maximum number of shares that may be purchased under the NCIB is based on the $1.99 weighted average share price for the month of March 2020. The $13.6 million dollar value of maximum number of shares that may be purchased does not include the $25.0 million authorized for the SIB.

| (2) |  | The Board authorization permits the Company to repurchase common and preferred shares and convertible debentures. Therefore, in addition to the current NCIBs, from time to time we may repurchase our securities, including our common shares, our convertible debentures and our APPEL preferred shares through open market

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purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, NCIBs, issuer self tender or substantial issuer bids, or in privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions, other market opportunities and other factors. Any share repurchases outside of previously authorized NCIBs would be effected after taking into account our then current cash position and then anticipated cash obligations or business opportunities.

Substantial Issuer Bid

On March 25, 2020, we commenced a SIB for the purchase of up to $25 million of common shares. This was equivalent to 12,820,512 common shares, or approximately 12% of our total issued and outstanding common shares based on a $1.95 per share purchase price (the minimum price per common share under the offer) as measured on the date of commencement. The SIB expired on April 30, 2020. During the time the SIB was active, the NCIB was suspended for the purchase of common shares and Series E Debentures, but not for the preferred shares of APPEL.

The SIB proceeded by way of a “modified Dutch auction”. Holders of common shares were able to tender to the offer by: (i) auction tenders in which they specified the number of common shares being tendered at a price of not less than US$1.95 and not more than US$2.20 per Common Share in increments of US$0.05 per Common Share, or (ii) purchase price tenders in which they did not specify a price per Common Share, but rather agreed to have a specified number of common shares purchased at the purchase price determined by auction tenders.

The purchase price paid by the Company for each validly deposited common share was based on the number of common shares validly deposited pursuant to auction tenders and purchase price tenders, and the prices specified by shareholders making auction tenders. The purchase price was the lowest price which enabled the Company to purchase common shares up to the maximum amount available for auction tenders and purchase price tenders, determined in accordance with the terms of the offer. Common shares that were deposited at or below the final determined purchase price were purchased at such purchase price. Common shares that were not taken up in connection with the offer, including common shares deposited pursuant to auction tenders at prices above the purchase price, were returned to the shareholders.

We repurchased and cancelled 12,500,000 common shares under the SIB at a total cost of $25 million upon its expiration on April 30, 2020. All common shares repurchased and cancelled under the SIB occurred subsequent to March 31, 2020. A fter giving effect to the cancellation of the common shares purchased under the SIB, 93,002,338 common shares were issued and outstanding at May 6, 2020.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

HIDDEN_ROW |  |
Exhibit No. |  | Description
10.35 |  | Sixth Amendment to the Credit Agreement, dated as of March 18, 2020, among APLP Holdings, the Company and certain subsidiaries of APLP Holdings, as guarantors, Goldman Sachs Lending Partners LLC, as administrative agent and collateral agent, and the other lenders and L/C issuers party thereto
10.36* |  | Letter agreement for Philip D. Rorabaugh dated November 11, 2019
31.1* |  | Certification of Chief Executive Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934
31.2* |  | Certification of Chief Financial Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934
32.1** |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
32.2** |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
101.INS* |  | XBRL Instance Document
101.SCH* |  | XBRL Taxonomy Extension Schema
101.CAL* |  | XBRL Taxonomy Extension Calculation Linkbase
101.DEF* |  | XBRL Taxonomy Extension Definition Linkbase
101.LAB* |  | XBRL Taxonomy Extension Label Linkbase
101.PRE* |  | XBRL Taxonomy Extension Presentation Linkbase

*Filed herewith.

**Furnished herewith.

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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 thereunto duly authorized.

Date: May 7, 2020 | Atlantic Power Corporation
| By: | /s/ Terrence Ronan
|  | Name: | Terrence Ronan
|  | Title: | Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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