Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Mar. 03, 2021 | Jun. 30, 2020 | |
Cover [Abstract] | |||
Entity Registrant Name | ATLANTIC POWER CORPORATION | ||
Entity Central Index Key | 0001419242 | ||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2020 | ||
Document Transition Report | false | ||
Entity File Number | 001-34691 | ||
Entity Incorporation, State or Country Code | A1 | ||
Entity Tax Identification Number | 55-0886410 | ||
Entity Address, Address Line One | 3 Allied Drive, Suite 155 | ||
Entity Address, City or Town | Dedham | ||
Entity Address, State or Province | MA | ||
Entity Address, Postal Zip Code | 02026 | ||
City Area Code | 617 | ||
Local Phone Number | 977-2400 | ||
Title of 12(b) Security | Common Shares | ||
Trading Symbol | AT | ||
Security Exchange Name | NYSE | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
ICFR Auditor Attestation Flag | true | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 176.5 | ||
Entity Common Stock, Shares Outstanding | 89,714,323 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2020 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Current assets: | ||
Cash and cash equivalents | $ 38.8 | $ 74.9 |
Restricted cash | 7.1 | 7.7 |
Accounts receivable | 31.3 | 30.4 |
Insurance recovery receivable (Note 23) | 13.5 | |
Current portion of derivative instruments asset (Notes 14 and 15) | 0.4 | 0.7 |
Inventory (Note 7) | 18.3 | 18.6 |
Prepayments | 7 | 3.8 |
Income taxes receivable (Note 16) | 3.2 | 1.8 |
Lease receivable | 0.9 | |
Other current assets | 0.3 | 0.4 |
Total current assets | 106.4 | 152.7 |
Property, plant, and equipment, net (Note 8) | 491.8 | 502.1 |
Equity investments in unconsolidated affiliates (Note 6) | 85 | 96.6 |
Power purchase agreements and intangible assets, net (Note 10) | 120.3 | 144.3 |
Goodwill (Note 9) | 21.3 | 21.3 |
Operating lease right-of-use assets (Note 24) | 4.6 | 6.3 |
Deferred income taxes (Note 16) | 17.2 | 10.4 |
Other assets | 0.6 | 1.9 |
Total assets | 847.2 | 935.6 |
Current liabilities: | ||
Accounts payable | 6.3 | 8.9 |
Accrued interest | 2.5 | 2.6 |
Other accrued liabilities | 19.3 | 20.8 |
Current portion of long-term debt (Note 12) | 95.7 | 76.4 |
Current portion of derivative instruments liability (Notes 14 and 15) | 11 | 12 |
Operating lease liabilities (Note 24) | 1.9 | 2 |
Other current liabilities | 0.2 | 0.2 |
Total current liabilities | 136.9 | 122.9 |
Long-term debt, net of unamortized discount and deferred financing costs (Note 12) | 384.1 | 473.5 |
Convertible debentures, net of discount and unamortized deferred financing costs (Note 13) | 84.1 | 81.1 |
Derivative instruments liability (Notes 14 and 15) | 8.1 | 15.9 |
Deferred income taxes (Note 16) | 23.7 | |
Power purchase agreements and intangible liabilities, net (Note 10) | 18 | 19.8 |
Asset retirement obligations, net (Note 11) | 48.1 | 51.5 |
Operating lease liabilities (Note 24) | 3.1 | 4.8 |
Other long-term liabilities (Note 11) | 6.2 | 4.7 |
Total liabilities | 688.6 | 797.9 |
Equity | ||
Common shares, no par value, unlimited authorized shares; 89,222,568 and 108,675,294 issued and outstanding at December 31, 2020 and 2019 | 1,219.7 | 1,259.9 |
Accumulated other comprehensive loss (Note 5) | (139.9) | (140.7) |
Retained deficit | (1,090) | (1,164.2) |
Total Atlantic Power Corporation shareholders' deficit | (10.2) | (45) |
Preferred shares issued by a subsidiary company (Note 20) | 168.8 | 182.7 |
Total equity | 158.6 | 137.7 |
Total liabilities and equity | $ 847.2 | $ 935.6 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
CONSOLIDATED BALANCE SHEETS | ||
Common shares, no par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized, unlimited | Unlimited | Unlimited |
Common shares, issued shares (in shares) | 89,222,568 | 108,675,294 |
Common shares, outstanding shares (in shares) | 89,222,568 | 108,675,294 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Project revenue: | ||
Project revenue | $ 272 | $ 281.6 |
Project expenses: | ||
Fuel | 70.9 | 72.3 |
Operations and maintenance | 89.5 | 77 |
Depreciation and amortization | 59.7 | 64.5 |
Total project expenses | 220.1 | 213.8 |
Project other income (loss): | ||
Change in fair value of derivative instruments (Notes 14 and 15) | 6.8 | (8.9) |
Equity in earnings (loss) of unconsolidated affiliates (Note 6) | 42.9 | (3) |
Interest, net | (1.2) | (1.1) |
Impairment (Note 8) | (5.8) | |
Insurance gain (loss) (Note 23) | 16.4 | (1) |
Other income (expense), net | 2.1 | (1.2) |
Total project other income (loss) | 67 | (21) |
Project income (loss) | 118.9 | 46.8 |
Administrative and other expenses: | ||
Administration | 24.8 | 23.9 |
Interest expense, net | 42.4 | 44 |
Foreign exchange loss | 5.1 | 11.9 |
Other (income) expense, net (Note 14) | (2.7) | 1 |
Total administrative and other expenses | 69.6 | 80.8 |
Income (loss) from operations before income taxes | 49.3 | (34) |
Income tax (benefit) expense (Note 16) | (24.2) | 9.8 |
Net income (loss) | 73.5 | (43.8) |
Net loss attributable to preferred shares of a subsidiary company (Note 20) | (0.7) | (1.2) |
Net income (loss) attributable to Atlantic Power Corporation | $ 74.2 | $ (42.6) |
Net earnings (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 21) | ||
Basic (in dollars per share) | $ 0.77 | $ (0.39) |
Diluted (in dollars per share) | $ 0.62 | $ (0.39) |
Weighted average number of common shares outstanding: (Note 21) | ||
Basic (in shares) | 95.8 | 109.3 |
Diluted (in shares) | 124.9 | 109.3 |
Energy sales | ||
Project revenue: | ||
Project revenue | $ 137.9 | $ 138 |
Energy capacity revenue | ||
Project revenue: | ||
Project revenue | 113.8 | 125.4 |
Other | ||
Project revenue: | ||
Project revenue | $ 20.3 | $ 18.2 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||
Net income (loss) | $ 73.5 | $ (43.8) |
Other comprehensive income, net of tax: | ||
Unrealized loss on hedging activities | (0.5) | (0.3) |
Net amount reclassified to earnings | 0.5 | 0.3 |
Defined benefit plan, net of tax | (1.4) | (0.3) |
Foreign currency translation adjustments | 2.2 | 5.8 |
Other comprehensive income, net of tax | 0.8 | 5.5 |
Comprehensive income (loss) | 74.3 | (38.3) |
Less: Comprehensive loss attributable to preferred shares of a subsidiary company | (0.7) | (1.2) |
Comprehensive income (loss) attributable to Atlantic Power Corporation | $ 75 | $ (37.1) |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions | Series 1Preferred Shares of a Subsidiary Company | Series 1 | Series 2Preferred Shares of a Subsidiary Company | Series 2 | Series 3Preferred Shares of a Subsidiary Company | Series 3 | Common Shares | Retained Deficit | Accumulated Other Comprehensive (loss) income | Total Atlantic Power Corporation Shareholder's Deficit | Preferred Shares of a Subsidiary Company | Total |
Balance at the beginning of the period at Dec. 31, 2018 | $ 1,260.9 | $ (1,121.6) | $ (146.2) | $ (6.9) | $ 199.3 | $ 192.4 | ||||||
Balance (in shares) at Dec. 31, 2018 | 108.3 | |||||||||||
Increase (decrease) in shareholders' equity | ||||||||||||
Net income (loss) | (42.6) | (42.6) | (1.2) | (43.8) | ||||||||
Share-based compensation | $ 1.5 | 1.5 | 1.5 | |||||||||
Share-based compensation (in shares) | 1.4 | |||||||||||
Common share repurchases | $ (2.5) | (2.5) | (2.5) | |||||||||
Common share repurchases (in shares) | (1.1) | |||||||||||
Preferred share repurchases | (8) | (8) | ||||||||||
Dividends on preferred shares of a subsidiary company | $ (3.5) | $ (3.5) | $ (2.4) | $ (2.4) | $ (1.5) | $ (1.5) | ||||||
Foreign currency translation adjustments | 5.8 | 5.8 | 5.8 | |||||||||
Defined benefit plan, net of tax | (0.3) | (0.3) | (0.3) | |||||||||
Balance at the end of the period at Dec. 31, 2019 | $ 1,259.9 | (1,164.2) | (140.7) | (45) | 182.7 | 137.7 | ||||||
Balance (in shares) at Dec. 31, 2019 | 108.6 | |||||||||||
Increase (decrease) in shareholders' equity | ||||||||||||
Net income (loss) | 74.2 | 74.2 | (0.7) | 73.5 | ||||||||
Share-based compensation | $ 1.4 | 1.4 | 1.4 | |||||||||
Share-based compensation (in shares) | 0.6 | |||||||||||
Common share repurchases | $ (41.6) | (41.6) | (41.6) | |||||||||
Common share repurchases (in shares) | (20) | |||||||||||
Preferred share repurchases | (6.4) | (6.4) | ||||||||||
Dividends on preferred shares of a subsidiary company | $ (3.3) | $ (3.3) | $ (2.6) | $ (2.6) | $ (0.9) | $ (0.9) | ||||||
Foreign currency translation adjustments | 2.2 | 2.2 | 2.2 | |||||||||
Defined benefit plan, net of tax | (1.4) | (1.4) | (1.4) | |||||||||
Balance at the end of the period at Dec. 31, 2020 | $ 1,219.7 | $ (1,090) | $ (139.9) | $ (10.2) | $ 168.8 | $ 158.6 | ||||||
Balance (in shares) at Dec. 31, 2020 | 89.2 |
CONSOLIDATED STATEMENTS OF SH_2
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) $ in Millions | 12 Months Ended | |||
Dec. 31, 2020$ / shares | Dec. 31, 2020USD ($) | Dec. 31, 2019$ / shares | Dec. 31, 2019USD ($) | |
Defined benefit plan, tax | $ | $ 0.4 | $ (0.1) | ||
Series 1 | ||||
Dividends on preferred shares of a subsidiary company (in CAD per share) | $ 1.212500 | $ 1.212500 | ||
Series 2 | ||||
Dividends on preferred shares of a subsidiary company (in CAD per share) | 1.434752 | 1.392500 | ||
Series 3 | ||||
Dividends on preferred shares of a subsidiary company (in CAD per share) | $ 1.288117 | $ 1.459115 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Cash provided by operating activities: | ||
Net income (loss) | $ 73.5 | $ (43.8) |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 59.7 | 64.4 |
Share-based compensation | 1.4 | 1.5 |
Asset retirement obligations | (2.1) | 1.4 |
Gain on disposal of fixed assets and inventory | (0.8) | (0.9) |
Impairment | 5.8 | |
Insurance (gain) Loss | (0.7) | 1 |
Equity in (earnings) loss from unconsolidated affiliates | (42.9) | 3 |
Distributions from unconsolidated affiliates | 54.2 | 59.5 |
Unrealized foreign exchange loss | 4.7 | 12.2 |
Change in fair value of derivative instruments | (8.6) | 10.7 |
Amortization of debt discount and deferred financing costs | 6 | 6.9 |
Non-cash operating lease expense | 1.9 | 1.7 |
Deferred income taxes | (29.9) | 4.8 |
Change in other operating balances | ||
Accounts receivable | (0.6) | 8.2 |
Inventory | 0.2 | (1.8) |
Prepayments and other assets | (1.1) | 3.9 |
Accounts payable | (2.1) | 5.1 |
Accruals and other liabilities | (5.5) | 1.1 |
Cash provided by operating activities | 107.3 | 144.7 |
Cash used in investing activities: | ||
Investment in unconsolidated affiliate | (18.7) | |
Insurance proceeds | 13.5 | 11.3 |
Cash paid for acquisition, net of cash received | (8.6) | |
Proceeds from sales of assets | 0.9 | 1.6 |
Purchase of property, plant and equipment | (24.8) | (7.3) |
Cash used in investing activities | (10.4) | (21.7) |
Cash used in financing activities: | ||
Common share repurchases | (41.6) | (2.5) |
Preferred share repurchases | (6.4) | (8) |
Repayment of corporate and project-level debt | (76.4) | (72.3) |
Repayment of convertible debentures | (18.5) | |
Cash payments for vested LTIP withheld for taxes | (0.7) | (2.1) |
Deferred financing costs | (1.7) | |
Dividends paid to preferred shareholders | (6.8) | (7.4) |
Cash used in financing activities | (133.6) | (110.8) |
Net (decrease) increase in cash, restricted cash and cash equivalents | (36.7) | 12.2 |
Cash, restricted cash and cash equivalents at beginning of period | 82.6 | 70.4 |
Cash, restricted cash and cash equivalents at end of period | 45.9 | 82.6 |
Supplemental cash flow information | ||
Interest paid | 37.2 | 37.6 |
Income taxes paid, net | 5.7 | 2.3 |
Accruals for construction in progress | $ 0.1 | $ 0.3 |
Nature of business
Nature of business | 12 Months Ended |
Dec. 31, 2020 | |
Nature of business | |
Nature of business | 1. Nature of business General Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the 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. |
Summary of significant accounti
Summary of significant accounting policies | 12 Months Ended |
Dec. 31, 2020 | |
Summary of significant accounting policies | |
Summary of significant accounting policies. | 2. Summary of significant accounting policies (a) The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity (“VIE”), through arrangements that do not involve controlling voting interests. We apply the standard that requires consolidation of VIEs, for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation. (b) Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased. (c) Restricted cash represents cash, cash equivalents and cash advances that are maintained by the projects or corporate to support payments for maintenance costs, reconstruction costs and meet project level and corporate contractual debt obligations. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. (d) Accounts receivable are carried at cost. We periodically assesses the collectability of accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and record an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. We had no allowance for doubtful accounts recorded at December 31, 2020 and 2019, respectively. (e) Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt, which ranges from 1 to 6 years. The carrying amount of deferred financing costs were recorded on the consolidated balance sheets as net of long-term debt and convertible debentures and was $7.1 million and $8.5 million at December 31, 2020 and 2019, respectively. Interest expense from the amortization of deferred financing costs for the years ended December 31, 2020 and 2019 was $2.6 million and $3.2 million, respectively. (f) Inventory represents spare parts, biofuel and natural gas, the majority of which is consumed by our projects in provision of their services, and are valued at the lower of cost and net realizable value. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs. (g) Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset. Significant additions or improvements extending asset lives or increasing generating capacity are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. (h) Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, obtaining a PPA. When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project’s related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. (i) Intangible assets include PPAs and fuel supply agreements at our projects acquired as part of business combinations. Carrying amounts for PPAs and fuel supply agreements are based on the fair value assigned in the allocation of the purchase price of the acquired business. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement. (j) We have investments in entities that own power-producing assets with the objective of generating cash flow. The equity method of accounting is applied to such investments in affiliates, which include joint ventures, partnerships, and limited liability companies because the ownership structure prevents us from exercising a controlling influence over the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with 50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships and limited liability companies with greater than 5% ownership because our influence over the investment’s operating and financial policies is considered to be more than minor. Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings of unconsolidated affiliates in the consolidated statements of operations. We apply the nature of distributions method for the classification of our investments accounted for by the equity method in the Consolidated Statements of Cash Flows. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates’ power-producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows. We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets. (k) Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset group exceeds its fair value. Our asset groups have been determined to be at the plant level, which is the lowest level in which independent, separately identifiable cash flows have been identified. We also review a project for impairment at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets for impairment. Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its estimated fair value. (l) Goodwill: Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination. Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances indicate that would more likely than not reduce the fair value of a reporting unit below its carrying value. In 2020, we changed our annual impairment testing from November 30 to October 31. We made the change to better align the timing of the goodwill impairment test with the timing of our annual planning and budgeting processes and to provide us with adequate time to evaluate goodwill for impairment. This change did not result in the delay, acceleration or avoidance of an impairment charge. We completed our annual impairment testing in the fourth quarter of 2020 and determined that no adjustments to the carrying value of goodwill were necessary. In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and other relevant entity-specific events. If the qualitative assessment determines that an impairment is more likely than not, then we perform a quantitative impairment test. In the quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired. When the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying amount of goodwill, and is recorded in the consolidated statements of operations. We determine the fair value of our reporting units using an income approach with discounted cash flow models (“DCF”), as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery, equity method investment, and goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilize estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of our reporting units. The valuation of long-lived assets, equity method investments and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of an impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts. (m) Accounts payable and other accrued liabilities: Accounts payable consists of amounts due to trade creditors related to our core business operations. These payables include amounts owed to vendors and suppliers for items such as fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, legal contingencies and employee-related costs including payroll, benefits and related taxes. (n) We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We also separate the conversion option of certain convertible debentures from the host instrument and account for it as an embedded derivative liability as the conversion option is in a currency different from our functional currency. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a significant operating cost. We do not enter into derivative financial instruments for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales in the ordinary course of conducting business. This exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying physical commodity. We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains or losses on derivatives designated as a hedge for accounting purposes are deferred and recorded as a component of accumulated other comprehensive income (loss) (“OCI”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings. Derivative financial instruments not designated as a hedge for accounting purposes are measured at fair value with changes in fair value recorded in the consolidated statements of operations. Derivative financial instruments under master netting arrangements are recorded net, when applicable, in the consolidated balance sheets. The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument: Derivative financial instrument Classification of changes in fair value Classification of cash settlements Natural gas swaps Change in fair value of derivative instrument Fuel expense Fuel purchase agreements Change in fair value of derivative instrument Fuel expense Interest rate swaps Change in fair value of derivative instrument Interest expense, net Convertible debenture conversion option Other (income) expense, net NA Foreign currency forward contract Foreign exchange loss Foreign exchange loss (o) Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 16 for more information. (p) We recognize energy sales revenue on a gross basis when electricity and steam are delivered and capacity revenue when capacity is provided under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts with performance obligations to provide electricity, steam and capacity on a predetermined basis. For certain PPAs determined to be operating 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. 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, which have expiration dates ranging from September 2021 to November 2043, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). 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. The following is a description of principal activities from which we generate our revenue. Products and services Nature, timing of satisfaction of performance obligations, and significant payment terms Energy Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations. The price of energy could be contracted under PPAs at set prices or merchant sales based on market merchant price. Energy revenue is also recognized under certain contracts for avoided generation during curtailment periods. Energy revenue is billed and paid on a monthly basis. Energy capacity Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at a negotiated contract price under the applicable PPAs for making installed generation capacity available in order to satisfy reliability requirements or merchant capacity sales based on the market price for such capacity. Energy capacity is billed and paid on a monthly basis. Other revenue includes the following: Steam energy and capacity Steam revenue is recognized upon delivery to the customer. Steam capacity payments under the applicable PPAs are recognized as the amount billable under the respective PPA. Steam capacity is billed and paid on a monthly basis. Waste heat We generate electricity from excess steam provided by a nearby pipeline and its pumping station in the Solid Fuel segment. Waste heat is earned when it is generated and paid as a portion of monthly energy and capacity billing. Ancillary and transmission services We provide ancillary and transmission services to our customers under the terms of our PPAs. These services are billed and paid on a monthly basis. Asset management and operation, operation and maintenance We provide asset management and operation supervision to the Frederickson project, a facility that we jointly own with Puget Sound Energy. We also provide operation and maintenance services to several electric energy customers under the PPAs. All services are billed and paid on a monthly basis. Refer to Note 4, Revenue from contracts, We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases. For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of energy revenue due to variable volume of the generation. When energy is delivered, we recognize lease income in energy revenue. (q) Administrative expenses include corporate and other expenses primarily for executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. (r) The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of our statements of operations for the period, but are accumulated and reported as a separate component of shareholders’ equity until sale of the net investment in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in our consolidated statements of operations. (s) The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan (“LTIP”). Notional shares granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional shares granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Unvested notional shares are entitled to receive dividends, if paid, equal to the dividends per common share during the vesting period in the form of additional notional shares. Unvested shares are subject to forfeiture if the participant is not an employee at the vesting date. We initially recognize compensation expense on the estimated number of notional shares for which the requisite service is expected to be rendered. We have estimated a weighted average forfeiture rate of 11% for all notional share grants under the LTIP. This estimate will be revisited if subsequent information indicates the actual number of notional shares forfeited is likely to differ from previous estimates. Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional shares accounted for as equity awards and the fair value of the award at each balance sheet date for notional shares accounted for as liability awards. (t) The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss. (u) We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the funded status of our defined benefit plan in the consolidated balance sheets in other long-term liabilities and record an offset to other comprehensive income (loss). In addition, we also recognize on an after-tax basis, as a component of other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets, the rate of future compensation increases and retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of our pension obligation or expense recorded. (v) Business combinations are accounted for using the acquisition method of accounting, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred. Asset acquisitions are measured based on their cost to the Company, including transaction costs. Asset acquisition costs, or the consideration transferred by the Company, are assumed to be equal to the fair value of the net assets acquired. If the consideration transferred is cash, measurement is based on the amount of cash the Company paid to the seller as well as transaction costs incurred. Consideration given in the form of nonmonetary assets, liabilities incurred or equity interests issued is measured based on either the cost to the Company or the fair value of the assets or net assets acquired, whichever is more clearly evident. The cost of an asset acquisition is allocated to the assets acquired based on their estimated relative fair values. Goodwill is not recognized in an asset acquisition. (w) The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to the credit-worthiness and payment history of our customers. See Note 22, Segment and geographic information (x) 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 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, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations, and the fair values of acquired assets and liabilities assumed. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. 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. (y) There are many uncertainties regarding the ongoing COVID-19 pandemic, and we are closely monitoring the impact of COVID-19 on all aspects of our business, including how it will impact our customers, employees, suppliers, vendors and business partners. 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 the high level of reliability and availability of our plants. We continue to implement strong physical and cybersecurity 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. While COVID-19 did not materially adversely affect our financial results and business operations for the year ended December 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. (z) Accounting Standards Adopted in 2020 In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326), Measurement of Credit Losses on Financial Instruments In August 2018, the FASB issued authoritative guidance 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 was effective for fiscal years beginning after December 15, 2019. The Company has adopted this guidance effectiv |
Acquisitions and divestments
Acquisitions and divestments | 12 Months Ended |
Dec. 31, 2020 | |
Acquisitions and divestments | |
Acquisitions and divestments | 3. Acquisitions and divestments 2019 Acquisitions (a) On July 31, 2019, we completed the acquisition of two biomass plants in South Carolina, Allendale and Dorchester, from EDF Renewables Inc. The Allendale plant is located in Allendale, South Carolina and has been in service since November 2013. The Dorchester plant is located in Harleyville, South Carolina and has been in service since October 2013. The two plants are identical in design and each of the plants has a capacity of 20 megawatts. All of the output of the two plants is sold to Santee Cooper, a state-owned utility, under PPAs that run to 2043. The biomass fuel for the plants consists primarily of mill and harvesting residues. We believe the acquisition represents a meaningful addition to the level and length of our existing contracted cash flows. The final consideration paid for the two plants was $12.6 million. In September 2018, we made a $2.6 million down payment for the acquisition of the plants and paid the remaining due at closing, less working capital adjustments and transaction costs, from discretionary cash and cash equivalents. The South Carolina biomass plants are reflected in our Solid Fuel segment. See Note 22, Segment and geographic information Fair values Cash (1) $ 1.4 Accounts receivable 4.3 Inventory 2.9 Property, plant, and equipment 4.0 Intangible assets 2.6 Accounts payable (2.0) Accrued liabilities (0.3) Other liabilities (0.3) Total purchase consideration $ 12.6 (1) The cash acquired was received in October 2019 and has been included in the Cash paid for acquisition, net of cash received within the Statement of Cash Flows. The $2.6 million of intangible assets recorded will be amortized straight-line through the remaining life of each plant’s PPA, which expire on October 31, 2043 (Dorchester) and November 18, 2043 (Allendale). Allendale and Dorchester contributed $10.8 million of revenue and net income of $1.0 million to the consolidated statements of operations for the period from July 31, 2019 to December 31, 2019. (b) On August 13, 2019, we completed our acquisition of the equity ownership interests held by AltaGas Power Holdings (U.S.) Inc. ("AltaGas") in two contracted biomass plants, Craven and Grayling (as defined below), in North Carolina and Michigan. Craven County Wood Energy (“Craven”) is a 48 megawatt (MW) biomass plant in North Carolina that has been in service since October 1990. We acquired a 50% interest in the plant from AltaGas. The remaining 50% interest is held by CMS Energy. Craven has a PPA with Duke Energy Carolinas that will expire on December 31, 2027. The plant burns wood waste and poultry litter. Grayling Generating Station (“Grayling”) is a 37 MW biomass plant in Michigan that has been in service since June 1992. We acquired a 30% interest in the plant from AltaGas. The remaining interests are held by Fortistar (20%) and CMS Energy (50%). Grayling has a PPA with Consumers Energy, the utility subsidiary of CMS Energy, which will expire on December 31, 2027. The plant burns wood waste from local mills, forestry residues, mill waste and bark. Both plants are operated by an affiliate of CMS Energy. The purchase price totaled $18.7 million in cash consideration inclusive of approximately $0.2 million of acquisition-related transaction costs. Craven and Grayling are limited partnerships. We do not have financial control of the partnerships because decision-making is shared and the partners must agree on all major decisions for each of the entities. Accordingly, we account for our ownership in Craven and Grayling under the equity method of accounting because our ownership is between five and fifty percent resulting in Atlantic Power Corporation maintaining more than minor influence over the partnerships’ operating and financing policies. Craven and Grayling contributed $1.0 million in equity in earnings from unconsolidated affiliates to the consolidated statements of operations, and $0.9 million in equity method distributions for the period from August 13, 2019 to December 31, 2019. |
Revenue from contracts
Revenue from contracts | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from contracts | |
Revenue from contracts | 4. Revenue from contracts Year Ended December 31, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 58.8 $ 24.2 $ 54.9 $ — $ 137.9 Energy capacity revenue 34.6 79.2 — — 113.8 Steam energy and capacity revenue — 10.5 — — 10.5 Waste heat revenue 1.0 — — — 1.0 Ancillary and transmission services — 3.1 3.4 — 6.5 Asset management and operation — — — 1.0 1.0 Miscellaneous revenue 0.1 1.2 — — 1.3 94.5 118.2 58.3 1.0 272.0 Year Ended December 31, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 41.1 $ 31.0 $ 65.9 $ — $ 138.0 Energy capacity revenue 38.7 86.7 — — 125.4 Steam energy and capacity revenue — 11.7 — — 11.7 Waste heat revenue 0.2 — — — 0.2 Ancillary and transmission services — 4.7 2.9 — 7.6 Asset management and operation — — — 1.0 1.0 Miscellaneous revenue — (2.3) — — (2.3) 80.0 131.8 68.8 1.0 281.6 Contract balances Contract liabilities as of December 31, 2020 include a $0.2 million fuel reserve fund at Dorchester and a $0.1 million steam sale credit at the San Diego plants. 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 |
Changes in accumulated other co
Changes in accumulated other comprehensive income (loss) by component | 12 Months Ended |
Dec. 31, 2020 | |
Changes in accumulated other comprehensive income (loss) by component | |
Changes in accumulated other comprehensive income (loss) by component | 5. Changes in accumulated other comprehensive income (loss) by component The changes in accumulated other comprehensive income (loss) by component were as follows: Year Ended December 31, 2020 2019 Foreign currency translation Balance at beginning of period $ (140.6) $ (146.4) Other comprehensive income: Foreign currency translation adjustments (1) 2.2 5.8 Balance at end of period $ (138.4) $ (140.6) Pension Balance at beginning and end of period $ (1.7) $ (1.4) Other comprehensive income: Settlement — 0.3 Tax expense — (0.1) Total Other comprehensive income before reclassifications, net of tax — 0.2 Total amount reclassified from accumulated other comprehensive (loss), net of tax (1.4) (0.5) Total other comprehensive (loss) (1.4) (0.3) Balance at end of period $ (3.1) $ (1.7) Cash flow hedges Balance at beginning of period $ 1.6 $ 1.6 Other comprehensive (loss): Net change from periodic revaluations (0.7) (0.5) Tax benefit 0.2 0.2 Total other comprehensive (loss) before reclassifications, net of tax (0.5) (0.3) Net amount reclassified to earnings: Interest rate swaps (2) 0.6 0.4 Tax expense (0.1) (0.1) Total amount reclassified from accumulated other comprehensive income, net of tax 0.5 0.3 Total other comprehensive (loss) — — Balance at end of period $ 1.6 $ 1.6 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to (loss) earnings. (2) This amount was included in interest expense, net on the accompanying consolidated statements of operations. |
Equity method investments in un
Equity method investments in unconsolidated affiliates | 12 Months Ended |
Dec. 31, 2020 | |
Equity method investments in unconsolidated affiliates | |
Equity method investments in unconsolidated affiliates | 6. Equity method investments in unconsolidated affiliates The following tables summarize our equity method investments in unconsolidated affiliates: Percentage of Carrying value as of Ownership as of December 31, Entity name December 31, 2020 2020 2019 Frederickson (1) 50% $ 58.9 $ 65.2 Orlando Cogen, LP 50% 2.5 3.6 Chambers Cogen, LP 40% 8.0 9.0 Craven County Wood Energy, LP (2) 50% 8.2 9.5 Grayling Generating Station, LP (2) 30% 7.4 9.3 Total $ 85.0 $ 96.6 (1) We own 50.15% of Frederickson. However, we do not have financial control of the entity. The Frederickson entity is organized under a joint ownership agreement. Under the terms of that agreement, the two owner parties have joint control of the asset and substantive participating rights through the structure of its Owner’s Committee. Each party has equal representation on this committee and unanimous consent is required over all significant decisions of the entity. These significant decisions include, but are not limited to (i) approval of the annual operating plan, annual operating budget, annual capital budget and five-year forecasts, (ii) approval of all expenditures in excess of the approved budget, (iii) adoption of procedures intended to govern the operation and conduct of the facility, and (iv) entering into, amending, supplementing or terminating any project agreement. Disputes between the owners for these significant decisions are subject to independent arbitration. Accordingly, since we do not control the project, Frederickson is accounted for under the equity method of accounting. (2) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . Deficit in earnings of equity method investments, net of distributions, was as follows: Year Ended December 31, Entity name 2020 2019 Frederickson $ 8.3 $ 9.1 Orlando Cogen, LP 33.1 33.0 Chambers Cogen, LP 4.4 (46.0) Craven County Wood Energy, LP (1) (1.8) 0.1 Grayling Generating Station, LP (1) (1.1) 0.8 Total earnings (loss) of unconsolidated affiliates 42.9 (3.0) Distributions from equity method investments (54.2) (59.5) Deficit in earnings of equity method investments, net of distributions $ (11.3) $ (62.5) (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . Distributions from equity method investments exceeded earnings (loss) for equity method investments for the years ended December 31, 2020 and 2019, respectively. Distributions from our equity method investments are typically based on project-level cash flows from operations or other non-GAAP metrics, whereas equity earnings include non-cash expenses such as depreciation and amortization, investment impairments or changes in the fair value of derivative financial instruments. The following summarizes the financial position at December 31, 2020 and 2019, and operating results for the years ended December 31, 2020 and 2019, respectively, for our proportional ownership interest in equity method investments: 2020 2019 Assets Current assets Frederickson $ 1.9 $ 2.1 Orlando Cogen, LP 7.8 7.8 Chambers Cogen, LP 14.8 14.4 Craven County Wood Energy, LP (1) 2.2 4.4 Grayling Generating Station, LP (1) 2.6 3.3 Non-current assets Frederickson 57.8 63.9 Orlando Cogen, LP 5.1 6.1 Chambers Cogen, LP 44.6 56.5 Craven County Wood Energy, LP (1) 7.9 5.8 Grayling Generating Station, LP (1) 6.5 6.8 $ 151.2 $ 171.1 Liabilities Current liabilities Frederickson $ 0.3 $ 0.3 Orlando Cogen, LP 10.3 10.2 Chambers Cogen, LP 15.8 13.7 Craven County Wood Energy, LP (1) 2.3 0.8 Grayling Generating Station, LP (1) 0.7 0.5 Non-current liabilities Frederickson 0.5 0.5 Orlando Cogen, LP 0.1 — Chambers Cogen, LP 35.6 48.2 Craven County Wood Energy, LP (1) 0.4 — Grayling Generating Station, LP (1) 0.2 0.3 $ 66.2 $ 74.5 (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . Operating results 2020 2019 Revenue Frederickson $ 29.2 $ 36.0 Orlando Cogen, LP 60.2 61.5 Chambers Cogen, LP 38.4 39.4 Craven County Wood Energy, LP (1) 9.6 4.9 Grayling Generating Station, LP (1) 3.5 2.2 140.9 144.0 Project expenses Frederickson 20.9 26.9 Orlando Cogen, LP 27.0 28.5 Chambers Cogen, LP 32.5 34.6 Craven County Wood Energy, LP (1) 11.4 4.7 Grayling Generating Station, LP (1) 4.5 1.8 96.3 96.5 Project other (income) expenses Frederickson — — Orlando Cogen, LP (0.1) — Chambers Cogen, LP (1.5) (50.9) Craven County Wood Energy, LP (1) — — Grayling Generating Station, LP (1) (0.1) 0.4 (1.7) (50.5) Net income (loss) Frederickson 8.3 9.1 Orlando Cogen, LP 33.1 33.0 Chambers Cogen, LP 4.4 (46.1) Craven County Wood Energy, LP (1) (1.8) 0.2 Grayling Generating Station, LP (1) (1.1) 0.8 Equity in earnings (loss) of unconsolidated affiliates $ 42.9 $ (3.0) (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . During the year ended December 31, 2019, we recorded an investment impairment of $49.2 million at our Chambers project. This impairment is a component of the operating results in the table above. There were no impairment triggers during 2020, and accordingly no impairment tests were performed on equity method investments. 2019 – Event-driven test in the fourth quarter Chambers We own a 40% limited partner interest in Chambers Cogeneration Limited Partnership. The Chambers project operates under a PPA that expires in March 2024. Prior to our impairment analysis, Chambers was recorded as a $58.2 million component of our equity investments in unconsolidated affiliates on the consolidated balance sheets. In connection with the preparation of the long-term forecast during the fourth quarter of 2019, we performed an analysis of the post-PPA value of Chambers operating as a merchant facility. As a result, we identified a significant decrease in the long-term outlook for power prices and spark spreads in PJM, the region where Chambers operates. These forward power prices, which were obtained from a third party, including analysis of the forward prices for natural gas and coal, had a significant negative impact on the discounted cash flows of Chambers post-PPA. The estimated post-PPA value is a significant component of the project’s overall value when compared to its carrying value of $58.2 million. When determining if this decrease in estimated fair value was other than temporary, we considered the likelihood that future conditions would change such that the gas and coal prices currently observed in the forward pricing models would become more favorable over time in order for the plant to be profitable in a merchant market. While declining power prices have been observed over the past several years, given that merchant curves have declined further than what was observed in 2017, it was our assessment that future merchant pricing and spark spreads were likely to remain low and that Chambers would be unable to recover its start fuel and start operations and maintenance costs after expiration of its PPA in 2024. Based on these factors, we determined that the decline in the fair value of our investment in Chambers was other than temporary. We recorded a $49.2 million impairment in earnings (loss) from unconsolidated affiliates in the consolidated statements of operations for the year ended December 31, 2019. |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2020 | |
Inventory | |
Inventory | 7. Inventory Inventory consists of the following: December 31, 2020 2019 Parts and other consumables $ 11.9 $ 12.2 Fuel 6.4 6.4 Total inventory $ 18.3 $ 18.6 |
Property, plant and equipment,
Property, plant and equipment, net | 12 Months Ended |
Dec. 31, 2020 | |
Property, plant and equipment, net | |
Property, plant and equipment, net | 8. Property, plant and equipment, net Property, plant and equipment, net consists of the following: December 31, December 31, Depreciable 2020 2019 Lives Land $ 6.4 $ 6.4 Office equipment, machinery and other 6.7 6.5 3 - 10 years Leasehold improvements 2.1 2.1 7 - 15 years Asset retirement obligation 23.6 23.4 1 - 43 years Plant in service 885.1 848.1 1 - 45 years Construction in progress 0.8 7.2 924.7 893.7 Less accumulated depreciation (432.9) (391.6) Total property, plant and equipment, net $ 491.8 $ 502.1 Depreciation expense of $36.8 million and $37.6 million was recorded for the years ended December 31, 2020 and 2019, respectively. No long-lived asset impairments to property, plant and equipment were recorded in the year ended December 31, 2020. As described below, we recorded $4.0 million of long-lived asset impairments to property, plant and equipment in the years ended December 31, 2019, respectively, with a corresponding charge to Impairment in the statement of operations. 2019 – Event-driven test performed in fourth quarter Calstock – Long-lived assets Calstock previously operated under a PPA that expired in June 2020. We performed the test as of December 31, 2019, six months prior to the contract expiration date. Calstock’s asset group for testing of long-lived assets totaled $7.8 million consisting of $2.3 million of net working capital, $4.7 million property, plant and equipment (“PPE”), net and a $0.8 million intangible PPA asset. Because of the uncertainty of our ability to recontract the project, fair value of Calstock was determined based solely on the cash flows remaining under the current contract. If our efforts to recontract are unsuccessful, the project will be taken out of service but not decommissioned. Upon testing Calstock for long-lived asset impairment, the carrying value of the asset group exceeded the estimated cash flows. Accordingly, we recorded a $4.7 million long-lived asset impairment in the year ended December 31, 2019, which is the difference between the fair value and carrying value of the reporting unit’s asset group, $0.7 million of the impairment related to intangible PPA assets and $4.0 million of the impairment related to property, plant and equipment. We also recorded impairment losses of $1.1 million related to spare parts inventory at Calstock. The Calstock biomass plant is a component of our Solid Fuel segment. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill | |
Goodwill | 9. Goodwill The following table presents goodwill by reportable segment for the years ended December 31, 2020 and 2019: Segment 2020 2019 Curtis Palmer Hydroelectric $ 14.4 $ 14.4 Morris Natural Gas 3.3 3.3 Nipigon Natural Gas 3.6 3.6 Total $ 21.3 $ 21.3 Goodwill Impairment Testing We perform our annual goodwill impairment test as of October 31 and update the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. For the years ended December 31, 2020 and 2019, we performed a quantitative test at each reporting unit. Based on the results of the annual goodwill impairment tests for years ended December 31, 2020 and 2019, management determined that no adjustment to the carrying value for any reporting unit was necessary because in all cases, the estimated fair values of the reporting units exceeded their respective carrying values. The fair value of all reporting units was determined using an income approach and considered project-specific assumptions for the future discounted cash flows. |
PPAs and other definite-lived i
PPAs and other definite-lived intangible assets and liabilities | 12 Months Ended |
Dec. 31, 2020 | |
PPAs and other definite-lived intangible assets and liabilities | |
PPAs and other definite-lived intangible assets and liabilities | 10. PPAs and other definite-lived intangible assets and liabilities Other intangible assets and liabilities include PPAs, fuel supply agreements and capitalized development costs. The following tables summarize the components of our intangible assets and other liabilities subject to amortization at December 31, 2020 and 2019: Assets Other Intangible Assets, Net Power Purchase Agreements Total Gross balances, January 1, 2020 $ 365.6 $ 365.6 Write-off of fully amortized balances (13.5) (13.5) Gross balances, December 31, 2020 352.1 352.1 Less: accumulated amortization (231.8) (231.8) Net carrying amounts, December 31, 2020 $ 120.3 $ 120.3 Other Intangible Assets, Net Power Purchase Agreements Total Gross balances, December 31, 2019 $ 365.6 $ 365.6 Less: accumulated amortization (221.3) (221.3) Net carrying amounts, December 31, 2019 $ 144.3 $ 144.3 Liabilities Power Purchase and Fuel Supply Agreement Liabilities, Net Power Purchase Fuel Supply Agreements Agreements Total Gross balances, December 31, 2020 $ (28.5) $ (12.6) $ (41.1) Less: accumulated amortization 16.2 6.9 23.1 Net carrying amounts, December 31, 2020 $ (12.3) $ (5.7) $ (18.0) Power Purchase and Fuel Supply Agreement Liabilities, Net Power Purchase Fuel Supply Agreements Agreements Total Gross balances, December 31, 2019 $ (28.1) $ (12.6) $ (40.7) Less: accumulated amortization 14.4 6.5 20.9 Net carrying amounts, December 31, 2019 $ (13.7) $ (6.1) $ (19.8) The following table presents amortization expense of intangible assets for the years ended December 31, 2020 and 2019: 2020 2019 PPAs $ 22.5 $ 26.4 Fuel supply agreements (0.4) (0.4) Total amortization $ 22.1 $ 26.0 The following table presents estimated future amortization expense for the next five years: Year Ended December 31, 2021 $ 20.2 2022 15.9 2023 12.6 2024 12.6 2025 12.6 The weighted average remaining amortization period related to our intangible assets and liabilities was 8.1 years as of December 31, 2020. |
Other long-term liabilities
Other long-term liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Other long-term liabilities | |
Other long-term liabilities | 11. Other long-term liabilities Other long-term liabilities consist of the following at December 31: 2020 2019 Long-term contract liability $ 0.2 $ 0.2 Net pension liability 3.1 1.2 Accrued LTIP and director share units 1.5 1.6 Other 1.4 1.7 $ 6.2 $ 4.7 The following table is a rollforward of asset retirement obligations for the years ended December 31: 2020 2019 Asset retirement obligations beginning of year $ 51.5 $ 49.2 Accretion and change in estimate of asset retirement obligation (1.3) 2.3 Costs incurred (2.5) (1.0) Translation adjustments 0.4 1.0 Asset retirement obligations, end of year $ 48.1 $ 51.5 |
Long-term debt
Long-term debt | 12 Months Ended |
Dec. 31, 2020 | |
Long-term debt excluding debentures | |
Long-term debt | 12. Long-term debt Long-term debt consists of the following: December 31, December 31, 2020 2019 Interest Rate Recourse Debt: Senior secured term loan facility, due 2025 (1) $ 307.5 $ 380.0 LIBOR (2) plus 2.50 % Senior unsecured notes, due June 2036 (Cdn$210.0) 164.9 161.7 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3) 14.8 18.7 LIBOR plus 1.61 % Less: unamortized discount (3.5) (5.8) Less: unamortized deferred financing costs (3.9) (4.7) Less: current maturities (95.7) (76.4) Total long-term debt $ 384.1 $ 473.5 Current maturities consist of the following: December 31, December 31, 2020 2019 Interest Rate Current Maturities: Senior secured term loan facility, due 2025 (1) $ 93.0 $ 72.5 LIBOR (2) plus 2.50 % Cadillac term loan, due 2025 (3) 2.7 3.9 LIBOR plus 1.61 % Total current maturities $ 95.7 $ 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 Credit Agreement and disclosed below. The portion of the Term Loan classified as current is based on principal payments required to reduce the aggregate principal amount of Term Loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. (2) LIBOR cannot be less than 1.00% . We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $307.5 million remaining aggregate borrowings under our Term Loan at December 31, 2020. See Note 15, Accounting for derivative instruments and hedging activities, for further details. On January 31, 2020, the repricing of the Term Loan became effective, reducing the interest rate to LIBOR plus 2.50% with no change to the 1.00% LIBOR floor. The maturity date for the Term Loan was also extended 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) replacement. (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 15, Accounting for derivative instruments and hedging activities , for further details. Principal payments on the maturities of our debt due in the next five years and thereafter are as follows: 2021 $ 95.7 2022 109.3 2023 63.3 2024 39.7 2025 14.3 Thereafter 164.9 $ 487.2 Credit Facilities On April 13, 2016, APLP Holdings, our wholly-owned subsidiary, entered into new Senior Secured Credit Facilities, comprising $700 million in aggregate principal amount of Senior Secured Term Loan facilities (the “Term Loan”) and $200 million in aggregate principal amount of senior secured credit facilities (the “Revolver” and together with the Term Loan, the “Credit Facilities”). At December 31, 2020, $307.5 million of the Term Loan is outstanding and letters of credit in an aggregate face amount of $77.1 million are issued (but not drawn) pursuant to the revolving commitments under the Revolver and used (i) to fund a debt service reserve in an amount equivalent to six months of debt service, and (ii) to support contractual credit support obligations of APLP Holdings and its subsidiaries and of certain other affiliates of the Company. Borrowings under Credit Facilities are available in U.S. dollars and Canadian dollars and, at inception, bore interest at a rate equal to the Adjusted Eurodollar Rate, the Base Rate or the Canadian Prime Rate as applicable, plus an applicable margin between 4.00% and 5.00% that varied depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. In April 2017, the repricing of the Credit Facilities became effective reducing the interest rate margin on the Term Loan and Revolver by 0.75% to LIBOR plus 4.25%. In October 2017, a second repricing reduced the interest rate margin on the Credit Facilities by another 0.75% to LIBOR plus 3.50%. In April 2018, a third repricing reduced the interest rate margin on the Credit Facilities by an additional 0.50% to LIBOR plus 3.00% and in October 2018, a fourth repricing reduced the interest rate margin on the Credit Facilities by 0.25% to LIBOR plus 2.75%. In January 2020, APLP Holdings completed the repricing of the $307.5 million Term Loan and 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. 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) replacement. 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. For the year ended December 31, 2020, we recorded $0.8 million of new deferred financing costs associated with the amendment, which will be amortized over the remaining terms of the Term Loan and the Revolver. Additionally, we wrote off $0.5 million of existing deferred financing costs to interest expense. In March 2020, APLP Holdings executed an amendment to the Revolver providing for an extension of the Revolver maturity date to April 2025, to coincide with the maturity date of the Term Loan. Both the Revolver and the Term Loan are at our APLP Holdings subsidiary. As of December 31, 2020, we had no borrowings under the Revolver and utilized $77.1 issued in 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. As a result of the extension, for the year ended December 31, 2020, we recorded $0.9 million of new deferred financing costs, which will be amortized over the remaining term of the Revolver. The Term Loan includes a 3% original issue discount. Letters of credit are available to be issued under the Revolver until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. In addition to paying interest on outstanding principal under the Credit Facilities, APLP Holdings is required to pay a commitment fee of 0.75% times the unused commitments under the Revolver. The Credit Facilities are secured by a pledge of the equity interests in APLP Holdings and certain of its subsidiaries, guaranties from certain of the subsidiaries of APLP Holdings (the “Subsidiary Guarantors”), a downstream guarantee from the Company, a limited recourse guaranty from Atlantic Power GP II, Inc., the entity that holds all of the equity interest in APLP Holdings, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of APLP Holdings and its subsidiaries (subject to certain exceptions), and certain other assets. The Credit Facilities also have the benefit of a debt service reserve account, which is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. The reserve requirement is maintained utilizing a letter of credit. APLP, a wholly-owned, indirect subsidiary of the Company, is a party to an existing indenture governing its Cdn$210 million aggregate principal amount of MTNs that prohibits APLP (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, APLP Holdings has granted an equal and ratable security interest in the collateral package securing the Credit Facilities in favor of the trustee under the indenture governing the MTNs for the benefit of the holders of the MTNs. The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The negative covenants include a requirement that APLP Holdings and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) of 4.25:1.00 at December 31, 2020 through March 31, 2023, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 3.5:1.00 at December 31, 2020 to 4.00:1.00 through March 31, 2023. At December 31, 2020, we were in compliance with these covenants. In addition, the Credit Agreement includes customary restrictions and limitations on APLP Holdings’ and its subsidiaries’ ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to certain exceptions and other customary carve-outs and various thresholds. Specifically, APLP Holdings may be restricted from making dividend payments or other distributions to Atlantic Power Corporation, and APLP and its subsidiaries may be prohibited from making dividends or distributions to Atlantic Power Preferred Equity Limited shareholders in the event of a covenant default or if APLP Holdings fails to achieve a target principal amount on the new Term Loan that declines quarterly based on a predetermined specified schedule. Under the Credit Agreement, if a Change of Control (as defined in the Credit Agreement) occurs, unless APLP Holdings elects to make a voluntary prepayment of the Term Loan under the Credit Facilities, it will be required to offer each electing lender a prepayment of such lender’s term loan under the Credit Facilities at a price equal to 101% of par. In addition, in the event that APLP Holdings elects to repay, prepay, refinance or replace all or any portion of the Term Loan within six months from the repricing date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid, refinanced or replaced. The Credit Agreement also contains a mandatory amortization feature and other mandatory prepayment provisions, including prepayments: ● from the proceeds of asset sales (except from the sale proceeds of certain excluded projects), insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and ● with respect to excess cash flows, to be 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 Credit Facilities and the MTNs, funding of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Credit Agreement, 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 Term Loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Failure to achieve the specified target principal amount for any quarter does not constitute a default by APLP Holdings. Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect, non-payment or acceleration of other material debt of APLP Holdings and its subsidiaries, bankruptcy, material judgments rendered against APLP Holdings or certain of its subsidiaries, certain ERISA or regulatory events, a Change of Control of APLP Holdings (solely with respect to the Revolver), or defaults under certain guaranties and collateral documents securing the Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods. Notes of the Partnership The Partnership has outstanding Cdn$210.0 million ($164.9 million as of December 31, 2020) aggregate principal amount of 5.95% senior unsecured notes, due June 2036 (MTNs). Interest on the MTNs is payable semi-annually at 5.95%. Pursuant to the terms of the MTNs, we must meet certain financial and other covenants, including a financial covenant generally based on the ratio of debt to capitalization of the Partnership. At December 31, 2020, we were in compliance with these covenants. The MTNs are guaranteed by Atlantic Power Corporation and APPEL, an indirect, wholly-owned subsidiary acquired in connection with the acquisition of the Partnership. Non-Recourse Debt Project-level debt at 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 loans have certain financial covenants that must be met in order to distribute available cash. At December 31, 2020, all of our projects 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 the debt is not callable or subject to acceleration under the terms of their debt agreements. |
Convertible debentures
Convertible debentures | 12 Months Ended |
Dec. 31, 2020 | |
Convertible Debentures | |
Long-term debt | 13. Convertible debentures The following table provides details related to outstanding convertible debentures: December 31, December 31, 2020 2019 6.00% Debentures due January 2025 (Series E) (Cdn$115.0 million) $ 90.3 $ 88.5 Less: Unamortized deferred financing costs (3.2) (3.8) Less: Unamortized discount (3.0) (3.6) Total current and long-term convertible debentures $ 84.1 $ 81.1 On April 10, 2019, we redeemed, in full, the aggregate principal amount of Cdn$24.7 million of the outstanding 6.00% Debentures due December 2019 (the “Series D Debentures”) and paid accrued interest of Cdn$0.4 million. Series E Debentures On January 29, 2018, we closed the Series E Debentures Offering of Cdn $100 million aggregate principal amount of Series E Debentures. We also granted the underwriters the option to purchase up to an additional Cdn $15 million aggregate principal amount of Series E Debentures at any time up to 30 days after the date of closing of the Series E Debentures offering to cover over-allotments. The underwriters exercised that option, for the full Cdn $15 million aggregate principal amount, on February 2, 2018. The Series E Debentures have a maturity date of January 31, 2025. The Series E Debentures bear interest at a rate of 6.00% per year, and are convertible into our common shares at an initial conversion rate of approximately 238.0952 common shares per Cdn $1,000 principal amount, representing a conversion price of Cdn $4.20 per common share. The Series E Debentures may not be redeemed by the Company prior to January 31, 2021 (except in certain limited circumstances following a change of control). On and after January 31, 2021 and prior to January 31, 2023, the Series E Debentures may be redeemed by us, in whole or in part from time to time, on not more than 60 days and not less than 30 days prior notice at a redemption price equal to their principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption, provided that the daily volume-weighted average trading price of our common shares on the TSX, averaged for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided, is not less than 125% of the conversion price at the time notice of redemption is given. On and after January 31, 2023 and prior to the maturity date, the Series E Debentures may be redeemed in whole or in part from time to time, on not more than 60 days and not less than 30 days prior notice, at a redemption price equal to their principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption. The Series E Debentures are our direct, subordinated, unsecured obligations and rank equally with the other series of debentures and with all other future subordinated unsecured indebtedness and rank subordinate to all of our existing and future senior indebtedness. On the initial closing date, we received net proceeds from the Series E Debentures offering, after deducting the underwriting fee and expenses, of approximately Cdn$94.7 million. We received an additional Cdn$14.4 million of net proceeds from the exercise of the over-allotment option. On March 2, 2018, we redeemed all of the $42.5 million remaining principal amount of Series C Debentures with the use of a portion of the proceeds from the Series E Debentures Offering. On March 3, 2018, we redeemed Cdn$56.2 million principal amount of the Series D Debentures with the remaining proceeds from the Series E Debentures Offering. Series E Conversion Option We assessed the conversion option of the Series E Debentures and determined it should be separated from the host instrument and accounted for as an embedded derivative liability as the conversion option is in a currency different from our functional currency. Changes in the fair value of the conversion option derivative are recorded in the consolidated statements of operation. The conversion option derivative was initially measured at fair value ($4.7 million), with the host contract carried at a value equal to the difference between the carrying value of the Series E Debenture and the fair value of the derivative. Accordingly, no gain or loss was recorded on the initial measurement of the derivative. The fair value of the conversion option derivative liability was $1.5 million and $3.2 million at December 31, 2020 and December 31, 2019, respectively. The portion of the proceeds allocated to the separated derivative also created a discount of $4.7 million, which will be amortized to interest expense over the maturity period of the Series E Debentures. For additional information, see Note 15, Accounting for derivative instruments and hedging activities. |
Fair value of financial instrum
Fair value of financial instruments | 12 Months Ended |
Dec. 31, 2020 | |
Fair value of financial instruments | |
Fair value of financial instruments | 14. Fair value of financial instruments The estimated carrying values and fair values of our recorded financial instruments related to operations are as follows: December 31, 2020 2019 Carrying Carrying Amount Fair Value Amount Fair Value Long-term debt, including current portion $ 487.2 $ 539.0 $ 560.4 $ 589.5 Convertible debentures 90.3 94.6 88.5 93.0 At both December 31, 2020, and December 31, 2019, fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates. Our financial instruments that are recorded at fair value have been classified into levels using a fair value hierarchy. The three levels of the fair value hierarchy are defined below: Level 1—Unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Financial assets utilizing Level 1 inputs include active exchange-traded securities. Level 2—Quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data. Level 3—Unobservable inputs from objective sources. These inputs may be based on entity-specific inputs. Level 3 inputs include all inputs that do not meet the requirements of Level 1 or Level 2. The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of December 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. December 31, 2020 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 38.8 $ — $ — $ 38.8 Restricted cash 7.1 — — 7.1 Derivative instruments asset — 0.4 — 0.4 Total $ 45.9 $ 0.4 $ — $ 46.3 Liabilities: Derivative instruments liability $ — $ 17.6 $ 1.5 $ 19.1 Total $ — $ 17.6 $ 1.5 $ 19.1 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 For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy. The fair values of our derivative instruments 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 December 31, 2020, the credit valuation adjustments resulted in a $0.5 million net increase in fair value, which consists of a $0.1 million pre-tax gain in other comprehensive income and a $0.4 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 carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature. The fair value of long-term debt and convertible debentures was determined using quoted market prices, as well as discounting the remaining contractual cash flows using a rate at which we could issue debt with a similar maturity as of the balance sheet date. 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 to fair value of the conversion option derivative. The following table reconciles, for the year ended December 31, 2020, the beginning and ending balances for the conversion option derivative liability that is recognized at fair value in the consolidated financial statements, using significant unobservable inputs: Fair value Year Ended December 31, 2020 Beginning balance of liability at January 1, 2020 $ 3.2 Total unrealized gain (1.8) Currency translation loss 0.1 Ending balance of liability at December 31, 2020 $ 1.5 |
Accounting for derivative instr
Accounting for derivative instruments and hedging activities | 12 Months Ended |
Dec. 31, 2020 | |
Accounting for derivative instruments and hedging activities | |
Accounting for derivative instruments and hedging activities | 15. 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 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 (loss) earnings. The ineffective portion of a cash flow hedge is immediately recognized in (loss) earnings. For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in (loss) earnings. 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 consolidated balance sheets at fair value and the changes in its fair market value is recorded in the consolidated statements of operations. We 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. On May 15, 2020, we also entered into natural gas purchase agreements at our Morris project for approximately 700,000 MMBtu to effectively mitigate seasonal fluctuations of future natural gas prices from January 2021 through February 2021. This contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value. Changes in the fair market value of this contract are recorded in the consolidated statement of operations. 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 consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations. We have entered into various natural gas swaps to effectively fix the price of 12.4 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 2021 through 2023. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2020. Changes in the fair market value of these contracts are recorded in the 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 December 31, 2020, these agreements totaled $307.5 million notional amount of the remaining $307.5 million aggregate principal amount of borrowings under the Term loan. These interest rate swap agreements expire at various dates through March 31, 2022. Borrowings under the $700.0 million Term Loan bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 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 MTNs due June 23, 2036. Principal and interest payments for our Term Loan 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 consolidated statements of operations. As of December 31, 2020, we have no foreign currency forward contracts. 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 the NPNS exemption at December 31, 2020 and December 31, 2019: December 31, December 31, Units 2020 2019 Natural gas swaps Natural Gas (MMBtu) 12.4 16.3 Gas purchase agreements Natural Gas (Gigajoules) 4.0 6.4 Interest rate swaps Interest (US$) 122.3 468.4 Fair value of derivative instruments We have elected to 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: December 31, 2020 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.6 Interest rate swaps long-term — 1.0 Total derivative instruments designated as cash flow hedges — 1.6 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 4.1 Interest rate swaps long-term — 0.9 Natural gas swaps current — 0.8 Natural gas swaps long-term — 1.9 Gas purchase agreements current 0.4 4.0 Gas purchase agreements long-term — 4.3 Convertible debenture conversion option — 1.5 Total derivative instruments not designated as cash flow hedges 0.4 17.5 Total derivative instruments $ 0.4 $ 19.1 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 (“OCI”) balance attributable to derivative financial instruments designated as a hedge, net of tax: Interest Rate Year Ended December 31, 2020 Swaps Accumulated OCI balance at January 1, 2020 $ 1.6 Change in fair value of cash flow hedges (0.5) Realized from OCI during the period 0.5 Accumulated OCI balance at December 31, 2020 $ 1.6 Settlements expected to be recognized from OCI in expense in the next 12 months, net of $0.1 million of tax $ 0.5 Interest Rate Year Ended December 31, 2019 Swaps Accumulated OCI balance at January 1, 2019 $ 1.6 Change in fair value of cash flow hedges (0.3) Realized from OCI during the period 0.3 Accumulated OCI balance at December 31, 2019 $ 1.6 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) Year Ended December 31, recognized in income 2020 2019 Gas purchase agreements Fuel $ 8.3 $ 8.2 Natural gas swaps Fuel 2.5 0.9 Interest rate swaps Interest, net 5.0 (3.2) 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 gain (loss) Year ended December 31, recognized in income 2020 2019 Natural gas swaps Change in fair value of derivative instruments $ 3.4 $ (4.6) Gas purchase agreements Change in fair value of derivative instruments 5.4 3.2 Interest rate swaps Change in fair value of derivative instruments (2.0) (7.5) 6.8 (8.9) Convertible debenture conversion option Other (income) expense, net (1.8) 1.8 Foreign currency forwards Foreign exchange loss $ — $ — |
Income tax expense
Income tax expense | 12 Months Ended |
Dec. 31, 2020 | |
Income tax expense | |
Income tax expense | 16. Income tax expense The following table summarizes the current and deferred portions of the net income tax (benefit) expense by jurisdiction: Year Ended December 31, 2020 2019 U.S. Canada U.S. Canada Current income tax expense $ 2.8 $ 2.8 $ 1.9 $ 3.0 Deferred income tax (benefit) expense (28.1) (1.7) 7.7 (2.8) Total income tax (benefit) expense, net $ (25.3) $ 1.1 $ 9.6 $ 0.2 The following is a reconciliation of the income taxes calculated at the Canadian enacted statutory rate of 27% for the years ended December 31, 2020 and 2019, respectively, to the provision for income taxes in the consolidated statements of operations: Year Ended December 31, 2020 2019 U.S. Canada U.S. Canada Computed income tax expense (benefit) at Canadian statutory rate $ 11.2 $ 2.1 $ (2.2) $ (7.0) (Decreases) increases resulting from: Operating in countries with different income tax rates (0.3) — 0.1 — 10.9 2.1 (2.1) (7.0) Change in valuation allowance (39.7) (0.5) (2.2) 7.9 (28.8) 1.6 (4.3) 0.9 Dividend withholding tax and other cash taxes 1.8 0.2 1.1 0.2 Foreign exchange — (0.6) 1.7 Changes in tax rates (0.1) — 2.2 — Changes in estimates due to tax filings 3.0 — (0.1) (0.2) Capital gain on intercompany notes — 0.2 0.1 — Impairments — — 7.7 — Other (1.2) (0.3) 2.9 (2.4) 3.5 (0.5) 13.9 (0.7) Income tax (benefit) expense $ (25.3) 1.1 $ 9.6 $ 0.2 The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2020 and 2019 are presented below: Year Ended December 31, 2020 2019 Deferred tax assets: Loss carryforwards $ 123.9 $ 135.9 Capital loss carryforwards 35.3 35.8 Interest expense limitation carryforwards - 9.7 Finance and share issuance costs - 0.1 Tax credits 1.4 1.4 Stock-based compensation 2.4 2.4 Derivative contracts 3.8 5.7 Other long-term notes 2.3 — Other 3.1 0.9 Total deferred tax assets 172.2 191.9 Less: Valuation allowance (105.2) (145.4) 67.0 46.5 Deferred tax liabilities: Intangible assets (22.0) (21.9) Property, plant and equipment (22.0) (31.2) Basis difference in joint ventures (5.8) (5.4) Other long-term investments - (1.3) Total deferred tax liabilities (49.8) (59.8) Net deferred tax asset (liability) $ 17.2 $ (13.3) Year Ended December 31, Net deferred tax asset (liability) by jurisdiction 2020 2019 U.S. Federal and State $ 4.5 $ (23.7) Canada 12.7 10.4 Net deferred tax asset (liability) $ 17.2 $ (13.3) Income tax benefit for the year ended December 31, 2020 was $24.2 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 27%, was $13.3 million. The primary item impacting the tax rate for the year ended December 31, 2020 was a net decrease to our valuation allowances of $40.2 million, consisting of $0.5 million decreases in Canada and $39.7 million decreases in the United States. As of December 31, 2020, in the United States our deferred tax assets were primarily the result of net operating losses. For the year ended December 31, 2020, we recorded a net valuation allowance release of $39.7 million in the United States on the basis of management's reassessment of the amount of its deferred tax assets that are more likely than not to be realized. As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. As of December 31, 2020, in part because in the current year we achieved three years of cumulative pre-tax income in the United States federal tax jurisdiction, management determined that there is sufficient positive evidence to conclude that it is more likely than not that deferred taxes of $39.7 million are realizable. We reduced the valuation allowances accordingly. Any remaining valuation allowances in the United States is related to tax credits and a portion of state net operating losses that were determined to be currently unrealizable based on our expected ability to generate income on remaining purchase price agreements in certain state jurisdictions. Valuation allowances remain on certain net operating losses in Canada. In addition, the rate was further impacted by $0.6 million relating to foreign exchange. These items were offset by $3.0 million related to changes in estimates due to tax filings and $0.3 million of other permanent differences. Income tax expense for the year ended December 31, 2019 was $9.8 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 27%, was $9.2 million. The primary items impacting the tax rate for the year ended December 31, 2019 were $7.7 million related to impairments and a net increase to our valuation allowances of $5.7 million, consisting of $7.9 million increases in Canada and $2.2 million decreases in the United States. In addition, the rate was further impacted by $2.2 million related to changes in tax rates, $1.7 million relating to foreign exchange, $1.3 million relating to withholding and state taxes and $0.4 million of other permanent differences. As of December 31, 2020, we have recorded a valuation allowance of $105.2 million. This amount is comprised primarily of provisions against available 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 asset will be realized. The ultimate realization of the deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies. As of December 31, 2020, we had the following net operating loss carryforwards that are scheduled to expire in the following years: U.S. Canada Total 2029 $ - $ 19.9 $ 19.9 2030 - - - 2031 25.4 - 25.4 2032 13.4 6.0 19.4 2033 20.6 24.0 44.6 2034 122.3 9.3 131.6 2035 154.1 - 154.1 2036 17.0 20.7 37.7 2037 16.7 9.0 25.7 2038 - 10.3 10.3 2039 - 7.2 7.2 2040 - 1.2 1.2 $ 369.5 $ 107.6 $ 477.1 |
Equity compensation plans
Equity compensation plans | 12 Months Ended |
Dec. 31, 2020 | |
Equity compensation plans | |
Equity compensation plans | 17. Equity compensation plans Long-term incentive plan (“LTIP”) The following table summarizes the changes in outstanding LTIP notional shares during the years ended December 31, 2020 and 2019: Grant Date Weighted-Average Notional Shares Fair Value per Notional Share Outstanding at December 31, 2018 3,952,201 $ 2.09 Granted 1,724,081 2.72 Vested and redeemed (2,071,335) 2.10 Forfeitures (26,855) 2.17 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 (31,929) 2.42 Outstanding at December 31, 2020 3,710,340 $ 2.45 On March 29, 2019, the compensation committee of our board of directors determined that all notional shares granted under the LTIP held by non-officer employees will be settled in cash following vesting, rather than two-thirds one-third The total grant date fair value of all outstanding notional shares under the LTIP was $9.1 million and $8.5 million for the years ended December 31, 2020 and 2019. The weighted average remaining vesting term for outstanding notional shares was 1.7 years at December 31, 2020. Approximately $3.0 million of total unrecognized compensation expense is expected to be recognized over the term of the outstanding LTIP shares. Compensation expense related to LTIP was $4.1 million and $4.9 million for the years ended December 31, 2020 and 2019, respectively. Cash payments made for vested notional shares were $3.3 million and $2.1 million for the years ended December 31, 2020 and 2019, respectively. Transition Equity Participation Agreement We also have 269,952 transition notional shares outstanding at December 31, 2020 under the Transition Equity Participation Agreement with James J. Moore, Jr. These notional shares will vest on or any time after January 22, 2017 if the weighted average Canadian dollar closing price of our common shares on the TSX for a period of at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015 (Cdn$3.18) by at least 50% (Cdn$4.77). These notional shares will also vest in the event that Mr. Moore is terminated without cause, resigns for good reason, retirement after attaining the age of 62 or dies |
Employee benefit plans
Employee benefit plans | 12 Months Ended |
Dec. 31, 2020 | |
Employee benefit plans | |
Employee benefit plans | 18. Employee benefit plans Defined benefit pension plan We sponsor and operate a defined benefit pension plan that is available to certain legacy employees of Atlantic Power Limited. The Atlantic Power Services Canada LP Pension Plan (the “Plan”) is maintained solely for certain eligible legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee contributions. We expect to contribute Cdn$0.5 million to the pension plan in 2021. The net annual periodic pension cost related to the pension plan for the years ended December 31, 2020 and 2019 includes the following components: 2020 2019 Service cost benefits earned $ 0.3 $ 0.3 Interest cost on benefit obligation 0.4 0.5 Expected return on plan assets (0.7) (0.7) Amortization of actuarial loss 0.1 — Settlements — 0.3 Net period benefit cost $ 0.1 $ 0.4 A comparison of the pension benefit obligation and related plan assets for the pension plan at December 31 is as follows: 2020 2019 Projected benefit obligation at January 1 $ (14.1) $ (13.2) Service cost (0.3) (0.3) Interest cost (0.4) (0.5) Actuarial loss (2.3) (2.0) Employee contributions (0.1) (0.1) Benefits paid 0.3 0.2 Settlements — 2.4 Foreign currency adjustment (0.5) (0.6) Projected benefit obligation at December 31 (17.4) (14.1) Fair value of plan assets at January 1 $ 12.9 $ 12.0 Actual return on plan assets 1.2 2.0 Employer contributions 0.2 0.8 Employee contributions 0.1 0.1 Benefits paid (0.3) (0.2) Settlements — (2.4) Foreign currency adjustment 0.2 0.6 Fair value of plan assets at December 31 14.3 12.9 Funded status at December 31-excess of obligation over assets $ (3.1) $ (1.2) Amounts recognized in the balance sheet at December 31 were as follows: 2020 2019 Non-current liabilities $ 3.1 $ 1.2 Amounts recognized in accumulated OCL that have not yet been recognized as components of net periodic benefit cost were as follows, net of tax: 2020 2019 Unrecognized loss $ (3.1) $ (1.7) The following table presents the balances of significant components of the pension plan: 2020 2019 Projected benefit obligation $ 17.4 $ 14.1 Accumulated benefit obligation 16.4 12.9 Fair value of plan assets 14.3 12.9 The market-related value of the pension plan’s assets is the fair value of the assets. Plan assets are invested in a common collective trust which totaled $14.3 million and $12.9 million for the years ended December 31, 2020 and 2019, respectively. We determine the level in the fair value hierarchy within which the fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the common/collective trust is valued at a fair value which is equal to the sum of the market value of the fund’s investments, and is categorized as Level 2. There are no investments categorized as Level 1 or 3. The following table presents the significant assumptions used to calculate our benefit obligations: 2020 2019 Weighted-Average Assumptions Discount rate 2.50 % 3.25 % Rate of compensation increase 2.0 % 2.0 % The following table presents the significant assumptions used to calculate our benefit expense: 2020 2019 Weighted-Average Assumptions Discount rate 3.3 % 4.0 % Rate of return on plan assets 5.5 % 5.8 % Rate of compensation increase 2.0 % 2.0 % We use December 31 as the measurement date for the Plan, and we set the discount rate assumptions on an annual basis on the measurement date. This rate is determined by management based on information agreed with our actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of the year ended December 31, 2020 and 2019, were based on the CIA / Fiera curve, which was designed by the Canadian Institute of Actuaries and Fiera Capital Investment Management Inc. to provide a means for sponsors of Canadian plans to value the liabilities of their pension and postretirement benefit plans. The CIA / Fiera curve is a hypothetical yield curve represented by extrapolating the corporate AA-rated yield curve beyond 10 years using yields on provincial AA bonds with a spread added to the provincial AA yields to approximate the difference between corporate AA and provincial AA credit risk. The CIA / Fiera curve utilizes this approach because there are very few corporate bonds rated AA or above with maturities of 10 years or more in Canada. We employ a balanced total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, and the plan’s funded status. Plan assets in the common collective trust are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across Canadian, U.S. and other international equities, as well as among growth, value and small and large capitalization stocks. The pension plan assets weighted average allocations in the common collective trust were as follows: 2020 2019 Canadian equity 31 % 30 % U.S. equity 14 % 14 % International equity 17 % 14 % Canadian fixed income 38 % 39 % Real estate equities — % 3 % 100 % 100 % Our expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter, are as follows in Cdn$: Years ending December 31, 2021 Cdn$ 0.5 2022 0.5 2023 0.6 2024 0.6 2025 0.6 2026-2030 4.0 Defined Contribution Plans We maintain a 401(k) retirement savings plan, registered retirement savings plan, and another defined contribution plan for the benefit of our eligible employees. Substantially all of our employees who meet certain service and age requirements are eligible to participate in these plans. Our plan documents provide that any matching contributions by us are discretionary. We have made or accrued matching contributions to these plans of $1.5 million and $1.3 million for the years ended December 31, 2020 and 2019, respectively. |
Common shares
Common shares | 12 Months Ended |
Dec. 31, 2020 | |
Common shares. | |
Common shares | 19. Common shares Our common shares have no par value and unlimited authorization. We had 89,222,568 and 108,675,294 common shares issued and outstanding December 31, 2019 , respectively. Stock Repurchase Program During the year ended December 31, 2020, we repurchased and canceled 7,540,105 common shares at a total cost of approximately $15.8 million under an NCIB that expired on December 30, 2020. On December 31, 2020, we commenced a new 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, 2021 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. Under the NCIBs, we may purchase up to a total of 8,554,391 common shares based on 10% of our public float as of December 18, 2020 and we are limited to daily purchases of 10,420 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. 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 U.S. in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval. 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 purchases, including pursuant to one or more “Rule 10b5-1 plans” pursuant to such provision under the Exchange Act, as amended, 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. On May 1, 2020, the Company completed a SIB for its common shares, repurchasing We repurchased and cancelled 12,500,000 common shares under the SIB at a total cost of $25.8 million, including transaction costs, upon its expiration on April 30, 2020. Renewal of Shelf Registration Statement On August 24, 2020, we filed a shelf registration statement on Form S-3, which was declared effective by the SEC on August 25, 2020 (the “Shelf Registration Statement”), and is available for use for three years in the United States. The Shelf Registration Statement allows the Company to sell from time to time up to $250 million of common shares, debt securities, warrants, subscription receipts or units comprised of any combination of these securities, for its own account in one or more offerings. We also filed a base short-form prospectus dated August 24, 2020 qualifying the distribution of such securities concurrently with Canadian securities regulators. |
Preferred shares issued by a su
Preferred shares issued by a subsidiary company | 12 Months Ended |
Dec. 31, 2020 | |
Preferred shares issued by a subsidiary company. | |
Preferred shares issued by a subsidiary company | 20. Preferred shares issued by a subsidiary company In 2007, a subsidiary acquired in our acquisition of the Partnership issued 5.0 million 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”) priced at Cdn$25.00 per share. Cumulative dividends are payable on a quarterly basis. The Series 1 Shares are redeemable by the subsidiary company at Cdn$25.00 per share, plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2020, there were 3,465,706 Series 1 Shares outstanding. In 2009, a subsidiary company acquired in our acquisition of the Partnership issued 4.0 million 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the “Series 2 Shares”) priced at Cdn$25.00 per share. The Series 2 Shares pays a fixed dividend when declared. The dividend on the Series 2 Shares is cumulative. Beginning on December 31, 2014 and each fifth-year anniversary thereafter, (i) the rate on the Series 2 shares is reset at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%, and (ii) holders of Series 2 Shares have the right, subject to certain limitations, to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the “Series 3 Shares”) of the subsidiary. The dividend rate for the Series 2 Shares was reset on December 31, 2019 to 5.74%. The holders of Series 3 Shares are entitled to receive quarterly floating rate dividends, as and when declared by the board of directors of the subsidiary, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill rate and 4.18%. The dividend on the Series 3 Shares is cumulative. The dividend rate for the Series 3 Shares was reset on December 31, 2020 to 4.30%. Beginning on December 31, 2019, and on each fifth-year The Series 2 Shares are redeemable by the subsidiary company at Cdn$25.00 per share, on each fifth-year anniversary date, plus an amount equal to all accrued and unpaid dividends thereon. The Series 3 Shares are redeemable at any time by the subsidiary company at Cdn$25.50 per share, plus an amount equal to all accrued and unpaid dividends thereon. At December 31, 2020, there were 2,441,766 Series 2 Shares and 957,391 Series 3 Shares outstanding. The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are fully and unconditionally guaranteed by us and by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution or winding up of the subsidiary company. If, and for so long as, the declaration or payment of dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares is in arrears, the Partnership will not make any distributions on its limited partnership units and we will not pay any dividends on our common shares. The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are accounted for as a non-controlling interest on our consolidated balance sheets and consolidated statements of operations. The subsidiary company paid aggregate dividends of $6.8 million and $7.4 million for the years ended December 31, 2020 and 2019, respectively. For the year ended December 31, 2020, we repurchased and cancelled 381,794 Series 1 Shares, 62,365 Series 2 Shares and 120,000 Series 3 Shares, respectively for a total cost of $6.4 million. We also repurchased and cancelled preferred shares at a cost of $8.0 million in the year ended December 31, 2019. As a result of the repurchases, losses of $7.4 million and $8.6 million were attributed to the preferred shares of a subsidiary company in the Consolidated Statements of Operations for the years ended December 31, 2020 and 2019, respectively. |
Basic and diluted earnings (los
Basic and diluted earnings (loss) per share | 12 Months Ended |
Dec. 31, 2020 | |
Basic and diluted earnings (loss) per share | |
Basic and diluted earnings (loss) per share | 21. Basic and diluted earnings (loss) per share Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to Atlantic Power Corporation by the 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 (loss) per share is computed in a manner consistent with that of basic earnings (loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of our convertible debentures is calculated using the “if-converted method.” Under the if-converted method, the 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 (loss) 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 (loss) per share. However, these instruments are included in the denominator, when dilutive, for purposes of computing diluted earnings (loss) per share under the treasury stock method. The following table sets forth the diluted net income (loss) and potentially dilutive shares utilized in the per share calculation for the years ended December 31, 2020 and 2019: Basic 2020 2019 Numerator: Net income (loss) attributable to Atlantic Power Corporation $ 74.2 $ (42.6) Denominator: Weighted average basic shares outstanding 95.8 109.3 Basic earnings (loss) per share attributable to Atlantic Power Corporation $ 0.77 $ (0.39) Diluted Numerator: Net income (loss) attributable to Atlantic Power Corporation 74.2 (42.6) Add: convertible debenture interest expense 3.8 — 78.0 (42.6) Denominator: Weighted average basic shares outstanding 95.8 109.3 Share-based compensation 1.7 — Convertible debentures 27.4 — 124.9 109.3 Diluted earnings (loss) per share attributable to Atlantic Power Corporation 0.62 (0.39) 2020 2019 Share-based compensation — 1.5 Convertible debentures — 27.8 Total — 29.3 |
Segment and geographic informat
Segment and geographic information | 12 Months Ended |
Dec. 31, 2020 | |
Segment and geographic information | |
Segment and geographic information | 22. 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. 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 method 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 (loss) is included in the tables below: Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Year Ended December 31, 2020 Project revenues $ 94.5 $ 118.2 $ 58.3 $ 1.0 $ 272.0 Segment assets 202.8 190.8 306.3 147.3 847.2 Goodwill — 6.9 14.4 — 21.3 Capital expenditures 24.1 — 0.6 0.1 24.8 Project Adjusted EBITDA $ 39.9 $ 105.0 $ 45.3 $ (1.5) $ 188.7 Change in fair value of derivative instruments — (8.9) — 2.1 (6.8) Depreciation and amortization 22.7 34.3 19.6 — 76.6 Interest, net 2.7 — — 0.1 2.8 Insurance gain (0.7) — — — (0.7) Other project income — (2.1) — — (2.1) Project income (loss) 15.2 81.7 25.7 (3.7) 118.9 Administration — — — 24.8 24.8 Interest expense, net — — — 42.4 42.4 Foreign exchange loss — — — 5.1 5.1 Other income, net — — — (2.7) (2.7) Net income (loss) before income taxes 15.2 81.7 25.7 (73.3) 49.3 Income tax benefit — — — (24.2) (24.2) Net income (loss) $ 15.2 $ 81.7 $ 25.7 $ (49.1) $ 73.5 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Year Ended December 31, 2019 Project revenues $ 80.0 $ 131.8 $ 68.8 $ 1.0 $ 281.6 Segment assets 222.7 241.0 388.3 83.6 935.6 Goodwill — 6.9 14.4 — 21.3 Capital expenditures 6.8 0.1 0.4 — 7.3 Project Adjusted EBITDA $ 32.7 $ 108.2 $ 55.5 $ (0.3) $ 196.1 Change in fair value of derivative instruments — 1.4 — 7.5 8.9 Depreciation and amortization 23.9 37.2 19.5 0.1 80.7 Interest, net 2.6 (0.1) — — 2.5 Insurance loss 1.0 — — — 1.0 Impairment 55.0 — — — 55.0 Other project expense — 1.2 — — 1.2 Project (loss) income (49.8) 68.5 36.0 (7.9) 46.8 Administration — — — 23.9 23.9 Interest expense, net — — — 44.0 44.0 Foreign exchange loss — — — 11.9 11.9 Other expense, net — — — 1.0 1.0 Net (loss) income before income taxes (49.8) 68.5 36.0 (88.7) (34.0) Income tax expense — — — 9.8 9.8 Net (loss) income $ (49.8) $ 68.5 $ 36.0 $ (98.5) $ (43.8) The table below provides information, by country, about our consolidated operations for each of the years ended December 31, 2020 and 2019 and Property, Plant and Equipment, PPAs and other Intangible and total assets as of December 31, 2020 and 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. Revenue 2020 2019 United States $ 184.9 $ 208.4 Canada 87.1 73.2 Total $ 272.0 $ 281.6 Property, Plant and PPAs and Equipment, net of other intangible assets, net of accumulated depreciation accumulated amortization Total assets 2020 2019 2020 2019 2020 2019 United States $ 351.2 $ 353.9 $ 119.4 $ 142.8 $ 666.4 $ 762.3 Canada 140.6 148.2 0.9 1.5 180.8 173.3 Total $ 491.8 $ 502.1 $ 120.3 $ 144.3 $ 847.2 $ 935.6 Niagara Mohawk Power Corporation, IESO, BC Hydro, Equistar Chemicals L.P. and Georgia Power Company provided 14.8%, 13.8%, 12.5%, 10.9% and 10.4 %, respectively, of total consolidated revenues for the year ended December 31, 2020. Niagara Mohawk Power Corporation, IESO, Equistar Chemicals L.P. and Georgia Power Company provided 19.6%, 12.9%, 12.0% and 11.1 %, respectively, of total consolidated revenues for the year ended December 31, 2019. IESO purchased electricity from the Calstock, Nipigon and Tunis projects and previously purchased electricity from our North Bay and Kapuskasing projects in the Natural Gas segment. BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Hydroelectric and Solid Fuel segments and Niagara Mohawk purchases electricity from the Curtis Palmer project in the Hydroelectric segment. Equistar Chemicals L.P. purchases electricity from the Morris project in the Natural Gas segment and Georgia Power Company purchases electricity from the Piedmont project in the Solid Fuel segment. |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and contingencies | |
Commitments and contingencies | 23. Commitments and contingencies Commitments Management Service Commitments Our Manchief project is operated by a third party under a contract that expires in April 2022. As of December 31, 2020, our commitments under this agreement are estimated as follows: 2021 $ 0.4 2022 0.2 2023 — 2024 — 2025 — Thereafter — $ 0.6 Fuel Supply and Transportation Commitments We have entered into long-term contractual arrangements to procure fuel and transportation services for our projects. We have also entered into long-term arrangements for firm gas sales. The commitments listed below include only contracts for fuel contracts that are not reimbursed or passed through under the terms of the relevant PPAs and are presented net of estimated future gas sales. As of December 31, 2020, our commitments under such outstanding agreements are estimated as follows: 2021 $ 4.2 2022 4.4 2023 — 2024 — 2025 — Thereafter — $ 8.6 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. Reconstruction of Cadillac was completed in late July 2020 and the plant was recommissioned, tested and returned to service on August 20, 2020. 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. 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 Cadillac biomass plant is a component of our Solid Fuel segment. 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 was probable that insurance proceeds would be received in order to repair the facility, we applied accounting for gains and losses on involuntary conversions. Insurance proceeds received in excess of incurred losses were accounted for as gain contingencies. Reimbursements for lost profits, or business interruption losses, were accounted for as a gain contingency because lost profits are not considered an incurred loss. Based on loss estimates and expenses incurred through December 31, 2019, we recorded a $25 million write-down of Cadillac’s property, plant and equipment and a $0.8 million write-down of capital spares inventory during the year ended December 31, 2020. We also recorded a corresponding insurance receivable ( $24.8 million), a component of other current assets, less the $1.0 million property damage deductible, which was recorded as a charge to project other income (loss), because we believed that it was probable we would receive insurance recoveries up to our estimated plant write-down. As the plant was repaired, any costs incurred were capitalized to property, plant and equipment. 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 cumulative insurance receivable of $24.8 million. In December 2020, we executed a final settlement of our insurance claim for the Cadillac plant under which final payments were received from the insurers as of December 31, 2020. We received insurance proceeds of $10.1 million and $29.9 million for the three and twelve months ended December 31, 2020, respectively, bringing the total cumulative proceeds received to $41.2 million. Proceeds were applied against the Cadillac insurance receivable of $13.5 million as of December 31, 2019, reducing the balance to zero as of December 31, 2020. Reimbursements for lost profits, or business interruption losses, were accounted for as a gain contingency. For the three and twelve months ended December 31, 2020, we recorded business interruption proceeds of $9.4 million and $15.6 million, respectively. Insurance recoveries for property losses in excess of incurred losses were accounted for as a gain contingency. For the three and twelve months ended December 31, 2020, we recorded insurance proceeds for property losses in excess of incurred losses of $0.8 million. Insurance recoveries related to business interruption losses and property losses in excess of incurred losses are included in project other income (loss) on our condensed consolidated statements of operations. Balance at Insurance Beginning of Proceeds Insurance Balance at Period Additions Received Gain (Loss) End of Period Insurance recovery receivable: Year ended December 31, 2020 $ 13.5 $ — $ (29.9) $ 16.4 (1) $ — Year ended December 31, 2019 $ — $ 25.8 $ (11.3) $ (1.0) (2) $ 13.5 (1) Represents recoveries for business interruption losses and property losses in excess of incurred losses of $15.6 million and $0.8 million, respectively. Of the $15.6 million recorded for the recovery of business interruption losses, $6.0 million relates to the expected reduction in capacity payments in 2021 under the Cadillac PPA due to the reduced availability of the plant in 2020 during the extended outage. (2) Represents the $1.0 million property damage deductible. 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 December 31, 2020. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2020 | |
Leases | |
Leases | 24. 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 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 for the non-swapped portion of the remaining principal amount. The following table presents the components of lease expense. Year Ended December 31, 2020 2019 Lease cost: (1) Operating lease cost $ 2.1 $ 1.9 Short-term lease cost — 0.1 Sublease income (1.1) (1.2) Total lease cost $ 1.0 $ 0.8 (1) Finance lease costs are immaterial to the Company. The following table presents operating lease maturities and a reconciliation of the undiscounted cash flows to operating lease liabilities. Lease Income from Net lease Payments subleasing payments 2021 $ 2.0 $ (1.1) $ 0.9 2022 1.8 (1.1) 0.7 2023 1.3 (0.7) 0.6 2024 0.2 — 0.2 2025 — — — Thereafter — — — Total operating lease payments $ 5.3 $ (2.9) $ 2.4 Less: present value discount (0.3) Total operating lease liabilities $ 5.0 Lease Payments 2021 $ 0.1 2022 0.1 2023 — Thereafter — Total finance lease payments $ 0.2 Less: amount representing interest (0.1) Total finance lease liabilities $ 0.1 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) Operating cash flows from operating leases $ 1.1 Lease assets obtained in exchange for new lease liabilities (non-cash): Operating $ 0.1 Weighted average remaining lease term (in years): Operating leases 2.7 Finance leases 1.4 Weighted average discount rate - operating leases 3.9 % Weighted average discount rate - finance leases 4.1 % (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 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 As of December 31, 2020, we have ten PPAs accounted for as operating leases 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 one year to twenty-three years . 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 Year Ended December 31, 2020 2019 Solid Fuel $ 65.9 $ 79.1 Natural Gas 25.4 24.4 Hydroelectric 58.3 68.8 $ 149.6 $ 172.3 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 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. |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2020 | |
Subsequent events | |
Subsequent events | 25. Subsequent events |
Summary of significant accoun_2
Summary of significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
Summary of significant accounting policies | |
Principles of consolidation and basis of presentation | (a) The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity (“VIE”), through arrangements that do not involve controlling voting interests. We apply the standard that requires consolidation of VIEs, for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation. |
Cash and cash equivalents | (b) Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased. |
Restricted cash | (c) Restricted cash represents cash, cash equivalents and cash advances that are maintained by the projects or corporate to support payments for maintenance costs, reconstruction costs and meet project level and corporate contractual debt obligations. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. |
Accounts receivable | (d) Accounts receivable are carried at cost. We periodically assesses the collectability of accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and record an allowance for doubtful accounts for the estimated uncollectible amount as appropriate. We had no allowance for doubtful accounts recorded at December 31, 2020 and 2019, respectively. |
Deferred financing costs | (e) Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt, which ranges from 1 to 6 years. The carrying amount of deferred financing costs were recorded on the consolidated balance sheets as net of long-term debt and convertible debentures and was $7.1 million and $8.5 million at December 31, 2020 and 2019, respectively. Interest expense from the amortization of deferred financing costs for the years ended December 31, 2020 and 2019 was $2.6 million and $3.2 million, respectively. |
Inventory | (f) Inventory represents spare parts, biofuel and natural gas, the majority of which is consumed by our projects in provision of their services, and are valued at the lower of cost and net realizable value. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs. |
Property, plant and equipment | (g) Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset. Significant additions or improvements extending asset lives or increasing generating capacity are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. |
Project development costs and capitalized interest | (h) Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, obtaining a PPA. When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project’s related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. |
Power purchase agreements and intangible assets | (i) Intangible assets include PPAs and fuel supply agreements at our projects acquired as part of business combinations. Carrying amounts for PPAs and fuel supply agreements are based on the fair value assigned in the allocation of the purchase price of the acquired business. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement. |
Investments accounted for by the equity method | (j) We have investments in entities that own power-producing assets with the objective of generating cash flow. The equity method of accounting is applied to such investments in affiliates, which include joint ventures, partnerships, and limited liability companies because the ownership structure prevents us from exercising a controlling influence over the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with 50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships and limited liability companies with greater than 5% ownership because our influence over the investment’s operating and financial policies is considered to be more than minor. Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings of unconsolidated affiliates in the consolidated statements of operations. We apply the nature of distributions method for the classification of our investments accounted for by the equity method in the Consolidated Statements of Cash Flows. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates’ power-producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows. We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets. |
Impairment of long-lived assets, intangible assets and equity method investments | (k) Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset group exceeds its fair value. Our asset groups have been determined to be at the plant level, which is the lowest level in which independent, separately identifiable cash flows have been identified. We also review a project for impairment at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets for impairment. Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its estimated fair value. |
Goodwill | (l) Goodwill: Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination. Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances indicate that would more likely than not reduce the fair value of a reporting unit below its carrying value. In 2020, we changed our annual impairment testing from November 30 to October 31. We made the change to better align the timing of the goodwill impairment test with the timing of our annual planning and budgeting processes and to provide us with adequate time to evaluate goodwill for impairment. This change did not result in the delay, acceleration or avoidance of an impairment charge. We completed our annual impairment testing in the fourth quarter of 2020 and determined that no adjustments to the carrying value of goodwill were necessary. In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and other relevant entity-specific events. If the qualitative assessment determines that an impairment is more likely than not, then we perform a quantitative impairment test. In the quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired. When the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying amount of goodwill, and is recorded in the consolidated statements of operations. We determine the fair value of our reporting units using an income approach with discounted cash flow models (“DCF”), as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery, equity method investment, and goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilize estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of our reporting units. The valuation of long-lived assets, equity method investments and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of an impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts. |
Accounts payable and other accrued liabilities | (m) Accounts payable and other accrued liabilities: Accounts payable consists of amounts due to trade creditors related to our core business operations. These payables include amounts owed to vendors and suppliers for items such as fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, legal contingencies and employee-related costs including payroll, benefits and related taxes. |
Derivative financial instruments | (n) We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We also separate the conversion option of certain convertible debentures from the host instrument and account for it as an embedded derivative liability as the conversion option is in a currency different from our functional currency. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a significant operating cost. We do not enter into derivative financial instruments for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales in the ordinary course of conducting business. This exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying physical commodity. We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains or losses on derivatives designated as a hedge for accounting purposes are deferred and recorded as a component of accumulated other comprehensive income (loss) (“OCI”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings. Derivative financial instruments not designated as a hedge for accounting purposes are measured at fair value with changes in fair value recorded in the consolidated statements of operations. Derivative financial instruments under master netting arrangements are recorded net, when applicable, in the consolidated balance sheets. The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument: Derivative financial instrument Classification of changes in fair value Classification of cash settlements Natural gas swaps Change in fair value of derivative instrument Fuel expense Fuel purchase agreements Change in fair value of derivative instrument Fuel expense Interest rate swaps Change in fair value of derivative instrument Interest expense, net Convertible debenture conversion option Other (income) expense, net NA Foreign currency forward contract Foreign exchange loss Foreign exchange loss |
Income taxes | (o) Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 16 for more information. |
Revenue recognition | (p) We recognize energy sales revenue on a gross basis when electricity and steam are delivered and capacity revenue when capacity is provided under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts with performance obligations to provide electricity, steam and capacity on a predetermined basis. For certain PPAs determined to be operating 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. 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, which have expiration dates ranging from September 2021 to November 2043, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). 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. The following is a description of principal activities from which we generate our revenue. Products and services Nature, timing of satisfaction of performance obligations, and significant payment terms Energy Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations. The price of energy could be contracted under PPAs at set prices or merchant sales based on market merchant price. Energy revenue is also recognized under certain contracts for avoided generation during curtailment periods. Energy revenue is billed and paid on a monthly basis. Energy capacity Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at a negotiated contract price under the applicable PPAs for making installed generation capacity available in order to satisfy reliability requirements or merchant capacity sales based on the market price for such capacity. Energy capacity is billed and paid on a monthly basis. Other revenue includes the following: Steam energy and capacity Steam revenue is recognized upon delivery to the customer. Steam capacity payments under the applicable PPAs are recognized as the amount billable under the respective PPA. Steam capacity is billed and paid on a monthly basis. Waste heat We generate electricity from excess steam provided by a nearby pipeline and its pumping station in the Solid Fuel segment. Waste heat is earned when it is generated and paid as a portion of monthly energy and capacity billing. Ancillary and transmission services We provide ancillary and transmission services to our customers under the terms of our PPAs. These services are billed and paid on a monthly basis. Asset management and operation, operation and maintenance We provide asset management and operation supervision to the Frederickson project, a facility that we jointly own with Puget Sound Energy. We also provide operation and maintenance services to several electric energy customers under the PPAs. All services are billed and paid on a monthly basis. Refer to Note 4, Revenue from contracts, We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases. For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of energy revenue due to variable volume of the generation. When energy is delivered, we recognize lease income in energy revenue. |
Administrative expenses | (q) Administrative expenses include corporate and other expenses primarily for executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments. |
Foreign currency translation and transaction gains and losses | (r) The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of our statements of operations for the period, but are accumulated and reported as a separate component of shareholders’ equity until sale of the net investment in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in our consolidated statements of operations. |
Equity compensation plans | (s) The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan (“LTIP”). Notional shares granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional shares granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Unvested notional shares are entitled to receive dividends, if paid, equal to the dividends per common share during the vesting period in the form of additional notional shares. Unvested shares are subject to forfeiture if the participant is not an employee at the vesting date. We initially recognize compensation expense on the estimated number of notional shares for which the requisite service is expected to be rendered. We have estimated a weighted average forfeiture rate of 11% for all notional share grants under the LTIP. This estimate will be revisited if subsequent information indicates the actual number of notional shares forfeited is likely to differ from previous estimates. Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional shares accounted for as equity awards and the fair value of the award at each balance sheet date for notional shares accounted for as liability awards. |
Asset retirement obligations | (t) The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss. |
Pension | (u) We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the funded status of our defined benefit plan in the consolidated balance sheets in other long-term liabilities and record an offset to other comprehensive income (loss). In addition, we also recognize on an after-tax basis, as a component of other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets, the rate of future compensation increases and retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of our pension obligation or expense recorded. |
Business combinations and Asset Acquisitions | (v) Business combinations are accounted for using the acquisition method of accounting, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred. Asset acquisitions are measured based on their cost to the Company, including transaction costs. Asset acquisition costs, or the consideration transferred by the Company, are assumed to be equal to the fair value of the net assets acquired. If the consideration transferred is cash, measurement is based on the amount of cash the Company paid to the seller as well as transaction costs incurred. Consideration given in the form of nonmonetary assets, liabilities incurred or equity interests issued is measured based on either the cost to the Company or the fair value of the assets or net assets acquired, whichever is more clearly evident. The cost of an asset acquisition is allocated to the assets acquired based on their estimated relative fair values. Goodwill is not recognized in an asset acquisition. |
Concentration of credit risk | (w) The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to the credit-worthiness and payment history of our customers. See Note 22, Segment and geographic information |
Use of estimates | (x) 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 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, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations, and the fair values of acquired assets and liabilities assumed. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. 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. |
COVID-19 Pandemic | (y) There are many uncertainties regarding the ongoing COVID-19 pandemic, and we are closely monitoring the impact of COVID-19 on all aspects of our business, including how it will impact our customers, employees, suppliers, vendors and business partners. 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 the high level of reliability and availability of our plants. We continue to implement strong physical and cybersecurity 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. While COVID-19 did not materially adversely affect our financial results and business operations for the year ended December 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. |
Recently adopted and issued accounting standards | Accounting Standards Adopted in 2020 In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses”(Topic 326), Measurement of Credit Losses on Financial Instruments In August 2018, the FASB issued authoritative guidance 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 was effective for fiscal years beginning after December 15, 2019. The Company has adopted this guidance effective January 1, 2020. Adoption of this guidance did not impact the consolidated financial statements. In August 2018, the FASB issued authoritative guidance 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 was effective for fiscal years beginning after December 15, 2019. The Company has adopted this guidance effective January 1, 2020. Adoption of this guidance did not impact the consolidated financial statements. In August 2018, the FASB issued ASU No. 2018-14, “Compensation -Retirement Benefits -Defined Benefit Plans -General (Subtopic 715-20)” Accounting Standards Not Yet Adopted 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. 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. |
Summary of significant accoun_3
Summary of significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Summary of significant accounting policies | |
Summary of derivative instruments not designated, treatment of changes in fair value and cash settlements | Derivative financial instrument Classification of changes in fair value Classification of cash settlements Natural gas swaps Change in fair value of derivative instrument Fuel expense Fuel purchase agreements Change in fair value of derivative instrument Fuel expense Interest rate swaps Change in fair value of derivative instrument Interest expense, net Convertible debenture conversion option Other (income) expense, net NA Foreign currency forward contract Foreign exchange loss Foreign exchange loss |
Acquisitions and divestments (T
Acquisitions and divestments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
South Carolina Biomass Plant | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of preliminary purchase price allocation for the business combination | Fair values Cash (1) $ 1.4 Accounts receivable 4.3 Inventory 2.9 Property, plant, and equipment 4.0 Intangible assets 2.6 Accounts payable (2.0) Accrued liabilities (0.3) Other liabilities (0.3) Total purchase consideration $ 12.6 (1) The cash acquired was received in October 2019 and has been included in the Cash paid for acquisition, net of cash received within the Statement of Cash Flows. |
Revenue from contracts (Tables)
Revenue from contracts (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from contracts | |
Schedule of disaggregation of revenue | Year Ended December 31, 2020 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 58.8 $ 24.2 $ 54.9 $ — $ 137.9 Energy capacity revenue 34.6 79.2 — — 113.8 Steam energy and capacity revenue — 10.5 — — 10.5 Waste heat revenue 1.0 — — — 1.0 Ancillary and transmission services — 3.1 3.4 — 6.5 Asset management and operation — — — 1.0 1.0 Miscellaneous revenue 0.1 1.2 — — 1.3 94.5 118.2 58.3 1.0 272.0 Year Ended December 31, 2019 Consolidated Solid Fuel Natural Gas Hydroelectric Corporate Total Project revenue: Energy sales $ 41.1 $ 31.0 $ 65.9 $ — $ 138.0 Energy capacity revenue 38.7 86.7 — — 125.4 Steam energy and capacity revenue — 11.7 — — 11.7 Waste heat revenue 0.2 — — — 0.2 Ancillary and transmission services — 4.7 2.9 — 7.6 Asset management and operation — — — 1.0 1.0 Miscellaneous revenue — (2.3) — — (2.3) 80.0 131.8 68.8 1.0 281.6 |
Changes in accumulated other _2
Changes in accumulated other comprehensive income (loss) by component (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Changes in accumulated other comprehensive income (loss) by component | |
Schedule of changes in accumulated other comprehensive income (loss) | Year Ended December 31, 2020 2019 Foreign currency translation Balance at beginning of period $ (140.6) $ (146.4) Other comprehensive income: Foreign currency translation adjustments (1) 2.2 5.8 Balance at end of period $ (138.4) $ (140.6) Pension Balance at beginning and end of period $ (1.7) $ (1.4) Other comprehensive income: Settlement — 0.3 Tax expense — (0.1) Total Other comprehensive income before reclassifications, net of tax — 0.2 Total amount reclassified from accumulated other comprehensive (loss), net of tax (1.4) (0.5) Total other comprehensive (loss) (1.4) (0.3) Balance at end of period $ (3.1) $ (1.7) Cash flow hedges Balance at beginning of period $ 1.6 $ 1.6 Other comprehensive (loss): Net change from periodic revaluations (0.7) (0.5) Tax benefit 0.2 0.2 Total other comprehensive (loss) before reclassifications, net of tax (0.5) (0.3) Net amount reclassified to earnings: Interest rate swaps (2) 0.6 0.4 Tax expense (0.1) (0.1) Total amount reclassified from accumulated other comprehensive income, net of tax 0.5 0.3 Total other comprehensive (loss) — — Balance at end of period $ 1.6 $ 1.6 (1) In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to (loss) earnings. (2) This amount was included in interest expense, net on the accompanying consolidated statements of operations. |
Equity method investments in _2
Equity method investments in unconsolidated affiliates (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Equity method investments in unconsolidated affiliates | |
Schedule of equity method investments | Percentage of Carrying value as of Ownership as of December 31, Entity name December 31, 2020 2020 2019 Frederickson (1) 50% $ 58.9 $ 65.2 Orlando Cogen, LP 50% 2.5 3.6 Chambers Cogen, LP 40% 8.0 9.0 Craven County Wood Energy, LP (2) 50% 8.2 9.5 Grayling Generating Station, LP (2) 30% 7.4 9.3 Total $ 85.0 $ 96.6 (1) We own 50.15% of Frederickson. However, we do not have financial control of the entity. The Frederickson entity is organized under a joint ownership agreement. Under the terms of that agreement, the two owner parties have joint control of the asset and substantive participating rights through the structure of its Owner’s Committee. Each party has equal representation on this committee and unanimous consent is required over all significant decisions of the entity. These significant decisions include, but are not limited to (i) approval of the annual operating plan, annual operating budget, annual capital budget and five-year forecasts, (ii) approval of all expenditures in excess of the approved budget, (iii) adoption of procedures intended to govern the operation and conduct of the facility, and (iv) entering into, amending, supplementing or terminating any project agreement. Disputes between the owners for these significant decisions are subject to independent arbitration. Accordingly, since we do not control the project, Frederickson is accounted for under the equity method of accounting. (2) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . |
Equity (deficit) in earnings (loss) of equity method investments | Year Ended December 31, Entity name 2020 2019 Frederickson $ 8.3 $ 9.1 Orlando Cogen, LP 33.1 33.0 Chambers Cogen, LP 4.4 (46.0) Craven County Wood Energy, LP (1) (1.8) 0.1 Grayling Generating Station, LP (1) (1.1) 0.8 Total earnings (loss) of unconsolidated affiliates 42.9 (3.0) Distributions from equity method investments (54.2) (59.5) Deficit in earnings of equity method investments, net of distributions $ (11.3) $ (62.5) (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . |
Summarized financial position information | 2020 2019 Assets Current assets Frederickson $ 1.9 $ 2.1 Orlando Cogen, LP 7.8 7.8 Chambers Cogen, LP 14.8 14.4 Craven County Wood Energy, LP (1) 2.2 4.4 Grayling Generating Station, LP (1) 2.6 3.3 Non-current assets Frederickson 57.8 63.9 Orlando Cogen, LP 5.1 6.1 Chambers Cogen, LP 44.6 56.5 Craven County Wood Energy, LP (1) 7.9 5.8 Grayling Generating Station, LP (1) 6.5 6.8 $ 151.2 $ 171.1 Liabilities Current liabilities Frederickson $ 0.3 $ 0.3 Orlando Cogen, LP 10.3 10.2 Chambers Cogen, LP 15.8 13.7 Craven County Wood Energy, LP (1) 2.3 0.8 Grayling Generating Station, LP (1) 0.7 0.5 Non-current liabilities Frederickson 0.5 0.5 Orlando Cogen, LP 0.1 — Chambers Cogen, LP 35.6 48.2 Craven County Wood Energy, LP (1) 0.4 — Grayling Generating Station, LP (1) 0.2 0.3 $ 66.2 $ 74.5 (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . |
Summary of operating results | Operating results 2020 2019 Revenue Frederickson $ 29.2 $ 36.0 Orlando Cogen, LP 60.2 61.5 Chambers Cogen, LP 38.4 39.4 Craven County Wood Energy, LP (1) 9.6 4.9 Grayling Generating Station, LP (1) 3.5 2.2 140.9 144.0 Project expenses Frederickson 20.9 26.9 Orlando Cogen, LP 27.0 28.5 Chambers Cogen, LP 32.5 34.6 Craven County Wood Energy, LP (1) 11.4 4.7 Grayling Generating Station, LP (1) 4.5 1.8 96.3 96.5 Project other (income) expenses Frederickson — — Orlando Cogen, LP (0.1) — Chambers Cogen, LP (1.5) (50.9) Craven County Wood Energy, LP (1) — — Grayling Generating Station, LP (1) (0.1) 0.4 (1.7) (50.5) Net income (loss) Frederickson 8.3 9.1 Orlando Cogen, LP 33.1 33.0 Chambers Cogen, LP 4.4 (46.1) Craven County Wood Energy, LP (1) (1.8) 0.2 Grayling Generating Station, LP (1) (1.1) 0.8 Equity in earnings (loss) of unconsolidated affiliates $ 42.9 $ (3.0) (1) In May 2019, we acquired the equity ownership interests held by AltaGas in Craven and Grayling. See Note 3, Acquisitions and divestments . |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Inventory | |
Schedule of inventory | December 31, 2020 2019 Parts and other consumables $ 11.9 $ 12.2 Fuel 6.4 6.4 Total inventory $ 18.3 $ 18.6 |
Property, plant and equipment_2
Property, plant and equipment, net (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Property, plant and equipment, net | |
Schedule of property, plant and equipment, net | December 31, December 31, Depreciable 2020 2019 Lives Land $ 6.4 $ 6.4 Office equipment, machinery and other 6.7 6.5 3 - 10 years Leasehold improvements 2.1 2.1 7 - 15 years Asset retirement obligation 23.6 23.4 1 - 43 years Plant in service 885.1 848.1 1 - 45 years Construction in progress 0.8 7.2 924.7 893.7 Less accumulated depreciation (432.9) (391.6) Total property, plant and equipment, net $ 491.8 $ 502.1 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill.. | |
Schedule of changes in the carrying amount of goodwill | Segment 2020 2019 Curtis Palmer Hydroelectric $ 14.4 $ 14.4 Morris Natural Gas 3.3 3.3 Nipigon Natural Gas 3.6 3.6 Total $ 21.3 $ 21.3 |
PPAs and other definite-lived_2
PPAs and other definite-lived intangible assets and liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
PPAs and other definite-lived intangible assets and liabilities | |
Schedule of components of intangible assets subject to amortization | Assets Other Intangible Assets, Net Power Purchase Agreements Total Gross balances, January 1, 2020 $ 365.6 $ 365.6 Write-off of fully amortized balances (13.5) (13.5) Gross balances, December 31, 2020 352.1 352.1 Less: accumulated amortization (231.8) (231.8) Net carrying amounts, December 31, 2020 $ 120.3 $ 120.3 Other Intangible Assets, Net Power Purchase Agreements Total Gross balances, December 31, 2019 $ 365.6 $ 365.6 Less: accumulated amortization (221.3) (221.3) Net carrying amounts, December 31, 2019 $ 144.3 $ 144.3 Liabilities Power Purchase and Fuel Supply Agreement Liabilities, Net Power Purchase Fuel Supply Agreements Agreements Total Gross balances, December 31, 2020 $ (28.5) $ (12.6) $ (41.1) Less: accumulated amortization 16.2 6.9 23.1 Net carrying amounts, December 31, 2020 $ (12.3) $ (5.7) $ (18.0) Power Purchase and Fuel Supply Agreement Liabilities, Net Power Purchase Fuel Supply Agreements Agreements Total Gross balances, December 31, 2019 $ (28.1) $ (12.6) $ (40.7) Less: accumulated amortization 14.4 6.5 20.9 Net carrying amounts, December 31, 2019 $ (13.7) $ (6.1) $ (19.8) |
Schedule of amortization expense of intangible assets | 2020 2019 PPAs $ 22.5 $ 26.4 Fuel supply agreements (0.4) (0.4) Total amortization $ 22.1 $ 26.0 |
Schedule of estimated future amortization expense for the next five years | Year Ended December 31, 2021 $ 20.2 2022 15.9 2023 12.6 2024 12.6 2025 12.6 |
Other long-term liabilities (Ta
Other long-term liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Other long-term liabilities | |
Schedule of other long-term liabilities | 2020 2019 Long-term contract liability $ 0.2 $ 0.2 Net pension liability 3.1 1.2 Accrued LTIP and director share units 1.5 1.6 Other 1.4 1.7 $ 6.2 $ 4.7 |
Rollforward of asset retirement obligations | 2020 2019 Asset retirement obligations beginning of year $ 51.5 $ 49.2 Accretion and change in estimate of asset retirement obligation (1.3) 2.3 Costs incurred (2.5) (1.0) Translation adjustments 0.4 1.0 Asset retirement obligations, end of year $ 48.1 $ 51.5 |
Long-term debt (Tables)
Long-term debt (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Schedule of current maturities | December 31, December 31, 2020 2019 Interest Rate Current Maturities: Senior secured term loan facility, due 2025 (1) $ 93.0 $ 72.5 LIBOR (2) plus 2.50 % Cadillac term loan, due 2025 (3) 2.7 3.9 LIBOR plus 1.61 % Total current maturities $ 95.7 $ 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 Credit Agreement and disclosed below. The portion of the Term Loan classified as current is based on principal payments required to reduce the aggregate principal amount of Term Loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. (2) LIBOR cannot be less than 1.00% . We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $307.5 million remaining aggregate borrowings under our Term Loan at December 31, 2020. See Note 15, Accounting for derivative instruments and hedging activities, for further details. On January 31, 2020, the repricing of the Term Loan became effective, reducing the interest rate to LIBOR plus 2.50% with no change to the 1.00% LIBOR floor. The maturity date for the Term Loan was also extended 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) replacement. (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 15, Accounting for derivative instruments and hedging activities , for further details. |
Schedule of principal payments on the maturities of debt due in next five years | 2021 $ 95.7 2022 109.3 2023 63.3 2024 39.7 2025 14.3 Thereafter 164.9 $ 487.2 |
Long-term debt excluding debentures | |
Schedule of long-term debt | December 31, December 31, 2020 2019 Interest Rate Recourse Debt: Senior secured term loan facility, due 2025 (1) $ 307.5 $ 380.0 LIBOR (2) plus 2.50 % Senior unsecured notes, due June 2036 (Cdn$210.0) 164.9 161.7 5.95 % Non-Recourse Debt: Cadillac term loan, due 2025 (3) 14.8 18.7 LIBOR plus 1.61 % Less: unamortized discount (3.5) (5.8) Less: unamortized deferred financing costs (3.9) (4.7) Less: current maturities (95.7) (76.4) Total long-term debt $ 384.1 $ 473.5 |
Convertible debentures (Tables)
Convertible debentures (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Convertible Debentures | |
Schedule of long-term debt | December 31, December 31, 2020 2019 6.00% Debentures due January 2025 (Series E) (Cdn$115.0 million) $ 90.3 $ 88.5 Less: Unamortized deferred financing costs (3.2) (3.8) Less: Unamortized discount (3.0) (3.6) Total current and long-term convertible debentures $ 84.1 $ 81.1 |
Fair value of financial instr_2
Fair value of financial instruments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair value of financial instruments | |
Schedule of estimated carrying values and fair values of financial instruments | December 31, 2020 2019 Carrying Carrying Amount Fair Value Amount Fair Value Long-term debt, including current portion $ 487.2 $ 539.0 $ 560.4 $ 589.5 Convertible debentures 90.3 94.6 88.5 93.0 |
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities | December 31, 2020 Level 1 Level 2 Level 3 Total Assets: Cash and cash equivalents $ 38.8 $ — $ — $ 38.8 Restricted cash 7.1 — — 7.1 Derivative instruments asset — 0.4 — 0.4 Total $ 45.9 $ 0.4 $ — $ 46.3 Liabilities: Derivative instruments liability $ — $ 17.6 $ 1.5 $ 19.1 Total $ — $ 17.6 $ 1.5 $ 19.1 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 |
Schedule of FVM of conversion option derivative | Fair value Year Ended December 31, 2020 Beginning balance of liability at January 1, 2020 $ 3.2 Total unrealized gain (1.8) Currency translation loss 0.1 Ending balance of liability at December 31, 2020 $ 1.5 |
Accounting for derivative ins_2
Accounting for derivative instruments and hedging activities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting for derivative instruments and hedging activities | |
Schedule of notional volumes of forecasted transactions | December 31, December 31, Units 2020 2019 Natural gas swaps Natural Gas (MMBtu) 12.4 16.3 Gas purchase agreements Natural Gas (Gigajoules) 4.0 6.4 Interest rate swaps Interest (US$) 122.3 468.4 |
Schedule of fair value of derivative instruments | December 31, 2020 Derivative Derivative Assets Liabilities Derivative instruments designated as cash flow hedges: Interest rate swaps current $ — $ 0.6 Interest rate swaps long-term — 1.0 Total derivative instruments designated as cash flow hedges — 1.6 Derivative instruments not designated as cash flow hedges: Interest rate swaps current — 4.1 Interest rate swaps long-term — 0.9 Natural gas swaps current — 0.8 Natural gas swaps long-term — 1.9 Gas purchase agreements current 0.4 4.0 Gas purchase agreements long-term — 4.3 Convertible debenture conversion option — 1.5 Total derivative instruments not designated as cash flow hedges 0.4 17.5 Total derivative instruments $ 0.4 $ 19.1 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 |
Schedule of changes in OCI attributable to derivative financial instruments designated as cash flow hedges | Interest Rate Year Ended December 31, 2020 Swaps Accumulated OCI balance at January 1, 2020 $ 1.6 Change in fair value of cash flow hedges (0.5) Realized from OCI during the period 0.5 Accumulated OCI balance at December 31, 2020 $ 1.6 Settlements expected to be recognized from OCI in expense in the next 12 months, net of $0.1 million of tax $ 0.5 Interest Rate Year Ended December 31, 2019 Swaps Accumulated OCI balance at January 1, 2019 $ 1.6 Change in fair value of cash flow hedges (0.3) Realized from OCI during the period 0.3 Accumulated OCI balance at December 31, 2019 $ 1.6 |
Summary of realized loss (gain) for derivative instruments not designated as cash flow hedges | Classification of loss (gain) Year Ended December 31, recognized in income 2020 2019 Gas purchase agreements Fuel $ 8.3 $ 8.2 Natural gas swaps Fuel 2.5 0.9 Interest rate swaps Interest, net 5.0 (3.2) |
Summary of the unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges | Classification of gain (loss) Year ended December 31, recognized in income 2020 2019 Natural gas swaps Change in fair value of derivative instruments $ 3.4 $ (4.6) Gas purchase agreements Change in fair value of derivative instruments 5.4 3.2 Interest rate swaps Change in fair value of derivative instruments (2.0) (7.5) 6.8 (8.9) Convertible debenture conversion option Other (income) expense, net (1.8) 1.8 Foreign currency forwards Foreign exchange loss $ — $ — |
Income tax expense (Tables)
Income tax expense (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income tax expense | |
Schedule of components of income tax expense (benefit) | Year Ended December 31, 2020 2019 U.S. Canada U.S. Canada Current income tax expense $ 2.8 $ 2.8 $ 1.9 $ 3.0 Deferred income tax (benefit) expense (28.1) (1.7) 7.7 (2.8) Total income tax (benefit) expense, net $ (25.3) $ 1.1 $ 9.6 $ 0.2 |
Schedule of reconciliation of income taxes calculated at the Canadian enacted statutory rate to the provision for income taxes in the consolidated statements of operations | Year Ended December 31, 2020 2019 U.S. Canada U.S. Canada Computed income tax expense (benefit) at Canadian statutory rate $ 11.2 $ 2.1 $ (2.2) $ (7.0) (Decreases) increases resulting from: Operating in countries with different income tax rates (0.3) — 0.1 — 10.9 2.1 (2.1) (7.0) Change in valuation allowance (39.7) (0.5) (2.2) 7.9 (28.8) 1.6 (4.3) 0.9 Dividend withholding tax and other cash taxes 1.8 0.2 1.1 0.2 Foreign exchange — (0.6) 1.7 Changes in tax rates (0.1) — 2.2 — Changes in estimates due to tax filings 3.0 — (0.1) (0.2) Capital gain on intercompany notes — 0.2 0.1 — Impairments — — 7.7 — Other (1.2) (0.3) 2.9 (2.4) 3.5 (0.5) 13.9 (0.7) Income tax (benefit) expense $ (25.3) 1.1 $ 9.6 $ 0.2 |
Schedule of significant portions of the deferred tax assets and deferred tax liabilities | Year Ended December 31, 2020 2019 Deferred tax assets: Loss carryforwards $ 123.9 $ 135.9 Capital loss carryforwards 35.3 35.8 Interest expense limitation carryforwards - 9.7 Finance and share issuance costs - 0.1 Tax credits 1.4 1.4 Stock-based compensation 2.4 2.4 Derivative contracts 3.8 5.7 Other long-term notes 2.3 — Other 3.1 0.9 Total deferred tax assets 172.2 191.9 Less: Valuation allowance (105.2) (145.4) 67.0 46.5 Deferred tax liabilities: Intangible assets (22.0) (21.9) Property, plant and equipment (22.0) (31.2) Basis difference in joint ventures (5.8) (5.4) Other long-term investments - (1.3) Total deferred tax liabilities (49.8) (59.8) Net deferred tax asset (liability) $ 17.2 $ (13.3) Year Ended December 31, Net deferred tax asset (liability) by jurisdiction 2020 2019 U.S. Federal and State $ 4.5 $ (23.7) Canada 12.7 10.4 Net deferred tax asset (liability) $ 17.2 $ (13.3) |
Schedule of amounts of net operating loss carryforwards and their expiration years | U.S. Canada Total 2029 $ - $ 19.9 $ 19.9 2030 - - - 2031 25.4 - 25.4 2032 13.4 6.0 19.4 2033 20.6 24.0 44.6 2034 122.3 9.3 131.6 2035 154.1 - 154.1 2036 17.0 20.7 37.7 2037 16.7 9.0 25.7 2038 - 10.3 10.3 2039 - 7.2 7.2 2040 - 1.2 1.2 $ 369.5 $ 107.6 $ 477.1 |
Equity compensation plans (Tabl
Equity compensation plans (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Equity compensation plans | |
Schedule of changes in outstanding LTIP notional units | Grant Date Weighted-Average Notional Shares Fair Value per Notional Share Outstanding at December 31, 2018 3,952,201 $ 2.09 Granted 1,724,081 2.72 Vested and redeemed (2,071,335) 2.10 Forfeitures (26,855) 2.17 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 (31,929) 2.42 Outstanding at December 31, 2020 3,710,340 $ 2.45 |
Employee benefit plans (Tables)
Employee benefit plans (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Employee benefit plans | |
Schedule of components of net annual periodic pension cost | 2020 2019 Service cost benefits earned $ 0.3 $ 0.3 Interest cost on benefit obligation 0.4 0.5 Expected return on plan assets (0.7) (0.7) Amortization of actuarial loss 0.1 — Settlements — 0.3 Net period benefit cost $ 0.1 $ 0.4 |
Schedule of comparison of the pension benefit obligation and related plan assets | 2020 2019 Projected benefit obligation at January 1 $ (14.1) $ (13.2) Service cost (0.3) (0.3) Interest cost (0.4) (0.5) Actuarial loss (2.3) (2.0) Employee contributions (0.1) (0.1) Benefits paid 0.3 0.2 Settlements — 2.4 Foreign currency adjustment (0.5) (0.6) Projected benefit obligation at December 31 (17.4) (14.1) Fair value of plan assets at January 1 $ 12.9 $ 12.0 Actual return on plan assets 1.2 2.0 Employer contributions 0.2 0.8 Employee contributions 0.1 0.1 Benefits paid (0.3) (0.2) Settlements — (2.4) Foreign currency adjustment 0.2 0.6 Fair value of plan assets at December 31 14.3 12.9 Funded status at December 31-excess of obligation over assets $ (3.1) $ (1.2) |
Schedule of amount recognized in the balance sheet | 2020 2019 Non-current liabilities $ 3.1 $ 1.2 |
Schedule of amounts recognized in accumulated OCI that have not yet been recognized as components of net periodic benefit cost | 2020 2019 Unrecognized loss $ (3.1) $ (1.7) |
Schedule of the balances of significant components of the pension plan | 2020 2019 Projected benefit obligation $ 17.4 $ 14.1 Accumulated benefit obligation 16.4 12.9 Fair value of plan assets 14.3 12.9 |
Schedule of assumptions used to calculate benefit obligations and expense | The following table presents the significant assumptions used to calculate our benefit obligations: 2020 2019 Weighted-Average Assumptions Discount rate 2.50 % 3.25 % Rate of compensation increase 2.0 % 2.0 % The following table presents the significant assumptions used to calculate our benefit expense: 2020 2019 Weighted-Average Assumptions Discount rate 3.3 % 4.0 % Rate of return on plan assets 5.5 % 5.8 % Rate of compensation increase 2.0 % 2.0 % |
Schedule of pension plan assets weighted average allocations in the common collective trust | 2020 2019 Canadian equity 31 % 30 % U.S. equity 14 % 14 % International equity 17 % 14 % Canadian fixed income 38 % 39 % Real estate equities — % 3 % 100 % 100 % |
Schedule of expected future benefit payments | Years ending December 31, 2021 Cdn$ 0.5 2022 0.5 2023 0.6 2024 0.6 2025 0.6 2026-2030 4.0 |
Basic and diluted earnings (l_2
Basic and diluted earnings (loss) per share (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Basic and diluted earnings (loss) per share | |
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation | Basic 2020 2019 Numerator: Net income (loss) attributable to Atlantic Power Corporation $ 74.2 $ (42.6) Denominator: Weighted average basic shares outstanding 95.8 109.3 Basic earnings (loss) per share attributable to Atlantic Power Corporation $ 0.77 $ (0.39) Diluted Numerator: Net income (loss) attributable to Atlantic Power Corporation 74.2 (42.6) Add: convertible debenture interest expense 3.8 — 78.0 (42.6) Denominator: Weighted average basic shares outstanding 95.8 109.3 Share-based compensation 1.7 — Convertible debentures 27.4 — 124.9 109.3 Diluted earnings (loss) per share attributable to Atlantic Power Corporation 0.62 (0.39) |
Summary of outstanding instruments that are anti-dilutive and not included in the computation of our diluted (loss) earnings per share | 2020 2019 Share-based compensation — 1.5 Convertible debentures — 27.8 Total — 29.3 |
Segment and geographic inform_2
Segment and geographic information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Segment and geographic information | |
Reconciliation of Project Adjusted EBITDA to net income (loss) from continuing operations | Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Year Ended December 31, 2020 Project revenues $ 94.5 $ 118.2 $ 58.3 $ 1.0 $ 272.0 Segment assets 202.8 190.8 306.3 147.3 847.2 Goodwill — 6.9 14.4 — 21.3 Capital expenditures 24.1 — 0.6 0.1 24.8 Project Adjusted EBITDA $ 39.9 $ 105.0 $ 45.3 $ (1.5) $ 188.7 Change in fair value of derivative instruments — (8.9) — 2.1 (6.8) Depreciation and amortization 22.7 34.3 19.6 — 76.6 Interest, net 2.7 — — 0.1 2.8 Insurance gain (0.7) — — — (0.7) Other project income — (2.1) — — (2.1) Project income (loss) 15.2 81.7 25.7 (3.7) 118.9 Administration — — — 24.8 24.8 Interest expense, net — — — 42.4 42.4 Foreign exchange loss — — — 5.1 5.1 Other income, net — — — (2.7) (2.7) Net income (loss) before income taxes 15.2 81.7 25.7 (73.3) 49.3 Income tax benefit — — — (24.2) (24.2) Net income (loss) $ 15.2 $ 81.7 $ 25.7 $ (49.1) $ 73.5 Solid Fuel Natural Gas Hydroelectric Corporate Consolidated Year Ended December 31, 2019 Project revenues $ 80.0 $ 131.8 $ 68.8 $ 1.0 $ 281.6 Segment assets 222.7 241.0 388.3 83.6 935.6 Goodwill — 6.9 14.4 — 21.3 Capital expenditures 6.8 0.1 0.4 — 7.3 Project Adjusted EBITDA $ 32.7 $ 108.2 $ 55.5 $ (0.3) $ 196.1 Change in fair value of derivative instruments — 1.4 — 7.5 8.9 Depreciation and amortization 23.9 37.2 19.5 0.1 80.7 Interest, net 2.6 (0.1) — — 2.5 Insurance loss 1.0 — — — 1.0 Impairment 55.0 — — — 55.0 Other project expense — 1.2 — — 1.2 Project (loss) income (49.8) 68.5 36.0 (7.9) 46.8 Administration — — — 23.9 23.9 Interest expense, net — — — 44.0 44.0 Foreign exchange loss — — — 11.9 11.9 Other expense, net — — — 1.0 1.0 Net (loss) income before income taxes (49.8) 68.5 36.0 (88.7) (34.0) Income tax expense — — — 9.8 9.8 Net (loss) income $ (49.8) $ 68.5 $ 36.0 $ (98.5) $ (43.8) |
Schedule of revenue and property, plant and equipment by country | The table below provides information, by country, about our consolidated operations for each of the years ended December 31, 2020 and 2019 and Property, Plant and Equipment, PPAs and other Intangible and total assets as of December 31, 2020 and 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. Revenue 2020 2019 United States $ 184.9 $ 208.4 Canada 87.1 73.2 Total $ 272.0 $ 281.6 Property, Plant and PPAs and Equipment, net of other intangible assets, net of accumulated depreciation accumulated amortization Total assets 2020 2019 2020 2019 2020 2019 United States $ 351.2 $ 353.9 $ 119.4 $ 142.8 $ 666.4 $ 762.3 Canada 140.6 148.2 0.9 1.5 180.8 173.3 Total $ 491.8 $ 502.1 $ 120.3 $ 144.3 $ 847.2 $ 935.6 |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Schedule of insurance recoveries related to business interruption losses and property losses | Balance at Insurance Beginning of Proceeds Insurance Balance at Period Additions Received Gain (Loss) End of Period Insurance recovery receivable: Year ended December 31, 2020 $ 13.5 $ — $ (29.9) $ 16.4 (1) $ — Year ended December 31, 2019 $ — $ 25.8 $ (11.3) $ (1.0) (2) $ 13.5 (1) Represents recoveries for business interruption losses and property losses in excess of incurred losses of $15.6 million and $0.8 million, respectively. Of the $15.6 million recorded for the recovery of business interruption losses, $6.0 million relates to the expected reduction in capacity payments in 2021 under the Cadillac PPA due to the reduced availability of the plant in 2020 during the extended outage. (2) Represents the $1.0 million property damage deductible. |
Management Service Commitments | |
Schedule of estimated commitments under fuel supply and transportation agreements | 2021 $ 0.4 2022 0.2 2023 — 2024 — 2025 — Thereafter — $ 0.6 |
Fuel Supply and Transportation Commitments | |
Schedule of estimated commitments under fuel supply and transportation agreements | 2021 $ 4.2 2022 4.4 2023 — 2024 — 2025 — Thereafter — $ 8.6 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Leases | |
Schedule of operating lease information | Year Ended December 31, 2020 2019 Lease cost: (1) Operating lease cost $ 2.1 $ 1.9 Short-term lease cost — 0.1 Sublease income (1.1) (1.2) Total lease cost $ 1.0 $ 0.8 (1) Finance lease costs are immaterial to the Company. |
Schedule of other information | Lease Income from Net lease Payments subleasing payments 2021 $ 2.0 $ (1.1) $ 0.9 2022 1.8 (1.1) 0.7 2023 1.3 (0.7) 0.6 2024 0.2 — 0.2 2025 — — — Thereafter — — — Total operating lease payments $ 5.3 $ (2.9) $ 2.4 Less: present value discount (0.3) Total operating lease liabilities $ 5.0 Lease Payments 2021 $ 0.1 2022 0.1 2023 — Thereafter — Total finance lease payments $ 0.2 Less: amount representing interest (0.1) Total finance lease liabilities $ 0.1 Other Information: Cash paid for amounts included in the measurement of lease liabilities (1) Operating cash flows from operating leases $ 1.1 Lease assets obtained in exchange for new lease liabilities (non-cash): Operating $ 0.1 Weighted average remaining lease term (in years): Operating leases 2.7 Finance leases 1.4 Weighted average discount rate - operating leases 3.9 % Weighted average discount rate - finance leases 4.1 % (1) Cash flows from finance leases are immaterial to the Company. We have no lease transactions with related parties. |
Schedule of rental income from operating leases | Rental Income from operating leases Year Ended December 31, 2020 2019 Solid Fuel $ 65.9 $ 79.1 Natural Gas 25.4 24.4 Hydroelectric 58.3 68.8 $ 149.6 $ 172.3 |
Nature of business (Details)
Nature of business (Details) | 12 Months Ended |
Dec. 31, 2020regionstateprojectMW | |
Nature of business | |
Number of states in which power generation projects operate | state | 11 |
Number of provinces in which power generation projects operate | region | 2 |
Number of power generation projects | project | 21 |
Gross generating capacity of project (in MW) | MW | 1,723 |
Ownership interest in power generation projects (in MW) | MW | 1,327 |
Number of projects which are majority owned | project | 16 |
Summary of significant accoun_4
Summary of significant accounting policies - through derivatives (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)item | Dec. 31, 2019USD ($) | |
Accounts receivable | ||
Allowance for doubtful accounts | $ 0 | $ 0 |
Deferred financing costs | ||
Net carrying amount of deferred financing cost | 7.1 | 8.5 |
Amortization expense | $ 2.6 | $ 3.2 |
Impairment of long-lived assets, non-amortizing intangible assets and equity method investments | ||
Period prior to expiration of PPA when impairment review is conducted | 6 months | |
Derivative financial instruments | ||
Number of interest rate swaps designated as cash flow hedges | item | 1 | |
Minimum | ||
Deferred financing costs | ||
Amortization period | 1 year | |
Investments accounted for by the equity method | ||
Ownership level triggering equity method of accounting, as a percent | 5.00% | |
Maximum | ||
Deferred financing costs | ||
Amortization period | 6 years | |
Investments accounted for by the equity method | ||
Ownership level triggering equity method of accounting, as a percent | 50.00% | |
Impairment of long-lived assets, non-amortizing intangible assets and equity method investments | ||
Maximum percentage of ownership in entities in which consolidation is not required | 50.00% |
Summary of significant accoun_5
Summary of significant accounting policies - Equity comp (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Long-term incentive plan | |
Equity compensation plans | |
Weighted average forfeiture rate | 11.00% |
Acquisitions and divestments -
Acquisitions and divestments - (Details) - South Carolina Biomass Plant $ in Millions | Jul. 31, 2019USD ($)MWhPlant | Sep. 30, 2018USD ($) | Dec. 31, 2019USD ($) |
Asset acquisitions | |||
Number Of Plants Acquired | Plant | 2 | ||
Plant Capacity | MWh | 20 | ||
Final consideration | $ 12.6 | ||
Down payment | $ 2.6 | ||
Revenue contributed | $ 10.8 | ||
Net income contributed | $ 1 | ||
Fair Value Measurements Nonrecurring | |||
Estimated fair values | |||
Cash | 1.4 | ||
Accounts receivable | 4.3 | ||
Inventory | 2.9 | ||
Property, plant, and equipment | 4 | ||
Intangible assets | 2.6 | ||
Accounts payable | (2) | ||
Accrued liabilities | (0.3) | ||
Other liabilities | (0.3) | ||
Total purchase consideration | $ 12.6 |
Acquisitions and divestments _2
Acquisitions and divestments - AltaGas acquisition (Details) $ in Millions | Aug. 13, 2019USD ($)MWhMWPlant | Dec. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Aug. 31, 2019USD ($) |
AltaGas Acquisition [Member] | Craven | CMS Energy [Member] | ||||
Asset acquisitions | ||||
Percentage of interest | 50.00% | |||
AltaGas Acquisition [Member] | Grayling | CMS Energy [Member] | ||||
Asset acquisitions | ||||
Percentage of interest | 50.00% | |||
AltaGas Acquisition [Member] | Grayling | Fortistar [Member] | ||||
Asset acquisitions | ||||
Percentage of interest | 20.00% | |||
AltaGas Acquisition [Member] | ||||
Asset acquisitions | ||||
Number Of Plants Acquired | Plant | 2 | |||
Purchase price | $ 18.7 | |||
Acquisition related transaction cost | $ 0.2 | |||
Equity in earnings from unconsolidated affiliates | $ 1 | $ 1 | $ 1 | |
Equity method distributions | $ 0.9 | $ 0.9 | $ 0.9 | |
AltaGas Acquisition [Member] | Minimum | ||||
Asset acquisitions | ||||
Percentage of equity method ownership interest | 5.00% | |||
AltaGas Acquisition [Member] | Maximum | ||||
Asset acquisitions | ||||
Percentage of equity method ownership interest | 50.00% | |||
AltaGas Acquisition [Member] | Craven | ||||
Asset acquisitions | ||||
Plant Capacity | MWh | 48 | |||
Interest acquired in the plant | 50.00% | |||
AltaGas Acquisition [Member] | Grayling | ||||
Asset acquisitions | ||||
Number Of Plants Acquired | MW | 37 | |||
Interest acquired in the plant | 30.00% |
Revenue from contracts - Disagg
Revenue from contracts - Disaggregation of revenue (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of revenue | ||
Project revenue | $ 272 | $ 281.6 |
Solid Fuel | ||
Disaggregation of revenue | ||
Project revenue | 94.5 | 80 |
Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | 118.2 | 131.8 |
Hydroelectric | ||
Disaggregation of revenue | ||
Project revenue | 58.3 | 68.8 |
Corporate | ||
Disaggregation of revenue | ||
Project revenue | 1 | 1 |
Energy sales | ||
Disaggregation of revenue | ||
Project revenue | 137.9 | 138 |
Energy sales | Solid Fuel | ||
Disaggregation of revenue | ||
Project revenue | 58.8 | 41.1 |
Energy sales | Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | 24.2 | 31 |
Energy sales | Hydroelectric | ||
Disaggregation of revenue | ||
Project revenue | 54.9 | 65.9 |
Energy capacity revenue | ||
Disaggregation of revenue | ||
Project revenue | 113.8 | 125.4 |
Energy capacity revenue | Solid Fuel | ||
Disaggregation of revenue | ||
Project revenue | 34.6 | 38.7 |
Energy capacity revenue | Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | 79.2 | 86.7 |
Other | ||
Disaggregation of revenue | ||
Project revenue | 20.3 | 18.2 |
Asset management and operation | ||
Disaggregation of revenue | ||
Project revenue | 1 | 1 |
Asset management and operation | Corporate | ||
Disaggregation of revenue | ||
Project revenue | 1 | 1 |
Ancillary and transmission services | ||
Disaggregation of revenue | ||
Project revenue | 6.5 | 7.6 |
Ancillary and transmission services | Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | 3.1 | 4.7 |
Ancillary and transmission services | Hydroelectric | ||
Disaggregation of revenue | ||
Project revenue | 3.4 | 2.9 |
Waste heat revenue | ||
Disaggregation of revenue | ||
Project revenue | 1 | 0.2 |
Waste heat revenue | Solid Fuel | ||
Disaggregation of revenue | ||
Project revenue | 1 | 0.2 |
Steam energy and capacity revenue | ||
Disaggregation of revenue | ||
Project revenue | 10.5 | 11.7 |
Steam energy and capacity revenue | Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | 10.5 | 11.7 |
Miscellaneous | ||
Disaggregation of revenue | ||
Project revenue | 1.3 | (2.3) |
Miscellaneous | Solid Fuel | ||
Disaggregation of revenue | ||
Project revenue | 0.1 | |
Miscellaneous | Natural Gas | ||
Disaggregation of revenue | ||
Project revenue | $ 1.2 | $ (2.3) |
Revenue from contracts - Contra
Revenue from contracts - Contract balances (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Disaggregation of Revenue [Line Items] | ||
Accounts receivables | $ 31.3 | $ 30.4 |
Contract assets | 0 | |
Dorchester | ||
Disaggregation of Revenue [Line Items] | ||
Fuel reserve fund | 0.2 | 0.2 |
San Diego Projects | ||
Disaggregation of Revenue [Line Items] | ||
Contract liabilities | $ 0.1 | $ 0.1 |
Changes in accumulated other _3
Changes in accumulated other comprehensive income (loss) by component (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
AOCI Attributable to Parent, Net of Tax | ||
Beginning Balance | $ (45) | |
Net amount reclassified to earnings: | ||
Ending Balance | (10.2) | $ (45) |
Foreign currency translation | ||
AOCI Attributable to Parent, Net of Tax | ||
Beginning Balance | (140.6) | (146.4) |
Other comprehensive income (loss): | ||
Foreign currency translation adjustments | 2.2 | 5.8 |
Net amount reclassified to earnings: | ||
Ending Balance | (138.4) | (140.6) |
Accumulated other comprehensive loss, tax impacts related to rate changes | 0 | 0 |
Pension | ||
AOCI Attributable to Parent, Net of Tax | ||
Beginning Balance | (1.7) | (1.4) |
Other comprehensive income (loss): | ||
Settlement | 0.3 | |
Tax benefit (expense) | (0.1) | |
Total other comprehensive (loss) income before reclassifications, net of tax | 0.2 | |
Net amount reclassified to earnings: | ||
Total amount reclassified from accumulated other comprehensive income (loss), net of tax | (1.4) | (0.5) |
Total other comprehensive (loss) income | (1.4) | (0.3) |
Ending Balance | (3.1) | (1.7) |
Cash flow hedges | ||
AOCI Attributable to Parent, Net of Tax | ||
Beginning Balance | 1.6 | 1.6 |
Other comprehensive income (loss): | ||
Net change from periodic revaluations | (0.7) | (0.5) |
Tax benefit (expense) | 0.2 | 0.2 |
Total other comprehensive (loss) income before reclassifications, net of tax | (0.5) | (0.3) |
Net amount reclassified to earnings: | ||
Interest rate swaps | 0.6 | 0.4 |
Tax expense | (0.1) | (0.1) |
Total amount reclassified from accumulated other comprehensive income (loss), net of tax | 0.5 | 0.3 |
Ending Balance | 1.6 | 1.6 |
Amount reclassified from accumulated other comprehensive income | Foreign currency translation | ||
Net amount reclassified to earnings: | ||
Amounts reclassified to earnings, foreign currency | $ 0 | $ 0 |
Equity method investments in _3
Equity method investments in unconsolidated affiliates (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)item | Dec. 31, 2019USD ($) | |
Asset acquisitions | ||
Carrying value | $ 85 | $ 96.6 |
Equity in earnings of unconsolidated affiliates | 42.9 | (3) |
Distributions from equity method investments | 54.2 | 59.5 |
Deficit in earnings of equity method investments, net of distributions | $ (11.3) | (62.5) |
Frederickson | ||
Asset acquisitions | ||
Percentage of equity method ownership interest | 50.15% | |
Carrying value | $ 58.9 | 65.2 |
Number of ownership parties | item | 2 | |
Equity in earnings of unconsolidated affiliates | $ 8.3 | 9.1 |
Orlando Cogen, LP | ||
Asset acquisitions | ||
Percentage of equity method ownership interest | 50.00% | |
Carrying value | $ 2.5 | 3.6 |
Equity in earnings of unconsolidated affiliates | $ 33.1 | 33 |
Chambers Cogen, LP | ||
Asset acquisitions | ||
Percentage of equity method ownership interest | 40.00% | |
Carrying value | $ 8 | 9 |
Equity in earnings of unconsolidated affiliates | $ 4.4 | (46) |
Craven County Wood Energy, LP | ||
Asset acquisitions | ||
Percentage of equity method ownership interest | 50.00% | |
Carrying value | $ 8.2 | 9.5 |
Equity in earnings of unconsolidated affiliates | $ (1.8) | 0.1 |
Grayling Generating Station, LP | ||
Asset acquisitions | ||
Percentage of equity method ownership interest | 30.00% | |
Carrying value | $ 7.4 | 9.3 |
Equity in earnings of unconsolidated affiliates | $ (1.1) | $ 0.8 |
Equity method investments in _4
Equity method investments in unconsolidated affiliates - B/S (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Assets | ||
Current assets | $ 106.4 | $ 152.7 |
Total assets | 847.2 | 935.6 |
Liabilities | ||
Current liabilities | 136.9 | 122.9 |
Total liabilities | 688.6 | 797.9 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Total assets | 151.2 | 171.1 |
Liabilities | ||
Total liabilities | 66.2 | 74.5 |
Frederickson | Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Current assets | 1.9 | 2.1 |
Non-current assets | 57.8 | 63.9 |
Liabilities | ||
Current liabilities | 0.3 | 0.3 |
Non-current liabilities | 0.5 | 0.5 |
Orlando Cogen, LP | Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Current assets | 7.8 | 7.8 |
Non-current assets | 5.1 | 6.1 |
Liabilities | ||
Current liabilities | 10.3 | 10.2 |
Non-current liabilities | 0.1 | |
Chambers Cogen, LP | Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Current assets | 14.8 | 14.4 |
Non-current assets | 44.6 | 56.5 |
Liabilities | ||
Current liabilities | 15.8 | 13.7 |
Non-current liabilities | 35.6 | 48.2 |
Craven County Wood Energy, LP | Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Current assets | 2.2 | 4.4 |
Non-current assets | 7.9 | 5.8 |
Liabilities | ||
Current liabilities | 2.3 | 0.8 |
Non-current liabilities | 0.4 | |
Grayling Generating Station, LP | Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Assets | ||
Current assets | 2.6 | 3.3 |
Non-current assets | 6.5 | 6.8 |
Liabilities | ||
Current liabilities | 0.7 | 0.5 |
Non-current liabilities | $ 0.2 | $ 0.3 |
Equity method investments in _5
Equity method investments in unconsolidated affiliates - Op Results (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 272 | $ 281.6 |
Net income (loss) | 73.5 | (43.8) |
Equity in earnings of unconsolidated affiliates | 42.9 | (3) |
Frederickson | ||
Operating results | ||
Equity in earnings of unconsolidated affiliates | 8.3 | 9.1 |
Orlando Cogen, LP | ||
Operating results | ||
Equity in earnings of unconsolidated affiliates | 33.1 | 33 |
Chambers Cogen, LP | ||
Operating results | ||
Equity in earnings of unconsolidated affiliates | 4.4 | (46) |
Craven County Wood Energy, LP | ||
Operating results | ||
Equity in earnings of unconsolidated affiliates | (1.8) | 0.1 |
Grayling Generating Station, LP | ||
Operating results | ||
Equity in earnings of unconsolidated affiliates | (1.1) | 0.8 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 140.9 | 144 |
Project expenses | 96.3 | 96.5 |
Project other expenses | (1.7) | (50.5) |
Equity in earnings of unconsolidated affiliates | 42.9 | (3) |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Frederickson | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 29.2 | 36 |
Project expenses | 20.9 | 26.9 |
Net income (loss) | 8.3 | 9.1 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Orlando Cogen, LP | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 60.2 | 61.5 |
Project expenses | 27 | 28.5 |
Project other expenses | (0.1) | |
Net income (loss) | 33.1 | 33 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Chambers Cogen, LP | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 38.4 | 39.4 |
Project expenses | 32.5 | 34.6 |
Project other expenses | (1.5) | (50.9) |
Net income (loss) | 4.4 | (46.1) |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Craven County Wood Energy, LP | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 9.6 | 4.9 |
Project expenses | 11.4 | 4.7 |
Net income (loss) | (1.8) | 0.2 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member] | Grayling Generating Station, LP | ||
Operating results | ||
Revenue from Contract with Customer, Excluding Assessed Tax | 3.5 | 2.2 |
Project expenses | 4.5 | 1.8 |
Project other expenses | (0.1) | 0.4 |
Net income (loss) | $ (1.1) | $ 0.8 |
Equity method investments in _6
Equity method investments in unconsolidated affiliates - impairments (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Equity in earnings of unconsolidated affiliates | ||
Equity Method Investments. | $ 85,000,000 | $ 96,600,000 |
Chambers Cogen, LP | ||
Equity in earnings of unconsolidated affiliates | ||
Percentage of equity method ownership interest | 40.00% | |
Equity Method Investments. | $ 8,000,000 | $ 9,000,000 |
Earnings from unconsolidated affiliates | ||
Equity in earnings of unconsolidated affiliates | ||
Equity impairment other than temporary | $ 0 | |
Earnings from unconsolidated affiliates | Chambers Cogen, LP | ||
Equity in earnings of unconsolidated affiliates | ||
Percentage of equity method ownership interest | 40.00% | |
Equity impairment other than temporary | $ 49,200,000 | |
Equity Method Investments. | $ 58,200,000 |
Inventory (Details)
Inventory (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Inventory | ||
Parts and other consumables | $ 11.9 | $ 12.2 |
Fuel | 6.4 | 6.4 |
Total inventory | $ 18.3 | $ 18.6 |
Property, plant and equipment_3
Property, plant and equipment, net (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 924.7 | $ 893.7 |
Less accumulated depreciation | (432.9) | (391.6) |
Total property, plant and equipment, net | 491.8 | 502.1 |
Depreciation expense | 36.8 | 37.6 |
Impairment of property, plant and equipment | 0 | 4 |
Land | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | 6.4 | 6.4 |
Office equipment, machinery and other | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 6.7 | 6.5 |
Office equipment, machinery and other | Minimum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 3 years | |
Office equipment, machinery and other | Maximum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 10 years | |
Leasehold improvements | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 2.1 | 2.1 |
Leasehold improvements | Minimum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 7 years | |
Leasehold improvements | Maximum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 15 years | |
Asset retirement obligation. | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 23.6 | 23.4 |
Asset retirement obligation. | Minimum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 1 year | |
Asset retirement obligation. | Maximum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 43 years | |
Plant in service | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 885.1 | 848.1 |
Plant in service | Minimum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 1 year | |
Plant in service | Maximum | ||
Property, plant and equipment, net | ||
Depreciable Lives | 45 years | |
Construction in progress | ||
Property, plant and equipment, net | ||
Property, plant and equipment, gross | $ 0.8 | $ 7.2 |
Property, plant and equipment_4
Property, plant and equipment, net - Impairments (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Impairment Charges [Abstract] | ||
Impairment of property, plant and equipment | $ 0 | $ 4 |
Impairment of Ongoing Project | 55 | |
Calstock | ||
Asset Impairment Charges [Abstract] | ||
Asset group for testing long-lived assets | 7.8 | |
Net working capital | 2.3 | |
Impairment of Ongoing Project | 4.7 | |
Impairment of intangible assets related to PPAs | 0.7 | |
Partial impairment of PP&E | 4 | |
Impairment losses related to spare parts inventory | 1.1 | |
Calstock | Property, Plant and Equipment | ||
Asset Impairment Charges [Abstract] | ||
Impairment of intangible assets related to PPAs | 4.7 | |
Calstock | Power Purchase agreements | ||
Asset Impairment Charges [Abstract] | ||
Impairment of intangible assets related to PPAs | $ 0.8 |
Goodwill - Goodwill by reportab
Goodwill - Goodwill by reportable segment (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Changes in the carrying amount of goodwill | ||
Goodwill | $ 21.3 | $ 21.3 |
Curtis Palmer | ||
Changes in the carrying amount of goodwill | ||
Goodwill | 14.4 | 14.4 |
Morris | ||
Changes in the carrying amount of goodwill | ||
Goodwill | 3.3 | 3.3 |
Nipigon | ||
Changes in the carrying amount of goodwill | ||
Goodwill | $ 3.6 | $ 3.6 |
Goodwill - impairments (Details
Goodwill - impairments (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Goodwill, Impaired [Abstract] | ||
Impairment of goodwill | $ 0 | $ 0 |
PPAs and other definite-lived_3
PPAs and other definite-lived intangible assets and liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Components of intangible assets | ||
Assets, gross balance at the end of the period | $ 352.1 | $ 365.6 |
Write-off of fully amortized balances | (13.5) | |
Less: accumulated amortization | (231.8) | (221.3) |
Assets, net balance at the end of the period | 120.3 | 144.3 |
Liabilities, gross balances at the end of the period | (41.1) | (40.7) |
Less: accumulated amortization | 23.1 | 20.9 |
Liabilities, net balance at the end of the period | (18) | (19.8) |
PPAs | ||
Components of intangible assets | ||
Assets, gross balance at the end of the period | 352.1 | 365.6 |
Write-off of fully amortized balances | (13.5) | |
Less: accumulated amortization | (231.8) | (221.3) |
Assets, net balance at the end of the period | 120.3 | 144.3 |
Liabilities, gross balances at the end of the period | (28.5) | (28.1) |
Less: accumulated amortization | 16.2 | 14.4 |
Liabilities, net balance at the end of the period | (12.3) | (13.7) |
Fuel Supply Agreements | ||
Components of intangible assets | ||
Liabilities, gross balances at the end of the period | (12.6) | (12.6) |
Less: accumulated amortization | 6.9 | 6.5 |
Liabilities, net balance at the end of the period | $ (5.7) | $ (6.1) |
PPAs and other definite-lived_4
PPAs and other definite-lived intangible assets and liabilities, etc. - amortization (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Amortization expense of intangible assets | ||
Amortization of intangible assets (liabilities) | $ 22.1 | $ 26 |
Estimated future amortization expense | ||
2021 | 20.2 | |
2022 | 15.9 | |
2023 | 12.6 | |
2024 | 12.6 | |
2025 | $ 12.6 | |
Weighted average remaining amortization period related to our intangible assets | ||
Weighted average remaining amortization period | 8 years 1 month 6 days | |
PPAs | ||
Amortization expense of intangible assets | ||
Amortization of intangible assets (liabilities) | $ 22.5 | 26.4 |
Fuel Supply Agreements | ||
Amortization expense of intangible assets | ||
Amortization of intangible assets (liabilities) | $ (0.4) | $ (0.4) |
Other long-term liabilities (De
Other long-term liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Other long-term liabilities | ||
Long-term contract liability | $ 0.2 | $ 0.2 |
Net pension liability | 3.1 | 1.2 |
Accrued LTIP and director share units | 1.5 | 1.6 |
Other | 1.4 | 1.7 |
Other long-term liabilities | 6.2 | 4.7 |
Asset retirement obligations rollforward | ||
Asset retirement obligations beginning of year | 51.5 | 49.2 |
Accretion and change in estimate of asset retirement obligation | (1.3) | 2.3 |
Costs incurred | (2.5) | (1) |
Translation adjustments | 0.4 | 1 |
Asset retirement obligations, end of year | $ 48.1 | $ 51.5 |
Long-term debt (Details)
Long-term debt (Details) $ in Millions, $ in Millions | Aug. 24, 2020 | Jan. 31, 2020USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2019USD ($) |
Long-term debt | |||||
Less: unamortized discount | $ (3.5) | $ (5.8) | |||
Less: unamortized deferred financing costs | (3.9) | (4.7) | |||
Less: current maturities | (95.7) | (76.4) | |||
Total long-term debt | 384.1 | 473.5 | |||
Availability of future shelf registration period | 3 years | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | |||||
2020 | 95.7 | ||||
2021 | 109.3 | ||||
2022 | 63.3 | ||||
2023 | 39.7 | ||||
2024 | 14.3 | ||||
Thereafter | 164.9 | ||||
Total debt | 487.2 | ||||
Senior secured term loan facility, due 2025 | APLP Holdings | |||||
Long-term debt | |||||
Write-off of deferred financing costs | 0.5 | ||||
Debt repriced | $ 307.5 | ||||
Interest rate margin reduction due to repricing, as a percent | 0.25% | ||||
Interest rate margin additional reduction due to repricing, as a percent | 0.25% | ||||
Leverage ratio as defined in Credit Agreement | 2.75 | ||||
Term loan maturity | 2 years | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | |||||
Total debt | 307.5 | ||||
Senior unsecured notes, due June 2036 | |||||
Long-term debt | |||||
Long-term Debt, Gross | $ 210 | ||||
Interest rate swaps | |||||
Long-term debt | |||||
Notional amount | 122.3 | 468.4 | |||
Interest rate swaps | Senior secured term loan facility, due 2025 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | |||||
Total debt | $ 307.5 | ||||
London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2025 | |||||
Long-term debt | |||||
Minimum percentage of variable rate base | 1.00% | 1.00% | |||
Applicable margin (as a percent) | 2.50% | ||||
London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2025 | APLP Holdings | |||||
Long-term debt | |||||
Minimum percentage of variable rate base | 1.00% | ||||
Applicable margin (as a percent) | 2.50% | ||||
Long-term debt excluding debentures | Senior secured term loan facility, due 2025 | |||||
Long-term debt | |||||
Long-term Debt, Gross | $ 307.5 | 380 | |||
Less: current maturities | (93) | (72.5) | |||
Long-term debt excluding debentures | Senior unsecured notes, due June 2036 | |||||
Long-term debt | |||||
Long-term Debt, Gross | $ 164.9 | 161.7 | |||
Interest rate (as a percent) | 5.95% | 5.95% | |||
Long-term debt excluding debentures | Cadillac term loan, due 2025 | |||||
Long-term debt | |||||
Long-term Debt, Gross | $ 14.8 | 18.7 | |||
Less: current maturities | $ (2.7) | $ (3.9) | |||
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Senior secured term loan facility, due 2025 | |||||
Long-term debt | |||||
Applicable margin (as a percent) | 2.50% | ||||
Long-term debt excluding debentures | London Interbank Offered Rate (LIBOR) | Cadillac term loan, due 2025 | |||||
Long-term debt | |||||
Applicable margin (as a percent) | 1.61% |
Long-term debt - Credit Facilit
Long-term debt - Credit Facilities (Details) $ in Millions, $ in Millions | Apr. 13, 2016USD ($) | Jan. 31, 2020USD ($) | Oct. 31, 2018 | Apr. 30, 2018 | Oct. 31, 2017 | Apr. 30, 2017 | Dec. 31, 2020USD ($)Lender | Dec. 31, 2020CAD ($) | Mar. 31, 2020USD ($) | Feb. 29, 2020USD ($) | Dec. 31, 2019USD ($) |
Debt Instrument [Line Items] | |||||||||||
Total debt | $ 487.2 | ||||||||||
Original issue discount amount | 3.5 | $ 5.8 | |||||||||
Deferred financing costs | $ 1.7 | ||||||||||
Credit Facilities | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Original issue discount (as a percent) | 3.00% | ||||||||||
Number of days prior to the Letter of Credit Expiration Date that letters of credit are available to be issued | 30 days | ||||||||||
Commitment fee related to New Revolver, as a percent | 0.75% | ||||||||||
Senior secured term loan facility, due 2025 | London Interbank Offered Rate (LIBOR) | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Applicable margin (as a percent) | 2.50% | ||||||||||
Minimum percentage of variable rate base | 1.00% | 1.00% | |||||||||
Senior unsecured notes, due June 2036 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Amount drawn under loan | $ 210 | ||||||||||
APLP Holdings | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Period of debt service covered by debt service reserve fund | 6 months | ||||||||||
Period from initial funding date that APLP would be required to repay, prepay, refinance or replace at a price of 101 percent of the principal amount if they elect to do so for any portion or all of the term loan facilities | 6 months | ||||||||||
APLP Holdings | Letters of credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Face amount of debt | $ 77.1 | ||||||||||
Outstanding balance of senior credit facility | $ 77.1 | ||||||||||
APLP Holdings | Credit Facilities | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest rate margin reduction due to repricing, as a percent | 0.25% | 0.50% | 0.75% | 0.75% | |||||||
Amount of cash flow of APLP Holdings and its subsidiaries remaining after application of funds according to the Credit Agreement to be applied under | 50.00% | ||||||||||
APLP Holdings | Credit Facilities | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Applicable margin (as a percent) | 4.00% | ||||||||||
APLP Holdings | Credit Facilities | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Applicable margin (as a percent) | 5.00% | ||||||||||
Other percentage of cash flow required to reduce aggregate principal amount of new term loans outstanding to achieve target principal amount that declines | 100.00% | ||||||||||
APLP Holdings | Credit Facilities | London Interbank Offered Rate (LIBOR) | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Applicable margin (as a percent) | 2.75% | 3.00% | 3.50% | 4.25% | |||||||
APLP Holdings | Credit Facilities | Through March 31,2023 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Leverage ratio as defined in Credit Agreement | 4.25 | 4.25 | |||||||||
APLP Holdings | Credit Facilities | Through March 31,2023 | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest coverage ratio as defined in Credit Agreement | 3.5 | 3.5 | |||||||||
APLP Holdings | Credit Facilities | Through March 31,2023 | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest coverage ratio as defined in Credit Agreement | 4 | 4 | |||||||||
APLP Holdings | Senior secured term loans | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Face amount of debt | $ 700 | $ 700 | |||||||||
Prepayment of term loans if change of control occurs, as a percentage of par | 101.00% | ||||||||||
Percent of principal amount required to be repaid, prepaid, refinanced or replaced if APLP elects to do so within one year of initial funding date | 101.00% | ||||||||||
APLP Holdings | Revolver | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Face amount of debt | $ 200 | ||||||||||
Outstanding balance of senior credit facility | $ 0 | ||||||||||
Borrowing capacity | $ 200 | $ 180 | |||||||||
Number Of Banks | Lender | 2 | ||||||||||
Deferred financing costs | $ 0.9 | ||||||||||
APLP Holdings | Revolver | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Upsizing borrowing capacity | $ 30 | ||||||||||
Borrowing capacity | 210 | ||||||||||
APLP Holdings | Senior secured term loan facility, due 2025 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Total debt | 307.5 | ||||||||||
Debt repriced | $ 307.5 | ||||||||||
Interest rate margin reduction due to repricing, as a percent | 0.25% | ||||||||||
Interest rate margin additional reduction due to repricing, as a percent | 0.25% | ||||||||||
Leverage ratio as defined in Credit Agreement | 2.75 | ||||||||||
Term loan maturity | 2 years | ||||||||||
Deferred financing costs | 0.8 | ||||||||||
Write-off of deferred financing costs | $ 0.5 | ||||||||||
APLP Holdings | Senior secured term loan facility, due 2025 | London Interbank Offered Rate (LIBOR) | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Applicable margin (as a percent) | 2.50% | ||||||||||
Minimum percentage of variable rate base | 1.00% |
Long-term debt - Notes of the P
Long-term debt - Notes of the Partnership and Non-Recourse Debt (Details) - Senior unsecured notes, due June 2036 $ in Millions, $ in Millions | Dec. 31, 2020USD ($) | Dec. 31, 2020CAD ($) |
Long-term debt | ||
Long-term Debt, Gross | $ 210 | |
APLP Partnership | ||
Long-term debt | ||
Long-term Debt, Gross | $ 164.9 | $ 210 |
Interest rate (as a percent) | 5.95% | 5.95% |
Convertible debentures (Details
Convertible debentures (Details) - Convertible Debentures $ in Millions, $ in Millions | Dec. 31, 2020USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2019USD ($) | Apr. 10, 2019 |
Convertible debentures | ||||
Less: unamortized deferred financing costs | $ 3.2 | $ 3.8 | ||
Less: Unamortized discount | (3) | (3.6) | ||
Total current and long-term convertible debentures | $ 84.1 | 81.1 | ||
6.00% Debenture Due January 31, 2025 | ||||
Convertible debentures | ||||
Convertible debentures stated interest rate percentage | 6.00% | 6.00% | ||
Long-term Debt, Gross | $ 90.3 | $ 115 | $ 88.5 | |
6.00% Debenture due December 2019 | ||||
Convertible debentures | ||||
Convertible debentures stated interest rate percentage | 6.00% |
Convertible debentures - Series
Convertible debentures - Series E Debentures (Details) $ / shares in Units, $ in Thousands, $ in Millions | Feb. 02, 2018CAD ($) | Jan. 29, 2018CAD ($)item$ / shares | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Apr. 10, 2019CAD ($) | Mar. 03, 2018CAD ($) | Mar. 02, 2018USD ($) |
Convertible debentures | |||||||
Accrued interest | $ 2.5 | $ 2.6 | |||||
Series E Debentures | |||||||
Convertible debentures | |||||||
Sale offering, principal amount | $ 100,000 | ||||||
Amount of underwriters option to purchase additional debentures | 15,000 | ||||||
Sale of offering, principal amount after issuance costs | $ 94,700 | ||||||
Series E Debentures | Maximum | |||||||
Convertible debentures | |||||||
Period of underwriters option to purchase | 30 days | ||||||
Series E Debentures | Over-Allotment Option | |||||||
Convertible debentures | |||||||
Net proceeds from issuance of convertible debentures, after underwriting discounts and expenses | $ 15,000 | ||||||
Sale of offering, principal amount after issuance costs | $ 14,400 | ||||||
Series E Debentures | 6.00% Debenture Due January 31, 2025 | |||||||
Convertible debentures | |||||||
Conversion debt principal amount | $ 1,000 | ||||||
Conversion rate of the debentures (in Shares per Dollar) | 238.0952 | ||||||
Conversion price of shares (in dollars per share) | $ / shares | $ 4.20 | ||||||
Number of consecutive trading days used to determine weighted average trading price | item | 20 | ||||||
Number of days common stock price must exceed threshold percentage | item | 5 | ||||||
Series E Debentures | 6.00% Debenture Due January 31, 2025 | Maximum | |||||||
Convertible debentures | |||||||
Period of prior notice of redemption | 60 days | ||||||
Series E Debentures | 6.00% Debenture Due January 31, 2025 | Minimum | |||||||
Convertible debentures | |||||||
Period of prior notice of redemption | 30 days | ||||||
Debt instrument, redemption price threshold, percentage | 125.00% | ||||||
Series D Debentures | |||||||
Convertible debentures | |||||||
Notice to redeem remaining principal amount | $ 56,200 | ||||||
Series D Debentures | 6.00% Debenture due December 2019 | |||||||
Convertible debentures | |||||||
Accrued interest | $ 400 | ||||||
Notice to redeem remaining principal amount | $ 24,700 | ||||||
Series C Debentures | |||||||
Convertible debentures | |||||||
Notice to redeem remaining principal amount | $ 42.5 |
Convertible debentures - Seri_2
Convertible debentures - Series E Conversion Option (Details) - USD ($) $ in Millions | Jan. 29, 2018 | Dec. 31, 2020 | Dec. 31, 2019 |
Convertible debentures | |||
Derivative Liabilities measured at fair value | $ 19.1 | $ 27.9 | |
Series E Debentures | |||
Convertible debentures | |||
Derivative Liabilities measured at fair value | $ 4.7 | 1.5 | $ 3.2 |
Gain (loss) on derivatives | $ 0 | ||
Derivative fair value of derivative liability discount | $ 4.7 |
Fair value of financial instr_3
Fair value of financial instruments - carrying value and FV (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Carrying Amount | ||
Fair value of financial instruments | ||
Long-term debt, including current portion | $ 487.2 | $ 560.4 |
Convertible debentures | 90.3 | 88.5 |
Fair Value | ||
Fair value of financial instruments | ||
Long-term debt, including current portion | 539 | 589.5 |
Convertible debentures | $ 94.6 | $ 93 |
Fair value of financial instr_4
Fair value of financial instruments - recurring (Details) - Recurring - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Assets: | ||
Cash and cash equivalents | $ 38.8 | $ 74.9 |
Restricted cash | 7.1 | 7.7 |
Derivative instruments asset | 0.4 | 0.7 |
Total | 46.3 | 83.3 |
Liabilities: | ||
Derivative instruments liability | 19.1 | 27.9 |
Total | 19.1 | 27.9 |
Level 1 | ||
Assets: | ||
Cash and cash equivalents | 38.8 | 74.9 |
Restricted cash | 7.1 | 7.7 |
Total | 45.9 | 82.6 |
Level 2 | ||
Assets: | ||
Derivative instruments asset | 0.4 | 0.7 |
Total | 0.4 | 0.7 |
Liabilities: | ||
Derivative instruments liability | 17.6 | 24.7 |
Total | 17.6 | 24.7 |
Level 3 | ||
Liabilities: | ||
Derivative instruments liability | 1.5 | 3.2 |
Total | $ 1.5 | $ 3.2 |
Fair value of financial instr_5
Fair value of financial instruments - credit valuation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Asset acquisitions | ||
Gain in change in fair value of derivative instruments | $ 6.8 | $ (8.9) |
Recurring | Credit valuation adjustments | ||
Asset acquisitions | ||
Net increase in fair value | 0.5 | 1.1 |
Pre-tax gain in other comprehensive income | 0.1 | 0.1 |
Gain in change in fair value of derivative instruments | $ 0.4 | $ 1 |
Fair value of financial instr_6
Fair value of financial instruments - Conversion Option Derivative (Details) - Derivative Financial Instruments, Assets - Level 3 $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Beginning balance of liability | $ 3.2 |
Total unrealized gain (loss) | 1.8 |
Currency transaction loss | (0.1) |
Ending balance of liability | $ 1.5 |
Accounting for derivative ins_3
Accounting for derivative instruments and hedging activities (Details) $ in Millions, kJ in Billions | May 15, 2020MMBTU | Dec. 31, 2020USD ($)kJMMBTUcontract$ / J | Dec. 31, 2019USD ($)MMBTU | Apr. 13, 2016USD ($) |
Derivative instruments designated as cash flow hedges | ||||
Derivative instruments | ||||
Number of derivative contracts designated as cash flow hedges | contract | 1 | |||
Adjusted Eurodollar Rate | ||||
Derivative instruments | ||||
Applicable margin (as a percent) | 2.50% | |||
Nipigon Project | ||||
Derivative instruments | ||||
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | kJ | 6,500 | |||
Gas purchase agreements | Nipigon Project | ||||
Derivative instruments | ||||
Price per Gj | $ / J | 4.57 | |||
Gas purchase agreements | Nipigon Project | Minimum | ||||
Derivative instruments | ||||
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | kJ | 6,500 | |||
Gas purchase and sales agreements | Morris Project | ||||
Derivative instruments | ||||
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | MMBTU | 700,000 | |||
Natural gas swaps | ||||
Derivative instruments | ||||
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | MMBTU | 12,400,000 | 16,300,000 | ||
Natural gas swaps | Orlando project | ||||
Derivative instruments | ||||
Notional amount, energy (in joules: Ontario, in Mmbtu: Orlando and Morris) | MMBTU | 12,400,000 | |||
Natural gas swaps during 2016 | Orlando project | ||||
Derivative instruments | ||||
Percentage of the entity's share in required natural gas purchases hedge | 100.00% | |||
Interest rate swaps | ||||
Derivative instruments | ||||
Notional amount | $ 122.3 | $ 468.4 | ||
Derivative, Average Swaption Interest Rate | 2.20% | |||
Swaption interest rate (as a percent) | 4.70% | |||
Interest rate swaps | Adjusted Eurodollar Rate | ||||
Derivative instruments | ||||
Derivative, Floor Interest Rate | 1.00% | |||
Interest rate swaps | Minimum | ||||
Derivative instruments | ||||
Minimum fixed interest rate (as a percent) | 3.50% | |||
Interest rate swaps | Swaption interest rate until February 15, 2023 | Cadillac Project | ||||
Derivative instruments | ||||
Swaption interest rate (as a percent) | 6.30% | |||
Interest rate swaps | Swaption interest rate after February 15, 2023 | Cadillac Project | ||||
Derivative instruments | ||||
Swaption interest rate (as a percent) | 6.40% | |||
Foreign currency forward contracts | Derivative instruments not designated as cash flow hedges | ||||
Derivative instruments | ||||
Number of forward contracts | contract | 0 | |||
APLP Holdings | Senior secured term loans | ||||
Derivative instruments | ||||
Face amount of debt | $ 700 | $ 700 | ||
APLP Holdings | Interest rate swaps | Adjusted Eurodollar Rate | Senior secured term loans | Long-term debt excluding debentures | ||||
Derivative instruments | ||||
Notional amount | 307.5 | |||
Remaining aggregate principal amount | $ 307.5 |
Accounting for derivative ins_4
Accounting for derivative instruments and hedging activities - forecasted transactions (Details) kJ in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)MMBTUkJ | Dec. 31, 2019USD ($)kJMMBTU | |
Natural gas swaps | ||
Derivative instruments | ||
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | MMBTU | 12.4 | 16.3 |
Gas purchase agreements | ||
Derivative instruments | ||
Volume of forecasted transactions, energy (swaps: Mmbtu, agreements: joules) | kJ | 4 | 6.4 |
Interest rate swaps | ||
Derivative instruments | ||
Volume of forecasted transactions, (in dollars) | $ | $ 122.3 | $ 468.4 |
Accounting for derivative ins_5
Accounting for derivative instruments and hedging activities - FV by Bal Sht Loc (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Fair value of derivative instruments | ||
Derivative Assets | $ 0.4 | $ 0.7 |
Derivative Liabilities | 19.1 | 27.9 |
Derivative instruments designated as cash flow hedges | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 1.6 | 1.5 |
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 0.6 | 0.4 |
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 1 | 1.1 |
Derivative instruments not designated as cash flow hedges | ||
Fair value of derivative instruments | ||
Derivative Assets | 0.4 | 0.7 |
Derivative Liabilities | 17.5 | 26.4 |
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 4.1 | 1.9 |
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 0.9 | 1.1 |
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 0.8 | 1.9 |
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 1.9 | 4.2 |
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current | ||
Fair value of derivative instruments | ||
Derivative Assets | 0.4 | 0.7 |
Derivative Liabilities | 4 | 4.6 |
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term | ||
Fair value of derivative instruments | ||
Derivative Liabilities | 4.3 | 9.5 |
Derivative instruments not designated as cash flow hedges | Convertible Debentures | Current | ||
Fair value of derivative instruments | ||
Derivative Liabilities | $ 1.5 | $ 3.2 |
Accounting for derivative ins_6
Accounting for derivative instruments and hedging activities - AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
AOCI Attributable to Parent, Net of Tax | ||
Change in fair value of cash flow hedges | $ (0.5) | $ (0.3) |
Realized from OCI during the period | (0.5) | (0.3) |
Interest rate swaps | ||
AOCI Attributable to Parent, Net of Tax | ||
Accumulated OCI balance at beginning of period | 1.6 | 1.6 |
Change in fair value of cash flow hedges | (0.5) | (0.3) |
Realized from OCI during the period | 0.5 | 0.3 |
Accumulated OCI balance at end of period | 1.6 | $ 1.6 |
Settlements expected to be recognized from OCI in expense in the next 12 months, net of tax | 0.5 | |
Tax effect of gains (losses) expected to be realized from OCI in the next 12 months | $ 0.1 |
Accounting for derivative ins_7
Accounting for derivative instruments and hedging activities - gain, loss (Details) - Derivative instruments not designated as cash flow hedges - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Change in fair value of derivatives | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments | $ 6.8 | $ (8.9) |
Natural gas swaps | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Realized loss (gain) for derivative instruments | 2.5 | 0.9 |
Natural gas swaps | Change in fair value of derivatives | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments | 3.4 | (4.6) |
Gas purchase agreements | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Realized loss (gain) for derivative instruments | 8.3 | 8.2 |
Gas purchase agreements | Change in fair value of derivatives | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments | 5.4 | 3.2 |
Interest rate swaps | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Realized loss (gain) for derivative instruments | 5 | (3.2) |
Interest rate swaps | Change in fair value of derivatives | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments | (2) | (7.5) |
Convertible Debentures | Other (income) expense, net | ||
Impact of derivative instruments on the consolidated statements of operations | ||
Unrealized gain (loss) resulting from changes in the fair value of derivative financial instruments | $ (1.8) | $ 1.8 |
Income tax expense - Current an
Income tax expense - Current and Deferred tax benefit (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Components of income tax expenses (benefit) | ||
Income tax (benefit) expense | $ (24.2) | $ 9.8 |
US | ||
Components of income tax expenses (benefit) | ||
Current income tax expense | 2.8 | 1.9 |
Deferred income tax (benefit) expense | (28.1) | 7.7 |
Income tax (benefit) expense | (25.3) | 9.6 |
Canada. | ||
Components of income tax expenses (benefit) | ||
Current income tax expense | 2.8 | 3 |
Deferred income tax (benefit) expense | (1.7) | (2.8) |
Income tax (benefit) expense | $ 1.1 | $ 0.2 |
Income tax expense - Reconcilia
Income tax expense - Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Reconciliation of income taxes | ||
Computed income tax expense (benefit) at Canadian statutory rate | $ 13.3 | $ (9.2) |
Change in valuation allowance | (40.2) | 5.7 |
Dividend withholding tax and other cash taxes | 1.3 | |
Foreign exchange | 0.6 | |
Impairments | 7.7 | |
Income tax (benefit) expense | (24.2) | 9.8 |
US | ||
Reconciliation of income taxes | ||
Computed income tax expense (benefit) at Canadian statutory rate | 11.2 | (2.2) |
Operating in countries with different income tax rates | (0.3) | 0.1 |
Income tax benefit after adjustments for countries with different income tax rates | 10.9 | (2.1) |
Change in valuation allowance | (39.7) | (2.2) |
Income tax benefit after adjustments for countries with different income tax rates and valuation allowance | (28.8) | (4.3) |
Dividend withholding tax and other cash taxes | 1.8 | 1.1 |
Changes in tax rates | (0.1) | 2.2 |
Changes in estimates due to tax filings | 3 | (0.1) |
Capital gain on intercompany notes | 0.1 | |
Impairments | 7.7 | |
Other | (1.2) | 2.9 |
Total other reconciliation items | 3.5 | 13.9 |
Income tax (benefit) expense | $ (25.3) | $ 9.6 |
Canada. | ||
Reconciliation of income taxes | ||
Effective income tax rate | 27.00% | 27.00% |
Computed income tax expense (benefit) at Canadian statutory rate | $ 2.1 | $ (7) |
Income tax benefit after adjustments for countries with different income tax rates | 2.1 | (7) |
Change in valuation allowance | (0.5) | 7.9 |
Income tax benefit after adjustments for countries with different income tax rates and valuation allowance | 1.6 | 0.9 |
Dividend withholding tax and other cash taxes | 0.2 | 0.2 |
Foreign exchange | (0.6) | 1.7 |
Changes in estimates due to tax filings | (0.2) | |
Capital gain on intercompany notes | 0.2 | |
Other | (0.3) | (2.4) |
Total other reconciliation items | (0.5) | (0.7) |
Income tax (benefit) expense | $ 1.1 | $ 0.2 |
Income tax expense - Deferred t
Income tax expense - Deferred tax assets and liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Deferred tax assets: | ||
Loss carryforwards | $ 123.9 | $ 135.9 |
Capital loss carryforwards | 35.3 | 35.8 |
Interest expense limitation carryforwards | 9.7 | |
Finance and share issuance costs | 0.1 | |
Tax Credits | 1.4 | 1.4 |
Stock-based compensation | 2.4 | 2.4 |
Derivative contracts | 3.8 | 5.7 |
Other long-term notes | 2.3 | |
Other | 3.1 | 0.9 |
Total deferred tax assets | 172.2 | 191.9 |
Less: Valuation allowance | (105.2) | (145.4) |
Net deferred tax assets | 67 | 46.5 |
Deferred tax liabilities: | ||
Intangible assets | (22) | (21.9) |
Property, plant and equipment | (22) | (31.2) |
Basis difference in joint ventures | (5.8) | (5.4) |
Other long-term investments | (1.3) | |
Total deferred tax liabilities | (49.8) | (59.8) |
Net deferred tax liability | (13.3) | |
Net deferred tax asset (liability) | 17.2 | |
US | ||
Deferred tax liabilities: | ||
Net deferred tax liability | (23.7) | |
Net deferred tax asset (liability) | 4.5 | |
Canada. | ||
Deferred tax liabilities: | ||
Net deferred tax asset (liability) | $ 12.7 | $ 10.4 |
Income tax expense - Other (Det
Income tax expense - Other (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Reconciliation of income taxes | ||
Tax expense | $ (24.2) | $ 9.8 |
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 13.3 | (9.2) |
Impact related to change in estimates | 3 | |
Other permanent differences | 0.3 | 0.4 |
Net deferred tax liability | (13.3) | |
Net deferred tax liability | 17.2 | |
Valuation allowance | 105.2 | 145.4 |
Increase (decrease) in the valuation allowance | (40.2) | 5.7 |
Foreign exchange | 0.6 | |
Dividend withholding tax and other cash taxes | 1.3 | |
Impairments | 7.7 | |
US | ||
Reconciliation of income taxes | ||
Tax expense | (25.3) | 9.6 |
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 11.2 | (2.2) |
Net deferred tax liability | (23.7) | |
Net deferred tax liability | 4.5 | |
Capital gain on intercompany notes | 0.1 | |
Changes in tax rates | (0.1) | 2.2 |
Increase (decrease) in the valuation allowance | (39.7) | (2.2) |
Operating in countries with different income tax rates | (0.3) | 0.1 |
Dividend withholding tax and other cash taxes | $ 1.8 | 1.1 |
Impairments | $ 7.7 | |
Cumulative pre tax period | 3 years | |
Canada. | ||
Reconciliation of income taxes | ||
Enacted statutory income tax rate | 27.00% | 27.00% |
Tax expense | $ 1.1 | $ 0.2 |
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 2.1 | (7) |
Net deferred tax liability | 12.7 | 10.4 |
Capital gain on intercompany notes | 0.2 | |
Increase (decrease) in the valuation allowance | (0.5) | 7.9 |
Foreign exchange | (0.6) | 1.7 |
Dividend withholding tax and other cash taxes | $ 0.2 | $ 0.2 |
Income tax expense - NOL (Detai
Income tax expense - NOL (Details) $ in Millions | Dec. 31, 2020USD ($) |
Operating loss carryforwards | |
Net operating loss carryforwards | $ 477.1 |
2029 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 19.9 |
2031 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 25.4 |
2032 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 19.4 |
2033 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 44.6 |
2034 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 131.6 |
2035 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 154.1 |
2036 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 37.7 |
2037 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 25.7 |
2038 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 10.3 |
2039 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 7.2 |
2040 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 1.2 |
US | |
Operating loss carryforwards | |
Net operating loss carryforwards | 369.5 |
US | 2031 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 25.4 |
US | 2032 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 13.4 |
US | 2033 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 20.6 |
US | 2034 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 122.3 |
US | 2035 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 154.1 |
US | 2036 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 17 |
US | 2037 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 16.7 |
Canada. | |
Operating loss carryforwards | |
Net operating loss carryforwards | 107.6 |
Canada. | 2029 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 19.9 |
Canada. | 2032 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 6 |
Canada. | 2033 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 24 |
Canada. | 2034 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 9.3 |
Canada. | 2036 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 20.7 |
Canada. | 2037 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 9 |
Canada. | 2038 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 10.3 |
Canada. | 2039 | |
Operating loss carryforwards | |
Net operating loss carryforwards | 7.2 |
Canada. | 2040 | |
Operating loss carryforwards | |
Net operating loss carryforwards | $ 1.2 |
Equity compensation plans (Deta
Equity compensation plans (Details) $ / shares in Units, $ in Millions | Mar. 29, 2019 | Jan. 22, 2015$ / shares | Dec. 31, 2020USD ($)$ / sharesshares | Dec. 31, 2019USD ($)$ / sharesshares |
Weighted-Average Fair Value per Unit | ||||
Portion of notional units settled in common stock prior to Plan modification | 66.6667% | |||
Portion of notional units settled in cash prior to Plan modification | 33.3333% | |||
Long-term incentive plan | ||||
Units | ||||
Outstanding at the beginning of the period (in shares) | shares | 3,578,092 | 3,952,201 | ||
Granted (in shares) | shares | 1,866,748 | 1,724,081 | ||
Vested and redeemed (in shares) | shares | (1,702,571) | (2,071,335) | ||
Forfeitures (in shares) | shares | (31,929) | (26,855) | ||
Outstanding at the end of the period (in shares) | shares | 3,710,340 | 3,578,092 | ||
Weighted-Average Fair Value per Unit | ||||
Outstanding at the beginning of the period (in dollars per share) | $ 2.38 | $ 2.09 | ||
Granted (in dollars per share) | 2.49 | 2.72 | ||
Vested and redeemed (in dollars per share) | 2.34 | 2.10 | ||
Forfeitures (in dollars per share) | 2.42 | 2.17 | ||
Outstanding at the end of the period (in dollars per share) | $ 2.45 | $ 2.38 | ||
Fair value of outstanding notional units | $ | $ 9.1 | $ 8.5 | ||
Weighted average vesting term | 1 year 8 months 12 days | |||
Unrecognized compensation expense | $ | $ 3 | |||
Cash payments made for vested notional units | $ | 3.3 | 2.1 | ||
Compensation expense related to LTIP | $ | $ 4.1 | $ 4.9 | ||
Transition equity participation agreement | ||||
Transition equity participation agreement | ||||
Number of transition notional shares outstanding | shares | 269,952 | |||
Minimum market price required for 3 consecutive months to vest remaining shares | $ 4.77 | |||
Minimum percentage by which weighted average Canadian dollar price exceeds market price | 50.00% | |||
Share Price | $ 3.18 | |||
Notional shares vest age | 62 years | |||
Transition equity participation agreement | Minimum | ||||
Transition equity participation agreement | ||||
Number of consecutive months, weighted average Canadian dollar price must exceed market price of share by 50% for vesting | 3 months |
Employee benefit plans - Net an
Employee benefit plans - Net annual benefit cost (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2020CAD ($) | |
Employee benefit plans | |||
Expected contribution to pension plans | $ 0.5 | ||
Net annual periodic pension cost | |||
Service cost benefits earned | $ 0.3 | $ 0.3 | |
Interest cost on benefit obligation | 0.4 | 0.5 | |
Expected return on plan assets | (0.7) | (0.7) | |
Amortization of actuarial loss | 0.1 | ||
Settlements | 0.3 | ||
Net period benefit cost | $ 0.1 | $ 0.4 |
Employee benefit plans - Change
Employee benefit plans - Changes in obligations and assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Change in benefit obligation | ||
Benefit obligation at beginning of the year | $ (14.1) | $ (13.2) |
Service cost | (0.3) | (0.3) |
Interest cost | (0.4) | (0.5) |
Actuarial loss | (2.3) | (2) |
Employee contributions | (0.1) | (0.1) |
Benefits paid | 0.3 | 0.2 |
Settlements | 2.4 | |
Foreign currency adjustment | (0.5) | (0.6) |
Benefit obligation at end of year | (17.4) | (14.1) |
Change in plan assets | ||
Fair value of plan assets at beginning of the year | 12.9 | 12 |
Actual return on plan assets | 1.2 | 2 |
Employer contributions | 0.2 | 0.8 |
Employee contributions | 0.1 | 0.1 |
Benefits paid | (0.3) | (0.2) |
Settlements | (2.4) | |
Foreign currency adjustment | 0.2 | 0.6 |
Fair value of plan assets at end of year | 14.3 | 12.9 |
Funded status at end of year - excess of obligation over assets | $ (3.1) | $ (1.2) |
Employee benefit plans - Amount
Employee benefit plans - Amounts recognized and significant components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Amount recognized in the balance sheet | |||
Non-current liabilities | $ 3.1 | $ 1.2 | |
Amounts recognized in accumulated OCL | |||
Unrecognized loss | (3.1) | (1.7) | |
Balances of significant components of the pension plan | |||
Projected benefit obligation | 17.4 | 14.1 | $ 13.2 |
Accumulated benefit obligation | 16.4 | 12.9 | |
Fair value of plan assets | 14.3 | 12.9 | $ 12 |
Amount invested in common collective trust | 14.3 | $ 12.9 | |
Amount of investments categorized as Level 1 or Level 3 | $ 0 |
Employee benefit plans - Weight
Employee benefit plans - Weighted average assumptions (Details) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Weighted-Average Assumptions used to calculate benefit obligations | ||
Discount rate (as a percent) | 2.50% | 3.25% |
Rate of compensation increase (as a percent) | 2.00% | 2.00% |
Weighted-Average Assumptions used to calculate benefit expense | ||
Discount rate (as a percent) | 3.30% | 4.00% |
Rate of return on plan assets (as a percent) | 5.50% | 5.80% |
Rate of compensation increase (as a percent) | 2.00% | 2.00% |
Period over which corporate AA rated yield curve extrapolated to derive CIA/Natcan curve | 10 years | |
Maturity period of corporate bonds rated AA | 10 years |
Employee benefit plans - Weig_2
Employee benefit plans - Weighted average asset allocations (Details) | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plan | ||
Percentage of plan assets | 100.00% | 100.00% |
Canadian equity | ||
Defined Benefit Plan | ||
Percentage of plan assets | 31.00% | 30.00% |
U.S. equity | ||
Defined Benefit Plan | ||
Percentage of plan assets | 14.00% | 14.00% |
International equity | ||
Defined Benefit Plan | ||
Percentage of plan assets | 17.00% | 14.00% |
Canadian fixed income | ||
Defined Benefit Plan | ||
Percentage of plan assets | 38.00% | 39.00% |
Real estate equities | ||
Defined Benefit Plan | ||
Percentage of plan assets | 3.00% |
Employee benefit plans - Future
Employee benefit plans - Future benefit payments (Details) $ in Millions | Dec. 31, 2020CAD ($) |
Expected future benefit payments | |
2021 | $ 0.5 |
2022 | 0.5 |
2023 | 0.6 |
2024 | 0.6 |
2025 | 0.6 |
2026-2030 | $ 4 |
Employee benefit plans - 401K (
Employee benefit plans - 401K (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Employee benefit plans | ||
Defined Contribution Plan, Cost | $ 1.5 | $ 1.3 |
Common shares (Details)
Common shares (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 18, 2020 | Aug. 24, 2020 | May 01, 2020 | Apr. 30, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | Mar. 25, 2020 |
Common shares | |||||||
Common Stock, No Par Value | $ 0 | $ 0 | |||||
Common Stock, Shares Authorized, Unlimited | Unlimited | Unlimited | |||||
Common Stock, Shares, Issued | 89,222,568 | 108,675,294 | |||||
Common Stock, Shares, Outstanding | 89,222,568 | 108,675,294 | |||||
Stock Repurchase Program | |||||||
Shares repurchased and canceled | $ 41.6 | $ 2.5 | |||||
Future Shelf Registration Period Available | 3 years | ||||||
Shelf Registration, Authorized Amount | $ 250 | ||||||
Normal Course Issuer Bid [Member] | |||||||
Stock Repurchase Program | |||||||
Public float amount used to determine share amount, percent | 10.00% | ||||||
Shares repurchased and canceled | $ 15.8 | ||||||
Shares repurchased and canceled (in shares) | 7,540,105 | ||||||
Normal Course Issuer Bid [Member] | Maximum | |||||||
Stock Repurchase Program | |||||||
Number of shares authorized for repurchase | 8,554,391 | ||||||
Number of shares that may be purchased per day | 10,420 | ||||||
SIB | |||||||
Stock Repurchase Program | |||||||
Number of shares authorized for repurchase | 12,820,512 | ||||||
Shares repurchased and canceled | $ 25.8 | $ 25.8 | |||||
Shares repurchased and canceled (in shares) | 12,500,000 | 12,500,000 | |||||
Stock Repurchase Program, Authorized Amount | $ 25 | ||||||
Stock Repurchase Program, Number of Shares Authorized to be Repurchased As Percentage Of Common Stock Issued And Outstanding | 12.00% | ||||||
Share Price | $ 2 | $ 1.95 | |||||
Share Price, Increment | 0.05 | ||||||
SIB | Maximum | |||||||
Stock Repurchase Program | |||||||
Share Price | 2.20 | ||||||
SIB | Minimum | |||||||
Stock Repurchase Program | |||||||
Share Price | $ 1.95 |
Preferred shares issued by a _2
Preferred shares issued by a subsidiary company - (Details) $ in Millions | Dec. 31, 2020$ / sharesshares | Dec. 31, 2020USD ($)shares | Dec. 31, 2019USD ($) | Dec. 31, 2014 | Dec. 31, 2009$ / sharesshares | Dec. 31, 2007$ / sharesshares |
Preferred shares issued by a subsidiary company | ||||||
Preferred shares repurchased and retired | $ | $ 6.4 | $ 8 | ||||
Net income attributable to preferred shares of a subsidiary company | $ | 0.7 | 1.2 | ||||
Subsidiary Issuer | Cumulative Preferred Stock | ||||||
Preferred shares issued by a subsidiary company | ||||||
Dividend paid | $ | 6.8 | 7.4 | ||||
Preferred shares repurchased and retired | $ | 6.4 | 8 | ||||
Net income attributable to preferred shares of a subsidiary company | $ | $ 7.4 | $ 8.6 | ||||
Subsidiary Issuer | Series 1 Shares | ||||||
Preferred shares issued by a subsidiary company | ||||||
Number of shares issued in transaction | 5,000,000 | |||||
Dividend rate on preferred shares (as a percent) | 4.85% | |||||
Issuance price per share | $ / shares | $ 25 | |||||
Preferred Stock, Shares Outstanding | 3,465,706 | |||||
Redemption price after specified date and thereafter (in Canadian dollars per share) | $ / shares | $ 25 | |||||
Preferred shares repurchased and retired (in shares) | 381,794 | |||||
Subsidiary Issuer | Series 2 Shares | ||||||
Preferred shares issued by a subsidiary company | ||||||
Number of shares issued in transaction | 4,000,000 | |||||
Dividend rate on preferred shares (as a percent) | 5.74% | 7.00% | ||||
Issuance price per share | $ / shares | $ 25 | |||||
Preferred Stock, Shares Outstanding | 2,441,766 | |||||
Redemption price after specified date and thereafter (in Canadian dollars per share) | $ / shares | $ 25 | |||||
Period for declaration of dividend at reset rate | 5 years | |||||
Reference rate for dividend | five-year Government of Canada bond yield | |||||
Percentage points added to the reference rate | 4.18% | |||||
Preferred shares repurchased and retired (in shares) | 62,365 | |||||
Subsidiary Issuer | Series 3 Shares | ||||||
Preferred shares issued by a subsidiary company | ||||||
Dividend rate on preferred shares (as a percent) | 4.30% | |||||
Preferred Stock, Shares Outstanding | 957,391 | |||||
Redemption price after specified date and thereafter (in Canadian dollars per share) | $ / shares | $ 25.50 | |||||
Period for declaration of dividend at reset rate | 5 years | |||||
Reference rate for dividend | 90-day Government of Canada Treasury bill rate | |||||
Percentage points added to the reference rate | 4.18% | |||||
Preferred shares repurchased and retired (in shares) | 120,000 |
Basic and diluted earnings (l_3
Basic and diluted earnings (loss) per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Numerator: | ||
Net income (loss) attributable to Atlantic Power Corporation | $ 74.2 | $ (42.6) |
Add: convertible debenture interest expense | 3.8 | |
Net income (loss) available to common stockholder, Diluted | $ 78 | $ (42.6) |
Denominator: | ||
Weighted average basic shares outstanding | 95.8 | 109.3 |
Basic earnings per share attributable to Atlantic Power Corporation | $ 0.77 | $ (0.39) |
Share-based compensation (in shares) | 1.7 | |
Convertible debentures (in shares) | 27.4 | |
Weighted Average Number of Potentially Diluted Shares | 124.9 | 109.3 |
Diluted earnings per share attributable to Atlantic Power Corporation | $ 0.62 | $ (0.39) |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract] | ||
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS | $ 29.3 | |
Share-based compensation. | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract] | ||
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS | 1.5 | |
Convertible Debentures | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract] | ||
Anti-dilutive instruments outstanding that were excluded from computation of diluted EPS | $ 27.8 |
Segment and geographic inform_3
Segment and geographic information - EBITDA (Detail) $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)segment | Dec. 31, 2019USD ($) | |
Segment and geographic information | ||
Number of reportable segments | segment | 4 | |
Project revenue | $ 272 | $ 281.6 |
Segment assets | 847.2 | 935.6 |
Goodwill. | 21.3 | 21.3 |
Capital expenditures | 24.8 | 7.3 |
Project Adjusted EBITDA | 188.7 | 196.1 |
Change in fair value of derivative instruments | (6.8) | 8.9 |
Depreciation and amortization | 76.6 | 80.7 |
Interest, net | 2.8 | 2.5 |
Insurance (gain) Loss | (0.7) | 1 |
Impairment | 55 | |
Other project (income) expense | (2.1) | 1.2 |
Project income (loss) | 118.9 | 46.8 |
Administration | 24.8 | 23.9 |
Interest expense, net | 42.4 | 44 |
Foreign exchange (gain) loss | 5.1 | 11.9 |
Other income (expense), net | (2.7) | 1 |
Income (loss) from operations before income taxes | 49.3 | (34) |
Income tax expense | (24.2) | 9.8 |
Net income (loss) | 73.5 | (43.8) |
Solid Fuel | ||
Segment and geographic information | ||
Project revenue | 94.5 | 80 |
Segment assets | 202.8 | 222.7 |
Capital expenditures | 24.1 | 6.8 |
Project Adjusted EBITDA | 39.9 | 32.7 |
Depreciation and amortization | 22.7 | 23.9 |
Interest, net | 2.7 | 2.6 |
Insurance (gain) Loss | (0.7) | 1 |
Impairment | 55 | |
Project income (loss) | 15.2 | (49.8) |
Income (loss) from operations before income taxes | 15.2 | (49.8) |
Net income (loss) | 15.2 | (49.8) |
Natural Gas | ||
Segment and geographic information | ||
Project revenue | 118.2 | 131.8 |
Segment assets | 190.8 | 241 |
Goodwill. | 6.9 | 6.9 |
Capital expenditures | 0.1 | |
Project Adjusted EBITDA | 105 | 108.2 |
Change in fair value of derivative instruments | (8.9) | 1.4 |
Depreciation and amortization | 34.3 | 37.2 |
Interest, net | (0.1) | |
Other project (income) expense | (2.1) | 1.2 |
Project income (loss) | 81.7 | 68.5 |
Income (loss) from operations before income taxes | 81.7 | 68.5 |
Net income (loss) | 81.7 | 68.5 |
Hydroelectric | ||
Segment and geographic information | ||
Project revenue | 58.3 | 68.8 |
Segment assets | 306.3 | 388.3 |
Goodwill. | 14.4 | 14.4 |
Capital expenditures | 0.6 | 0.4 |
Project Adjusted EBITDA | 45.3 | 55.5 |
Depreciation and amortization | 19.6 | 19.5 |
Project income (loss) | 25.7 | 36 |
Income (loss) from operations before income taxes | 25.7 | 36 |
Net income (loss) | 25.7 | 36 |
Corporate | ||
Segment and geographic information | ||
Project revenue | 1 | 1 |
Segment assets | 147.3 | 83.6 |
Capital expenditures | 0.1 | |
Project Adjusted EBITDA | (1.5) | (0.3) |
Change in fair value of derivative instruments | 2.1 | 7.5 |
Depreciation and amortization | 0.1 | |
Interest, net | 0.1 | |
Project income (loss) | (3.7) | (7.9) |
Administration | 24.8 | 23.9 |
Interest expense, net | 42.4 | 44 |
Foreign exchange (gain) loss | 5.1 | 11.9 |
Other income (expense), net | (2.7) | 1 |
Income (loss) from operations before income taxes | (73.3) | (88.7) |
Income tax expense | (24.2) | 9.8 |
Net income (loss) | $ (49.1) | $ (98.5) |
Segment and geographic inform_4
Segment and geographic information - Geographic (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Revenue and Assets | ||
Project revenue | $ 272 | $ 281.6 |
Property, Plant and Equipment, net of accumulated depreciation | 491.8 | 502.1 |
PPA'S and other intangible assets, net of accumulated amortization | 120.3 | 144.3 |
Assets | 847.2 | 935.6 |
United States | ||
Revenue and Assets | ||
Project revenue | 184.9 | 208.4 |
Property, Plant and Equipment, net of accumulated depreciation | 351.2 | 353.9 |
PPA'S and other intangible assets, net of accumulated amortization | 119.4 | 142.8 |
Assets | 666.4 | 762.3 |
Canada | ||
Revenue and Assets | ||
Project revenue | 87.1 | 73.2 |
Property, Plant and Equipment, net of accumulated depreciation | 140.6 | 148.2 |
PPA'S and other intangible assets, net of accumulated amortization | 0.9 | 1.5 |
Assets | $ 180.8 | $ 173.3 |
Segment and geographic inform_5
Segment and geographic information - risk (Details) - Consolidated revenue | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Georgia Power | ||
Consolidated revenue concentration | ||
Percentage of consolidated revenue | 10.40% | 11.10% |
Niagara Mohawk | ||
Consolidated revenue concentration | ||
Percentage of consolidated revenue | 14.80% | 19.60% |
Independent Electricity System Operator | ||
Consolidated revenue concentration | ||
Percentage of consolidated revenue | 13.80% | 12.90% |
BC Hydro | ||
Consolidated revenue concentration | ||
Percentage of consolidated revenue | 12.50% | |
Equistar Chemicals, LP | ||
Consolidated revenue concentration | ||
Percentage of consolidated revenue | 10.90% | 12.00% |
Commitments and contingencies -
Commitments and contingencies - Long-term Commitments (Details) $ in Millions | Dec. 31, 2020USD ($) |
Management Service Commitments | |
Long-term Purchase Commitments | |
2021 | $ 0.4 |
2022 | 0.2 |
Total | 0.6 |
Fuel Supply and Transportation Commitments | |
Long-term Purchase Commitments | |
2021 | 4.2 |
2022 | 4.4 |
Total | $ 8.6 |
Commitments and contingencies_2
Commitments and contingencies - Guarantees and Contingencies (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | 24 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2020 | |
Contingencies | ||||
Insurance Deductible | $ (1) | |||
Impairment | 5.8 | |||
Insurance | $ (16.4) | 1 | ||
Insurance Recoveries | 29.9 | 11.3 | $ 41.2 | |
Insurance Settlements Receivable | $ 0 | 0 | $ 13.5 | 0 |
Gain on business interruption insurance recovery | 15.6 | |||
Gain (Loss) On Insurance Recovery Relating To Property Losses | 0.8 | 0.8 | ||
Cadillac Project | ||||
Contingencies | ||||
Insurance Deductible | 1 | |||
Business interruption loss period | 45 days | |||
Estimate damages claimed for statutory misrepresentation | $ 1.4 | |||
Impairment | 25 | |||
Write-down of capital spares | 0.8 | |||
Insurance receivable | 24.8 | 24.8 | 24.8 | 24.8 |
Insurance Recoveries | 10.1 | 29.9 | $ 11.3 | |
Insurance Settlements Receivable | 13.5 | 13.5 | $ 13.5 | |
Gain on business interruption insurance recovery | $ 9.4 | $ 15.6 |
Commitments and contingencies_3
Commitments and contingencies - Insurance recovery receivable (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | 24 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2020 | |
Commitments and contingencies | ||||
Balance at Beginning of Period | $ 13.5 | |||
Additions | $ 25.8 | |||
Insurance proceeds | (29.9) | (11.3) | $ (41.2) | |
Insured Event, Gain (Loss) | 16.4 | (1) | ||
Insurance Gain (Loss) | 0.7 | (1) | ||
Balance at End of Period | $ 0 | 0 | $ 13.5 | $ 0 |
Gain on business interruption insurance recovery | 15.6 | |||
Amount of gain (loss) on insurance recovery relating to property losses | $ 0.8 | 0.8 | ||
Expected reduction in capacity payments | $ 6 |
Leases - Real estate and equipm
Leases - Real estate and equipment (Details) - item | 12 Months Ended | |
Dec. 31, 2020 | Jan. 01, 2019 | |
Operating Lease Commitments | ||
Number of properties subleased | 1 | |
Rate used to determine lease liabilities at implementation date | 3.75% |
Leases - Lease cost (Details)
Leases - Lease cost (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Lease cost: | ||
Operating lease cost | $ 2.1 | $ 1.9 |
Short-term lease cost | 0.1 | |
Sublease income | (1.1) | (1.2) |
Total lease cost | $ 1 | $ 0.8 |
Leases - Operating lease maturi
Leases - Operating lease maturities - Topic 842 (Details) $ in Millions | Dec. 31, 2020USD ($) |
Future minimum lease commitments | |
2021 | $ 2 |
2022 | 1.8 |
2023 | 1.3 |
2024 | 0.2 |
Total operating lease payments | 5.3 |
Less: present value discount | (0.3) |
Total operating lease liabilities | 5 |
Finance lease payment | |
2021 | 0.1 |
2022 | 0.1 |
Total finance lease payments | 0.2 |
Less: amount representing interest | (0.1) |
Total finance lease liabilities | 0.1 |
Income from subleasing | |
2021 | (1.1) |
2022 | (1.1) |
2023 | (0.7) |
Total income from subleasing | (2.9) |
Net lease payments | |
2021 | 0.9 |
2022 | 0.7 |
2023 | 0.6 |
2024 | 0.2 |
Total net lease payments | $ 2.4 |
Leases - Operating lease matu_2
Leases - Operating lease maturities - Supplemental Information (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)item | |
Cash paid for amounts included in the measurement of lease liabilities: | |
Operating cash flows from operating leases | $ 1.1 |
Lease assets obtained in exchange for new lease liabilities (non-cash): | |
Operating | $ 0.1 |
Weighted average items: | |
Weighted average remaining lease term (in years), Operating leases | 2 years 8 months 12 days |
Weighted average remaining lease term (in years), Finance leases | 1 year 4 months 24 days |
Weighted average discount rate - operating leases | 3.90% |
Weighted average discount rate - finance leases | 4.10% |
Number of lease transactions with related parties | item | 0 |
Leases - PPA Leases (Details)
Leases - PPA Leases (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
May 31, 2019USD ($) | Dec. 31, 2020USD ($)projectagreement | Dec. 31, 2019USD ($) | |
Lessor, Lease, Description [Line Items] | |||
Lease, Practical Expedients, Package [true false] | true | ||
Number of PPAs accounted for as operating leases | agreement | 10 | ||
Number of project which are in operation | project | 21 | ||
Lessor, Operating Lease, Existence of Option to Extend [true false] | false | ||
Operating Lease, Lease Income [Abstract] | |||
Rental income from operating leases | $ 149.6 | $ 172.3 | |
Minimum | |||
Lessor, Lease, Description [Line Items] | |||
Remaining lease term | 1 year | ||
Maximum | |||
Lessor, Lease, Description [Line Items] | |||
Remaining lease term | 23 years | ||
Solid Fuel | |||
Operating Lease, Lease Income [Abstract] | |||
Rental income from operating leases | $ 65.9 | 79.1 | |
Natural Gas | |||
Operating Lease, Lease Income [Abstract] | |||
Rental income from operating leases | 25.4 | 24.4 | |
Manchief | |||
Operating Lease Lessor Sale Of Plant [Abstract] | |||
Sales price of Manchief plant | $ 45.2 | ||
Hydroelectric | |||
Operating Lease, Lease Income [Abstract] | |||
Rental income from operating leases | $ 58.3 | $ 68.8 | |
Mamquam | BC Hydro | |||
Operating Lease Lessor Sale Of Plant [Abstract] | |||
Period of time between the anniversaries the option to purchase will become exercisable after the option is first exercisable | 5 years |
Subsequent Event (Details)
Subsequent Event (Details) - Subsequent event - Squared Capital $ in Millions | Jan. 14, 2021USD ($) |
Subsequent Event [Line Items] | |
Total enterprise value | $ 961 |
Reverse termination fee payable | 12.5 |
Termination fee receivable | $ 15 |