Cover Page
Cover Page | 12 Months Ended |
Dec. 31, 2021shares | |
Cover [Abstract] | |
Entity Central Index Key | 0001127248 |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2021 |
Document Fiscal Period Focus | FY |
Document Fiscal Year Focus | 2021 |
Current Fiscal Year End Date | --12-31 |
Entity File Number | 000-54516 |
Entity Registrant Name | EMERA INC |
Entity Incorporation, State or Country Code | A5 |
Entity Listings [Line Items] | |
Entity Address, Address Line One | 5151 Terminal Road |
Entity Address, City or Town | Halifax |
Entity Address, Country | CA |
Entity Address, Postal Zip Code | B3J 1A1 |
City Area Code | 902 |
Local Phone Number | 428-6096 |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Current Reporting Status | No |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
ICFR Auditor | false |
Auditor Firm Id | 1263 |
Auditor Location | Halifax, Nova Scotia |
Auditor Name | Ernst & Young LLP |
Business Contact [Member] | |
Entity Listings [Line Items] | |
Name of contact personnel | Emera US Finance LP |
Entity Address, Address Line One | 251 Little Falls Drive |
Entity Address, City or Town | Wilmington |
Entity Address, State or Province | DE |
Entity Address, Postal Zip Code | 19808 |
City Area Code | 302 |
Local Phone Number | 636-5401 |
Common Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 261,065,175 |
Series A Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 4,866,814 |
Series B Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 1,133,186 |
Series C Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 10,000,000 |
Series E Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 5,000,000 |
Series F Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Series H Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 12,000,000 |
Series J Preferred Stock [Member] | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Series L Preferred Stock [Member] | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 9,000,000 |
Consolidated Statements of Inco
Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Operating revenues | ||
Total operating revenues (note 6) | $ 5,765 | $ 5,506 |
Operating expenses | ||
Operating, maintenance and general | 1,369 | 1,419 |
Provincial, state, and municipal taxes | 330 | 317 |
Depreciation and amortization | 902 | 881 |
Impairment charges | 0 | 25 |
Total operating expenses | 4,835 | 4,359 |
Income from operations | 930 | 1,147 |
Income from equity investments (note 8) | 143 | 149 |
Other income net (note 9) | 93 | 708 |
Interest expense, net | 611 | 679 |
Income before provision for income taxes | 555 | 1,325 |
Income tax (recovery) expense (note 10) | (6) | 341 |
Net income | 561 | 984 |
Non-controlling interest in subsidiaries | 1 | 1 |
Preferred stock dividends | 50 | 45 |
Net income attributable to common shareholders | $ 510.5 | $ 937.6 |
Earnings per common share (note 12) | ||
Basic | $ 1.98 | $ 3.78 |
Diluted | $ 1.98 | $ 3.78 |
Weighted average shares of common stock outstanding (in millions) (note 12) | ||
Basic | 257.2 | 247.8 |
Diluted | 257.6 | 248.2 |
Dividends per common share declared | $ 2.575 | $ 2.4750 |
Regulated | Electric Revenue | ||
Operating revenues | ||
Total operating revenues (note 6) | $ 4,665 | $ 4,442 |
Operating expenses | ||
Fuel for generation and purchased power (notes 17 and 19) | 1,763 | 1,420 |
Regulated | Gas Revenue | ||
Operating revenues | ||
Total operating revenues (note 6) | 1,261 | 1,034 |
Operating expenses | ||
Fuel for generation and purchased power (notes 17 and 19) | 472 | 293 |
Non-Regulated | ||
Operating revenues | ||
Total operating revenues (note 6) | (161) | 30 |
Non-Regulated | Electric Revenue | ||
Operating expenses | ||
Fuel for generation and purchased power (notes 17 and 19) | $ (1) | $ 4 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Consolidated Statements of Comprehensive Income | ||
Net income | $ 561 | $ 984 |
Other comprehensive income (loss), net of tax | ||
Foreign currency translation adjustment | (42) | (201) |
Unrealized gains on net investment hedges | 5 | 26 |
Cash flow hedges | ||
Net derivative gains | 18 | 0 |
Less: reclassification adjustment for (gains) losses included in income | (1) | 2 |
Net effects of cash flow hedges | 17 | 2 |
Net change in unrecognized pension and post-retirement benefit obligation | 124 | (1) |
Other comprehensive income | 104 | (174) |
Comprehensive income | 665 | 810 |
Comprehensive income attributable to non-controlling interest | 1 | 1 |
Comprehensive Income of Emera Incorporated | $ 664 | $ 809 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Foreign currency translation, tax expense (recovery) | $ 5 | $ (1) |
Hybrid Notes as a hedge of the foreign currency exposure | 1,700 | 1,800 |
Unrealized gains (losses) on net investment hedges | 1 | 4 |
Net derivative gain, tax | 6 | |
Net change in unrecognized pension and post-retirement benefit obligation | 2 | (1) |
Other comprehensive loss, Tax | 14 | $ 2 |
Net investment in United States dollar denominated operations | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,200 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets | ||
Cash and cash equivalents | $ 394 | $ 220 |
Restricted cash (note 32) | 23 | 34 |
Inventory (note 14) | 538 | 453 |
Derivative instruments (notes 15 and 16) | 195 | 73 |
Regulatory assets (note 7) | 253 | 165 |
Receivables and other current assets (note 18) | 1,733 | 1,233 |
Total current assets | 3,136 | 2,178 |
Property, plant and equipment, net of accumulated depreciation and amortization of $8,739 and $8,714, respectively (note 20) | 20,353 | 19,535 |
Other assets | ||
Deferred income taxes (note 10) | 295 | 209 |
Derivative instruments (notes 15 and 16) | 106 | 25 |
Regulatory assets (note 7) | 2,313 | 1,419 |
Net investment in direct financing lease (note 19) | 462 | 475 |
Investments subject to significant influence (note 8) | 1,382 | 1,346 |
Goodwill (note 22) | 5,696 | 5,720 |
Other long term assets | 501 | 327 |
Total other assets | 10,755 | 9,521 |
Total assets | 34,244 | 31,234 |
Current liabilities | ||
Short-term debt (note 23) | 1,742 | 1,625 |
Current portion of long-term debt (note 25) | 462 | 1,382 |
Accounts payable | 1,485 | 1,148 |
Derivative instruments (notes 15 and 16) | 533 | 251 |
Regulatory liabilities (note 7) | 290 | 129 |
Other current liabilities (note 24) | 366 | 340 |
Total current liabilities | 4,878 | 4,875 |
Long-term liabilities | ||
Long-term debt (note 25) | 14,196 | 12,339 |
Deferred income taxes (note 10) | 1,868 | 1,629 |
Derivative instruments (notes 15 and 16) | 149 | 87 |
Regulatory liabilities (note 7) | 1,765 | 1,832 |
Pension and post-retirement liabilities (note 21) | 370 | 453 |
Other long-term liabilities (notes 8 and 26) | 868 | 781 |
Total long-term liabilities | 19,216 | 17,121 |
Equity | ||
Common stock (note 11) | 7,242 | 6,705 |
Cumulative preferred stock (note 28) | 1,422 | 1,004 |
Contributed surplus | 79 | 79 |
Accumulated other comprehensive income (loss) (note 13) | 25 | (79) |
Retained earnings | 1,348 | 1,495 |
Total Emera Incorporated equity | 10,116 | 9,204 |
Non-controlling interest in subsidiaries (note 29) | 34 | 34 |
Total equity | 10,150 | 9,238 |
Total liabilities and equity | $ 34,244 | $ 31,234 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Consolidated Balance Sheets | ||
Accumulated depreciation and amortization on property, plant and equipment | $ 8,739 | $ 8,714 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Operating activities | ||
Net income | $ 561 | $ 984 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 915 | 899 |
Income from equity investments, net of dividends | (69) | (76) |
Allowance for equity funds used during construction | (61) | (45) |
Deferred income taxes, net | (37) | 381 |
Net change in pension and post-retirement obligations | (23) | (23) |
Regulated fuel adjustment mechanism | (166) | (94) |
Net changes in fair value of derivative instruments | 404 | (36) |
Net change in regulatory assets and liabilities | (176) | (87) |
Net change in capitalized transportation capacity | (107) | 52 |
Impairment charges | 0 | 25 |
Gain on sale, net of transaction costs | 0 | (603) |
Other operating activities, net | 96 | 43 |
Changes in non-cash working capital (note 30) | (152) | 217 |
Net cash provided by operating activities | 1,185 | 1,637 |
Investing activities | ||
Additions to property, plant and equipment | (2,359) | (2,623) |
Proceeds from dispositions (note 4) | 3 | 1,401 |
Other investing activities | 24 | (2) |
Net cash used in investing activities | (2,332) | (1,224) |
Financing activities | ||
Change in short-term debt, net | (155) | 385 |
Proceeds from short-term debt with maturities greater than 90 days | 640 | 399 |
Repayment of short-term debt with maturities greater than 90 days | (377) | (688) |
Proceeds from long-term debt, net of issuance costs | 2,554 | 428 |
Retirement of long-term debt | (1,660) | (513) |
Net proceeds (repayments) under committed credit facilities | 82 | (203) |
Issuance of common stock, net of issuance costs | 317 | 285 |
Issuance of preferred stock, net of issuance costs (note 28) | 416 | 0 |
Dividends on common stock | (443) | (409) |
Dividends on preferred stock | (50) | (45) |
Other financing activities | (13) | (11) |
Net cash provided by (used in) financing activities | 1,311 | (372) |
Effect of exchange rate changes on cash, cash equivalents, and restricted cash | (1) | (61) |
Net increase (decrease) in cash, cash equivalents, restricted cash | 163 | (20) |
Cash, cash equivalents, and restricted cash, beginning of year | 254 | 274 |
Cash, cash equivalents, and restricted cash, end of year | $ 417 | $ 254 |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Cash, cash equivalents and restricted cash consists of: | ||
Cash | $ 237 | $ 220 |
Short-term investments | 157 | 0 |
Restricted cash | 23 | 34 |
Cash, cash equivalents, and restricted cash | $ 417 | $ 254 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) $ in Millions | Total | Cumulative Effect, Period of Adoption, Adjustment | Common Stock [Member] | Common Stock [Member]Cumulative Effect, Period of Adoption, Adjustment | Preferred Stock | Preferred StockCumulative Effect, Period of Adoption, Adjustment | Contributed Surplus | Contributed SurplusCumulative Effect, Period of Adoption, Adjustment | Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss)Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings | Retained EarningsCumulative Effect, Period of Adoption, Adjustment | Non-Controlling Interest |
Beginning Balance at Dec. 31, 2019 | $ 8,601 | $ (7) | $ 6,216 | $ 0 | $ 1,004 | $ 0 | $ 78 | $ 0 | $ 95 | $ 0 | $ 1,173 | $ (7) | $ 35 |
Net income of Emera Incorporated | 984 | 0 | 0 | 0 | 0 | 983 | 1 | ||||||
Other comprehensive income (loss), net of tax | (174) | 0 | 0 | 0 | (174) | 0 | 0 | ||||||
Dividends declared on preferred stock (note 28) | (45) | 0 | 0 | 0 | 0 | (45) | 0 | ||||||
Dividends declared on common stock | (609) | 0 | 0 | 0 | 0 | (609) | 0 | ||||||
Common stock issued under purchase plan | 215 | 215 | 0 | 0 | 0 | 0 | 0 | ||||||
Issuance of common stock, net of after-tax issuance costs | 251 | 251 | 0 | 0 | 0 | 0 | 0 | ||||||
Senior management stock options exercised | 19 | 20 | 0 | (1) | 0 | 0 | 0 | ||||||
Other | 3 | 3 | 0 | 2 | 0 | 0 | (2) | ||||||
Ending Balance at Dec. 31, 2020 | 9,238 | 6,705 | 1,004 | 79 | (79) | 1,495 | 34 | ||||||
Net income of Emera Incorporated | 561 | 0 | 0 | 0 | 0 | 560 | 1 | ||||||
Other comprehensive income (loss), net of tax | 104 | 0 | 0 | 0 | 104 | 0 | 0 | ||||||
Dividends declared on preferred stock (note 28) | (50) | 0 | 0 | 0 | 0 | (50) | 0 | ||||||
Dividends declared on common stock | (657) | 0 | 0 | 0 | 0 | (657) | 0 | ||||||
Issuance of preferred shares, net of after-tax issuance costs | 418 | 0 | 418 | 0 | 0 | 0 | 0 | ||||||
Common stock issued under purchase plan | 235 | 235 | 0 | 0 | 0 | 0 | 0 | ||||||
Issuance of common stock, net of after-tax issuance costs | 284 | 284 | 0 | 0 | 0 | 0 | 0 | ||||||
Senior management stock options exercised | 14 | 14 | 0 | 0 | 0 | 0 | 0 | ||||||
Other | 3 | 4 | 0 | 0 | 0 | 0 | (1) | ||||||
Ending Balance at Dec. 31, 2021 | $ 10,150 | $ 7,242 | $ 1,422 | $ 79 | $ 25 | $ 1,348 | $ 34 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Consolidated Statements of Changes in Equity | ||
Other comprehensive loss, tax expense/recovery | $ 14 | $ 2 |
Dividends per common share declared | $ 2.575 | $ 2.4750 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2021 | |
1. Summary of Significant Accounting Policies | |
Summary of Significant Accounting Policies | 1. Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an electricity generation, transmission and distribution, and At December 31, 2021, Emera’s reportable segments ● utility, serving approximately 810,600 ● ● primary electricity supplier in Nova Scotia, serving approximately 536,000 ● investments related to an 824 Falls on the Lower Churchill River in Labrador being developed investments are: ● 100 Maritime Link Project, a $ 1.8 two 170 -kilometre sub-sea cables, connecting the island Scotia. This project went in service on January 15, 2018; ● 37.4 Partnership (“LIL”), a $ 3.7 Labrador to enable the transmission of Muskrat Falls energy the island of Newfoundland. Construction of the LIL has recognized the first flow of energy from Labrador to Newfoundland Muskrat Falls generators are completed and available fo forecasting it will achieve final commissioning of Muskrat of 2022. For further details, refer to note 27. ● with regulated electric utilities that include: ● electric utility on the island of Barbados, serving approximately 132,000 ● utility on Grand Bahama Island, serving approximately 19,000 ● 51.9 regulated electric utility on the island of Dominica, serving 35,700 and ● 19.5 integrated regulated electric utility on the island of St. On March 24, 2020, Emera completed the sale of Emera Other Electric Utilities segment. Refer to note 4. ● ● 445,000 ● approximately 542,000 ● transmission company offering services in Florida; ● 145 -kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint United States border under a 25 -year firm service agreement with Repsol Energy which expires in 2034; and ● 12.9 1,400 -kilometre pipeline, that transports natural gas throughout markets northeastern United States. ● which includes: ● ● natural gas and electricity and provides related energy ● 30 electricity facility in Brooklyn, Nova Scotia; and ● 50.0 Swamp”), a 633 Massachusetts. ● reinsurance to Emera and certain affiliates; ● financing subsidiaries of Emera; ● deliver renewables and resilient energy to customers; ● located in the United States; and ● In 2020, the outbreak of COVID-19, resulted in governments combat the spread of the virus. Management considered the estimates and results and concluded the financial statements as 2021 were not materially impacted. Basis of Presentation These consolidated financial statements are prepared Generally Accepted Accounting Principles (“USGAAP”). consolidated financial statements include all adjustments fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless Principles of Consolidation The consolidated financial statements of Emera include owned subsidiaries, and a variable interest entity (“VIE”) further details on VIEs, refer to note 32. Emera uses the investments in which the Company has the ability to exercise Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether reconsideration events have arisen with respect to existing To identify potential VIEs, management reviews contractual and ownership arrangements power agreements, tolling contracts, guarantees, jointly of which the Company is deemed the primary beneficiary beneficiary of a VIE has both the power to direct the activities impacts its economic performance and the obligation to potentially be significant to the entity. is not deemed the primary beneficiary, Intercompany balances and transactions have been eliminated on certain transactions between certain non-regulated and regulated accounting standards for rate-regulated entities. The net profit eliminated in the absence of the accounting standards regulated operating revenues. An offset is recorded regulated fuel for generation and purchased power, depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance to make estimates and assumptions. These may affect the date of the financial statements and reported amounts periods. Significant areas requiring the use of management liabilities, accumulated reserve for cost of removal, pension revenue, useful lives for depreciable assets, goodwill, income taxes, asset retirement obligations, and valuation the Company’s estimates on an ongoing basis based conditions and assumptions believed to be reasonable adjustments recognized in income in the year they arise. Management has analyzed the impact of the COVID-19 pandemic concluded that no material adjustments were required The extent of the future impact of COVID-19 on the Company’s cannot be predicted at this time and will depend on future severity of the pandemic, timing and effectiveness and future economic activity and energy usage. Actual estimates. Regulatory Matters Regulatory accounting applies where rates are established third-party regulator. The rates products or services and provide an opportunity for a reasonable applicable. For further detail, refer to note 7. Foreign Currency Translation Monetary assets and liabilities denominated in foreign rates of exchange prevailing at the balance sheet date. The resulting at the original transaction date and the balance sheet Assets and liabilities of foreign operations whose functional translated using the exchange rates in effect at the the average exchange rate in effect for the and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar functional currency companies as hedges of net investments operations. The change in the carrying amount of these effect at the balance sheet date is recorded in Revenue Recognition Regulated Electric Revenue Electric revenues, including energy charges, demand charges, riders, are recognized when obligations under the terms electricity is delivered to customers over time as the customer benefits of the electricity. unbilled revenues. Revenues related to the sale of electri respective regulator and recorded based on metered usage, which basis, generally monthly or bi-monthly. customers, but not billed, is estimated and the corresponding Company’s estimate of unbilled revenue at the number of megawatt hours (“MWh”) delivered to customers the upcoming billing cycle. This estimate includes assumptions weather, line losses and inter-period Regulated Gas Revenue Gas revenues, including energy charges, demand charges, clauses and riders, are recognized when obligations under the when gas is delivered to customers over time as the customer benefits of the gas. Gas revenues are recognized on an revenues. Revenues related to the distribution and sale respective regulator and recorded based on metered usage, which basis, generally monthly. billed, is estimated and the corresponding unbilled revenue unbilled revenue at the end of the reporting period is calculated delivered to customers at the established rates expected estimate includes assumptions as to the pattern of usage, classes. Non-regulated Revenue Marketing and trading margins are comprised of Emera natural gas and electricity, are recorded when obligations under terms of a contract reflecting the nature of the contractual relationships with Energy sales are recognized when obligations under the when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations Other Sales, value add, and other taxes, except for gross receipts taxes Company concurrent with revenue-producing activities Leases The Company determines whether a contract contains conveys the right to control the use of an identified asset for a consideration. Emera has leases with independent power producers (“IPP”) to purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets Sheets based on the present value of the future minimum lease commencement date. As most of Emera’s leases borrowing rate at commencement of the lease is used payments. Lease expense is recognized on a straight-line “Operating, maintenance and general” on the Consolidated Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value (net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the fair value and the carrying value commencement rather than deferred over the term of the Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. Franchise Fees and Gross Receipts Tampa through prices approved by the Florida Public Service Commission customers’ bills for franchise fees and gross receipt taxes “Regulated gas” revenues in the Consolidated Statements taxes payable by Tampa of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise required by a tariff to present the amounts on receipt taxes are presented net with no line item impact Property, Plant and Property, plant and construction (“AFUDC”) or capitalized interest, net of contributions The cost of additions, including betterments and replacements are included in “Property, are replaced, renewed or retired, their cost plus removal or charged to accumulated depreciation, with no gain or loss non-regulated property, dispositions occur. The cost of property, direct labour, AFUDC for regulated obligations (“ARO”), and overhead attributable to the capital such as finance, information technology and labour costs, functions, employee benefits, insurance, procurement, Expenditures for project development are capitalized if benefit. Normal maintenance projects are expensed as incurred. increase the overall life of the related assets are expensed. the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based the depreciable assets in each functional class of depreciable regulated subsidiaries, depreciation is calculated using to the average investment, adjusted for anticipated costs depreciable property. Intangible assets, which are included in “Property, software and land rights. Amortization is determined remaining service lives of the asset in each category. amortization is calculated using the amortizable life method over the remaining life of those assets. The service lives approval. Goodwill Goodwill is calculated as the excess of the purchase price values of identifiable assets acquired and liabilities assumed initial cost less any write-down for impairment and is adjusted the applicable accounting guidance, goodwill is subject level annually, or if may be below its carrying value. For further detail, refer Income Taxes and Emera recognizes deferred income tax assets and liabilities that have been included in the financial statements or income tax and liabilities are determined based on the difference on the Consolidated Balance Sheets, and their respective the year in which the differences are expected to deferred income tax assets and liabilities is recognized enacted, unless required to be offset to a regulatory Emera recognizes the effect of income tax positions realized. Management reviews all readily available current and looking information, and the income is assessed and assumptions about the expected liabilities are made. If management subsequently determines income tax asset will not be realized, then a valuation allowance deferred income tax asset expected to be realized. Generally, investment future periods to the extent that realization of such benefit earned by Tampa estimated service lives of the related properties, as required Tampa and deferred income taxes. NSPI, ENL and Brunswick Pipeline based on income tax that is currently payable except for balances specifically prescribed by the regulator. NSPI, ENL and Brunswick Pipeline recognize regulatory taxes are expected to be recovered from or returned to or liabilities are grossed up using the respective income future revenues that are required to fund these deferred associated with reduced revenues resulting from the realization not subject to income taxes. Emera classifies interest and penalties associated with unrecognized operating expense, respectively. Derivatives and Hedging Activities The Company manages its exposure to normal operating and foreign exchange, interest rates and share prices through where practicable, and by using financial instruments consisting swaps, interest rate options and swaps, equity derivatives, and swaps. In addition, the Company has contracts for These physical and financial contracts are classified as contracts and financial instruments are considered derivatives. The Company recognizes the fair value of all its derivatives derivatives that meet the normal purchases and normal sales meet the NPNS exception are not recognized on the balance income when they settle. A physical contract generally is reasonable in relation to the Company’s business within the proximity to allow for physical delivery, commodity, and the contracts designated under the NPNS exception and will discontinue under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent proven to effectively hedge the identified risk both Specifically, for cash recognized in income in the same period the related hedged effectiveness requirements are not met, the derivatives fair value recognized in net income in the reporting period, accounting. Derivatives entered into by NSPI, NMGC and GBPC that which the NPNS exception has not been taken, are subject change in fair value of the derivatives is deferred to a recognized in the hedged item when the hedged item losses resulting from settlement of these derivatives related will be refunded to or collected from customers in future derivatives related to hedging as a result of a FPSC approved gas purchases which ends on December 31, 2022. Tampa gas purchases will continue through December 31, 2024, settlement agreement. Derivatives that do not meet any of the above criteria are designated normally recorded in net income of the period. The Company to be included in the HFT category where another accounting Emera classifies gains and losses on derivatives as a component power, other expenses, inventory, the item being economically hedged. Tran derivative transactions is recognized as an asset in “Receivables over the period of the transportation contract term. Cash the same category as the item being hedged within Statements of Cash Flows. Non-hedged derivatives are included Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, cash collateral with the same counterparty. “Receivables and other current assets” and obligations “Accounts payable”. Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The Company is exposed to credit risk with respect to assessments may be conducted on new customers. Deposits with the Company’s policy. assessed on a regular basis. Management estimates credit losses related to accounts experience, customer deposits, current events, the characteristics and supportable forecasts that affect the collectability on receivables are expensed to maintain the allowance at a losses. Receivables are written off against the The economic impact of COVID-19 in the service territories aging of customer receivables resulting in higher allowances receivables, however it has not had a material impact on earnings. Inventory Fuel and materials inventories are valued using the weighted carried at the lower of weighted-average cost or net realizable weighted-average cost will be recovered in future customer Asset Impairment Long-Lived Assets Emera assesses whether there has been an impairment triggering event occurs, such as a significant market disruption The assessment involves comparing the undiscounted expected the asset. When the undiscounted cash flow analysis indicates amount of the impairment loss is determined by measuring lived asset over its estimated fair value. The Company’s operations or other recoverable amounts, are based fundamental economic analysis, observable market activity Company’s expectations regarding uses and holding budgets and projections, which consider external factors reporting period. The assumptions made are consistent assumptions used for valuation and pricing activities. Management considered whether the potential impacts future cash flows could indicate that long-lived assets there are no indications of impairment of Emera’s No impairment charges were recognized during the year charges of $ 25 26 “Impairment charges” in the Consolidated Statements of Income. Goodwill Goodwill is not amortized but is subject to an annual assessment with interim impairment tests performed when impairment generally determined at the operating segment level or one Reporting units with similar characteristics are grouped of goodwill. qualitative assessment to determine whether a quantitative qualitative assessment management considers, among other and market considerations and overall financial performance. If the Company performs the qualitative assessment and fair value is less than its carrying amount, or if the Company assessment, a quantitative test is performed. The quantitative reporting unit to its carrying amount, including goodwill. exceeds its fair value, an impairment loss is recorded as expense. Management estimates the fair value of the reporting combination of the income and market approach. The income cash flow analysis which relies on management’s flows. The analysis includes an estimate of terminal values methodology which derives a valuation using an assumed residual cash flows. The discount rate used is a market participant traded comparable companies and represents the weighted companies. When using the market approach, management companies and transactions within the utility industry. value include discount and growth rates, rate case assumptions, operating loss (“NOL”), utility sector market performance capital cash flows and the fair value of debt. Adverse changes result in a future material impairment of the goodwill assigned part of the goodwill impairment assessment management considered 19 pandemic on the future earnings of the reporting units. As of December 31, 2021, $ 5.6 PGS and NMGC reporting units). Qualitative assessments the significant excess of fair value over carrying amounts 2019. Management concluded it was more likely than not that exceeded their respective carrying amounts, including required. As of December 31, 2021, $ 68 Company performed a quantitative impairment assessment sensitive to changes in assumptions due to limited excess assessment estimated that the fair value of the reporting goodwill, by approximately 12 Equity Method Investments The carrying value of investments accounted for under comparing the fair value of these investments to their carrying completed, or by reviewing for the presence of impairment an impairment exists, and it is determined to be other-than-temporary, equal to the amount the carrying value exceeds the investment’s method investments was required in either 2021 or 2020. Financial Assets Equity investments, other than those accounted for under at fair value, with changes in fair value recognized in the investments that do not have readily determinable fair any, plus or minus identical or similar investments. No impairment of financial Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection resulting from the permanent retirement, abandonment may exist under an existing or enacted law or statute, under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash obligation, using the Company’s credit adjusted expenditures incurred. Estimated future cash flows are based remediation reports, prior experience, estimated useful The present value of the liability is recorded and the carrying correspondingly increased. The amount capitalized at inception related long-lived asset. Over time, the liability is accreted to included in “Other long-term liabilities” and accretion amortization”. Any regulated accretion expense not yet “Property, plant and equipment” Some of the Company’s transmission and distribution recognized in the consolidated financial statements as reasonably estimated, given there is insufficient information obligation to perform an asset retirement activity in which conditional on a future event that may or may not be monitors these obligations and a liability is recognized at fair be determined. Cost of Removal Tampa liabilities. The non-ARO COR represent funds received cover estimated future non-legally required COR of property, companies accrue for COR over the life of the related their respective regulators. The costs are estimated based expectations, including expected timing and estimated Stock-Based Compensation The Company has several stock-based compensation management; an employee common share purchase plan; performance share unit (“PSU”) plan; and a restricted its plans in accordance with the fair value based method of Stock-based compensation cost is measured at the grant date, award, and is recognized as an expense over the employee’s the graded vesting method. Stock-based compensation measured at fair value and re-measured at fair value at recognized in income. Employee Benefits The costs of the Company’s pension and other expensed over the periods during which employees render service. status of its defined-benefit and other post-retirement plans on changes in funded status in the year the change occurs. and losses and past service costs in AOCI or regulatory cost other than the service cost component are included Statements of Income. |
Change in Accounting Policy
Change in Accounting Policy | 12 Months Ended |
Dec. 31, 2021 | |
2. Change in Accounting Policy | |
Change in Accounting Policy | 2. CHANGE IN ACCOUNTING POLICY The new USGAAP accounting policies that are applicable to, described as follows: Accounting for Convertible Instruments and Contracts The Company adopted Accounting Standard Update ("ASU") 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. There was no material impact on the consolidated financial statements as a result of the adoption of this standard. Guaranteed Debt Securities Disclosure Requirements The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a result of adopting this standard, the disclosures related to certain registered debt securities that are guaranteed were amended and removed from the consolidated financial statements and added to Management’s Discussion & Analysis. |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2021 | |
3. Future Accounting Pronouncements | |
Future Accounting Pronouncements | 3. The Company considers the applicability and impact of Standards Board (“FASB”). The assessed and determined to be either not applicable the consolidated financial statements. |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2021 | |
4. Dispositions | |
Dispositions | 4. DISPOSITIONS On March 24, 2020, Emera completed the sale of Emera Maine approximately $ 2.0 1.4 adjustments. A gain on disposition of $ 585 309 recognized in the Other segment and included in “Other Income. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2021 | |
5. Segment Information | |
Segment Information | 5. Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. five Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2021 Operating revenues from external customers (1) $ 2,718 $ 1,501 $ 445 $ 1,276 $ (175) $ $ 5,765 Inter-segment revenues (1) 6 - - 4 18 (28) 2,724 1,501 445 1,280 (157) (28) 5,765 Regulated fuel for generation and purchased power 894 654 218 - - (3) 1,763 Regulated cost of natural gas - - - 472 - - 472 OM&G 536 291 140 325 93 (16) 1,369 Depreciation and amortization 469 246 58 121 8 - 902 Income from equity investments - 103 4 20 16 - 143 AFUDC - debt and equity 77 8 - 7 - - 92 Interest expense, net 138 132 21 51 269 - 611 Internally allocated interest (2) - - - 13 (13) - - Income tax expense (recovery) 72 9 1 62 (150) - (6) Net income (loss) attributable to common shareholders 462 241 21 198 (412) - 510 Capital expenditures 1,331 366 111 515 5 - 2,328 As at December 31, 2021 Total assets 17,903 7,418 1,402 6,666 2,034 (1,179) 34,244 Investments subject to significant influence - 1,215 44 123 - - 1,382 Goodwill 4,436 - 68 1,189 3 - 5,696 (1) All significant inter-company balances and inter-company transactions between non-regulated and regulated entities elimination of these transactions would understate and purchased power. Inter-company transactions that have not been established and agreed to by the related parties. (2) Segment net income is reported on a basis (3) Primarily relates to consolidated deferred tax reclassifications. liabilities upon consolidation. Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2020 Operating revenues from external customers (1) $ 2,473 $ 1,494 $ 474 $ 1,051 $ 14 $ $ 5,506 Inter-segment revenues (1) 7 - - 7 15 (29) 2,480 1,494 474 1,058 29 (29) 5,506 Regulated fuel for generation and purchased power 574 659 194 - - (7) 1,420 Regulated cost of natural gas - - - 293 - - 293 OM&G 552 282 151 334 115 (15) 1,419 Depreciation and amortization 455 236 71 111 8 - 881 Income from equity investments - 96 4 20 29 - 149 AFUDC - debt and equity 54 4 1 9 - - 68 Interest expense, net 151 139 32 56 301 - 679 Internally allocated interest (2) - - - 13 (13) - - Gain on sale, net of transactions costs Impairment charges - - - - (25) - (25) Income tax expense (recovery) 89 17 (8) 51 192 - 341 Net income attributable to common shareholders 501 221 35 162 19 - 938 Capital expenditures 1,361 338 148 749 4 - 2,600 As at December 31, 2020 Total assets 16,889 6,752 1,365 6,067 1,234 (1,073) 31,234 Investments subject to significant influence - 1,176 41 129 - - 1,346 Goodwill 4,455 - 68 1,194 3 - 5,720 (1) All significant inter-company balances and inter-company transactions between non-regulated and regulated entities elimination of these transactions would understate and purchased power. Inter-company transactions that have not been established and agreed to by the related parties. (2) Segment net income is reported on a basis (3) Primarily relates to consolidated deferred tax reclassifications. liabilities upon consolidation. Geographical Information Revenues (based on country of origin of the product For the Year ended December 31 millions of Canadian dollars 2021 2020 United States $ 3,754 $ 3,522 Canada 1,566 1,569 Barbados 292 263 The Bahamas 110 112 Dominica 43 40 $ 5,765 $ 5,506 Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2021 2020 United States $ 14,978 $ 14,353 Canada 4,440 4,304 Barbados 535 510 The Bahamas 322 289 Dominica 78 79 $ 20,353 $ 19,535 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2021 | |
6. Revenue | |
Revenue | 6. The following disaggregates the Company’s revenue Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2021 Regulated Electric Revenue Residential $ 1,449 $ 797 $ 165 $ - $ - $ - $ 2,411 Commercial 754 407 232 - - - 1,393 Industrial 215 237 26 - - - 478 Other electric and regulatory deferrals 289 27 7 - - - 323 Other (1) 17 33 15 1 - (6) 60 2,724 1,501 445 1 - (6) 4,665 Regulated Gas Revenue Residential - - - 642 - - 642 Commercial - - - 379 - - 379 Industrial - - - 65 - (2) 63 Finance income (2)(3) - - - 58 - - 58 Other 121 - (2) 119 - - - 1,265 - (4) 1,261 Non-Regulated Marketing and trading margin (4) - - - - 102 - 102 Energy sales - - - - 21 (21) - Other - - - 14 9 - 23 Mark-to-market (3) - - - - (289) 3 (286) - - - 14 (157) (18) (161) Total operating revenues $ 2,724 $ 1,501 $ 445 $ 1,280 $ (157) $ (28) $ 5,765 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers. Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2020 Regulated Electric Revenue Residential $ 1,365 $ 806 $ 179 $ - $ - $ - $ 2,350 Commercial 678 405 233 - - - 1,316 Industrial 178 224 32 - - - 434 Other electric and regulatory deferrals 242 31 8 - - - 281 Other (1) 17 28 22 1 - (7) 61 2,480 1,494 474 1 - (7) 4,442 Regulated Gas Revenue Residential - - - 495 - - 495 Commercial - - - 275 - - 275 Industrial - - - 54 - - 54 Finance income (2)(3) - - - 61 - - 61 Other 156 - (7) 149 - - - 1,041 - (7) 1,034 Non-Regulated Marketing and trading margin (4) - - - - 38 - 38 Energy sales - - - - 16 (16) - Other - - - 16 21 - 37 Mark-to-market (3) - - - - (46) 1 (45) - - - 16 29 (15) 30 Total operating revenues $ 2,480 $ 1,494 $ 474 $ 1,058 $ 29 $ (29) $ 5,506 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers. Remaining Performance Obligations Remaining performance obligations primarily represent and long-term steam supply arrangements with fixed contract aggregate amount of the transaction price allocated to 437 million (2020 – $ 464 142 to a gas transportation contract between SeaCoast and PGS contracts with an original expected length of one year recognizes revenue at the amount to which it has the right expects to recognize revenue for the remaining performance 2041 . |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2021 | |
7. Regulatory Assets and Liabilities | |
Regulatory Assets and Liabilities | 7. REGULATORY Regulatory assets represent prudently incurred costs that have will be recovered through future rates or tolls collected from customers. regulatory assets are probable for recovery either because the applicable regulator, or management no longer considers it probable that an asset charged to income. Regulatory liabilities represent obligations to make refunds previous collections. If management no longer considers related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization regulator. As at December 31 December 31 millions of Canadian dollars 2021 2020 Regulatory assets Deferred income tax regulatory assets $ 1,045 $ 887 Tampa 657 - Pension and post-retirement medical plan 291 394 Regulated fuel adjustment mechanism 145 - NMGC winter event gas cost recovery 117 - Cost recovery clauses 114 49 Storm restoration regulatory asset 35 41 Environmental remediations 27 28 Stranded cost recovery 26 26 Deferrals related to derivative instruments 23 65 Demand side management ("DSM") deferral 10 15 Unamortized defeasance costs 10 13 Other 66 66 $ 2,566 $ 1,584 Current $ 253 $ 165 Long-term 2,313 1,419 Total $ 2,566 $ 1,584 Regulatory liabilities Deferred income tax regulatory liabilities 863 933 Accumulated reserve - cost of remova l 819 865 Deferrals related to derivative instruments 241 15 Storm reserve 58 62 Cost recovery clauses 35 31 Self-insurance fund (note 32) 28 28 Regulated fuel adjustment mechanism - 21 Other 11 6 $ 2,055 $ 1,961 Current $ 290 $ 129 Long-term 1,765 1,832 Total $ 2,055 $ 1,961 Deferred Income Tax To years, a regulatory asset or liability is recognized as appropriate. Tampa Electric Capital This regulatory asset is related to the remaining net book through 3 and smart meter assets that were retired. The the FPSC and will be recovered as a separate line item on customer 15 years . This recovery mechanism is authorized by and survives the FPSC in 2021. See “Tampa Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension Electric, PGS and NMGC. It is included in rate base and and New Mexico Public Regulation Commission (“NMPRC”) remaining service life of plan participants. Regulated Fuel Adjustment Mechanism This regulated customers through electricity rates in a given year, regulatory asset or liability and recovered from or returned approved on December 6, 2019 as part of NSPI’s actual fuel costs and fuel revenues recovered from customers recovered or returned to customers after 2022. The Nova Scotia Utility decision to approve the fuel stability plan directed that approved range of ROE are to be applied to the FAM. NMGC Winter Event Gas Cost Recovery In February 2021, the State of New Mexico experienced an incremental $ 108 NMGC normally recovers gas supply and related costs April 16, 2021, NMGC filed a Motion for Extraordinary Relief, the terms of the repayment of the incremental gas costs 2021, the NMPRC approved the recovery of $ 108 of 30 months beginning July 1, 2021. Cost Recovery Clauses These assets and liabilities are related to Tampa recovered or refunded through cost-recovery mechanisms applicable, on a dollar-for-dollar basis in a subsequent Storm Restoration Regulatory Asset This asset represents storm restoration costs, primarily its generation facilities and, as with most utilities, its transmission covered by commercial insurance. In January 2020, the Grand Bahama Port Authority (“GBPA”) 15 of costs related to Hurricane Dorian in 2019, over a five -year period. The recovery was implemented through rates on January 1, 2021. Restoration costs fuel charge. Additional details on the recovery are included of the regulatory asset as at December 31, 2021 is $ 12 Environmental Remediations This asset is primarily related to PGS costs associated with environmental Gas Plant sites. rate of return as permitted by the FPSC. The timing of recovery approved by the FPSC. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine 21 million USD stranded cost through electricity rates; it is included in rates in future years. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in fair as economic hedges or that do not qualify for NPNS approved by its regulator. The regulated fuel for generation and purchased power, property, plant and equipment, DSM Deferral The UARB approved implementation of the 2015 DSM deferral set at $35 million in 2015 and recoverable from customers over an 8-year period beginning in 2016. The UARB directed EfficiencyOne, a franchisee NSPI with electricity efficiency and conservation Public Utilities Act , to review financing options through which EfficiencyOne lender in order to repay NSPI the amount it expended 2016, EfficiencyOne secured financing and $ 31 deferral. In February 2017, EfficiencyOne advanced 2 associated amounts from customers over the remaining three years , it will repay the balance to EfficiencyOne. This has been set up as a liability in the liability included in “Other current liabilities” on the Unamortized Defeasance Costs Upon privatization in 1992, NSPI became responsible for held in trust that provide the principal and interest streams at December 31, 2021, totalled $ 200 582 investments over the face value of the related debt is deferred the life of the defeased debt as permitted by the UARB. Accumulated Reserve – Cost of Removal (“COR”) This regulatory liability represents the non-ARO COR reserve AROs represent the fair value of estimated cash flows retire its property, customers through depreciation rates to cover future retirement that are not legally required. This reduces rate reduced as COR are incurred and increased as depreciation assets are put into service. Storm Reserve The storm reserve is for hurricanes and other named storms Electric and PGS systems. As allowed by the FPSC, if liability, the excess to seek recovery of restoration costs over a 12-month well as replenish the reserve. In 2021, 2020 and 2019, preparation costs for multiple hurricanes of approximately $ 10 storm reserve regulatory liability . Regulatory Environments Florida Electric Utility Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Tampa 9.25 to 11.25 54 10.25 used for the calculation of the return on investments for Beginning in 2022, Tampa approved regulated ROE range is 9.00 11.00 structure of 54 9.95 investments for clauses. See below for further detail. Fuel Recovery Tampa fluctuating fuel expenses from customers through annual fuel approves cost-recovery rates for purchased power, including a return on capital invested. Differences recovery rates and amounts recovered from customers regulatory asset or liability and recovered from or returned On January 19, 2022, Tampa to recover an additional $ 169 fuel commodity and capacity costs. The FPSC is expected On July 19, 2021, Tampa 83 capacity charges, effective with September 2021 capacity costs in 2021. On August 3, 2021, the FPSC the months of September through December 2021. Base rates On August 6, 2021, Tampa agreement (the “Settlement Agreement”) by Tampa filed with the FPSC in April 2021. The Settlement Agreement 191 million USD in rates annually, 123 USD in base rate charges and $ 68 coal generation assets Units 1 through 3 and meter assets. two subsequent year adjustments of $ 90 21 January 2024, respectively related to the recovery of future project and solar generation. The allowed equity in the 54 from investor sources of capital. The Settlement Agreement 9.0 11.0 9.95 25 the allowed ROE range and mid-point, and $ 10 yields exceed a specific threshold set on the date the agreement, base rates will not further change from January Tampa Agreement contains a provision whereby Tampa in tax rates on net operating income through a reduction when such tax change becomes law or its effective mechanism to recover the costs of retiring coal generation years which survives the term of that agreement. The dismantlement rates effective January 1, 2022 and have to file another depreciation study during the term study no more than one year, proceeding. Tampa 2024. On October 21, 2021, the FPSC approved the Settlement such approval, was issued in November 2021. On April 9, 2019, Tampa eligible storm costs as a result of Hurricane Irma in 2017, 2019. As a result, Tampa 12 minimal impact to the Consolidated Statements of Income. Solar Base Rate Adjustments Included in Base Rates As of December 31, 2021, Tampa 850 600 photovoltaic projects, which are recoverable through FPSC-approved (“SoBRAs”). AFUDC is being earned on these projects SoBRAs representing a total of 600 104 for in-service projects. The true-up filing for SoBRAs tranche 1 and 2 revenue rates as of September 2018 and January 2019, respectively, FPSC approved the amount on August 18, 2020. A $ 5 2020. On October 12, 2021, the FPSC approved the true-up filing rates as of January 2020. An estimated $ 4 true-up for SoBRA tranche 4 will be filed in early 2022. Storm Protection Cost Recovery Clause and Settlement On October 3, 2019, the FPSC issued a rule to implement Recovery Clause. This clause provides a process for Florida Electric, to recover transmission and distribution storm hardening already included in base rates. Tampa 10, 2020. On April 27, 2020, Tampa specified a $ 15 rates beginning January 1, 2021. On June 9, 2020, the August 3, 2020, Tampa including cost recovery of approximately $ 39 2020 and 2021. This cost recovery includes the $ 15 settlement agreement was approved on August 10, January 2021. The current approved plan will apply for Tampa Electric will file a new plan in April 2022 to determine cost The June 9, 2020 settlement agreement approved by the of Tampa 16 intangible software assets through a credit to amortization Big Bend Modernization Project Tampa 850 the Big Bend Power Station, of which approximately $ 695 December 31, 2021. The modernization project will repower cycle technology and eliminate coal as this unit’s Electric retired the Unit 1 components that will not be used in Unit 2 in 2021. Tampa customers from an economic, environmental risk and operationa At December 31, 2021, the balance sheet included $ 636 267 million USD in accumulated depreciation accordance with Tampa continued to account for its existing investment in Unit 1, 2 assets using the current depreciation rates until December to a regulatory asset on the balance sheet. Tampa phases. The first phase is a revenue increase to cover the costs among other items. The remainder of the project costs year adjustment. The Settlement Agreement also includes the retiring Big Bend coal generation assets, Units 1 15 years will survive the termination of the Settlement Agreement. The three units was applied beginning January 1, 2022. Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia subject to regulation under the Public Utilities Act by the UARB. supervisory powers over NSPI’s operations and also subject to UARB approval. NSPI is regulated under a cost-of-service model, with rates providing electricity service to customers and provide a regulated ROE range for 2021 and 2020 was 8.75 9.25 quarter average regulated common equity component 40 NSPI has a FAM, approved through regularly scheduled fuel rate adjustments. Differences recovered from customers through electricity rates in a liability and recovered from or returned to customers NSPI is currently operating under a three -year fuel stability plan which results in an average annual overall rate increase of 1.5 include recovery of Maritime Link costs. On January 27, 2022, NSPI filed a General Rate Application a rate stability plan for 2022 through 2024 which includes average 2.9 year and average fuel rate increases pursuant to the FAM 0.8 January 1, 2023 and January 1, 2024. The proposed rates revenue (base and fuel rates) increases of $ 52 21 through December 31, 2022), $ 54 56 expected later this year. The Maritime Link is a $ 1.8 sub-sea cables, connecting the island of Newfoundland and service on January 15, 2018 and NSPI started interim UARB approved 2021 interim cost assessment recovery 172 $ 145 139 135 The approved interim cost assessment payments are subject to a holdback of up to $10 million pending UARB agreement that benefits from the Maritime Link are realized for NSPI customers . For 2021, NSPI has recorded a $ 10 4 collection of $ 23 to pay to NSPML 10 As part of a three -year fuel stability plan, electricity rates have been 145 approved Maritime Link assessment for 2020 and amounts 164 162 2022, respectively. approved by the UARB through the NSPML interim assessment FAM. In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being developed by Nalcor Energy, the approved Maritime Link interim assessment payment in 2019 reflected a reduction in NSPML’s assessment, related to depreciation and amortization expenses. The UARB’s decision to approve NSPI’s 2020 through 2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. NSPI refunded approximately $40 million plus interest to customers, and the remaining $12 million plus interest will be returned to customers subsequent to 2022. NSPML Equity earnings from the Maritime Link are dependent performance of NSPML. NSPML’s 8.75 9.25 based on an actual five-quarter average regulated common 30 Nalcor’s NS Block delivery obligations commenced on August 15, next 35 application with the UARB seeking approval to recover and approval of NSPML’s from the UARB approving interim rates beginning January on the application. On February 9, 2022, the UARB issued Project, approving NSPML’s 1.8 otherwise have been recoverable if incurred by NSPI. 168 million of NSPML revenue requirement in 2022 subject 2 April 1, 2022 and thereafter energy costs incurred by NSPI due to a 10 per cent or each month and will otherwise be released to NSPML. compliance filing by February 16, 2022 which will confirm the amount of the unrecoverable items which are not expected 10 Other Electric Utilities The Barbados Light & Power Company Limited BLPC is regulated by the Fair Trading Regulation (Procedural) Rules 2003. The Government generate, transmit and distribute electricity on the island passed legislation amending the number of licenses required integrated license which currently exists to multiple licenses Distribution, Storage, Dispatch and Sales. In March 2021, Government of Barbados for each of the license types, legislation. Following a general election called late in 2021 expected to take effect in 2022 on completion term of 5 years 25 - 30 years . BLPC anticipates that any increased costs associated with the implementation recoverable through BLPC’s regulatory framework. licenses on its business and working towards the successful BLPC is regulated under a cost-of-service model, with providing electricity service to customers and provide an approved regulated return on rate base was 10 BLPC has a fuel pass-through mechanism which provides incurred fuel costs from customers in a timely manner. adjusted monthly and reported to the regulator. On October 4, 2021 BLPC submitted a general rate review a rate adjustment and the implementation of a cost reflective expected in the newly reformed electricity market and the renewable energy generation. The application seeks and related infrastructure and results in an increase in 23 million USD upon approval. The application includes a 12.50 cent on an allowed equity capital structure of 65 second half of 2022. On October 21, 2021 the FTC approved BLPC’s application will be incorporated into the calculation of the fuel clause requested the FTC review the required 50 /50 cost sharing arrangement between BLPC and customers relation to the hedging administrative costs, or any gains program. A decision is expected from the FTC in the first In December 2018, the Government of Barbados signed the Income Tax legislation, which was effective January 1, 2019, eliminated certain tax credits. At the date of enactment, BLPC income tax liability at the new lower corporate income tax recovery of $ 10 7 was recognized in earnings in Q1 2020. Grand Bahama Power Company Limited GBPC is regulated by the GBPA. franchise to produce, transmit and distribute electricity through mechanism and tariff review policy regulated return on rate base was 8.37 8.34 On January 14, 2022, the GBPA with the GBPA on an increase in revenues of $ 3.5 12.84 In 2017, as part of the recovery of costs incurred as a fixed per kWh fuel charge and allowed the difference applied to the Hurricane Matthew regulatory asset. In review with the GBPA. GBPA approved ending December 31, 2024. Dominica Electricity Services Ltd Domlec is regulated by the Independent Regulatory Commission, Independent Regulatory Commission, Dominica issued and a Generation License, both of which came into effect 25 years. Domlec’s approved allowable regulated return 15 Domlec has a fuel pass-through mechanism which provides prudently incurred fuel costs in a timely manner. Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at total revenues or revenue requirements equal to their on invested capital. PGS’s approved ROE range for 2021 was 8.9 11.0 9.9 based on an allowed equity capital structure of 54.7 9.25 11.75 54.7 10.75 PGS recovers the costs it pays for gas supply and purchased gas adjustment clause. This clause is designed to purchased gas, gas storage services, interstate pipeline capacity, the purchase, distribution, and sale of natural gas to its monthly based on a cap approved annually by the FPSC. The FPSC annually approves cost-recovery rates Replacement costs, including a return on capital invested energy conservation programs. The Cast Iron/Bare Steel of accelerating the replacement of cast iron and bare FPSC approved a replacement program of approximately 5 800 system at a cost of approximately $ 80 10 -year period beginning in 2013. In February 2017, the FPSC approved an amendment to the cast iron materials and pipe deemed obsolete by Pipeline and Hazardous approximately 880 removed from its system by the end of 2022, with the replacement 2028 under the rider. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. agreement allows for an increase to base rates by $ 58 which is a $ 34 24 recovered through the cast iron and bare steel replacement total of $ 34 accumulated depreciation to date. In addition, the agreement January 1, 2021. Under the agreement base rates are 2023, unless its earned ROE were to fall below 8.9 capital structure of 54.7 the deferral of income taxes as a result of changes in regulatory asset or liability and either result in an increase subsequent regulatory process. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC collect total revenues equal to its cost of providing NMGC’s approved ROE for 2021 was 9.375 52 The approved ROE for 2020 was 9.10 52 NMGC recovers gas supply costs through a purchased recovers NMGC’s actual costs for purchased gas, gas other related items associated with the purchase, transmi customers. On a monthly basis, NMGC can adjust the of gas and any prior month under-recovery or over-recovery. file a reconciliation of the PGAC period costs and recoveries. with the NMPRC every four years to establish that the necessary. In December period ending December 2024. In February 2021, the State of New Mexico experienced an incremental $ 108 On June 15, 2021, the NMPRC approved the recovery 30 2021. For more information, refer to the “NMGC Winter On December 16, 2020, the NMPRC approved a settlement effective on January 1, 2021. The new rates reflect related infrastructure and resulted in an increase in revenue 5 On December 13, 2021, NMGC filed a rate case with January 2023. NMGC requested a $ 41 increased operating costs and capital investments in pipelines the NMPRC is expected by the end of 2022. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Canaport™ terminal near Saint John, New Brunswick to markets in Pipeline entered into a 25 -year firm service agreement commencing in July Canada. The agreement provides for a predetermined contract. The pipeline is considered (“CER”). The CER Gas Transportation Tariff requirements of the CER Act Brunswick Pipeline. |
Investments Subject to Signific
Investments Subject to Significant Influence and Equity Income | 12 Months Ended |
Dec. 31, 2021 | |
8. Investments Subject to Significant Influence and Equity Income | |
Investments Subject to Significant Influence and Equity Income | 8. Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of Canadian dollars 2021 2020 2021 2020 2021 LIL (1) $ 682 $ 629 $ 54 $ 49 37.4 NSPML 533 547 49 47 100.0 M&NP 123 129 20 20 12.9 Lucelec (2) 44 41 4 4 19.5 Bear Swamp - - 16 29 50.0 $ 1,382 $ 1,346 $ 143 $ 149 (1) Emera indirectly owns 100 24.9 ownership in LIL is subject to change, based on complete construction of the LIL. Emera’s ultimate percentage all transmission projects related to the Muskrat Link Projects, such that Emera’s total investment in the Maritime 49 transmission developments. (2) Although Emera’s ownership percentage of these entities operating and financial decisions of these companies these entities using the equity method. (3) The investment balance in Bear Swamp is 179 Bear Swamp's credit investment balance of $ 104 118 Consolidated Balance Sheets. Equity investments include a $ 8 investees' assets as at the date of acquisition. The excess Emera accounts for its variable interest investment in NSPML's consolidated summarized balance sheets are illustrated As at December 31 millions of Canadian dollars 2021 2020 Balance Sheets Current assets $ 25 $ 57 Property, plant and equipment 1,587 1,629 Regulatory assets 247 210 Non-current assets 31 32 Total $ 1,890 $ 1,928 Current liabilities $ 50 $ 56 Long-term debt (1) 1,189 1,228 Non-current liabilities 118 97 Equity 533 547 Total $ 1,890 $ 1,928 (1) The project debt has been guaranteed |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2021 | |
9. Other Income (Expenses), Net | |
Other Income (Expenses), Net | 9. Other income, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2021 2020 Allowance for equity funds used during construction $ 61 $ 45 Gain on sale of Emera Maine, net of transaction costs - 585 TECO Guatemala Holdings award (2) - 49 Other 32 29 $ 93 $ 708 (1) Refer to note 4 for further detail related to (2) Refer to note 27 for further detail related |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2021 | |
10. Income Taxes | |
Income Taxes | 10. The income tax provision, for the years ended December enacted combined Canadian federal and provincial statutory millions of Canadian dollars 2021 2020 Income before provision for income taxes $ 555 $ 1,325 Statutory income tax rate 29.0% 29.5% Income taxes, at statutory income tax rate 161 391 Additional impact from the sale of Emera Maine - 102 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (62) (48) Foreign tax rate variance (42) (45) Amortization of deferred income tax regulatory liabilities (33) (44) Tax (16) (15) Tax (13) (12) Revaluation of deferred income taxes due to change in Nova Scotia tax rate - 12 Other (1) - Income tax (recovery) expense $ (6) $ 341 Effective income tax rate (1%) 26% The change in the effective income tax rate was income taxes and the additional impact from the sale On March 10, 2020, Bill 243 of the Nova Scotia Financial included a reduction in the Nova Scotia provincial corporate combined Canadian federal and provincial statutory income tax 31 29.5 per cent for 2020, and further reduced to 29 As a result of the change in tax rate in 2020, the Company 52 deferred income tax liabilities and an offsetting as the benefit of lower net deferred income tax liabilities years. The Company also recognized a $ 12 certain net deferred income tax assets. On March 27, 2020, the United States Coronavirus Aid, CARES Act”) was signed into law. alternative minimum tax (“AMT”) credit carryforwards. its $ 145 material impacts from the CARES Act. The following table reflects the composition of taxes on the Consolidated Statements of Income for the years ended millions of Canadian dollars 2021 2020 Current income taxes $ 20 $ 18 11 (58) Deferred income taxes (33) 20 118 426 2 (9) Investment tax credits (11) (10) Operating loss carryforwards (64) (46) (49) - Income tax (recovery) expense $ (6) $ 341 The following table reflects the composition of income Consolidated Statements of Income for the years ended millions of Canadian dollars 2021 2020 $ 244 $ 176 289 1,142 22 7 Income before provision for income taxes $ 555 $ 1,325 The deferred income tax assets and liabilities presented in December 31 consisted of the following: millions of Canadian dollars 2021 2020 Deferred income tax assets: Tax $ 873 $ 724 Tax 375 319 Derivative instruments 188 108 Regulatory liabilities - cost of removal 170 184 Other 434 375 Total 2,040 1,710 Valuation allowance (256) (202) Total $ 1,784 $ 1,508 Deferred income tax (liabilities): Property, plant and equipment $ (2,622) $ (2,450) Derivative instruments (197) (93) Other (538) (385) Total $ (3,357) $ (2,928) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 295 $ 209 Long-term deferred income tax liabilities (1,868) (1,629) Net deferred income tax liabilities $ (1,573) $ (1,420) Considering all evidence regarding the utilization of the Company’s been determined that Emera is more likely than not to realize except for certain loss carryforwards and unrealized capital of $ 256 202 carryforwards and investments. The Company intends to indefinitely reinvest earnings 2.9 billion as at December 31, 2021 (2020 - $ 2.7 deferred taxes might otherwise be required, have not amount of income and withholding tax that might be payable occurred. Emera’s net operating loss (“NOL”), capital loss as at December 31, 2021 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of Canadian dollars Carryforwards Allowance Carryforwards Period Canada $ 1,776 $ (791) $ 985 2026 - 2041 75 (75) - Indefinite United States $ 1,521 $ - $ 1,521 2032 - Indefinite 817 - 817 2032 - Indefinite 375 - 375 2025 - 2041 Other $ 52 $ (38) $ 14 2022 - 2028 The following table provides details of the change in unrecognized December 31 as follows: millions of Canadian dollars 2021 2020 Balance, January 1 $ 30 $ 29 Increases due to tax positions related to current year 4 1 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (1) (2) Decreases due to settlement with tax authorities (6) - Balance, December 31 $ 28 $ 30 The total amount of unrecognized tax benefits as at December 28 30 million), which would affect the effective respect to unrecognized tax benefits was $ 6 6 recognized in the Consolidated Statements of Income 1 No accrued. The balance of unrecognized tax benefits could resolving Canada Revenue Agency (“CRA”) and Internal Revenue of any change cannot be made at this time. NSPI and the CRA are currently in a dispute with respect NSPI’s 2006 through 2010 taxation years. The ultimate dispute; rather, it is the timing 62 million, including interest. NSPI has prepaid $ 23 On November 29, 2019, NSPI filed a Notice of Appeal dispute. Should NSPI be successful in defending its position, will be refunded. If NSPI is unsuccessful in defending applicable interest will be deducted from amounts previously The related tax deductions will be available in subsequent years. Should NSPI be similarly reassessed by the CRA for years be required; however, the NSPI and its advisors believe that NSPI has reported assess its options to resolving the dispute; however, determinable at this time. Emera files a Canadian federal income tax return, which includes provincial income tax. Emera’s subsidiaries file tax returns. As at December 31, 2021, the Company’s authorities include 2005 and subsequent years. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2021 | |
11. Common Stock | |
Common Stock | 11. Authorized : 2021 2020 Issued and outstanding: millions of shares Canadian dollars millions of shares Canadian dollars Balance, December 31, 2020 251.43 $ 6,705 242.48 $ 6,216 Issuance of common stock (1)(2) 4.99 284 4.54 251 Issued under Purchase Plans at market rate 4.32 239 3.99 219 Discount on shares purchased under Dividend Reinvestment Plan - (4) - (4) Options exercised under senior management share option plan 0.33 14 0.42 20 Employee Share Purchase Plan - 4 - 3 Balance, December 31, 2021 261.07 $ 7,242 251.43 $ 6,705 (1) As at December 31, 2020, a total of 4,544,025 at an average price of $ 56.04 255 251 (2) For the year ended December 31, 2021, 4,987,123 of $ 57.63 287 284 On August 12, 2021, Emera renewed its ATM 600 million of common shares from treasury to the public from the prevailing market price. The ATM Company's short form base shelf prospectus dated August remain in effect until September 5, 2023. As at $ 457 As at December 31, 2021, the following common shares 6.2 3.5 3.1 3.5 employee common share purchase plan and 14.2 5.1 reinvestment plan (“DRIP”). The issuance of common shares under the common share compensation the plans to exceed 10 Emera is in compliance with this requirement. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2021 | |
12. Earnings Per Share | |
Earnings Per Share | 12. Basic earnings per share (“EPS”) is determined by dividing shareholders by the weighted average number of common shares period. Diluted EPS is computed by dividing net income weighted average number of common shares and DSUs exercise and/or conversion of all potentially dilutive securities. contributions to the senior management stock option plan, convertible under the dividend reinvestment plan. The following table reconciles the computation of basic For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2021 2020 Numerator Net income attributable to common shareholders $ 510.5 $ 937.6 Diluted numerator 510.5 937.6 Denominator Weighted average shares of common stock outstanding 255.9 246.5 Weighted average deferred share units outstanding 1.3 1.3 Weighted average shares of common stock outstanding – basic 257.2 247.8 Stock-based compensation 0.4 0.4 Weighted average shares of common stock outstanding – diluted 257.6 248.2 Earnings per common share Basic $ 1.98 $ 3.78 Diluted $ 1.98 $ 3.78 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2021 | |
13. Accumulated Other Comprehensive Income (Loss) | |
Accumulated Other Comprehensive Income (Loss) | 13. The components of accumulated other comprehensive income millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total For the year ended December 31, 2021 Balance, January 1, 2021 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) Other comprehensive income (loss) before reclassifications (42) 5 18 - - (19) Amounts reclassified from accumulated other comprehensive income (loss) - - (1) - 124 123 Net current period other comprehensive income (loss) (42) 5 17 - 124 104 Balance, December 31, 2021 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 For the year ended December 31, 2020 Balance, January 1, 2020 $ 253 $ 4 $ (1) $ (1) $ (160) $ 95 Other comprehensive income (loss) before reclassifications (201) 26 - - - (175) Amounts reclassified from accumulated other comprehensive income (loss) - - 2 - (1) 1 Net current period other comprehensive income (loss) (201) 26 2 - (1) (174) Balance, December 31, 2020 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) The reclassifications out of accumulated other comprehensive For the Year ended December 31 millions of Canadian dollars 2021 2020 Affected line item in the Consolidated Financial Statements (Gains) Losses on derivatives recognized as cash flow hedges Operating revenue – regulated $ - $ 2 Interest expense, net (1) - Total $ (1) $ 2 Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 24 $ 15 Other income, net - (1) Pension and post-retirement benefits 102 (16) Total 126 (2) Income tax (expense) recovery (2) 1 Total $ 124 $ (1) Total reclassifications out of AOCI, net of tax, for the period $ 123 $ 1 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2021 | |
14. Inventory | |
Inventory | 14. As at December 31 December 31 millions of Canadian dollars 2021 2020 Fuel $ 255 $ 199 Materials 283 254 $ 538 $ 453 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2021 | |
15. Derivative Instruments | |
Derivative Instruments | 15. Derivative assets and liabilities relating to the foregoing categories Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2021 2020 2021 2020 Cash flow hedges Interest rate hedge $ - $ 1 $ - $ - Regulatory deferral Commodity swaps and forwards 22 1 1 6 83 10 8 34 20 4 7 2 21 1 - 5 Foreign exchange forwards 7 - 8 17 Physical natural gas purchases and sales 88 - - - 241 16 24 64 HFT derivatives Power swaps and physical contracts 33 13 32 13 Natural gas swaps, futures, forwards, physical contracts 208 139 818 346 241 152 850 359 Other derivatives Equity derivatives 11 - - 1 Foreign exchange forwards - 15 - - 11 15 - 1 Total 493 184 874 424 Impact of master netting agreements with intent to settle net or simultaneously (192) (86) (192) (86) Total derivatives $ 301 $ 98 $ 682 $ 338 Current $ 195 $ 73 $ 533 $ 251 Long-term 106 25 149 87 Total derivatives $ 301 $ 98 $ 682 $ 338 Derivative assets and liabilities are classified as current underlying contracts. Details of master netting agreements, shown net on the Consolidated the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2021 2020 2021 2020 Regulatory deferral $ 4 $ 2 $ 4 $ 2 HFT derivatives 188 84 188 84 Total intent to settle net or simultaneously $ 192 $ 86 $ 192 $ 86 Cash Flow Hedges On May 26, 2021 the treasury lock was settled for a gain 18 through interest expense over 10 years . As of December 31, 2021, there were no hedges. The amounts related to cash flow hedges recorded in income For the Year ended December 31 millions of Canadian dollars 2021 2020 Interest Foreign rate hedge exchange forwards Realized loss in operating revenue – regulated $ - $ (2) Realized gain in interest expense, net 1 - Total $ 1 $ (2) As at December 31 millions of Canadian dollars 2021 2020 Interest Interest rate hedge rate hedge Total $ 18 $ 1 The Company expects $ 2 within the next 12 months. Regulatory Deferral The Company has recorded the following changes in realized to derivatives receiving regulatory deferral: For the Year ended December 31 millions of Canadian dollars 2021 Natural gas Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ - $ (7) $ 9 Unrealized gain (loss) in regulatory liabilities 88 218 (3) Realized (gain) in regulatory liabilities - (3) - Realized (gain) loss in inventory (1) - (8) 5 Realized (gain) loss in regulated fuel for generation and purchased power (2) - (39) 5 Total $ 88 $ 161 $ 16 (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer For the Year ended December 31 millions of Canadian dollars 2020 Natural gas Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ - $ (36) $ (11) Unrealized gain (loss) in regulatory liabilities - 3 3 Realized gain (loss) in regulatory assets - 2 - Realized (gain) loss in regulatory liabilities - 14 - Realized (gain) loss in inventory (1) - 8 (2) Realized (gain) loss in regulated fuel for generation and purchased power (2) - 24 (3) Total $ - $ 15 $ (13) (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer Commodity Swaps and Forwards As at December 31, 2021, the Company had the following forward contracts designated for regulatory deferral that are 2022 2023-2024 millions Purchases Purchases Natural Gas (Mmbtu) 17 22 Power (MWh) 1 2 Foreign Exchange Swaps and Forwards As at December 31, 2021, the Company had the following and forward contracts designated for regulated deferral that 2022 2023-2024 Foreign exchange contracts (millions of US dollars) $ 170 $ 150 Weighted average rate 1.3047 1.2413 % of USD requirements 65% 29% The Company reassesses foreign exchange forecasted periodically or unwind existing hedges, as required. Held-for-Trading Derivatives In the ordinary course of its business, Emera enters into natural gas, as well as power and natural gas swaps, physical contracts. These derivatives are all considered The Company has recognized the following realized and derivatives: For the Year ended December 31 millions of Canadian dollars 2021 2020 Power swaps and physical contracts in non-regulated operating revenues $ 4 $ (1) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues (142) 205 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power - (4) $ (138) $ 200 As at December 31, 2021, the Company had the following derivatives that are expected to settle as outlined below: millions 2022 2023 2024 2025 2026 Natural gas purchases (Mmbtu) 308 91 56 26 26 Natural gas sales (Mmbtu) 335 103 30 2 2 Power purchases (MWh) 1 - - - - Power sales (MWh) 2 - - - - Other Derivatives As at December 31, 2021, the Company had equity derivatives associated with forecasted future cash settlements of deferred exchange forwards in place to manage cash flow risk The equity derivative hedges the return on 2.8 exchange forwards have a combined notional amount 52 2023. For the Year ended December 31 millions of Canadian dollars 2021 2020 Foreign Foreign Exchange Equity Exchange Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in operating, maintenance and general $ - $ 11 $ - $ (1) Unrealized gain (loss) in other income (expense), net (15) - 15 - Realized gain (loss) in operating, maintenance and general - 15 - (3) Realized gain (loss) in other income (expense) 18 - (2) - Total $ 3 $ 26 $ 13 $ (4) Credit Risk The Company is exposed to credit risk with respect to marketing collateral deposits and derivative assets. Credit risk non-performance under an agreement. The Company manages for counterparty analysis, exposure measurement, and assessments are conducted on all new customers and requested on any high risk accounts. The Company assesses the potential for credit losses maintains provisions. With respect to counterparties, the Company monitor the creditworthiness and credit exposure of counterparties valuing the counterparty positions. The Company monitors that are experiencing financial problems, have significant swings rating changes by external rating agencies, or have changes adjusted based on the Company’s current default probability. the counterparty’s current default probability. counterparties that are not rated. As at December 31, 2021, the maximum exposure the 1.3 $ 805 derivatives. It is possible that volatility in commodity prices could cause exposures with one or more counterparties. If such counterparties one or more agreements, the Company could suffer counterparties as part of its risk management strategy for managing and interest rate risk. Counterparties that exceed established letter of credit to the Company for the value in excess total cash deposits/collateral on hand as at December 341 251 which mitigates the Company’s maximum credit for the amount receivable or returns the deposit/collateral to longer required by the Company. The Company enters into commodity master arrangements risks, including credit risk to these counterparties. The and Derivatives Association agreements (“ISDA”), North American (“NAESB”) and, or Edison Electric Institute agreements. agreements offers protection by creating contractual rights performance and As at December 31, 2021, the Company had $ 114 123 considered to be past due, which have been outstanding for 57 financial assets is $ 93 101 credit losses. These assets primarily relate to accounts Concentration Risk The Company's concentrations of risk consisted of the As at December 31, 2021 December 31, 2020 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 384 24% $ 341 32% Commercial 167 10% 143 14% Industrial 54 3% 49 5% Other 91 6% 96 9% 696 43% 629 60% Trading group Credit rating of A- or above 66 4% 54 5% Credit rating of BBB- to BBB+ 107 7% 41 4% Not rated 132 8% 75 7% 305 19% 170 16% Other accounts receivable 329 20% 159 15% 1,330 82% 958 91% Derivative Instruments (current and long-term) Credit rating of A- or above 155 9% 60 6% Credit rating of BBB- to BBB+ 22 1% 13 1% Not rated 124 8% 25 2% 301 18% 98 9% $ 1,631 100% $ 1,056 100% Cash Collateral The Company’s cash collateral positions consisted As at December 31 December 31 millions of Canadian dollars 2021 2020 Cash collateral provided to others $ 212 $ 69 Cash collateral received from others $ 100 $ 6 Collateral is posted in the normal course of business based its senior unsecured credit rating as determined by certain derivatives contain financial assurance provisions that require credit-related event occurs. If a material adverse event resulted investment grade, the counterparties to such derivatives As at December 31, 2021, the total fair value of derivatives 682 (December 31, 2020 – 338 grade, the full value of the net liability position could be required derivatives. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2021 | |
16. Fair Value Measurements | |
Fair Value Measurements | 16. The Company is required to determine the fair value of NPNS exemption (see note 1) and uses a market approach hierarchy are defined as follows: Level 1 - Where possible, the Company bases the fair quoted prices in active markets (“quoted prices”) for identical Level 2 - Where quoted prices for identical assets and liabilities contracts must be based on quoted prices for similar assets location differences. Also, certain derivatives are valued houses. Level 3 - Where the information required for a Level 1 must be valued using unobservable or internally-developed classification are as follows: ● seasonal or monthly shaping and locational basis differentials. ● accordingly, assumptions end of the transaction term. ● utilized in the valuations. Derivative assets and liabilities are classified in their entirety based significant to the fair value measurement. The following tables set out the classification of the methodology derivatives: As at December 31, 2021 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards $ - $ 22 $ - $ 22 83 - - 83 15 1 - 16 3 18 - 21 Foreign exchange forwards - 7 - 7 Physical natural gas purchases and sales - - 88 88 101 48 88 237 HFT derivatives Power swaps and physical contracts 4 5 4 13 Natural gas swaps, futures, forwards, physical contracts and related transportation (1) 29 12 40 3 34 16 53 Other derivatives Equity derivatives 11 - - 11 Total assets 115 82 104 301 Liabilities Regulatory deferral Commodity swaps and forwards 7 - - 7 - 5 - 5 Foreign exchange forwards - 8 - 8 7 13 - 20 HFT derivatives Power swaps and physical contracts 4 5 3 12 Natural gas swaps, futures, forwards and physical contracts 13 122 515 650 17 127 518 662 Total liabilities 24 140 518 682 Net assets (liabilities) $ 91 $ (58) $ (414) $ (381) As at December 31, 2020 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Interest rate hedge $ 1 $ - $ - $ 1 1 - - 1 Regulatory deferral Commodity swaps and forwards 9 - - 9 2 1 - 3 - 2 - 2 11 3 - 14 HFT derivatives Power swaps and physical contracts 3 2 2 7 Natural gas swaps, futures, forwards, physical contracts and related transportation 1 48 12 61 4 50 14 68 Other derivatives Foreign exchange forwards - 15 - 15 - 15 - 15 Total assets 16 68 14 98 Liabilities Regulatory deferral Commodity swaps and forwards - 4 - 4 33 - - 33 3 3 - 6 - 2 - 2 Foreign exchange forwards - 17 - 17 36 26 - 62 HFT derivatives Power swaps and physical contracts 4 2 1 7 Natural gas swaps, futures, forwards and physical contracts 1 10 257 268 5 12 258 275 Other derivatives Equity derivatives 1 - - 1 1 - - 1 Total liabilities 42 38 258 338 Net assets (liabilities) $ (26) $ 30 $ (244) $ (240) The change in the fair value of the Level 3 financial assets follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2021 $ - $ 2 $ 12 $ 14 Unrealized gains included in regulatory assets or liabilities 88 - - 88 Total non-regulated operating revenues 2 - 2 Balance, December 31, 2021 $ 88 $ 4 $ 12 $ 104 The change in the fair value of the Level 3 financial liabilities for as follows: millions of Canadian dollars Power Natural gas Total Balance, January 1, 2021 $ 1 $ 257 $ 258 Total operating revenues 2 258 260 Balance, December 31, 2021 $ 3 $ 515 $ 518 Significant unobservable inputs used in the fair value derivatives include third-party sourced pricing for instruments based developed correlation factors and basis differentials; developed correlations and basis differentials analysis of the spot markets in the various illiquid term markets. premium for those long-term forward contracts with illiquid future uncertainty of these points. Any risk premiums for long-term industry practices and in discussion with industry peers. inputs in isolation would result in a significantly lower (higher) The following table outlines quantitative information about the fair value measurements categorized within Level 3 of the fair As at December 31, 2021 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average (1) Assets Regulatory deferral – Physical $ 88 Modelled pricing Third-party pricing $ 4.51 26.09 $ 9.74 natural gas purchases and sales Probability of default 2.52 % - 4.4 0% 3.31 % Discount rate 0.01 % - 1.6 0% 0.48 % HFT derivatives – Power swaps 4 Modelled pricing Third-party pricing $ 37.05 213.00 $ 93.60 and physical contracts Probability of default 0.01 % - 2.52 % 0.45 % Discount rate 0.00 % - 1.86 % 0.19 % HFT derivatives 20 Modelled pricing Third-party pricing $ 2.18 20.42 $ 3.75 Natural gas swaps, futures, Probability of default 0.01 % - 7.38 % 0.13 % forwards and physical contracts Discount rate 0.00 % - 11.98 % 0.37 % (8) Modelled pricing Third-party pricing $ 2.83 20.86 $ 10.85 Basis adjustment $ 0.00 -$ 0.44 $ 0.42 Probability of default 0.01 % - 4.17 % 0.46 % Discount rate 0.00 % - 1.73 % 0.21 % Total assets $ 104 Liabilities HFT derivatives $ 1 Modelled pricing Third-party pricing $ 37.8 0 - $ 145.8 0 $ 111.15 Power swaps and Own credit risk 0.01 % - 1.48 % 0.12 % physical contracts Discount rate 0.01 % - 1.86 % 0.31 % 2 Modelled pricing Third-party pricing $ 37.46 126.75 $ 95.02 Correlation factor 100% - 100% 100% Own credit risk 0.01 % - 11.16 % 0.07 % Discount rate 0.01 % - 1.86 % 0.21 % HFT derivatives 458 Modelled pricing Third-party pricing $ 1.9 0 - $ 20.42 $ 9.12 Natural gas swaps, futures, Own credit risk 0.01 % - 7.38 % 0.08 % forwards and physical contracts Discount rate 0.00 % - 14.59 % 1.54 % 57 Modelled pricing Third-party pricing $ 2.83 21.53 $ 12.03 Basis adjustment $ 0.00 1.11 $ 0.28 Own credit risk 0.01 % - 0.49 % 0.02 % Discount rate 0.00 % - 1.73 % 0.13 % Total liabilities $ 518 Net liabilities $ (414) (1) Unobservable inputs were weighted by the relative fair value of the instruments As at December 31, 2020 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average (1) Assets HFT derivatives $ 1 Modelled pricing Third-party pricing $20.50 - $62.45 $ 31.14 Power swaps and Probability of default 0.02 % - 9.74 % 2.52 % physical contracts Discount rate 0.01 % - 0.73 % 0.25 % 1 Modelled pricing Third-party pricing $25.70 - $36.05 $ 29.53 Probability of default 0.36 % - 0.85 % 0.6 0% Discount rate 0.06 % - 0.41 % 0.28 % Correlation factor 100 % - 100 % 100 % HFT derivatives 18 Modelled pricing Third-party pricing $1.66 - $6.22 $ 2.52 Natural gas swaps, futures, Probability of default 0.02 % - 2.52 % 0.4 0% forwards, and physical contracts Discount rate 0.00 % - 10.36 % 0.75 % (6) Modelled pricing Third-party pricing $1.82 - $6.44 $ 4.66 Basis adjustment $0.00 - $1.33 $ 0.44 Probability of default 0.02 % - 12.58 % 1.95 % Discount rate 0.00 % - 0.67 % 0.13 % Total assets $ 14 Liabilities HFT derivatives 1 Modelled pricing Third-party pricing $ 1.13 62.45 $ 36.90 Power swaps and physical contracts Own credit risk 0.02 % - 6.85 % 2.02 % Discount rate 0.01 % - 0.73 % 0.34 % 1 Modelled pricing Third-party pricing $ 37.25 62.45 $ 55.00 Own credit risk 0.36 % - 1.28 % 0.83 % Discount rate 0.01 % - 0.40 % 0.31 % Correlation factor 100 % - 100 % 100% HFT derivatives 226 Modelled pricing Third-party pricing $ 1.44 6.57 $ 3.68 Natural gas swaps, futures, Own credit risk 0.02 % - 2.52 % 0.10 % forwards and physical contracts Discount rate 0.00 % - 8.79 % 0.43 % 30 Modelled pricing Third-party pricing $ 1.54 8.44 $ 4.69 Basis adjustment $ 0.00 1.33 $ 0.87 Own credit risk 0.03 % - 12.58 % 0.10 % Discount rate 0.00 % - 0.67 % 0.16 % Total liabilities $ 258 Net assets (liabilities) $ (244) '(1) Unobservable inputs were weighted by the relative fair value of the instruments Long-term debt is a financial liability not measured at fair value balance consisted of the following: As at Carrying millions of Canadian dollars Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2021 $ 14,658 $ 16,775 $ - $ 16,308 $ 467 $ 16,775 December 31, 2020 $ 13,721 $ 16,487 $ - $ 16,020 $ 467 $ 16,487 The Company has designated $ 1.2 currency exposure of its ne t investment are contingently convertible into preferred shares in the redemption option on or after June 15, 2026 is available Notes are classified as Level 2 financial assets. As at Notes was $ 1.7 1.8 5 in OCI for the year ended December 31, 2021 (2020 – 26 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2021 | |
17. Related Party Transactions | |
Related Party Transactions | 17. In the ordinary course of business, Emera provides energy transactions with its subsidiaries, associates and other offered to non-related parties. Intercompany balances eliminated on consolidation, except for the net profit on regulated entities in accordance with accounting standards amounts are under normal interest and credit terms. Significant transactions ● Consolidated Statements of Income. NSPI’s expense purchased power, totalling 149 139 NSPML is accounted for as an equity investment and therefore, this revenue are reflected in Income from equity investments. Natural gas transportation capacity purchases from M&NP Statements of Income. Purchases from M&NP reported totalled $ 19 - $ 18 There were no significant receivables or payables between on Emera’s Consolidated Balance Sheets as at December |
Receivables and Other Current A
Receivables and Other Current Assets | 12 Months Ended |
Dec. 31, 2021 | |
18. Receivables and Other Current Assets | |
Receivables and Other Current Assets | 18. Receivables and other current assets consisted of the As at December 31 December 31 millions of Canadian dollars 2021 2020 Customer accounts receivable – billed $ 767 $ 570 Customer accounts receivable – unbilled 318 286 Allowance for credit losses (21) (22) Capitalized transportation capacity (1) 316 200 Income tax receivable 8 11 Prepaid expenses 65 50 Other 280 138 $ 1,733 $ 1,233 (1) Capitalized transportation capacity represents the agreements at the inception of the contracts. The |
Leases
Leases | 12 Months Ended |
Dec. 31, 2021 | |
19. Leases | |
Leases | 19. Lessee The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 64 years, some of which include options to extend the leases for up to 64 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised. As at December 31 December 31 millions of Canadian dollars Classification 2021 2020 Right-of-use asset Other long-term assets $ 58 $ 61 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 59 60 Total $ 62 $ 63 The Company has recorded lease expense of $ 150 – $ 160 142 149 facility finance leases, recorded in “Regulated fuel for Consolidated Statements of Income. Future minimum lease payments under non-cancellable operating and in aggregate thereafter are as follows: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments $ 5 $ 6 $ 5 $ 4 $ 3 $ 112 $ 135 Less imputed interest (73) Total $ 62 Additional information related to Emera's leases is as follows: Year ended December For the 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: $ 7 $ 7 Right-of-use assets obtained in exchange for lease obligations: $ - $ 7 Weighted average remaining lease term (years) 44 43 Weighted average discount rate- 3.98% 3.96% Lessor The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, compressed natural gas (“CNG”) stations and heat pumps. Direct finance and sales-type lease unearned income is recognized using a constant rate of interest equal to the internal “Operating revenues – regulated gas” and “Other income, Income. The Company manages its risk associated with the residual through proper routine maintenance of the asset. Customers have the option to purchase CNG station assets at any time after 2021 by paying a make- whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee. Net investment in direct finance and sales-type leases As at December 31 December 31 millions of Canadian dollars 2021 2020 Total $ 947 $ 1,018 Less: amounts representing estimated executory costs (165) (179) Minimum lease payments receivable $ 782 $ 839 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (443) (487) Net investment in direct finance and sales-type leases $ 522 $ 535 Principal due within one year (included in "Receivables and other current assets") 19 18 Net investment in sales-type leases - long-term (included in "Other long-term assets") 41 42 Net Investment in direct finance leases - long-term $ 462 $ 475 As at December 31, 2021, future minimum lease payments and in aggregate thereafter are as follows: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments to be received $ 78 $ 77 $ 79 $ 80 $ 78 $ 555 $ 947 Less: executory costs (165) Total $ 782 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2021 | |
20. Property, Plant and Equipment | |
Property, Plant and Equipment | 20. Property, plant and As at December 31 December 31 millions of Canadian dollars Estimated useful life 2021 2020 Generation 3 131 $ 11,173 $ 11,474 Transmission 11 80 2,532 2,414 Distribution 4 80 6,305 5,997 Gas transmission and distribution 7 85 4,385 3,879 General plant and other 2 60 2,473 2,127 Total 26,868 25,891 Less: Accumulated depreciation (1) (8,739) (8,714) 18,129 17,177 Construction work in progress (1) 2,224 2,358 Net book value $ 20,353 $ 19,535 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly 26 -mile pipeline lateral located in Florida, which went service in 2020. At December 31, 2021, SeaCoast’s 27 34 depreciation of $ 1 accounted for as if such participating interest were pipeline is included in OM&G in the Consolidated |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2021 | |
21. Employee Benefit Plans | |
Employee Benefit Plans | 21. Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. Emera Maine, refer to note 4 for further detail. Emera’s net periodic benefit cost included the following: Benefit Obligation and Plan Assets The changes in benefit obligation and plan assets, and the funded For the Year ended December 31 millions of Canadian dollars 2021 2020 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,759 $ 339 $ 2,822 $ 353 Service cost 43 5 46 5 Plan participant contributions 6 4 7 5 Interest cost 67 8 84 10 Benefits paid (160) (27) (135) (27) Actuarial gains (losses) (89) (10) 189 52 Settlements and curtailments - - (229) (52) Foreign currency translation adjustment (2) (1) (25) (7) Balance, December 31 2,624 318 2,759 339 Change in plan assets Balance, January 1 2,605 52 2,593 56 Employer contributions 42 21 41 21 Plan participant contributions 6 4 7 5 Benefits paid (160) (27) (135) (27) Actual return on assets, net of expenses 214 2 310 5 Settlements and curtailments - - (191) (7) Foreign currency translation adjustment (5) (1) (20) (1) Balance, December 31 2,702 51 2,605 52 Funded status, end of year $ 78 $ (267) $ (154) $ (287) The actuarial gains recognized in the period are primarily discount rate and demographic assumption changes. This was changes in inflation and compensation-related assumptions. Plans with PBO/APBO in Excess of Plan Assets The aggregate financial position for all pension plans plans) exceeds the plan assets for the years ended December millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 140 $ 290 $ 2,736 $ 308 Fair value of plan assets 35 - 2,568 - Funded status $ (105) $ (290) $ (168) $ (308) Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets The ABO for the defined benefit pension plans was $ 2,507 $ 2,639 for the years ended December 31 is as follows: millions of Canadian dollars 2021 2020 Defined benefit pension plans Defined benefit pension plans ABO $ 133 $ 1,519 Fair value of plan assets 35 1,419 Funded status $ (98) $ (100) Balance Sheet The amounts recognized in the Consolidated Balance Sheets As at December 31 December 31 millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (7) $ (20) $ (4) $ (19) Long-term liabilities (100) (270) (163) (290) Other long-term assets 185 23 13 20 Amount included in deferred income tax (8) 1 (4) (1) AOCI and regulatory assets, net of tax 230 90 443 107 Net amount recognized $ 300 $ (176) $ 285 $ (183) Amounts Recognized in AOCI and Regulatory Assets Unamortized gains and losses and past service costs AOCI or regulatory assets. The following table summarizes Regulatory assets Actuarial (gains) losses millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2021 $ 279 $ 160 Amortized in current period (24) (21) Current year addition to AOCI or regulatory assets (61) (109) Change in foreign exchange rate (2) - Balance, December 31, 2021 $ 192 $ 30 Non-pension benefits plans Balance, January 1, 2021 $ 110 $ (4) Amortized in current period (2) (3) Current year addition to AOCI or regulatory assets (16) 7 Change in foreign exchange rate (1) - Balance, December 31, 2021 $ 91 $ - 2021 2020 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 30 $ - $ 160 $ (4) Regulatory assets 192 91 279 110 Total deferred income taxes 222 91 439 106 Amount included in deferred income tax assets 8 (1) 4 1 Net amount in AOCI and regulatory assets $ 230 $ 90 $ 443 $ 107 Benefit Cost Components Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 43 $ 5 $ 46 $ 5 Interest cost 67 8 84 10 Expected return on plan assets (132) (1) (141) (1) Current year amortization of: 21 3 15 - - - (1) - 24 2 25 - Total $ 23 $ 17 $ 28 $ 14 The expected return on plan assets is determined based on $ 2,151 2,476 during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year Pension Plan Asset Allocations Emera’s investment policy includes discussion which the Company is prepared to accept with respect basis for measuring the performance of the assets. Central major asset categories. The objective of the target asset allocation returns that meet or exceed the plan’s actuarial inherent risk in financial markets by requiring that assets Within each asset class, a further diversification is undertaken investment and non-investment grade securities. Emera’s Canadian Pension Plans Asset Class Target Short-term securities 0% to 5% Fixed income 35% to 50% Equities: 12% to 22% 30% to 55% Non-Canadian Pension Plans Asset Class Target Weighted average Fixed income 30% to 50% Equities 50% to 70% Pension Plan assets are overseen by the respective Management companies. All pension investments are in accordance with policies Directors of each sponsoring company. The following tables set out the classification of the methodology investments: millions of Canadian dollars NAV Level 1 Level 2 Total Percentage December 31, 2021 Cash and cash equivalents $ - $ 60 $ - $ 60 2 % Net in-transits - (84) - (84) (3) % Equity Securities: - 97 - 97 4 % - 366 - 366 14 % - 215 - 215 8 % Fixed income securities: - - 132 132 5 % - - 117 117 4 % - 8 3 11 - % Mutual funds - 86 - 86 3 % Other - 1 (1) - - % Open-ended investments measured at NAV 952 - - 952 35 % Common collective trusts measured at NAV (2) 750 - - 750 28 % Total $ 1,702 $ 749 $ 251 $ 2,702 100 % December 31, 2020 Cash and cash equivalents $ - $ 68 $ - $ 68 3 % Net in-transits - (99) - (99) (4) % Equity securities: - 154 - 154 6 % - 380 - 380 15 % - 243 - 243 9 % Fixed Income securities: - - 119 119 5 % - - 141 141 5 % - 10 3 13 - % Mutual funds - 88 - 88 3 % Other - (3) (4) (7) - % Open-ended investments measured at NAV 801 - - 801 31 % Common collective trusts measured at NAV (2) 704 - - 704 27 % Total $ 1,505 $ 841 $ 259 $ 2,605 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, NAV’s are calculated daily and the funds honor subscription and redemption activity (2) The common collective trusts are private funds securities. Since the prices are not published to external primarily in equity securities of domestic and income assets and seeks to increase return through subscription and redemption activity regularly. Refer to note 16 for more information on the fair value Post-Retirement Benefit Plans There are no assets set aside to pay for most of the Company’s common practice, post-retirement health benefits are paid primary exceptions to this is the NMGC Retiree Medical Investments in Emera As at December 31, 2021 and 2020, the assets related plans do not hold any material investments in Emera or significant portion of assets for the benefit plan are held in pooled investments in these securities. Cash Flows The following table shows the expected cash flows for benefit plans: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2022 $ 41 $ 20 Expected benefit payments 2022 153 21 2023 162 22 2024 162 22 2025 165 22 2026 169 22 2027 – 2031 872 104 Assumptions The following table shows the assumptions that have been pension and other post-retirement benefit plans: 2021 2020 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 3.05 % 2.81 % 2.49 % 2.48 % Discount rate - future service 3.18 % 2.92 % 2.64 % 2.51 % Rate of compensation increase 3.31 % 3.29 % 2.89 % 3.04 % Health care trend - 5.09 % - 5.64 % - 3.77 % - 4.35 % 2042 2038 Benefit cost for year ended December 31: Discount rate - past service 2.49 % 2.48 % 3.17 % 3.28 % Discount rate - future service 2.64 % 2.51 % 3.21 % 3.28 % Expected long-term return on plan assets 5.86 % - % 6.29 % 3.25 % Rate of compensation increase 2.89 % 3.04 % 3.34 % 3.70 % Health care trend - 5.64 % - 5.91 % - 4.35 % - 4.37 % 2038 2038 Actual assumptions used differ by plan. The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate estimated cash flows from the pension plan. Defined Contribution Plan Emera also provides a defined contribution pension plan for certain contribution for the year ended December 31, 2021 was 45 45 |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2021 | |
22. Goodwill | |
Goodwill | 22. The change in goodwill for the year ended December 31 millions of Canadian dollars 2021 2020 Balance, January 1 $ 5,720 $ 5,835 Change in foreign exchange rate (24) (115) Balance, December 31 $ 5,696 $ 5,720 Goodwill is subject to an annual assessment for impairment Emera’s Consolidated Balance Sheets at December GBPC. Emera’s reporting units with goodwill In 2021, Emera performed a qualitative impairment assessment concluding that the fair value of the reporting units exceeded such, no quantitative assessments were performed and no Goodwill on Emera’s Consolidated Balance Sheets 68 $ 68 using a discounted cash flow analysis. This assessment estimated exceeded its carrying value, including goodwill, by approximately 12 assumptions used could result in a future impairment. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2021 | |
23. Short-Term Debt | |
Short-Term Debt | 23. Emera’s short-term borrowings consist of commercial revolving credit facilities and short-term notes. Short-term rates as at December 31 consisted of the following: millions of Canadian dollars 2021 Weighted average interest rate 2020 Weighted average interest rate Tampa Electric Company ("TEC") Advances on term, revolving and accounts receivable facilities $ 945 0.58 % $ 987 0.89 % Emera Non-revolving term facility 400 0.96 % 400 0.94 % Bank indebtedness 6 - % - - % TECO Finance Advances on revolving credit and term facilities 355 1.20 % 205 1.46 % NMGC Advances on revolving credit facilities 25 1.20 % 21 1.22 % GBPC Advances on revolving credit facilities 10 5.25 % 11 5.25 % NSPI Bank indebtedness 1 - % 1 - % Short-term debt $ 1,742 $ 1,625 The Company’s total short-term revolving and non-revolving available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2021 2020 Tampa 2026 $ 1,014 $ 1,019 TECO Energy/TECO Finance - revolving credit facility 2026 507 509 Emera - non-revolving term facility 2022 400 400 TEC - term loan 2022 634 382 TEC - accounts receivable revolving credit facility - 191 NMGC - revolving credit facility 2026 158 159 GBPC - revolving credit facility on demand 16 17 Total $ 2,729 $ 2,677 Less: Advances under revolving credit and term facilities 1,735 1,624 Letters of credit issued within the credit facilities 4 4 Total 1,739 1,628 Available capacity under existing agreements $ 990 $ 1,049 The weighted average interest rate on outstanding short-term 0.83 cent (2020 – 1.01 Recent Significant Financing Activity by Segment Florida Electric Utility On December 17, 2021, TEC entered into a $ 500 a maturity date of December 16, 2022 . The credit facility contains customary representations warranties, events of default, financial and other covenants London Inter-Bank Offered Rate (“LIBOR”), prime On December 17, 2021, TEC amended and restated its 800 amendment extended the maturity date from March 22, 2023 December 17, 2026 . There were no other significant changes in commercial terms from the prior On May 25, 2021, TEC established a commercial paper commercial paper program may be borrowed, repaid and reborrowed notes outstanding at any time not to exceed $ 800 issued is backed by TEC’s credit facility and results considered drawn and unavailable. As a result of the $ 800 repaid its $ 300 150 receivable collateralized borrowing facility and the agreement March 22, 2021. Gas Utilities and Infrastructure On December 17, 2021, NMGC amended and restated 125 amendment extended the maturity date from March 22, 2023 December 17, 2026 . There were no other significant changes in commercial terms from the prior Other On December 17, 2021, TECO Finance amended and 400 facility. The amendment March 22, 2023 December 17, 2026 . There were no other significant changes in commercial terms On December 3, 2021, Emera extended the maturity date 400 December 16, 2021 December 16, 2022 . There were no other significant changes in commercial from the prior agreement. |
Other Current Liabilities
Other Current Liabilities | 12 Months Ended |
Dec. 31, 2021 | |
Other Current Liabilities | |
Other Current Liabilities | 24. As at December 31 December 31 millions of Canadian dollars 2021 2020 Accrued charges $ 157 $ 141 Accrued interest on long-term debt 75 71 Pension and post-retirement liabilities (note 21) 27 23 Sales and other taxes payable 6 6 Income tax payable 6 1 Other 95 98 $ 366 $ 340 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2021 | |
25. Long-term Debt | |
Long-term Debt | 25. Bonds, notes and debentures are at fixed interest rates are certain bankers’ acceptances and commercial paper unencumbered ability to refinance the obligations for a period Long-term debt as at December 31 consisted of the following: Weighted average interest rate (1) millions of Canadian dollars 2021 2020 Maturity 2021 2020 Emera Bankers acceptances, LIBOR loans Variable Variable 2026 $ 378 $ 263 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) (2) 6.75% 6.75% 2076 1,521 1,528 $ 2,399 $ 2,291 Emera Finance Unsecured senior notes (USD) 3.65% 3.86% 2024 - 2046 $ 3,487 $ 3,501 TECO Finance Tampa Electric (3) Fixed rate notes and bonds (USD) 4.15% 4.53% 2022 - 2051 $ 3,683 $ 3,268 PGS Fixed rate notes and bonds (USD) 3.78% 4.58% 2022 - 2051 $ 660 $ 429 NMGC Fixed rate notes and bonds (USD) 3.11% 4.30% 2026 - 2051 $ 488 $ 465 Non-revolving term facility, floating rate Variable 2022 101 $ 589 $ 465 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 190 $ 191 NSPI Discount notes Variable Variable 2026 $ 376 $ 291 Medium term fixed rate notes 5.14% 5.14% 2025 - 2097 2,665 2,665 $ 3,041 $ 2,956 EBP Senior secured credit facility Variable Variable 2025 $ 249 $ 249 ECI Secured senior notes (USD) Variable Variable 2026 $ 84 $ 106 Amortizing fixed rate notes (USD) 3.97% 3.92% 2022 - 2026 104 $ 100 Non-revolving term facility, floating rate Variable Variable 2025 28 $ 28 Non-revolving term facility, fixed rate 2.36% 2.60% 2025 - 2026 101 $ 68 Secured fixed rate senior notes (4) 4.43% 4.39% 2022 - 2035 161 $ 174 $ 478 $ 476 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 3 $ 5 Debt issuance costs (121) (110) Amount due within one year (462) (1,382) $ (580) $ (1,487) Long-Term Debt $ 14,196 $ 12,339 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2021, the company recognized $ 102 109 subordinated notes. (3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (4) Notes are issued and payable in either USD, (5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment The fair market value adjustment is amortized over The Company’s total long-term revolving credit facilities, at December 31 were as follows: millions of Canadian dollars Maturity 2021 2020 Emera – revolving credit facility (1) June 2026 $ 900 $ 900 NSPI - revolving credit facility (1) December 2026 600 600 ECI – revolving credit facilities 2022-2032 27 28 Total 1,527 1,528 Less: Borrowings under credit facilities 770 569 Letters of credit issued inside credit facilities 124 31 Use of available facilities 894 600 Available capacity under existing agreements $ 633 $ 928 (1) Advances on the revolving credit facility can be 50 Debt Covenants Emera and its subsidiaries have debt covenants associated tested regularly and the Company is in compliance with covenants are listed below: As at Financial Covenant Requirement December 31, 2021 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 Recent Significant Financing Activity by Segment Florida Electric Utility On May 15, 2021, TEC repaid its $ 278 5.4 repaid using existing credit facilities. On March 18, 2021, TEC completed an issuance of $ 800 included $ 400 2.40 March 15, 2031 400 3.45 maturity date of March 15, 2051 . Canadian Electric Utilities On December 3, 2021, NSPI amended its operating credit October 2024 December 2026 . There were no other significant changes in commercial agreement. Other Electric On December 16, 2021, GBPC entered into a $ 75 4.00 date of December 31, 2026 . Proceeds from this loan were used to repay existing, loans totaling $ 55 Gas Utilities and Infrastructure On July 16, 2021, Brunswick Pipeline extended the maturity date 250 May 17, 2023 June 30, 2025 . There were no other significant changes in commercial prior agreement. On March 25, 2021, NMGC entered into a $ 100 maturity date of September 23, 2022 . The credit facility contains customary representations warranties, events of default, financial and other covenants prime rate, or the federal funds rate, plus a margin. On February 5, 2021, NMGC completed an issuance of 220 included $ 70 2.26 February 5, 2031 , $ 65 2.51 maturity date of February 5, 2036 , and $ 85 3.34 per cent with a maturity date of February 5, 2051 . Proceeds from this issuance were used to repay $ 200 Other On July 23, 2021, Emera extended the maturity date of 900 credit facility from June 30, 2024 June 30, 2026 . There were no other significant changes in commercial terms from the prior agreement. On June 4, 2021 Emera US Finance LP completed an issuance 750 issuance included $ 450 2.64 maturity date of June 15, 2031 300 0.83 cent with a maturity date of June 15, 2024 . The USD senior notes are guaranteed by Emera US Holdings Inc., a wholly owned Emera subsidiary. From the $ 750 Finance LP repaid its previously outstanding $ 750 Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital years and in aggregate thereafter are as follows: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Emera $ - $ 500 $ - $ - $ 1,899 $ - $ 2,399 Emera US Finance LP - - 571 - 951 1,965 3,487 Tampa 285 - - - - 3,398 3,683 PGS 32 - - - - 628 660 NMGC 101 - - - 89 399 589 NMGI - - 190 - - - 190 NSPI - - - 125 416 2,500 3,041 EBP - - - 249 - - 249 ECI 44 90 66 130 124 24 478 Total $ 462 $ 590 $ 827 $ 504 $ 3,479 $ 8,914 $ 14,776 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2021 | |
26. Asset Retirement Obligations | |
Asset Retirement Obligations | 26. AROs mostly relate to reclamation of land at the thermal, hydro disposal of polychlorinated biphenyls in transmission and Certain hydro, transmission and distribution assets may have additional as these assets are expected to be used for an indefinite the fair value of any related ARO cannot be made. The change in ARO for the years ended December 31 millions of Canadian dollars 2021 2020 Balance, January 1 $ 178 $ 185 Additions 1 10 Liabilities settled (1) (13) (25) Accretion included in depreciation expense 10 9 Accretion deferred to regulatory asset (included in property, plant and equipment) (2) (3) Other 1 1 Change in foreign exchange rate (1) 1 Balance, December 31 $ 174 $ 178 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at decreases in ARO in 2021 and 2020 are due |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2021 | |
27. Commitments and Contingencies Disclosure | |
Commitments and Contingencies | 27. Commitments As at December 31, 2021, contractual commitments (excluding obligations, long-term debt and asset retirement obligations) for aggregate thereafter consisted of the following: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Transportation (1) $ 563 $ 437 $ 372 $ 323 $ 297 $ 2,627 $ 4,619 Purchased power (2) 231 227 244 242 235 1,967 3,146 Fuel, gas supply and storage 694 104 45 40 25 - 908 Capital Projects 359 93 3 1 1 - 457 Long-term service agreements (3) 49 66 47 32 26 83 303 Equity investment commitments (4) 240 - - - - - 240 Leases and other (5) 15 14 14 12 4 116 175 Demand side management 44 1 1 - - - 46 $ 2,195 $ 942 $ 726 $ 650 $ 588 $ 4,793 $ 9,894 (1) $ 142 (2) (3) outsourced management of computer and communication (4) (5) investment commitments. NSPI has a contractual obligation to pay NSPML for the 38 years rates have been set to include $ 164 162 and amounts payable to NSPML for the remainder of 38 -year commitment period are subject to UARB approval. Any difference between the amounts approved by the UARB through the NSPML interim assessment FAM. On August 9, 2021, recover capital costs associated with the Maritime Link December 2021, NSPML obtained an interim decision January 1, 2022, until receipt of the UARB’s issued its decision relating to the Maritime Link Project, approximately $ 1.8 For further information on the UARB decision, refer to 7 . Once Muskrat Falls and LIL have achieved full power, Nalcor require true ups to finalize the respective investment Maritime Link and LIL. Emera has committed to obtain certain transmission rights energy which is not otherwise used in Newfoundland and Labrador transmit this energy from Nova Scotia to New England date the NS Block commenced, and continuing for 50 years . As transmission rights are contracted, the obligations are included within “Leases and other” in the Legal Proceedings TECO Guatemala Holdings (“TGH”) Prior to Emera’s acquisition of TECO Energy in 2016, divested of its indirect investment in the Guatemala electricity the Republic of Guatemala (“Guatemala”). In 2013, TGH with the International Centre for the Settlement of Investment Republic Central America – United States Free Trade allegation that Guatemala unfairly set the distribution tariff TGH’s investment in that company. Award”) and in November 2020, Guatemala made 38 final satisfaction of the First Award. On September 23, 2016, TGH had filed a request for resubmission addition to those awarded in the First Award. On additional damages and costs against Guatemala of more than 35 “Second Award”). TGH subsequently requested a reconsideration connection with this Second Award. On October additional interest. The additional amount is approximately $ 2 Guatemala filed an application for annulment of the Second constituted an ad hoc Committee to oversee the annulment proceeding. Committee issued (i) a decision continuing the stay of committee renders its decision on Guatemala’s briefings on the annulment and a hearing commencing July 27, Annulment on August 25, 2021. To 62 do not reflect any benefit of the Second Award. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa superfund sites and, through its PGS division, for certain former joint and several liability associated with these sites presents as at December 31, 2021, TEC has estimated its financial 18 14 primarily at PGS. This estimate assumes that other involved has been accrued and is primarily reflected in the long-term liabilities” on the Consolidated Balance Sheets. The environmental these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup to perform the work are based on TEC’s experience and agreements with the respective governmental agencies. are not discounted and do not assume any insurance In instances where other PRPs are involved, most of those worthy and are likely to continue to be credit-worthy for those instances that they are not, TEC could be liable for remediation costs. Other factors that could impact these investigation which could expand the scope of the cleanup activities, from the cleanup activities themselves or changes in remediation. Under current regulations, these costs are recoverable in base rate proceedings. Other Legal Proceedings Emera and its subsidiaries may, litigation that arise in the ordinary course of business be expected to have a material adverse effect on the Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially course of business. Risks associated with derivative instruments discussed in note 15 and note 16. Sound risk management is an essential discipline for running Company’s strategy successfully. the Board of Directors, to ensure a consistent and coherent Directors established a Risk and Sustainability Committee (‘RSC”) the RSC is to assist the Board in carrying out its risk and includes oversight of the Company’s Enterprise Risk assessment, monitoring and management Public Health Risk An outbreak of infectious disease, a pandemic or a similar pandemic, or a fear of any of the foregoing, could adversely operating, supply chain and project development delays (including as a result of government regulation and impact on the Company’s operations. Any adverse changes in general economic and market conditions threat could negatively impact demand for electricity and natural and extent of capital investments, results of financing could result in a material adverse and business contingency plans in each of its operations such public health threat. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. with an increasing amount of the Company’s net income exposed to movements in exchange rates between the which could positively or adversely affect results. Consistent with the Company’s risk management matching US denominated debt to finance its US operations instruments to hedge specific transactions and earnings exchange forward and swap contracts to limit exposure on certain fuel purchases, revenue streams and capital investment The regulatory framework for the Company’s rate incurred costs, including foreign exchange. The Company does not utilize derivative financial instruments purposes or to hedge the value of its investments in foreign subsidiaries. net investments in foreign subsidiaries do not impact net income Liquidity and Capital Market Risk Liquidity risk relates to Emera’s ability to ensure sufficient obligations. Emera manages this risk by forecasting cash determine whether sufficient funds are available. internally generated cash flows, asset sales, short-term credit markets. The Company reasonably expects liquidity sources Emera’s access to capital and cost of borrowing market conditions, market disruptions, and ratings assigned capital markets could prevent Emera from issuing new securities with less than preferred terms and conditions. investments in property, have an adverse effect on the cost of financing. The borrowing may be impacted by various market disruptions. The could have a material impact on Emera’s ability Emera is subject to financial risk associated with changes factors that rating agencies evaluate to determine credit regulatory framework, the ability to recover costs and earn increased exposure to climate change-related impacts, including hurricanes and other severe weather events. A decrease rates in future financings, increased borrowing costs under the commercial paper market or limit the availability of For certain derivative instruments, if the credit ratings of the grade, the full value of the net liability of these positions Emera manages these risks by actively monitoring and managing of sustaining investment grade credit ratings. The Company has exposure to its own common share stock-based compensation, which affect earnings period. The Company uses equity derivatives to reduce compensation. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financing investments, resulting in an exposure to interest rate risk. through a portfolio approach that includes the use of fixed maturities. The Company will, from time to time, issue long-term contracts to limit its exposure to fluctuations in floating For Emera’s regulated subsidiaries, the cost of costs are recovered from customers. Regulatory ROE such that regulatory ROE’s are likely to fall in increasing interest rates, albeit not directly and generally with process. Rising interest rates may also negatively affect and acquisition initiatives. Commodity Price Risk The Company’s utility fuel supply is subject to to commodity price risk through its portfolio of commodity The Company manages this risk through established and mitigate these risks. The Company’s commercial and purchase agreements, asset management agreements, financial hedging instruments are all used to manage and counterparty credit assessments, market and credit position reporting practices, are also used to manage and mitigate Regulated Utilities A large portion of the Company’s utility fuel supply comes be exposed to broader global conditions, which may include despite contracted terms. The Company seeks to manage this and physical contracts and through contractual protectio The majority of Emera’s regulated electric and gas adjustment mechanisms and purchased gas adjusted manage commodity price risk, as the regulatory framework permits the recovery of prudently incurred fuel and gas Emera Energy Marketing and Trading Emera Energy has employed further measures to manage Energy’s portfolio of electricity and gas marketing asset management arrangements, are contracted on a short commodity positions. However, respect to basis point differentials between relevant counterparty default. To including an estimated value-at-risk (“VaR”) estimate of the potential change in fair value that could changes in market factors within a given confidence level, if an specified time period. The VaR physical commodities, primarily natural gas and power Income Tax Risk The computation of the Company’s provision for Canada, the United States and the Caribbean. Any such earnings, cash flows, and financial position. The value liabilities are determined by existing tax laws and could Emera monitors the status of existing tax laws to ensure appropriately reflected in the Company’s tax compliance Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third guarantees and letters of credit are not included within 31, 2021: TECO Energy has issued a guarantee in connection with gas transportation precedent agreement. The guarantee is for 45 USD if SeaCoast fails to pay or perform under the contract. gas transportation precedent agreement termination date, which the event that TECO Energy’s and Emera’s below investment grade by Moody’s or S&P, a letter of credit or cash deposit of $ 27 Emera Inc. has issued a guarantee of up to $ 35 relating to outstanding notes of GBPC . The guarantee for the notes will expire in May 2023 . In 2021, NSPI issued guarantees in the amount of $ 15 Energy Marketing Incorporate (“NSPEMI”), to secure party suppliers and $ 85 15 -year natural gas transportation commitment. NSPI has $ 118 18 and will be renewed as required. The Company has standby letters of credit and surety 148 (December 31, 2020 - $ 55 subsidiaries. These letters of credit and surety bonds typically annually as required. Emera Inc., on behalf of NSPI, has a standby letter of retirement plan. The expiry date of this letter of credit was as at December 31, 2021 was $ 64 63 Collaborative Arrangements For the years ended December 31, 2021 and 2020, the collaborative arrangements: Through NSPI, the Company is a participant in three percentage ownership of the wind project assets is based on assets by the total project assets. NSPI has power output of the projects and, therefore, NSPI’s portion for generation and purchased power. expenses. In 2021, NSPI recognized $ 18 19 generation and purchased power” and $ 3 3 |
Cumulative Preferred Stock
Cumulative Preferred Stock | 12 Months Ended |
Dec. 31, 2021 | |
28. Cumulative Preferred Stock | |
Cumulative Preferred Stock | 28. Authorized: Unlimited number of First Preferred shares, issuable in Unlimited number of Second Preferred shares, issuable in December 31, 2021 December 31, 2020 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.25 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 - $ Series L $ 1.1500 $ 25.00 9,000,000 $ 222 - $ Total 58,000,000 $ 1,422 41,000,000 $ 1,004 First Preferred Shares, Series J On April 6, 2021, Emera issued 8 4.25 Shares, Series J 25.00 200 million ($ 196 First Preferred Shares, Series L On September 24, 2021, Emera issued 9 4.60 Shares, Series L 25.00 225 million ($ 222 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.1802 2.65 August 15, 2023 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A 4.900 1.2250 4.90 August 15, 2023 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.25 (6) 4.600 1.1500 November 15, 2026 25.00 (1) Holders are entitled to receive fixed or floating Corporation. (2) On or after the specified redemption dates, Shares, in whole or in part, at the specified per dates fixed for redemption. (3) On the redemption and/or conversion option 25.00 share by the annual fixed or floating dividend Bond Yield on the applicable reset date, plus the applicable 4.90 1.84 (4) On each conversion option date, the holders into an equal number of Cumulative Redeemable the outstanding Preferred Shares, Series D, Series for cash, in whole or in part at a price of 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, yield for Series I equals the Government of Treasury Bill Rate 2.54 (5) First Preferred Shares, Series E are redeemable 25.25 25.00 (6) First Preferred Shares, Series L are redeemable 26.00 $ 0.25 25.00 First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends is deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and is shown on the Consolidated Statement of Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in Sub
Non-Controlling Interest in Subsidiaries | 12 Months Ended |
Dec. 31, 2021 | |
29. Non-Controlling Interest in Subsidiaries | |
Non-Controlling Interest in Subsidiaries | 29. As at December 31 December 31 millions of Canadian dollars 2021 2020 Preferred shares of GBPC $ 14 $ 14 Domlec 20 20 $ 34 $ 34 Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual 2021 2020 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 GBPC Non–Voting The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 accrued and unpaid dividends and are entitled to a 6.0 dividend to be paid semi-annually. The Preferred Shares rank behind GBPC’s current all of GBPC’s current and future common stock. |
Supplemental Information to Con
Supplemental Information to Consolidated Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2021 | |
30. Supplementary Information to Consolidated Statements of Cash Flows | |
Supplementary Information to Consolidated Statements of Cash Flows | 30. SUPPLEMENTARY CASH FLOWS For the Year ended December 31 millions of Canadian dollars 2021 2020 Changes in non-cash working capital: $ (84) $ 6 (364) 187 289 55 7 (31) Total $ (152) $ 217 Supplemental disclosure of cash paid (received): Interest $ 603 $ 679 Income taxes $ 24 $ (148) Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 214 $ 199 Reclassification of long-term debt from current to non-current - 256 (Decrease) Increase in accrued capital expenditures $ (45) $ 17 |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2021 | |
31. Stock-Based Compensation | |
Stock-based Compensation | 31. Employee Common Share Purchase Plan and Common Shareholders Reinvestment and Share Purchase Plan Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2021, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. The maximum aggregate number of Emera common shares 7 million common shares (2020 – 7 compliance with this requirement. Compensation cost for shares issued by Emera for the year Employee Common Share Purchase Plan was $ 3 2 the Consolidated Statements of Income. The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2021. Stock-Based Compensation Plans Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2021, Emera is in compliance with this requirement. Stock options vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. Unless a stock option has expired, vested options may 27 months option holders date of retirement, six months following within sixty days exercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The following table shows the weighted average fair values incorporated into the valuation models for options granted, for 2021 2020 Weighted average fair value per option $ 3.63 $ 3.58 Expected term (1) 5 5 Risk-free interest rate (2) 0.60 % 1.33 % Expected dividend yield (3) 5.00 % 4.09 % Expected volatility (4) 19.14 % 14.10 % (1) The expected term of the option awards is that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government (3) Incorporates current dividend rates and historical (4) Estimated using the five-year historical volatility. The following table summarizes stock option information Total Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2020 2,267,782 $ 46.62 1,293,850 $ 2.69 Granted 653,600 51.12 653,600 3.63 Exercised (331,078) 40.97 N/A N/A Vested N/A N/A (494,975) 2.49 Options outstanding December 31, 2021 2,590,304 $ 48.48 1,452,475 $ 3.18 Options exercisable December 31, 2021 (2)(3) 1,137,829 $ 44.86 (1) As at December 31, 2021, there was $ 3 expected to be recognized over a weighted 3 2 3 (2) As at December 31, 2021, the weighted 6 $ 21 12 6 (3) As at December 31, 2021, the fair value of 1 2 Compensation cost recognized for stock options for the year 2 (2020 – $ 1 As at December 31, 2021, cash received from option exercises 14 19 total intrinsic value of options exercised for the year ended 6 6 million). The range of exercise prices for the options outstanding 32.35 $ 60.03 32.06 60.03 ). Share Unit Plans The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares. In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. A summary of the activity related to employee and director is presented in the following table: Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2020 661,998 $ 37.17 591,124 $ 41.69 Granted including DRIP 93,710 49.64 101,403 51.25 Exercised (145,107) 36.61 (78,162) 37.57 Outstanding and exercisable as at December 31, 2021 610,601 $ 39.22 614,365 $ 43.80 Compensation cost recognized for employee and director was $ 9 2 for the year ended December 31, 2021 were $ 3 1 of the outstanding shares for the year ended December 39 $ 36 2021 for directors was $ 39 32 December 31, 2021 associated with the DSU plan was 11 11 Performance Share Unit Plan Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. A summary of the activity related to employee PSUs for in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2020 1,126,529 $ 47.16 $ 68 Granted including DRIP 323,610 52.83 Exercised (464,290) 48.13 Forfeited (33,914) 47.78 Outstanding as at December 31, 2021 951,935 $ 48.60 $ 66 Compensation cost recognized for the PSU plan for the 12 (2020 – $ 27 ended December 31, 2021 were $ 3 7 ended December 31, 2021 associated with the PSU plan was 29 29 Restricted Share Unit Plan Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. A summary of the activity related to employee RSUs for in the following table: Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2020 166,275 $ 54.62 $ 10 Granted including DRIP 184,498 54.66 Exercised (232) 54.62 Forfeited (6,589) 54.63 Outstanding as at December 31, 2021 343,952 $ 54.64 $ 24 Compensation cost recognized for the RSU plan for the 8 (2020 – $ 4 ended December 31, 2021 were $2 million (2020 – $ 1 ended December 31, 2021 associated with the RSU plan was nil ). |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2021 | |
32. Variable Interest Entities | |
Variable Interest Entities | 32. Emera holds a variable interest in NSPML, a VIE for which primary beneficiary since it does not have the controlling milestones were achieved, Nalcor Energy was deemed the reporting purposes as it has significantly impact the economic performance of the Maritime Link as an equity investment. BLPC has established a Self-Insurance Fund (“SIF”), primarily risk against damage and consequential loss to certain systems. ECI holds a variable interest in the SIF for which beneficiary and, accordingly, the SIF, behalf of ECI’s subsidiary BLPC and BLPC, alone, operations. Additionally, exposed to the risks related to the activities of the SIF. Company would be subject to existing regulations. Emera’s “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” Sheets. Amounts included in restricted cash represent for the BLPC SIF. The Company has identified certain long-term purchase power variable interests as the Company has to purchase all price. However, it was determined power to direct the activities of the entity, management decisions. The following table provides information about Emera’s As at December 31, 2021 December 31, 2020 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 533 $ 11 $ 547 $ 16 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2021 | |
33. Subsequent Events | |
Subsequent Events | 33. These financial statements and notes reflect the Company’s the balance sheet date through February 14, 2022, the date |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
1. Summary of Significant Accounting Policies | |
Basis of Presentation | Basis of Presentation These consolidated financial statements are prepared Generally Accepted Accounting Principles (“USGAAP”). consolidated financial statements include all adjustments fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements of Emera include owned subsidiaries, and a variable interest entity (“VIE”) further details on VIEs, refer to note 32. Emera uses the investments in which the Company has the ability to exercise Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether reconsideration events have arisen with respect to existing To identify potential VIEs, management reviews contractual and ownership arrangements power agreements, tolling contracts, guarantees, jointly of which the Company is deemed the primary beneficiary beneficiary of a VIE has both the power to direct the activities impacts its economic performance and the obligation to potentially be significant to the entity. is not deemed the primary beneficiary, Intercompany balances and transactions have been eliminated on certain transactions between certain non-regulated and regulated accounting standards for rate-regulated entities. The net profit eliminated in the absence of the accounting standards regulated operating revenues. An offset is recorded regulated fuel for generation and purchased power, depending on the nature of the transaction. |
Use of Management Estimates | The preparation of consolidated financial statements in accordance to make estimates and assumptions. These may affect the date of the financial statements and reported amounts periods. Significant areas requiring the use of management liabilities, accumulated reserve for cost of removal, pension revenue, useful lives for depreciable assets, goodwill, income taxes, asset retirement obligations, and valuation the Company’s estimates on an ongoing basis based conditions and assumptions believed to be reasonable adjustments recognized in income in the year they arise. |
Regulatory Matters | Regulatory Matters Regulatory accounting applies where rates are established third-party regulator. The rates products or services and provide an opportunity for a reasonable applicable. For further detail, refer to note 7. |
Foreign Currency Translation | Foreign Currency Translation Monetary assets and liabilities denominated in foreign rates of exchange prevailing at the balance sheet date. The resulting at the original transaction date and the balance sheet Assets and liabilities of foreign operations whose functional translated using the exchange rates in effect at the the average exchange rate in effect for the and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar functional currency companies as hedges of net investments operations. The change in the carrying amount of these effect at the balance sheet date is recorded in |
Revenue Recognition | Revenue Recognition Regulated Electric Revenue Electric revenues, including energy charges, demand charges, riders, are recognized when obligations under the terms electricity is delivered to customers over time as the customer benefits of the electricity. unbilled revenues. Revenues related to the sale of electri respective regulator and recorded based on metered usage, which basis, generally monthly or bi-monthly. customers, but not billed, is estimated and the corresponding Company’s estimate of unbilled revenue at the number of megawatt hours (“MWh”) delivered to customers the upcoming billing cycle. This estimate includes assumptions weather, line losses and inter-period Regulated Gas Revenue Gas revenues, including energy charges, demand charges, clauses and riders, are recognized when obligations under the when gas is delivered to customers over time as the customer benefits of the gas. Gas revenues are recognized on an revenues. Revenues related to the distribution and sale respective regulator and recorded based on metered usage, which basis, generally monthly. billed, is estimated and the corresponding unbilled revenue unbilled revenue at the end of the reporting period is calculated delivered to customers at the established rates expected estimate includes assumptions as to the pattern of usage, classes. Non-regulated Revenue Marketing and trading margins are comprised of Emera natural gas and electricity, are recorded when obligations under terms of a contract reflecting the nature of the contractual relationships with Energy sales are recognized when obligations under the when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations Other Sales, value add, and other taxes, except for gross receipts taxes Company concurrent with revenue-producing activities Leases The Company determines whether a contract contains conveys the right to control the use of an identified asset for a consideration. Emera has leases with independent power producers (“IPP”) to purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets Sheets based on the present value of the future minimum lease commencement date. As most of Emera’s leases borrowing rate at commencement of the lease is used payments. Lease expense is recognized on a straight-line “Operating, maintenance and general” on the Consolidated Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value (net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the fair value and the carrying value commencement rather than deferred over the term of the Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. Franchise Fees and Gross Receipts Tampa through prices approved by the Florida Public Service Commission customers’ bills for franchise fees and gross receipt taxes “Regulated gas” revenues in the Consolidated Statements taxes payable by Tampa of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise required by a tariff to present the amounts on receipt taxes are presented net with no line item impact Property, Plant and |
Lessor, Leases | Leases The Company determines whether a contract contains conveys the right to control the use of an identified asset for a consideration. Emera has leases with independent power producers (“IPP”) to purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets Sheets based on the present value of the future minimum lease commencement date. As most of Emera’s leases borrowing rate at commencement of the lease is used payments. Lease expense is recognized on a straight-line “Operating, maintenance and general” on the Consolidated Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value (net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the fair value and the carrying value commencement rather than deferred over the term of the Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. |
Lease, Practical Expedient, Lessor Single Lease Component [true false] | true |
Lessee, Leases | Leases The Company determines whether a contract contains conveys the right to control the use of an identified asset for a consideration. Emera has leases with independent power producers (“IPP”) to purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets Sheets based on the present value of the future minimum lease commencement date. As most of Emera’s leases borrowing rate at commencement of the lease is used payments. Lease expense is recognized on a straight-line “Operating, maintenance and general” on the Consolidated Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value (net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the fair value and the carrying value commencement rather than deferred over the term of the Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. |
Franchise Fees and Gross Receipts | Franchise Fees and Gross Receipts Tampa through prices approved by the Florida Public Service Commission customers’ bills for franchise fees and gross receipt taxes “Regulated gas” revenues in the Consolidated Statements taxes payable by Tampa of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise required by a tariff to present the amounts on receipt taxes are presented net with no line item impact |
Property, Plant and Equipment | Property, Plant and Property, plant and construction (“AFUDC”) or capitalized interest, net of contributions The cost of additions, including betterments and replacements are included in “Property, are replaced, renewed or retired, their cost plus removal or charged to accumulated depreciation, with no gain or loss non-regulated property, dispositions occur. The cost of property, direct labour, AFUDC for regulated obligations (“ARO”), and overhead attributable to the capital such as finance, information technology and labour costs, functions, employee benefits, insurance, procurement, Expenditures for project development are capitalized if benefit. Normal maintenance projects are expensed as incurred. increase the overall life of the related assets are expensed. the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based the depreciable assets in each functional class of depreciable regulated subsidiaries, depreciation is calculated using to the average investment, adjusted for anticipated costs depreciable property. Intangible assets, which are included in “Property, software and land rights. Amortization is determined remaining service lives of the asset in each category. amortization is calculated using the amortizable life method over the remaining life of those assets. The service lives approval. Goodwill Goodwill is calculated as the excess of the purchase price values of identifiable assets acquired and liabilities assumed initial cost less any write-down for impairment and is adjusted the applicable accounting guidance, goodwill is subject level annually, or if may be below its carrying value. For further detail, refer Income Taxes and |
Goodwill | Goodwill Goodwill is calculated as the excess of the purchase price values of identifiable assets acquired and liabilities assumed initial cost less any write-down for impairment and is adjusted the applicable accounting guidance, goodwill is subject level annually, or if may be below its carrying value. For further detail, refer |
Income Taxes and Investment Tax Credits | Income Taxes and Emera recognizes deferred income tax assets and liabilities that have been included in the financial statements or income tax and liabilities are determined based on the difference on the Consolidated Balance Sheets, and their respective the year in which the differences are expected to deferred income tax assets and liabilities is recognized enacted, unless required to be offset to a regulatory Emera recognizes the effect of income tax positions realized. Management reviews all readily available current and looking information, and the income is assessed and assumptions about the expected liabilities are made. If management subsequently determines income tax asset will not be realized, then a valuation allowance deferred income tax asset expected to be realized. Generally, investment future periods to the extent that realization of such benefit earned by Tampa estimated service lives of the related properties, as required Tampa and deferred income taxes. NSPI, ENL and Brunswick Pipeline based on income tax that is currently payable except for balances specifically prescribed by the regulator. NSPI, ENL and Brunswick Pipeline recognize regulatory taxes are expected to be recovered from or returned to or liabilities are grossed up using the respective income future revenues that are required to fund these deferred associated with reduced revenues resulting from the realization not subject to income taxes. Emera classifies interest and penalties associated with unrecognized operating expense, respectively. Derivatives and Hedging Activities The Company manages its exposure to normal operating and foreign exchange, interest rates and share prices through where practicable, and by using financial instruments consisting swaps, interest rate options and swaps, equity derivatives, and swaps. In addition, the Company has contracts for These physical and financial contracts are classified as contracts and financial instruments are considered derivatives. The Company recognizes the fair value of all its derivatives derivatives that meet the normal purchases and normal sales meet the NPNS exception are not recognized on the balance income when they settle. A physical contract generally is reasonable in relation to the Company’s business within the proximity to allow for physical delivery, commodity, and the contracts designated under the NPNS exception and will discontinue under this exemption where the criteria are no longer met. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities The Company manages its exposure to normal operating and foreign exchange, interest rates and share prices through where practicable, and by using financial instruments consisting swaps, interest rate options and swaps, equity derivatives, and swaps. In addition, the Company has contracts for These physical and financial contracts are classified as contracts and financial instruments are considered derivatives. The Company recognizes the fair value of all its derivatives derivatives that meet the normal purchases and normal sales meet the NPNS exception are not recognized on the balance income when they settle. A physical contract generally is reasonable in relation to the Company’s business within the proximity to allow for physical delivery, commodity, and the contracts designated under the NPNS exception and will discontinue under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent proven to effectively hedge the identified risk both Specifically, for cash recognized in income in the same period the related hedged effectiveness requirements are not met, the derivatives fair value recognized in net income in the reporting period, accounting. Derivatives entered into by NSPI, NMGC and GBPC that which the NPNS exception has not been taken, are subject change in fair value of the derivatives is deferred to a recognized in the hedged item when the hedged item losses resulting from settlement of these derivatives related will be refunded to or collected from customers in future derivatives related to hedging as a result of a FPSC approved gas purchases which ends on December 31, 2022. Tampa gas purchases will continue through December 31, 2024, settlement agreement. Derivatives that do not meet any of the above criteria are designated normally recorded in net income of the period. The Company to be included in the HFT category where another accounting Emera classifies gains and losses on derivatives as a component power, other expenses, inventory, the item being economically hedged. Tran derivative transactions is recognized as an asset in “Receivables over the period of the transportation contract term. Cash the same category as the item being hedged within Statements of Cash Flows. Non-hedged derivatives are included Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, cash collateral with the same counterparty. “Receivables and other current assets” and obligations “Accounts payable”. Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The Company is exposed to credit risk with respect to assessments may be conducted on new customers. Deposits with the Company’s policy. assessed on a regular basis. |
Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments less at acquisition. |
Receivables | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount payment terms for electricity and gas sales are approximately assessed on account balances after the due date. |
Allowance for Credit Losses | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The Company is exposed to credit risk with respect to assessments may be conducted on new customers. Deposits with the Company’s policy. assessed on a regular basis. Management estimates credit losses related to accounts experience, customer deposits, current events, the characteristics and supportable forecasts that affect the collectability on receivables are expensed to maintain the allowance at a losses. Receivables are written off against the The economic impact of COVID-19 in the service territories aging of customer receivables resulting in higher allowances receivables, however it has not had a material impact on earnings. Inventory Fuel and materials inventories are valued using the weighted carried at the lower of weighted-average cost or net realizable weighted-average cost will be recovered in future customer |
Inventory | Inventory Fuel and materials inventories are valued using the weighted carried at the lower of weighted-average cost or net realizable weighted-average cost will be recovered in future customer |
Asset Impairment | Asset Impairment Long-Lived Assets Emera assesses whether there has been an impairment triggering event occurs, such as a significant market disruption The assessment involves comparing the undiscounted expected the asset. When the undiscounted cash flow analysis indicates amount of the impairment loss is determined by measuring lived asset over its estimated fair value. The Company’s operations or other recoverable amounts, are based fundamental economic analysis, observable market activity Company’s expectations regarding uses and holding budgets and projections, which consider external factors reporting period. The assumptions made are consistent assumptions used for valuation and pricing activities. Management considered whether the potential impacts future cash flows could indicate that long-lived assets there are no indications of impairment of Emera’s No impairment charges were recognized during the year charges of $ 25 26 “Impairment charges” in the Consolidated Statements of Income. Goodwill Goodwill is not amortized but is subject to an annual assessment with interim impairment tests performed when impairment generally determined at the operating segment level or one Reporting units with similar characteristics are grouped of goodwill. qualitative assessment to determine whether a quantitative qualitative assessment management considers, among other and market considerations and overall financial performance. If the Company performs the qualitative assessment and fair value is less than its carrying amount, or if the Company assessment, a quantitative test is performed. The quantitative reporting unit to its carrying amount, including goodwill. exceeds its fair value, an impairment loss is recorded as expense. Management estimates the fair value of the reporting combination of the income and market approach. The income cash flow analysis which relies on management’s flows. The analysis includes an estimate of terminal values methodology which derives a valuation using an assumed residual cash flows. The discount rate used is a market participant traded comparable companies and represents the weighted companies. When using the market approach, management companies and transactions within the utility industry. value include discount and growth rates, rate case assumptions, operating loss (“NOL”), utility sector market performance capital cash flows and the fair value of debt. Adverse changes result in a future material impairment of the goodwill assigned part of the goodwill impairment assessment management considered 19 pandemic on the future earnings of the reporting units. As of December 31, 2021, $ 5.6 PGS and NMGC reporting units). Qualitative assessments the significant excess of fair value over carrying amounts 2019. Management concluded it was more likely than not that exceeded their respective carrying amounts, including required. As of December 31, 2021, $ 68 Company performed a quantitative impairment assessment sensitive to changes in assumptions due to limited excess assessment estimated that the fair value of the reporting goodwill, by approximately 12 Equity Method Investments The carrying value of investments accounted for under comparing the fair value of these investments to their carrying completed, or by reviewing for the presence of impairment an impairment exists, and it is determined to be other-than-temporary, equal to the amount the carrying value exceeds the investment’s method investments was required in either 2021 or 2020. Financial Assets Equity investments, other than those accounted for under at fair value, with changes in fair value recognized in the investments that do not have readily determinable fair any, plus or minus identical or similar investments. No impairment of financial |
Asset Retirement Obligations and Cost of Removal | Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection resulting from the permanent retirement, abandonment may exist under an existing or enacted law or statute, under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash obligation, using the Company’s credit adjusted expenditures incurred. Estimated future cash flows are based remediation reports, prior experience, estimated useful The present value of the liability is recorded and the carrying correspondingly increased. The amount capitalized at inception related long-lived asset. Over time, the liability is accreted to included in “Other long-term liabilities” and accretion amortization”. Any regulated accretion expense not yet “Property, plant and equipment” Some of the Company’s transmission and distribution recognized in the consolidated financial statements as reasonably estimated, given there is insufficient information obligation to perform an asset retirement activity in which conditional on a future event that may or may not be monitors these obligations and a liability is recognized at fair be determined. Cost of Removal Tampa liabilities. The non-ARO COR represent funds received cover estimated future non-legally required COR of property, companies accrue for COR over the life of the related their respective regulators. The costs are estimated based expectations, including expected timing and estimated Stock-Based Compensation The Company has several stock-based compensation management; an employee common share purchase plan; performance share unit (“PSU”) plan; and a restricted its plans in accordance with the fair value based method of Stock-based compensation cost is measured at the grant date, award, and is recognized as an expense over the employee’s the graded vesting method. Stock-based compensation measured at fair value and re-measured at fair value at recognized in income. Employee Benefits The costs of the Company’s pension and other expensed over the periods during which employees render service. status of its defined-benefit and other post-retirement plans on changes in funded status in the year the change occurs. and losses and past service costs in AOCI or regulatory cost other than the service cost component are included Statements of Income. |
Stock-Based Compensation | Stock-Based Compensation The Company has several stock-based compensation management; an employee common share purchase plan; performance share unit (“PSU”) plan; and a restricted its plans in accordance with the fair value based method of Stock-based compensation cost is measured at the grant date, award, and is recognized as an expense over the employee’s the graded vesting method. Stock-based compensation measured at fair value and re-measured at fair value at recognized in income. |
Employee Benefits | Employee Benefits The costs of the Company’s pension and other expensed over the periods during which employees render service. status of its defined-benefit and other post-retirement plans on changes in funded status in the year the change occurs. and losses and past service costs in AOCI or regulatory cost other than the service cost component are included Statements of Income. |
Future accounting pronoucements | The Company considers the applicability and impact of Standards Board (“FASB”). The assessed and determined to be either not applicable the consolidated financial statements. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
5. Segment Information | |
Segment Information | Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2021 Operating revenues from external customers (1) $ 2,718 $ 1,501 $ 445 $ 1,276 $ (175) $ $ 5,765 Inter-segment revenues (1) 6 - - 4 18 (28) 2,724 1,501 445 1,280 (157) (28) 5,765 Regulated fuel for generation and purchased power 894 654 218 - - (3) 1,763 Regulated cost of natural gas - - - 472 - - 472 OM&G 536 291 140 325 93 (16) 1,369 Depreciation and amortization 469 246 58 121 8 - 902 Income from equity investments - 103 4 20 16 - 143 AFUDC - debt and equity 77 8 - 7 - - 92 Interest expense, net 138 132 21 51 269 - 611 Internally allocated interest (2) - - - 13 (13) - - Income tax expense (recovery) 72 9 1 62 (150) - (6) Net income (loss) attributable to common shareholders 462 241 21 198 (412) - 510 Capital expenditures 1,331 366 111 515 5 - 2,328 As at December 31, 2021 Total assets 17,903 7,418 1,402 6,666 2,034 (1,179) 34,244 Investments subject to significant influence - 1,215 44 123 - - 1,382 Goodwill 4,436 - 68 1,189 3 - 5,696 (1) All significant inter-company balances and inter-company transactions between non-regulated and regulated entities elimination of these transactions would understate and purchased power. Inter-company transactions that have not been established and agreed to by the related parties. (2) Segment net income is reported on a basis (3) Primarily relates to consolidated deferred tax reclassifications. liabilities upon consolidation. Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2020 Operating revenues from external customers (1) $ 2,473 $ 1,494 $ 474 $ 1,051 $ 14 $ $ 5,506 Inter-segment revenues (1) 7 - - 7 15 (29) 2,480 1,494 474 1,058 29 (29) 5,506 Regulated fuel for generation and purchased power 574 659 194 - - (7) 1,420 Regulated cost of natural gas - - - 293 - - 293 OM&G 552 282 151 334 115 (15) 1,419 Depreciation and amortization 455 236 71 111 8 - 881 Income from equity investments - 96 4 20 29 - 149 AFUDC - debt and equity 54 4 1 9 - - 68 Interest expense, net 151 139 32 56 301 - 679 Internally allocated interest (2) - - - 13 (13) - - Gain on sale, net of transactions costs Impairment charges - - - - (25) - (25) Income tax expense (recovery) 89 17 (8) 51 192 - 341 Net income attributable to common shareholders 501 221 35 162 19 - 938 Capital expenditures 1,361 338 148 749 4 - 2,600 As at December 31, 2020 Total assets 16,889 6,752 1,365 6,067 1,234 (1,073) 31,234 Investments subject to significant influence - 1,176 41 129 - - 1,346 Goodwill 4,455 - 68 1,194 3 - 5,720 (1) All significant inter-company balances and inter-company transactions between non-regulated and regulated entities elimination of these transactions would understate and purchased power. Inter-company transactions that have not been established and agreed to by the related parties. (2) Segment net income is reported on a basis (3) Primarily relates to consolidated deferred tax reclassifications. liabilities upon consolidation. Geographical Information Revenues (based on country of origin of the product For the Year ended December 31 millions of Canadian dollars 2021 2020 United States $ 3,754 $ 3,522 Canada 1,566 1,569 Barbados 292 263 The Bahamas 110 112 Dominica 43 40 $ 5,765 $ 5,506 Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2021 2020 United States $ 14,978 $ 14,353 Canada 4,440 4,304 Barbados 535 510 The Bahamas 322 289 Dominica 78 79 $ 20,353 $ 19,535 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
6. Revenue | |
Revenue | Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2021 Regulated Electric Revenue Residential $ 1,449 $ 797 $ 165 $ - $ - $ - $ 2,411 Commercial 754 407 232 - - - 1,393 Industrial 215 237 26 - - - 478 Other electric and regulatory deferrals 289 27 7 - - - 323 Other (1) 17 33 15 1 - (6) 60 2,724 1,501 445 1 - (6) 4,665 Regulated Gas Revenue Residential - - - 642 - - 642 Commercial - - - 379 - - 379 Industrial - - - 65 - (2) 63 Finance income (2)(3) - - - 58 - - 58 Other 121 - (2) 119 - - - 1,265 - (4) 1,261 Non-Regulated Marketing and trading margin (4) - - - - 102 - 102 Energy sales - - - - 21 (21) - Other - - - 14 9 - 23 Mark-to-market (3) - - - - (289) 3 (286) - - - 14 (157) (18) (161) Total operating revenues $ 2,724 $ 1,501 $ 445 $ 1,280 $ (157) $ (28) $ 5,765 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers. Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of Canadian dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2020 Regulated Electric Revenue Residential $ 1,365 $ 806 $ 179 $ - $ - $ - $ 2,350 Commercial 678 405 233 - - - 1,316 Industrial 178 224 32 - - - 434 Other electric and regulatory deferrals 242 31 8 - - - 281 Other (1) 17 28 22 1 - (7) 61 2,480 1,494 474 1 - (7) 4,442 Regulated Gas Revenue Residential - - - 495 - - 495 Commercial - - - 275 - - 275 Industrial - - - 54 - - 54 Finance income (2)(3) - - - 61 - - 61 Other 156 - (7) 149 - - - 1,041 - (7) 1,034 Non-Regulated Marketing and trading margin (4) - - - - 38 - 38 Energy sales - - - - 16 (16) - Other - - - 16 21 - 37 Mark-to-market (3) - - - - (46) 1 (45) - - - 16 29 (15) 30 Total operating revenues $ 2,480 $ 1,494 $ 474 $ 1,058 $ 29 $ (29) $ 5,506 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers. |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
7. Regulatory Assets and Liabilities | |
Regulatory Assets | As at December 31 December 31 millions of Canadian dollars 2021 2020 Regulatory assets Deferred income tax regulatory assets $ 1,045 $ 887 Tampa 657 - Pension and post-retirement medical plan 291 394 Regulated fuel adjustment mechanism 145 - NMGC winter event gas cost recovery 117 - Cost recovery clauses 114 49 Storm restoration regulatory asset 35 41 Environmental remediations 27 28 Stranded cost recovery 26 26 Deferrals related to derivative instruments 23 65 Demand side management ("DSM") deferral 10 15 Unamortized defeasance costs 10 13 Other 66 66 $ 2,566 $ 1,584 Current $ 253 $ 165 Long-term 2,313 1,419 Total $ 2,566 $ 1,584 Regulatory liabilities Deferred income tax regulatory liabilities 863 933 Accumulated reserve - cost of remova l 819 865 Deferrals related to derivative instruments 241 15 Storm reserve 58 62 Cost recovery clauses 35 31 Self-insurance fund (note 32) 28 28 Regulated fuel adjustment mechanism - 21 Other 11 6 $ 2,055 $ 1,961 Current $ 290 $ 129 Long-term 1,765 1,832 Total $ 2,055 $ 1,961 |
Regulatory Liabilities | As at December 31 December 31 millions of Canadian dollars 2021 2020 Regulatory assets Deferred income tax regulatory assets $ 1,045 $ 887 Tampa 657 - Pension and post-retirement medical plan 291 394 Regulated fuel adjustment mechanism 145 - NMGC winter event gas cost recovery 117 - Cost recovery clauses 114 49 Storm restoration regulatory asset 35 41 Environmental remediations 27 28 Stranded cost recovery 26 26 Deferrals related to derivative instruments 23 65 Demand side management ("DSM") deferral 10 15 Unamortized defeasance costs 10 13 Other 66 66 $ 2,566 $ 1,584 Current $ 253 $ 165 Long-term 2,313 1,419 Total $ 2,566 $ 1,584 Regulatory liabilities Deferred income tax regulatory liabilities 863 933 Accumulated reserve - cost of remova l 819 865 Deferrals related to derivative instruments 241 15 Storm reserve 58 62 Cost recovery clauses 35 31 Self-insurance fund (note 32) 28 28 Regulated fuel adjustment mechanism - 21 Other 11 6 $ 2,055 $ 1,961 Current $ 290 $ 129 Long-term 1,765 1,832 Total $ 2,055 $ 1,961 |
Investments Subject to Signif_2
Investments Subject to Significant Influence and Equity Income (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Variable Interest Entity [Line Items] | |
Investments subject to significant influence | Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of Canadian dollars 2021 2020 2021 2020 2021 LIL (1) $ 682 $ 629 $ 54 $ 49 37.4 NSPML 533 547 49 47 100.0 M&NP 123 129 20 20 12.9 Lucelec (2) 44 41 4 4 19.5 Bear Swamp - - 16 29 50.0 $ 1,382 $ 1,346 $ 143 $ 149 (1) Emera indirectly owns 100 24.9 ownership in LIL is subject to change, based on complete construction of the LIL. Emera’s ultimate percentage all transmission projects related to the Muskrat Link Projects, such that Emera’s total investment in the Maritime 49 transmission developments. (2) Although Emera’s ownership percentage of these entities operating and financial decisions of these companies these entities using the equity method. (3) The investment balance in Bear Swamp is 179 Bear Swamp's credit investment balance of $ 104 118 Consolidated Balance Sheets. |
NSPML | |
Variable Interest Entity [Line Items] | |
Investments subject to significant influence | Emera accounts for its variable interest investment in NSPML's consolidated summarized balance sheets are illustrated As at December 31 millions of Canadian dollars 2021 2020 Balance Sheets Current assets $ 25 $ 57 Property, plant and equipment 1,587 1,629 Regulatory assets 247 210 Non-current assets 31 32 Total $ 1,890 $ 1,928 Current liabilities $ 50 $ 56 Long-term debt (1) 1,189 1,228 Non-current liabilities 118 97 Equity 533 547 Total $ 1,890 $ 1,928 (1) The project debt has been guaranteed |
Other Income, Net (Table)
Other Income, Net (Table) | 12 Months Ended |
Dec. 31, 2021 | |
9. Other Income (Expenses), Net | |
Components of other income (expense), net | Other income, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2021 2020 Allowance for equity funds used during construction $ 61 $ 45 Gain on sale of Emera Maine, net of transaction costs - 585 TECO Guatemala Holdings award (2) - 49 Other 32 29 $ 93 $ 708 (1) Refer to note 4 for further detail related to (2) Refer to note 27 for further detail related |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
10. Income Taxes | |
Income tax provision | The income tax provision, for the years ended December enacted combined Canadian federal and provincial statutory millions of Canadian dollars 2021 2020 Income before provision for income taxes $ 555 $ 1,325 Statutory income tax rate 29.0% 29.5% Income taxes, at statutory income tax rate 161 391 Additional impact from the sale of Emera Maine - 102 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (62) (48) Foreign tax rate variance (42) (45) Amortization of deferred income tax regulatory liabilities (33) (44) Tax (16) (15) Tax (13) (12) Revaluation of deferred income taxes due to change in Nova Scotia tax rate - 12 Other (1) - Income tax (recovery) expense $ (6) $ 341 Effective income tax rate (1%) 26% |
Composition of taxes on income from continuing operations | millions of Canadian dollars 2021 2020 Current income taxes $ 20 $ 18 11 (58) Deferred income taxes (33) 20 118 426 2 (9) Investment tax credits (11) (10) Operating loss carryforwards (64) (46) (49) - Income tax (recovery) expense $ (6) $ 341 The following table reflects the composition of income Consolidated Statements of Income for the years ended millions of Canadian dollars 2021 2020 $ 244 $ 176 289 1,142 22 7 Income before provision for income taxes $ 555 $ 1,325 |
Deferred income tax assets and liabilities | The deferred income tax assets and liabilities presented in December 31 consisted of the following: millions of Canadian dollars 2021 2020 Deferred income tax assets: Tax $ 873 $ 724 Tax 375 319 Derivative instruments 188 108 Regulatory liabilities - cost of removal 170 184 Other 434 375 Total 2,040 1,710 Valuation allowance (256) (202) Total $ 1,784 $ 1,508 Deferred income tax (liabilities): Property, plant and equipment $ (2,622) $ (2,450) Derivative instruments (197) (93) Other (538) (385) Total $ (3,357) $ (2,928) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 295 $ 209 Long-term deferred income tax liabilities (1,868) (1,629) Net deferred income tax liabilities $ (1,573) $ (1,420) |
Net operating loss ("NOL"), capital loss and tax credit carryforwards and their expiration periods | Emera’s net operating loss (“NOL”), capital loss as at December 31, 2021 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of Canadian dollars Carryforwards Allowance Carryforwards Period Canada $ 1,776 $ (791) $ 985 2026 - 2041 75 (75) - Indefinite United States $ 1,521 $ - $ 1,521 2032 - Indefinite 817 - 817 2032 - Indefinite 375 - 375 2025 - 2041 Other $ 52 $ (38) $ 14 2022 - 2028 |
Details of the change in unrecognized tax benefits | millions of Canadian dollars 2021 2020 Balance, January 1 $ 30 $ 29 Increases due to tax positions related to current year 4 1 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (1) (2) Decreases due to settlement with tax authorities (6) - Balance, December 31 $ 28 $ 30 |
Common Stock (Tables)
Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
11. Common Stock | |
Common Stock | Authorized : 2021 2020 Issued and outstanding: millions of shares Canadian dollars millions of shares Canadian dollars Balance, December 31, 2020 251.43 $ 6,705 242.48 $ 6,216 Issuance of common stock (1)(2) 4.99 284 4.54 251 Issued under Purchase Plans at market rate 4.32 239 3.99 219 Discount on shares purchased under Dividend Reinvestment Plan - (4) - (4) Options exercised under senior management share option plan 0.33 14 0.42 20 Employee Share Purchase Plan - 4 - 3 Balance, December 31, 2021 261.07 $ 7,242 251.43 $ 6,705 (1) As at December 31, 2020, a total of 4,544,025 at an average price of $ 56.04 255 251 (2) For the year ended December 31, 2021, 4,987,123 of $ 57.63 287 284 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
12. Earnings Per Share | |
Computation of basic and diluted earnings per share | The following table reconciles the computation of basic For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2021 2020 Numerator Net income attributable to common shareholders $ 510.5 $ 937.6 Diluted numerator 510.5 937.6 Denominator Weighted average shares of common stock outstanding 255.9 246.5 Weighted average deferred share units outstanding 1.3 1.3 Weighted average shares of common stock outstanding – basic 257.2 247.8 Stock-based compensation 0.4 0.4 Weighted average shares of common stock outstanding – diluted 257.6 248.2 Earnings per common share Basic $ 1.98 $ 3.78 Diluted $ 1.98 $ 3.78 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
13. Accumulated Other Comprehensive Income (Loss) | |
Components of accumulated other comprehensive income | The components of accumulated other comprehensive income millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total For the year ended December 31, 2021 Balance, January 1, 2021 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) Other comprehensive income (loss) before reclassifications (42) 5 18 - - (19) Amounts reclassified from accumulated other comprehensive income (loss) - - (1) - 124 123 Net current period other comprehensive income (loss) (42) 5 17 - 124 104 Balance, December 31, 2021 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 For the year ended December 31, 2020 Balance, January 1, 2020 $ 253 $ 4 $ (1) $ (1) $ (160) $ 95 Other comprehensive income (loss) before reclassifications (201) 26 - - - (175) Amounts reclassified from accumulated other comprehensive income (loss) - - 2 - (1) 1 Net current period other comprehensive income (loss) (201) 26 2 - (1) (174) Balance, December 31, 2020 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) |
Reclassifications out of accumulated other comprehensive income (loss) | The reclassifications out of accumulated other comprehensive For the Year ended December 31 millions of Canadian dollars 2021 2020 Affected line item in the Consolidated Financial Statements (Gains) Losses on derivatives recognized as cash flow hedges Operating revenue – regulated $ - $ 2 Interest expense, net (1) - Total $ (1) $ 2 Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 24 $ 15 Other income, net - (1) Pension and post-retirement benefits 102 (16) Total 126 (2) Income tax (expense) recovery (2) 1 Total $ 124 $ (1) Total reclassifications out of AOCI, net of tax, for the period $ 123 $ 1 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
14. Inventory | |
Inventory | As at December 31 December 31 millions of Canadian dollars 2021 2020 Fuel $ 255 $ 199 Materials 283 254 $ 538 $ 453 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
15. Derivative Instruments | |
Derivative assets and liabilities | Derivative assets and liabilities relating to the foregoing categories Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2021 2020 2021 2020 Cash flow hedges Interest rate hedge $ - $ 1 $ - $ - Regulatory deferral Commodity swaps and forwards 22 1 1 6 83 10 8 34 20 4 7 2 21 1 - 5 Foreign exchange forwards 7 - 8 17 Physical natural gas purchases and sales 88 - - - 241 16 24 64 HFT derivatives Power swaps and physical contracts 33 13 32 13 Natural gas swaps, futures, forwards, physical contracts 208 139 818 346 241 152 850 359 Other derivatives Equity derivatives 11 - - 1 Foreign exchange forwards - 15 - - 11 15 - 1 Total 493 184 874 424 Impact of master netting agreements with intent to settle net or simultaneously (192) (86) (192) (86) Total derivatives $ 301 $ 98 $ 682 $ 338 Current $ 195 $ 73 $ 533 $ 251 Long-term 106 25 149 87 Total derivatives $ 301 $ 98 $ 682 $ 338 Derivative assets and liabilities are classified as current underlying contracts. |
Details of master netting agreements | Details of master netting agreements, shown net on the Consolidated the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2021 2020 2021 2020 Regulatory deferral $ 4 $ 2 $ 4 $ 2 HFT derivatives 188 84 188 84 Total intent to settle net or simultaneously $ 192 $ 86 $ 192 $ 86 |
Cash flow hedges recorded in income and AOCI | For the Year ended December 31 millions of Canadian dollars 2021 2020 Interest Foreign rate hedge exchange forwards Realized loss in operating revenue – regulated $ - $ (2) Realized gain in interest expense, net 1 - Total $ 1 $ (2) As at December 31 millions of Canadian dollars 2021 2020 Interest Interest rate hedge rate hedge Total $ 18 $ 1 The Company expects $ 2 within the next 12 months. |
Realized and unrealized gains (losses) with respect to derivatives | For the Year ended December 31 millions of Canadian dollars 2021 Natural gas Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ - $ (7) $ 9 Unrealized gain (loss) in regulatory liabilities 88 218 (3) Realized (gain) in regulatory liabilities - (3) - Realized (gain) loss in inventory (1) - (8) 5 Realized (gain) loss in regulated fuel for generation and purchased power (2) - (39) 5 Total $ 88 $ 161 $ 16 (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer For the Year ended December 31 millions of Canadian dollars 2020 Natural gas Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ - $ (36) $ (11) Unrealized gain (loss) in regulatory liabilities - 3 3 Realized gain (loss) in regulatory assets - 2 - Realized (gain) loss in regulatory liabilities - 14 - Realized (gain) loss in inventory (1) - 8 (2) Realized (gain) loss in regulated fuel for generation and purchased power (2) - 24 (3) Total $ - $ 15 $ (13) (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer For the Year ended December 31 millions of Canadian dollars 2021 2020 Power swaps and physical contracts in non-regulated operating revenues $ 4 $ (1) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues (142) 205 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power - (4) $ (138) $ 200 For the Year ended December 31 millions of Canadian dollars 2021 2020 Foreign Foreign Exchange Equity Exchange Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in operating, maintenance and general $ - $ 11 $ - $ (1) Unrealized gain (loss) in other income (expense), net (15) - 15 - Realized gain (loss) in operating, maintenance and general - 15 - (3) Realized gain (loss) in other income (expense) 18 - (2) - Total $ 3 $ 26 $ 13 $ (4) |
Notional volumes of derivatives designated for regulatory deferral that are expected to settle as outlined | 2022 2023-2024 millions Purchases Purchases Natural Gas (Mmbtu) 17 22 Power (MWh) 1 2 2022 2023-2024 Foreign exchange contracts (millions of US dollars) $ 170 $ 150 Weighted average rate 1.3047 1.2413 % of USD requirements 65% 29% The Company reassesses foreign exchange forecasted periodically or unwind existing hedges, as required. millions 2022 2023 2024 2025 2026 Natural gas purchases (Mmbtu) 308 91 56 26 26 Natural gas sales (Mmbtu) 335 103 30 2 2 Power purchases (MWh) 1 - - - - Power sales (MWh) 2 - - - - |
Concentration Risk | Concentration Risk The Company's concentrations of risk consisted of the As at December 31, 2021 December 31, 2020 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 384 24% $ 341 32% Commercial 167 10% 143 14% Industrial 54 3% 49 5% Other 91 6% 96 9% 696 43% 629 60% Trading group Credit rating of A- or above 66 4% 54 5% Credit rating of BBB- to BBB+ 107 7% 41 4% Not rated 132 8% 75 7% 305 19% 170 16% Other accounts receivable 329 20% 159 15% 1,330 82% 958 91% Derivative Instruments (current and long-term) Credit rating of A- or above 155 9% 60 6% Credit rating of BBB- to BBB+ 22 1% 13 1% Not rated 124 8% 25 2% 301 18% 98 9% $ 1,631 100% $ 1,056 100% |
Cash Collateral | As at December 31 December 31 millions of Canadian dollars 2021 2020 Cash collateral provided to others $ 212 $ 69 Cash collateral received from others $ 100 $ 6 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
16. Fair Value Measurements | |
Classification of the methodology used by the Company to fair value its derivatives | As at December 31, 2021 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards $ - $ 22 $ - $ 22 83 - - 83 15 1 - 16 3 18 - 21 Foreign exchange forwards - 7 - 7 Physical natural gas purchases and sales - - 88 88 101 48 88 237 HFT derivatives Power swaps and physical contracts 4 5 4 13 Natural gas swaps, futures, forwards, physical contracts and related transportation (1) 29 12 40 3 34 16 53 Other derivatives Equity derivatives 11 - - 11 Total assets 115 82 104 301 Liabilities Regulatory deferral Commodity swaps and forwards 7 - - 7 - 5 - 5 Foreign exchange forwards - 8 - 8 7 13 - 20 HFT derivatives Power swaps and physical contracts 4 5 3 12 Natural gas swaps, futures, forwards and physical contracts 13 122 515 650 17 127 518 662 Total liabilities 24 140 518 682 Net assets (liabilities) $ 91 $ (58) $ (414) $ (381) As at December 31, 2020 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Interest rate hedge $ 1 $ - $ - $ 1 1 - - 1 Regulatory deferral Commodity swaps and forwards 9 - - 9 2 1 - 3 - 2 - 2 11 3 - 14 HFT derivatives Power swaps and physical contracts 3 2 2 7 Natural gas swaps, futures, forwards, physical contracts and related transportation 1 48 12 61 4 50 14 68 Other derivatives Foreign exchange forwards - 15 - 15 - 15 - 15 Total assets 16 68 14 98 Liabilities Regulatory deferral Commodity swaps and forwards - 4 - 4 33 - - 33 3 3 - 6 - 2 - 2 Foreign exchange forwards - 17 - 17 36 26 - 62 HFT derivatives Power swaps and physical contracts 4 2 1 7 Natural gas swaps, futures, forwards and physical contracts 1 10 257 268 5 12 258 275 Other derivatives Equity derivatives 1 - - 1 1 - - 1 Total liabilities 42 38 258 338 Net assets (liabilities) $ (26) $ 30 $ (244) $ (240) |
Quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy | The change in the fair value of the Level 3 financial assets follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2021 $ - $ 2 $ 12 $ 14 Unrealized gains included in regulatory assets or liabilities 88 - - 88 Total non-regulated operating revenues 2 - 2 Balance, December 31, 2021 $ 88 $ 4 $ 12 $ 104 The change in the fair value of the Level 3 financial liabilities for as follows: millions of Canadian dollars Power Natural gas Total Balance, January 1, 2021 $ 1 $ 257 $ 258 Total operating revenues 2 258 260 Balance, December 31, 2021 $ 3 $ 515 $ 518 As at December 31, 2021 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average (1) Assets Regulatory deferral – Physical $ 88 Modelled pricing Third-party pricing $ 4.51 26.09 $ 9.74 natural gas purchases and sales Probability of default 2.52 % - 4.4 0% 3.31 % Discount rate 0.01 % - 1.6 0% 0.48 % HFT derivatives – Power swaps 4 Modelled pricing Third-party pricing $ 37.05 213.00 $ 93.60 and physical contracts Probability of default 0.01 % - 2.52 % 0.45 % Discount rate 0.00 % - 1.86 % 0.19 % HFT derivatives 20 Modelled pricing Third-party pricing $ 2.18 20.42 $ 3.75 Natural gas swaps, futures, Probability of default 0.01 % - 7.38 % 0.13 % forwards and physical contracts Discount rate 0.00 % - 11.98 % 0.37 % (8) Modelled pricing Third-party pricing $ 2.83 20.86 $ 10.85 Basis adjustment $ 0.00 -$ 0.44 $ 0.42 Probability of default 0.01 % - 4.17 % 0.46 % Discount rate 0.00 % - 1.73 % 0.21 % Total assets $ 104 Liabilities HFT derivatives $ 1 Modelled pricing Third-party pricing $ 37.8 0 - $ 145.8 0 $ 111.15 Power swaps and Own credit risk 0.01 % - 1.48 % 0.12 % physical contracts Discount rate 0.01 % - 1.86 % 0.31 % 2 Modelled pricing Third-party pricing $ 37.46 126.75 $ 95.02 Correlation factor 100% - 100% 100% Own credit risk 0.01 % - 11.16 % 0.07 % Discount rate 0.01 % - 1.86 % 0.21 % HFT derivatives 458 Modelled pricing Third-party pricing $ 1.9 0 - $ 20.42 $ 9.12 Natural gas swaps, futures, Own credit risk 0.01 % - 7.38 % 0.08 % forwards and physical contracts Discount rate 0.00 % - 14.59 % 1.54 % 57 Modelled pricing Third-party pricing $ 2.83 21.53 $ 12.03 Basis adjustment $ 0.00 1.11 $ 0.28 Own credit risk 0.01 % - 0.49 % 0.02 % Discount rate 0.00 % - 1.73 % 0.13 % Total liabilities $ 518 Net liabilities $ (414) (1) Unobservable inputs were weighted by the relative fair value of the instruments As at December 31, 2020 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average (1) Assets HFT derivatives $ 1 Modelled pricing Third-party pricing $20.50 - $62.45 $ 31.14 Power swaps and Probability of default 0.02 % - 9.74 % 2.52 % physical contracts Discount rate 0.01 % - 0.73 % 0.25 % 1 Modelled pricing Third-party pricing $25.70 - $36.05 $ 29.53 Probability of default 0.36 % - 0.85 % 0.6 0% Discount rate 0.06 % - 0.41 % 0.28 % Correlation factor 100 % - 100 % 100 % HFT derivatives 18 Modelled pricing Third-party pricing $1.66 - $6.22 $ 2.52 Natural gas swaps, futures, Probability of default 0.02 % - 2.52 % 0.4 0% forwards, and physical contracts Discount rate 0.00 % - 10.36 % 0.75 % (6) Modelled pricing Third-party pricing $1.82 - $6.44 $ 4.66 Basis adjustment $0.00 - $1.33 $ 0.44 Probability of default 0.02 % - 12.58 % 1.95 % Discount rate 0.00 % - 0.67 % 0.13 % Total assets $ 14 Liabilities HFT derivatives 1 Modelled pricing Third-party pricing $ 1.13 62.45 $ 36.90 Power swaps and physical contracts Own credit risk 0.02 % - 6.85 % 2.02 % Discount rate 0.01 % - 0.73 % 0.34 % 1 Modelled pricing Third-party pricing $ 37.25 62.45 $ 55.00 Own credit risk 0.36 % - 1.28 % 0.83 % Discount rate 0.01 % - 0.40 % 0.31 % Correlation factor 100 % - 100 % 100% HFT derivatives 226 Modelled pricing Third-party pricing $ 1.44 6.57 $ 3.68 Natural gas swaps, futures, Own credit risk 0.02 % - 2.52 % 0.10 % forwards and physical contracts Discount rate 0.00 % - 8.79 % 0.43 % 30 Modelled pricing Third-party pricing $ 1.54 8.44 $ 4.69 Basis adjustment $ 0.00 1.33 $ 0.87 Own credit risk 0.03 % - 12.58 % 0.10 % Discount rate 0.00 % - 0.67 % 0.16 % Total liabilities $ 258 Net assets (liabilities) $ (244) '(1) Unobservable inputs were weighted by the relative fair value of the instruments |
Financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value | Long-term debt is a financial liability not measured at fair value balance consisted of the following: As at Carrying millions of Canadian dollars Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2021 $ 14,658 $ 16,775 $ - $ 16,308 $ 467 $ 16,775 December 31, 2020 $ 13,721 $ 16,487 $ - $ 16,020 $ 467 $ 16,487 |
Receivables and Other Current_2
Receivables and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
18. Receivables and Other Current Assets | |
Summary of Receivables And Other Current Assets | 18. Receivables and other current assets consisted of the As at December 31 December 31 millions of Canadian dollars 2021 2020 Customer accounts receivable – billed $ 767 $ 570 Customer accounts receivable – unbilled 318 286 Allowance for credit losses (21) (22) Capitalized transportation capacity (1) 316 200 Income tax receivable 8 11 Prepaid expenses 65 50 Other 280 138 $ 1,733 $ 1,233 (1) Capitalized transportation capacity represents the agreements at the inception of the contracts. The |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
19. Leases | |
Lessee, Operating Lease and additional information | As at December 31 December 31 millions of Canadian dollars Classification 2021 2020 Right-of-use asset Other long-term assets $ 58 $ 61 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 59 60 Total $ 62 $ 63 Additional information related to Emera's leases is as follows: Year ended December For the 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: $ 7 $ 7 Right-of-use assets obtained in exchange for lease obligations: $ - $ 7 Weighted average remaining lease term (years) 44 43 Weighted average discount rate- 3.98% 3.96% |
Future minimum lease payments under non-cancellable operating leases | Future minimum lease payments under non-cancellable operating and in aggregate thereafter are as follows: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments $ 5 $ 6 $ 5 $ 4 $ 3 $ 112 $ 135 Less imputed interest (73) Total $ 62 |
Net Investment in direct finance leases | As at December 31 December 31 millions of Canadian dollars 2021 2020 Total $ 947 $ 1,018 Less: amounts representing estimated executory costs (165) (179) Minimum lease payments receivable $ 782 $ 839 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (443) (487) Net investment in direct finance and sales-type leases $ 522 $ 535 Principal due within one year (included in "Receivables and other current assets") 19 18 Net investment in sales-type leases - long-term (included in "Other long-term assets") 41 42 Net Investment in direct finance leases - long-term $ 462 $ 475 |
Future minimum lease payments to be received for the next five years | As at December 31, 2021, future minimum lease payments and in aggregate thereafter are as follows: millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments to be received $ 78 $ 77 $ 79 $ 80 $ 78 $ 555 $ 947 Less: executory costs (165) Total $ 782 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
20. Property, Plant and Equipment | |
Regulated and Non-Regulated Assets | Property, plant and As at December 31 December 31 millions of Canadian dollars Estimated useful life 2021 2020 Generation 3 131 $ 11,173 $ 11,474 Transmission 11 80 2,532 2,414 Distribution 4 80 6,305 5,997 Gas transmission and distribution 7 85 4,385 3,879 General plant and other 2 60 2,473 2,127 Total 26,868 25,891 Less: Accumulated depreciation (1) (8,739) (8,714) 18,129 17,177 Construction work in progress (1) 2,224 2,358 Net book value $ 20,353 $ 19,535 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly 26 -mile pipeline lateral located in Florida, which went service in 2020. At December 31, 2021, SeaCoast’s 27 34 depreciation of $ 1 accounted for as if such participating interest were pipeline is included in OM&G in the Consolidated |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
21. Employee Benefit Plans | |
Changes in benefit obligation and plan assets, and the funded status for all plans | For the Year ended December 31 millions of Canadian dollars 2021 2020 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,759 $ 339 $ 2,822 $ 353 Service cost 43 5 46 5 Plan participant contributions 6 4 7 5 Interest cost 67 8 84 10 Benefits paid (160) (27) (135) (27) Actuarial gains (losses) (89) (10) 189 52 Settlements and curtailments - - (229) (52) Foreign currency translation adjustment (2) (1) (25) (7) Balance, December 31 2,624 318 2,759 339 Change in plan assets Balance, January 1 2,605 52 2,593 56 Employer contributions 42 21 41 21 Plan participant contributions 6 4 7 5 Benefits paid (160) (27) (135) (27) Actual return on assets, net of expenses 214 2 310 5 Settlements and curtailments - - (191) (7) Foreign currency translation adjustment (5) (1) (20) (1) Balance, December 31 2,702 51 2,605 52 Funded status, end of year $ 78 $ (267) $ (154) $ (287) |
Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 140 $ 290 $ 2,736 $ 308 Fair value of plan assets 35 - 2,568 - Funded status $ (105) $ (290) $ (168) $ (308) millions of Canadian dollars 2021 2020 Defined benefit pension plans Defined benefit pension plans ABO $ 133 $ 1,519 Fair value of plan assets 35 1,419 Funded status $ (98) $ (100) |
Amounts recognized in the Consolidated Balance Sheets | As at December 31 December 31 millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (7) $ (20) $ (4) $ (19) Long-term liabilities (100) (270) (163) (290) Other long-term assets 185 23 13 20 Amount included in deferred income tax (8) 1 (4) (1) AOCI and regulatory assets, net of tax 230 90 443 107 Net amount recognized $ 300 $ (176) $ 285 $ (183) |
Amounts Recognized in AOCI and Regulatory Assets | Regulatory assets Actuarial (gains) losses millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2021 $ 279 $ 160 Amortized in current period (24) (21) Current year addition to AOCI or regulatory assets (61) (109) Change in foreign exchange rate (2) - Balance, December 31, 2021 $ 192 $ 30 Non-pension benefits plans Balance, January 1, 2021 $ 110 $ (4) Amortized in current period (2) (3) Current year addition to AOCI or regulatory assets (16) 7 Change in foreign exchange rate (1) - Balance, December 31, 2021 $ 91 $ - 2021 2020 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 30 $ - $ 160 $ (4) Regulatory assets 192 91 279 110 Total deferred income taxes 222 91 439 106 Amount included in deferred income tax assets 8 (1) 4 1 Net amount in AOCI and regulatory assets $ 230 $ 90 $ 443 $ 107 |
Benefit Cost Components | As at Year ended December 31 millions of Canadian dollars 2021 2020 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 43 $ 5 $ 46 $ 5 Interest cost 67 8 84 10 Expected return on plan assets (132) (1) (141) (1) Current year amortization of: 21 3 15 - - - (1) - 24 2 25 - Total $ 23 $ 17 $ 28 $ 14 |
Pension Plan Asset Allocations | Canadian Pension Plans Asset Class Target Short-term securities 0% to 5% Fixed income 35% to 50% Equities: 12% to 22% 30% to 55% Non-Canadian Pension Plans Asset Class Target Weighted average Fixed income 30% to 50% Equities 50% to 70% |
Cassification of the methodology used by the Company to fair value its investments | millions of Canadian dollars NAV Level 1 Level 2 Total Percentage December 31, 2021 Cash and cash equivalents $ - $ 60 $ - $ 60 2 % Net in-transits - (84) - (84) (3) % Equity Securities: - 97 - 97 4 % - 366 - 366 14 % - 215 - 215 8 % Fixed income securities: - - 132 132 5 % - - 117 117 4 % - 8 3 11 - % Mutual funds - 86 - 86 3 % Other - 1 (1) - - % Open-ended investments measured at NAV 952 - - 952 35 % Common collective trusts measured at NAV (2) 750 - - 750 28 % Total $ 1,702 $ 749 $ 251 $ 2,702 100 % December 31, 2020 Cash and cash equivalents $ - $ 68 $ - $ 68 3 % Net in-transits - (99) - (99) (4) % Equity securities: - 154 - 154 6 % - 380 - 380 15 % - 243 - 243 9 % Fixed Income securities: - - 119 119 5 % - - 141 141 5 % - 10 3 13 - % Mutual funds - 88 - 88 3 % Other - (3) (4) (7) - % Open-ended investments measured at NAV 801 - - 801 31 % Common collective trusts measured at NAV (2) 704 - - 704 27 % Total $ 1,505 $ 841 $ 259 $ 2,605 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, NAV’s are calculated daily and the funds honor subscription and redemption activity (2) The common collective trusts are private funds securities. Since the prices are not published to external primarily in equity securities of domestic and income assets and seeks to increase return through subscription and redemption activity regularly. |
Expected cash flows for defined benefit pension and other post-retirement benefit plans | millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2022 $ 41 $ 20 Expected benefit payments 2022 153 21 2023 162 22 2024 162 22 2025 165 22 2026 169 22 2027 – 2031 872 104 |
Assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans | Assumptions The following table shows the assumptions that have been pension and other post-retirement benefit plans: 2021 2020 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 3.05 % 2.81 % 2.49 % 2.48 % Discount rate - future service 3.18 % 2.92 % 2.64 % 2.51 % Rate of compensation increase 3.31 % 3.29 % 2.89 % 3.04 % Health care trend - 5.09 % - 5.64 % - 3.77 % - 4.35 % 2042 2038 Benefit cost for year ended December 31: Discount rate - past service 2.49 % 2.48 % 3.17 % 3.28 % Discount rate - future service 2.64 % 2.51 % 3.21 % 3.28 % Expected long-term return on plan assets 5.86 % - % 6.29 % 3.25 % Rate of compensation increase 2.89 % 3.04 % 3.34 % 3.70 % Health care trend - 5.64 % - 5.91 % - 4.35 % - 4.37 % 2038 2038 Actual assumptions used differ by plan. |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
22. Goodwill | |
Change in goodwill | 22. The change in goodwill for the year ended December 31 millions of Canadian dollars 2021 2020 Balance, January 1 $ 5,720 $ 5,835 Change in foreign exchange rate (24) (115) Balance, December 31 $ 5,696 $ 5,720 |
Short-Term Debt (Tables)
Short-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
23. Short-Term Debt | |
Short-term debt and the related weighted-average interest rates | millions of Canadian dollars 2021 Weighted average interest rate 2020 Weighted average interest rate Tampa Electric Company ("TEC") Advances on term, revolving and accounts receivable facilities $ 945 0.58 % $ 987 0.89 % Emera Non-revolving term facility 400 0.96 % 400 0.94 % Bank indebtedness 6 - % - - % TECO Finance Advances on revolving credit and term facilities 355 1.20 % 205 1.46 % NMGC Advances on revolving credit facilities 25 1.20 % 21 1.22 % GBPC Advances on revolving credit facilities 10 5.25 % 11 5.25 % NSPI Bank indebtedness 1 - % 1 - % Short-term debt $ 1,742 $ 1,625 The Company’s total short-term revolving and non-revolving available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2021 2020 Tampa 2026 $ 1,014 $ 1,019 TECO Energy/TECO Finance - revolving credit facility 2026 507 509 Emera - non-revolving term facility 2022 400 400 TEC - term loan 2022 634 382 TEC - accounts receivable revolving credit facility - 191 NMGC - revolving credit facility 2026 158 159 GBPC - revolving credit facility on demand 16 17 Total $ 2,729 $ 2,677 Less: Advances under revolving credit and term facilities 1,735 1,624 Letters of credit issued within the credit facilities 4 4 Total 1,739 1,628 Available capacity under existing agreements $ 990 $ 1,049 |
Other Current Liabilities (Tabl
Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Other Current Liabilities | |
Other Current Liabilities | As at December 31 December 31 millions of Canadian dollars 2021 2020 Accrued charges $ 157 $ 141 Accrued interest on long-term debt 75 71 Pension and post-retirement liabilities (note 21) 27 23 Sales and other taxes payable 6 6 Income tax payable 6 1 Other 95 98 $ 366 $ 340 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
25. Long-term Debt | |
Long-term debt & long-term revolving credit facilities, outstanding borrowings and available capacity | Weighted average interest rate (1) millions of Canadian dollars 2021 2020 Maturity 2021 2020 Emera Bankers acceptances, LIBOR loans Variable Variable 2026 $ 378 $ 263 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) (2) 6.75% 6.75% 2076 1,521 1,528 $ 2,399 $ 2,291 Emera Finance Unsecured senior notes (USD) 3.65% 3.86% 2024 - 2046 $ 3,487 $ 3,501 TECO Finance Tampa Electric (3) Fixed rate notes and bonds (USD) 4.15% 4.53% 2022 - 2051 $ 3,683 $ 3,268 PGS Fixed rate notes and bonds (USD) 3.78% 4.58% 2022 - 2051 $ 660 $ 429 NMGC Fixed rate notes and bonds (USD) 3.11% 4.30% 2026 - 2051 $ 488 $ 465 Non-revolving term facility, floating rate Variable 2022 101 $ 589 $ 465 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 190 $ 191 NSPI Discount notes Variable Variable 2026 $ 376 $ 291 Medium term fixed rate notes 5.14% 5.14% 2025 - 2097 2,665 2,665 $ 3,041 $ 2,956 EBP Senior secured credit facility Variable Variable 2025 $ 249 $ 249 ECI Secured senior notes (USD) Variable Variable 2026 $ 84 $ 106 Amortizing fixed rate notes (USD) 3.97% 3.92% 2022 - 2026 104 $ 100 Non-revolving term facility, floating rate Variable Variable 2025 28 $ 28 Non-revolving term facility, fixed rate 2.36% 2.60% 2025 - 2026 101 $ 68 Secured fixed rate senior notes (4) 4.43% 4.39% 2022 - 2035 161 $ 174 $ 478 $ 476 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 3 $ 5 Debt issuance costs (121) (110) Amount due within one year (462) (1,382) $ (580) $ (1,487) Long-Term Debt $ 14,196 $ 12,339 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2021, the company recognized $ 102 109 subordinated notes. (3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (4) Notes are issued and payable in either USD, (5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment The fair market value adjustment is amortized over The Company’s total long-term revolving credit facilities, at December 31 were as follows: millions of Canadian dollars Maturity 2021 2020 Emera – revolving credit facility (1) June 2026 $ 900 $ 900 NSPI - revolving credit facility (1) December 2026 600 600 ECI – revolving credit facilities 2022-2032 27 28 Total 1,527 1,528 Less: Borrowings under credit facilities 770 569 Letters of credit issued inside credit facilities 124 31 Use of available facilities 894 600 Available capacity under existing agreements $ 633 $ 928 (1) Advances on the revolving credit facility can be 50 As at Financial Covenant Requirement December 31, 2021 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 |
Long-Term Debt Maturities | millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Emera $ - $ 500 $ - $ - $ 1,899 $ - $ 2,399 Emera US Finance LP - - 571 - 951 1,965 3,487 Tampa 285 - - - - 3,398 3,683 PGS 32 - - - - 628 660 NMGC 101 - - - 89 399 589 NMGI - - 190 - - - 190 NSPI - - - 125 416 2,500 3,041 EBP - - - 249 - - 249 ECI 44 90 66 130 124 24 478 Total $ 462 $ 590 $ 827 $ 504 $ 3,479 $ 8,914 $ 14,776 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
26. Asset Retirement Obligations | |
Change in ARO | The change in ARO for the years ended December 31 millions of Canadian dollars 2021 2020 Balance, January 1 $ 178 $ 185 Additions 1 10 Liabilities settled (1) (13) (25) Accretion included in depreciation expense 10 9 Accretion deferred to regulatory asset (included in property, plant and equipment) (2) (3) Other 1 1 Change in foreign exchange rate (1) 1 Balance, December 31 $ 174 $ 178 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at decreases in ARO in 2021 and 2020 are due |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
27. Commitments and Contingencies Disclosure | |
Contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter | millions of Canadian dollars 2022 2023 2024 2025 2026 Thereafter Total Transportation (1) $ 563 $ 437 $ 372 $ 323 $ 297 $ 2,627 $ 4,619 Purchased power (2) 231 227 244 242 235 1,967 3,146 Fuel, gas supply and storage 694 104 45 40 25 - 908 Capital Projects 359 93 3 1 1 - 457 Long-term service agreements (3) 49 66 47 32 26 83 303 Equity investment commitments (4) 240 - - - - - 240 Leases and other (5) 15 14 14 12 4 116 175 Demand side management 44 1 1 - - - 46 $ 2,195 $ 942 $ 726 $ 650 $ 588 $ 4,793 $ 9,894 (1) $ 142 (2) (3) outsourced management of computer and communication (4) (5) investment commitments. |
Cumulative Preferred Stock (Tab
Cumulative Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
28. Cumulative Preferred Stock | |
Cumulative Preferred Stock | Authorized: Unlimited number of First Preferred shares, issuable in Unlimited number of Second Preferred shares, issuable in December 31, 2021 December 31, 2020 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.25 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 - $ Series L $ 1.1500 $ 25.00 9,000,000 $ 222 - $ Total 58,000,000 $ 1,422 41,000,000 $ 1,004 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.1802 2.65 August 15, 2023 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A 4.900 1.2250 4.90 August 15, 2023 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.25 (6) 4.600 1.1500 November 15, 2026 25.00 (1) Holders are entitled to receive fixed or floating Corporation. (2) On or after the specified redemption dates, Shares, in whole or in part, at the specified per dates fixed for redemption. (3) On the redemption and/or conversion option 25.00 share by the annual fixed or floating dividend Bond Yield on the applicable reset date, plus the applicable 4.90 1.84 (4) On each conversion option date, the holders into an equal number of Cumulative Redeemable the outstanding Preferred Shares, Series D, Series for cash, in whole or in part at a price of 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, yield for Series I equals the Government of Treasury Bill Rate 2.54 (5) First Preferred Shares, Series E are redeemable 25.25 25.00 (6) First Preferred Shares, Series L are redeemable 26.00 $ 0.25 25.00 |
Non-Controlling Interest in S_2
Non-Controlling Interest in Subsidiaries (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
29. Non-Controlling Interest in Subsidiaries | |
Non-controlling Interest | 29. As at December 31 December 31 millions of Canadian dollars 2021 2020 Preferred shares of GBPC $ 14 $ 14 Domlec 20 20 $ 34 $ 34 |
Preferred shares of GBPC | Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual 2021 2020 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 |
Supplemental Information to C_2
Supplemental Information to Consolidated Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
30. Supplementary Information to Consolidated Statements of Cash Flows | |
Supplementary Information to Consolidated Statement of Cash Flows | For the Year ended December 31 millions of Canadian dollars 2021 2020 Changes in non-cash working capital: $ (84) $ 6 (364) 187 289 55 7 (31) Total $ (152) $ 217 Supplemental disclosure of cash paid (received): Interest $ 603 $ 679 Income taxes $ 24 $ (148) Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 214 $ 199 Reclassification of long-term debt from current to non-current - 256 (Decrease) Increase in accrued capital expenditures $ (45) $ 17 |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
31. Stock-Based Compensation | |
Weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted | 2021 2020 Weighted average fair value per option $ 3.63 $ 3.58 Expected term (1) 5 5 Risk-free interest rate (2) 0.60 % 1.33 % Expected dividend yield (3) 5.00 % 4.09 % Expected volatility (4) 19.14 % 14.10 % (1) The expected term of the option awards is that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government (3) Incorporates current dividend rates and historical (4) Estimated using the five-year historical volatility. |
Stock option information | Total Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2020 2,267,782 $ 46.62 1,293,850 $ 2.69 Granted 653,600 51.12 653,600 3.63 Exercised (331,078) 40.97 N/A N/A Vested N/A N/A (494,975) 2.49 Options outstanding December 31, 2021 2,590,304 $ 48.48 1,452,475 $ 3.18 Options exercisable December 31, 2021 (2)(3) 1,137,829 $ 44.86 (1) As at December 31, 2021, there was $ 3 expected to be recognized over a weighted 3 2 3 (2) As at December 31, 2021, the weighted 6 $ 21 12 6 (3) As at December 31, 2021, the fair value of 1 2 |
Activity related to the Deferred Share Unit Plans | Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2020 661,998 $ 37.17 591,124 $ 41.69 Granted including DRIP 93,710 49.64 101,403 51.25 Exercised (145,107) 36.61 (78,162) 37.57 Outstanding and exercisable as at December 31, 2021 610,601 $ 39.22 614,365 $ 43.80 |
Activity related to the Performance Share Unit Plan | Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2020 1,126,529 $ 47.16 $ 68 Granted including DRIP 323,610 52.83 Exercised (464,290) 48.13 Forfeited (33,914) 47.78 Outstanding as at December 31, 2021 951,935 $ 48.60 $ 66 Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2020 166,275 $ 54.62 $ 10 Granted including DRIP 184,498 54.66 Exercised (232) 54.62 Forfeited (6,589) 54.63 Outstanding as at December 31, 2021 343,952 $ 54.64 $ 24 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
32. Variable Interest Entities | |
NSPML's consolidated summarized balance sheets | As at December 31, 2021 December 31, 2020 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 533 $ 11 $ 547 $ 16 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions | 3 Months Ended | 12 Months Ended |
Mar. 24, 2020 | Dec. 31, 2021CAD ($)CustomersMWkm | |
Emera Maine | Disposition | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Disposition, Name | Emera Maine | |
Maritimes and Northeast Pipline | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 12.90% | |
Maritimes and Northeast Pipline | Operating | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Length Of Pipeline | km | 1,400 | |
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 19.50% | |
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 51.90% | |
Tampa Electric | Operating | Florida Electric Utility | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 810,600 | |
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 536,000 | |
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Public Utilities Property Plant And Equipment Generation Capacity | MW | 824 | |
Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc. | Operating | Canadian Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 100.00% | |
Public Utilities, Equipment, Transmission and Distribution | $ | $ 1.8 | |
Length Of Pipeline | km | 170 | |
Emera Newfoundland and Labrador Holdings Inc. | Labrador-Island Link Limited Partnership | Operating | Canadian Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 37.40% | |
Public Utilities, Equipment, Transmission and Distribution | $ | $ 3.7 | |
Barbados Light and Power Company Limited | Operating | Other Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 132,000 | |
Grand Bahama Power Company Limited | Operating | Other Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 19,000 | |
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 35,700 | |
Peoples Gas System Division | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 445,000 | |
Peoples Gas System Division | Operating | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Length Of Pipeline | km | 800 | |
New Mexico Gas Company | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Number of Customers | 542,000 | |
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Length Of Pipeline | km | 145 | |
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life | 25 years | |
Emera Brunswick Pipeline Company Limited | Operating | Gas Utilities and Infrastructure | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Length Of Pipeline | km | 145 | |
Emera Energy | Bear Swamp Power Company LLC | Other | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Equity Method Investment, Ownership Percentage | 50.00% | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 633 | |
Brooklyn Power Corporation | Operating | Other | ||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items] | ||
Public Utilities Property Plant And Equipment Generation Capacity | MW | 30 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Impairment Charges | |||
Impairment charges | $ 0 | $ 25 | |
Asset Impairment Charges, net of tax | 26 | ||
Goodwill | |||
Goodwill | 5,696 | 5,720 | $ 5,835 |
TECO Energy | |||
Goodwill | |||
Goodwill | 5,600 | ||
GBPC | |||
Goodwill | |||
Goodwill | $ 68 | $ 68 | |
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 12.00% |
Change in Accounting Policy (Na
Change in Accounting Policy (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Equity | $ 10,150 | $ 9,238 | $ 8,601 |
Cumulative Effect, Period of Adoption, Adjustment | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Equity | (7) | ||
Retained Earnings | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Equity | $ 1,348 | $ 1,495 | 1,173 |
Retained Earnings | Cumulative Effect, Period of Adoption, Adjustment | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Equity | $ (7) | ||
Accounting Standards Update 2020-06 [Member] | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
New Accounting Pronouncement or Change in Accounting Principle, Description | The Company adopted Accounting Standard Update ("ASU") 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. There was no material impact on the consolidated financial statements as a result of the adoption of this standard. | ||
Change in Accounting Principle, Accounting Standards Update, Adopted [true false] | true | ||
Change in Accounting Principle, Accounting Standards Update, Adoption Date | Jan. 1, 2021 | ||
Accounting Standards Update 2020-09 [Member] | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
New Accounting Pronouncement or Change in Accounting Principle, Description | The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a result of adopting this standard, the disclosures related to certain registered debt securities that are guaranteed were amended and removed from the consolidated financial statements and added to Management’s Discussion & Analysis. | ||
Change in Accounting Principle, Accounting Standards Update, Adopted [true false] | true | ||
Change in Accounting Principle, Accounting Standards Update, Adoption Date | Dec. 31, 2021 |
Dispositions (Narrative) (Detai
Dispositions (Narrative) (Details) - Emera Maine - Disposition $ in Millions | 3 Months Ended |
Mar. 24, 2020CAD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Disposition, Name | Emera Maine |
Disposition, Value | $ 2,000 |
Proceeds on disposition of business | 1,400 |
Disposition, gain on disposition | 585 |
Disposition, gain on disposition, net of tax | $ 309 |
Segment Information (Reportable
Segment Information (Reportable Segments) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019CAD ($) | Dec. 31, 2015CAD ($) | |
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | $ 5,765 | $ 5,506 | ||||
OM&G | 1,369 | 1,419 | ||||
Depreciation and amortization | 902 | 881 | ||||
Income (loss) from equity investments and subsidiaries | 143 | 149 | ||||
AFUDC - debt and equity | 92 | 68 | ||||
Interest expense, net | 611 | 679 | ||||
Internally allocated interest | 0 | 0 | ||||
Impairment charges | 0 | (25) | ||||
Income tax expense (recovery) | (6) | 341 | ||||
Net income (loss) attributable to common shareholders | 510.5 | 937.6 | ||||
Capital expenditures | 2,328 | 2,600 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 34,244 | 31,234 | ||||
Investments subject to significant influence | 1,382 | 1,346 | ||||
Goodwill | 5,696 | 5,720 | $ 5,835 | |||
Other long-term liabilities | 868 | 781 | ||||
Bear Swamp | ||||||
Segment Reporting Information, As at December 31 | ||||||
Other long-term liabilities | 104 | 118 | $ 179 | |||
Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 4,665 | 4,442 | ||||
Fuel for generation and purchased power | 1,763 | 1,420 | ||||
Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 1,261 | 1,034 | ||||
Fuel for generation and purchased power | 472 | 293 | ||||
Florida Electric Utility | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 2,724 | 2,480 | ||||
Canadian Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 1,501 | 1,494 | ||||
Other Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 445 | 474 | ||||
Gas Utilities and Infrastructure | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 1,280 | 1,058 | ||||
Other | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | (157) | 29 | ||||
Other | Bear Swamp | ||||||
Segment Reporting Information, As at December 31 | ||||||
Other long-term liabilities | 104 | |||||
Operating | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 5,765 | 5,506 | ||||
Operating | Florida Electric Utility | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 2,718 | 2,473 | ||||
OM&G | 536 | 552 | ||||
Depreciation and amortization | 469 | 455 | ||||
Income (loss) from equity investments and subsidiaries | 0 | 0 | ||||
AFUDC - debt and equity | 77 | 54 | ||||
Interest expense, net | 138 | 151 | ||||
Internally allocated interest | 0 | 0 | ||||
Impairment charges | 0 | |||||
Income tax expense (recovery) | 72 | 89 | ||||
Net income (loss) attributable to common shareholders | 462 | 501 | ||||
Capital expenditures | 1,331 | 1,361 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 17,903 | 16,889 | ||||
Investments subject to significant influence | 0 | 0 | ||||
Goodwill | 4,436 | 4,455 | ||||
Operating | Florida Electric Utility | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 894 | 574 | ||||
Operating | Florida Electric Utility | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Operating | Canadian Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 1,501 | 1,494 | ||||
OM&G | 291 | 282 | ||||
Depreciation and amortization | 246 | 236 | ||||
Income (loss) from equity investments and subsidiaries | 103 | 96 | ||||
AFUDC - debt and equity | 8 | 4 | ||||
Interest expense, net | 132 | 139 | ||||
Internally allocated interest | 0 | 0 | ||||
Impairment charges | 0 | |||||
Income tax expense (recovery) | 9 | 17 | ||||
Net income (loss) attributable to common shareholders | 241 | 221 | ||||
Capital expenditures | 366 | 338 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 7,418 | 6,752 | ||||
Investments subject to significant influence | 1,215 | 1,176 | ||||
Goodwill | 0 | 0 | ||||
Operating | Canadian Electric Utilities | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 654 | 659 | ||||
Operating | Canadian Electric Utilities | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Operating | Other Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 445 | 474 | ||||
OM&G | 140 | 151 | ||||
Depreciation and amortization | 58 | 71 | ||||
Income (loss) from equity investments and subsidiaries | 4 | 4 | ||||
AFUDC - debt and equity | 0 | 1 | ||||
Interest expense, net | 21 | 32 | ||||
Internally allocated interest | 0 | 0 | ||||
Impairment charges | 0 | |||||
Income tax expense (recovery) | 1 | (8) | ||||
Net income (loss) attributable to common shareholders | 21 | 35 | ||||
Capital expenditures | 111 | 148 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 1,402 | 1,365 | ||||
Investments subject to significant influence | 44 | 41 | ||||
Goodwill | 68 | 68 | ||||
Operating | Other Electric Utilities | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 218 | 194 | ||||
Operating | Other Electric Utilities | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Operating | Gas Utilities and Infrastructure | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 1,276 | 1,051 | ||||
OM&G | 325 | 334 | ||||
Depreciation and amortization | 121 | 111 | ||||
Income (loss) from equity investments and subsidiaries | 20 | 20 | ||||
AFUDC - debt and equity | 7 | 9 | ||||
Interest expense, net | 51 | 56 | ||||
Internally allocated interest | 13 | 13 | ||||
Impairment charges | 0 | |||||
Income tax expense (recovery) | 62 | 51 | ||||
Net income (loss) attributable to common shareholders | 198 | 162 | ||||
Capital expenditures | 515 | 749 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 6,666 | 6,067 | ||||
Investments subject to significant influence | 123 | 129 | ||||
Goodwill | 1,189 | 1,194 | ||||
Operating | Gas Utilities and Infrastructure | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Operating | Gas Utilities and Infrastructure | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 472 | 293 | ||||
Operating | Other | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | (175) | 14 | ||||
OM&G | 93 | 115 | ||||
Depreciation and amortization | 8 | 8 | ||||
Income (loss) from equity investments and subsidiaries | 16 | 29 | ||||
AFUDC - debt and equity | 0 | 0 | ||||
Interest expense, net | 269 | 301 | ||||
Internally allocated interest | (13) | (13) | ||||
Impairment charges | (25) | |||||
Income tax expense (recovery) | (150) | 192 | ||||
Net income (loss) attributable to common shareholders | (412) | 19 | ||||
Capital expenditures | 5 | 4 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | 2,034 | 1,234 | ||||
Investments subject to significant influence | 0 | 0 | ||||
Goodwill | 3 | 3 | ||||
Operating | Other | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Operating | Other | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Intersegment Eliminations | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | (28) | (29) | ||||
OM&G | (16) | (15) | ||||
Depreciation and amortization | 0 | 0 | ||||
Income (loss) from equity investments and subsidiaries | 0 | 0 | ||||
AFUDC - debt and equity | 0 | 0 | ||||
Interest expense, net | 0 | 0 | ||||
Internally allocated interest | 0 | 0 | ||||
Impairment charges | 0 | |||||
Income tax expense (recovery) | 0 | 0 | ||||
Net income (loss) attributable to common shareholders | 0 | 0 | ||||
Capital expenditures | 0 | 0 | ||||
Segment Reporting Information, As at December 31 | ||||||
Total assets | (1,179) | (1,073) | ||||
Investments subject to significant influence | 0 | 0 | ||||
Goodwill | 0 | 0 | ||||
Intersegment Eliminations | Regulated | Electric Revenue | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | (3) | (7) | ||||
Intersegment Eliminations | Regulated | Natural gas | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Fuel for generation and purchased power | 0 | 0 | ||||
Eliminations | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | $ (28) | $ (29) | ||||
Eliminations | Florida Electric Utility | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 6 | 7 | ||||
Eliminations | Canadian Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 0 | 0 | ||||
Eliminations | Other Electric Utilities | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 0 | 0 | ||||
Eliminations | Gas Utilities and Infrastructure | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | 4 | 7 | ||||
Eliminations | Other | ||||||
Segment Reporting Information, For the year ended December 31 | ||||||
Total operating revenues | $ 18 | $ 15 |
Segment Information (Geographic
Segment Information (Geographical) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | $ 5,765 | $ 5,506 |
Property, Plant and Equipment, Net | 20,353 | 19,535 |
Canada | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 1,566 | 1,569 |
Property, Plant and Equipment, Net | 4,440 | 4,304 |
United States | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 3,754 | 3,522 |
Property, Plant and Equipment, Net | 14,978 | 14,353 |
Barbados | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 292 | 263 |
Property, Plant and Equipment, Net | 535 | 510 |
The Bahamas | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 110 | 112 |
Property, Plant and Equipment, Net | 322 | 289 |
Dominica | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 43 | 40 |
Property, Plant and Equipment, Net | $ 78 | $ 79 |
Segment Information (Narrative)
Segment Information (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2021segments | |
5. Segment Information | |
Segment Reporting, Factors Used to Identify Entity's Reportable Segments | Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. |
Number of reportable segments | 5 |
Revenue (Disaggregation) (Detai
Revenue (Disaggregation) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | |
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | $ 5,765 | $ 5,506 | ||
Total operating revenues | 5,765 | 5,506 | ||
Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 2,724 | 2,480 | ||
Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 1,501 | 1,494 | ||
Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 445 | 474 | ||
Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 1,280 | 1,058 | ||
Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | (157) | 29 | ||
Operating | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 5,765 | 5,506 | ||
Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 2,724 | 2,480 | ||
Total operating revenues | 2,718 | 2,473 | ||
Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,501 | 1,494 | ||
Total operating revenues | 1,501 | 1,494 | ||
Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 445 | 474 | ||
Total operating revenues | 445 | 474 | ||
Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,280 | 1,058 | ||
Total operating revenues | 1,276 | 1,051 | ||
Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (157) | 29 | ||
Total operating revenues | (175) | 14 | ||
Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (28) | (29) | ||
Total operating revenues | $ (28) | $ (29) | ||
Eliminations | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 6 | 7 | ||
Eliminations | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Eliminations | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Eliminations | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 4 | 7 | ||
Eliminations | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 18 | 15 | ||
Non-Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (161) | 30 | ||
Total operating revenues | (161) | 30 | ||
Non-Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Non-Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Non-Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Non-Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 14 | 16 | ||
Non-Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (157) | 29 | ||
Non-Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (18) | (15) | ||
Electric Revenue | Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 4,665 | 4,442 | ||
Total operating revenues | 4,665 | 4,442 | ||
Electric Revenue | Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 2,724 | 2,480 | ||
Electric Revenue | Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,501 | 1,494 | ||
Electric Revenue | Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 445 | 474 | ||
Electric Revenue | Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1 | 1 | ||
Electric Revenue | Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (6) | (7) | ||
Electric Revenue | Regulated | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 2,411 | 2,350 | ||
Electric Revenue | Regulated | Residential | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,449 | 1,365 | ||
Electric Revenue | Regulated | Residential | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 797 | 806 | ||
Electric Revenue | Regulated | Residential | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 165 | 179 | ||
Electric Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Residential | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Residential | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Commercial | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,393 | 1,316 | ||
Electric Revenue | Regulated | Commercial | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 754 | 678 | ||
Electric Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 407 | 405 | ||
Electric Revenue | Regulated | Commercial | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 232 | 233 | ||
Electric Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Commercial | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Commercial | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Industrial | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 478 | 434 | ||
Electric Revenue | Regulated | Industrial | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 215 | 178 | ||
Electric Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 237 | 224 | ||
Electric Revenue | Regulated | Industrial | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 26 | 32 | ||
Electric Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Industrial | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Industrial | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 323 | 281 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 289 | 242 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 27 | 31 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 7 | 8 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Electric Revenue | Regulated | Other Electric And Regulatory | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,261 | 1,034 | ||
Total operating revenues | 1,261 | 1,034 | ||
Gas Revenue | Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 1,265 | 1,041 | ||
Gas Revenue | Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (4) | (7) | ||
Gas Revenue | Regulated | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 642 | 495 | ||
Gas Revenue | Regulated | Residential | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Residential | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Residential | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 642 | 495 | ||
Gas Revenue | Regulated | Residential | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Residential | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Commercial | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 379 | 275 | ||
Gas Revenue | Regulated | Commercial | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Commercial | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 379 | 275 | ||
Gas Revenue | Regulated | Commercial | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Commercial | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Industrial | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 63 | 54 | ||
Gas Revenue | Regulated | Industrial | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Industrial | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 65 | 54 | ||
Gas Revenue | Regulated | Industrial | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Industrial | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (2) | 0 | ||
Gas Revenue | Regulated | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 119 | 149 | ||
Gas Revenue | Regulated | Other | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 121 | 156 | ||
Gas Revenue | Regulated | Other | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Gas Revenue | Regulated | Other | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | (2) | (7) | ||
Marketing and trading margin | Non-Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 102 | 38 | ||
Marketing and trading margin | Non-Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Marketing and trading margin | Non-Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Marketing and trading margin | Non-Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Marketing and trading margin | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Marketing and trading margin | Non-Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 102 | 38 | ||
Marketing and trading margin | Non-Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Energy sales | Non-Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 21 | 16 | ||
Energy sales | Non-Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | (21) | (16) | ||
Finance Income | Regulated | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 58 | 61 | ||
Finance Income | Regulated | Operating | Florida Electric Utility | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Finance Income | Regulated | Operating | Canadian Electric Utilities | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Finance Income | Regulated | Operating | Other Electric Utilities | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Finance Income | Regulated | Operating | Gas Utilities and Infrastructure | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 58 | 61 | ||
Finance Income | Regulated | Operating | Other | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Finance Income | Regulated | Eliminations | Repsol Energy Canada | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Other | Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 60 | 61 | ||
Other | Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 17 | 17 | ||
Other | Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 33 | 28 | ||
Other | Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 15 | 22 | ||
Other | Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 1 | 1 | ||
Other | Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | 0 | 0 | ||
Other | Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Total operating revenues | (6) | (7) | ||
Other | Non-Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 23 | 37 | ||
Other | Non-Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Other | Non-Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Other | Non-Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Other | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 14 | 16 | ||
Other | Non-Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 9 | 21 | ||
Other | Non-Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contract with customer | 0 | 0 | ||
Mark-To-Market | Non-Regulated | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | (286) | (45) | ||
Mark-To-Market | Non-Regulated | Operating | Florida Electric Utility | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Mark-To-Market | Non-Regulated | Operating | Canadian Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Mark-To-Market | Non-Regulated | Operating | Other Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Mark-To-Market | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | 0 | 0 | ||
Mark-To-Market | Non-Regulated | Operating | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | (289) | (46) | ||
Mark-To-Market | Non-Regulated | Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue which does not represent revenues from contracts with customers | $ 3 | $ 1 |
Revenue (Remaining Performance
Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
6. Revenue | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Explanation | 2041 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 437 | $ 464 |
SeaCoast Gas Transmission, LLC | PGS | ||
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 142 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | $ 253 | $ 165 |
Regulatory Assets, Long-term | 2,313 | 1,419 |
Total regulatory assets | 2,566 | 1,584 |
Deferred income tax regulatory assets | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,045 | 887 |
Tampa Electric capital cost recovery for early retired assets | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 657 | 0 |
Pension and post-retirement medical plan | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 291 | 394 |
Regulated fuel adjustment mechanism | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 145 | 0 |
NMGC winter event gas cost recovery | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 117 | 0 |
Cost recovery clauses | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 114 | 49 |
Storm restoration regulatory asset | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 35 | 41 |
Environmental remediations | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 27 | 28 |
Stranded cost recovery | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 26 | 26 |
Deferrals related to derivative instruments | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 23 | 65 |
Demand side management ("DSM") deferral | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 10 | 15 |
Unamortized defeasance costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 10 | 13 |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 66 | $ 66 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Regulatory Liabilities [Line Items] | ||
Regulatory Liability, Current | $ 290 | $ 129 |
Regulatory Liability, Long-term | 1,765 | 1,832 |
Total regulatory liabilities | 2,055 | 1,961 |
Deferred income tax regulatory liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 863 | 933 |
Accumulated reserve - cost of removal | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 819 | 865 |
Deferrals related to derivative instruments | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 241 | 15 |
Storm reserve | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 58 | 62 |
Cost recovery clauses | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 35 | 31 |
Self-insurance fund | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 28 | 28 |
Regulated fuel adjustment mechanism | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 0 | 21 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 11 | $ 6 |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||||||||||
Feb. 28, 2021USD ($) | Jan. 31, 2021 | Jan. 31, 2020USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Jun. 15, 2021USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2015CAD ($) | |
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Assets | $ 2,566 | $ 1,584 | ||||||||||
Renewable Energy Program | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Assets | 10 | 15 | ||||||||||
Unamortized defeasance costs | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Assets | 10 | 13 | ||||||||||
NMGC winter event gas cost recovery | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Assets | 117 | 0 | ||||||||||
GBPC | Hurricane | Loss from Catastrophes | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Storm cost | $ 15 | |||||||||||
Storm Reserve | $ 12 | |||||||||||
Recovery Period | 5 years | |||||||||||
GBPC | Steam turbine | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment | $ 21 | |||||||||||
NSPI | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Recovery Period | 3 years | |||||||||||
Regulatory Asset Recovery Assessments | . | |||||||||||
NSPI | Renewable Energy Program | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Recovery Period | 8 years | |||||||||||
Regulatory Asset Recovery Assessments | The UARB approved implementation of the 2015 DSM deferral set at $35 million in 2015 and recoverable from customers over an 8-year period beginning in 2016. | |||||||||||
Replacement program | $ 2 | $ 31 | $ 35 | |||||||||
NSPI | Unamortized defeasance costs | Defeased debt | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Long-term debt | $ 200 | $ 582 | ||||||||||
Tampa Electric | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Recovery Period | 15 years | |||||||||||
Tampa Electric | Hurricane | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Storm cost | $ 10 | |||||||||||
NMGC | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Incremental gas cost | $ 108 | |||||||||||
NMGC | NMGC winter event gas cost recovery | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Assets | $ 108 |
Regulatory Assets and Liabili_6
Regulatory Assets and Liabilities - Florida Electric Utility (Narrative) (Details) $ in Millions, $ in Millions | Jan. 19, 2022USD ($) | Jul. 19, 2021USD ($) | Aug. 03, 2020USD ($) | Jun. 09, 2020USD ($) | Apr. 27, 2020USD ($) | Jan. 31, 2024CAD ($) | Jan. 31, 2023CAD ($) | Jan. 31, 2022USD ($) | Jan. 31, 2020USD ($) | Dec. 31, 2021CAD ($)MW | Dec. 31, 2021USD ($)MW | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) |
Public Utilities, General Disclosures [Line Items] | |||||||||||||
State income tax | (1.00%) | (1.00%) | 0.26% | 0.26% | |||||||||
Utilities Operating Expense, Depreciation and Amortization | $ 902 | $ 881 | |||||||||||
Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Utilities Operating Expense, Depreciation and Amortization | $ 469 | $ 455 | |||||||||||
Tampa Electric | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Recovery Period | 15 years | 15 years | |||||||||||
Tampa Electric | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 83 | ||||||||||||
Tampa Electric | SoBRA | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Public Utilities, Property, Plant and Equipment, Generation or Processing | $ 850 | ||||||||||||
Estimated revenue in MW | MW | 600 | 600 | |||||||||||
Tampa Electric | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Estimated Amount of Investment | $ 850 | ||||||||||||
Public Utilities, Property, Plant and Equipment, Generation or Processing | $ 695 | ||||||||||||
Recovery Period | 15 years | 15 years | |||||||||||
Tampa Electric | Florida Public Service Commission | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 9.95% | 9.95% | |||||||||||
Increase in the allowed ROE | 0.25% | 0.25% | |||||||||||
Allowed equity capital structure | 54.00% | 54.00% | |||||||||||
Estimated additional revenue based on treasury bond's performance | $ 10 | ||||||||||||
Tampa Electric | Florida Public Service Commission | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Public Utilities, Disclosure of Rate Matters | Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. | Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. | |||||||||||
Allowed equity capital structure | 54.00% | 54.00% | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 15 | $ 4 | $ 5 | ||||||||||
Storm Damage Provision | $ 39 | $ 15 | $ 12 | ||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease) | $ 16 | ||||||||||||
Tampa Electric | Florida Public Service Commission | Subsequent Event | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Allowed equity capital structure | 54.00% | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 169 | $ 123 | |||||||||||
Tampa Electric | Florida Public Service Commission | Scenario Plan | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 21 | $ 90 | |||||||||||
Tampa Electric | Florida Public Service Commission | Cost recovery clauses | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Allowed equity capital structure | 10.25% | 10.25% | |||||||||||
Tampa Electric | Florida Public Service Commission | Cost recovery clauses | Subsequent Event | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 9.95% | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 68 | ||||||||||||
Tampa Electric | Florida Public Service Commission | SoBRA | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Estimated revenue in MW | MW | 600 | 600 | |||||||||||
Estimated revenue | $ 104 | ||||||||||||
Tampa Electric | Florida Public Service Commission | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Public Utilities, Property, Plant and Equipment, Plant in Service | 636 | ||||||||||||
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation | $ 267 | ||||||||||||
Tampa Electric | Florida Public Service Commission | Range, Minimum | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 9.00% | 9.00% | |||||||||||
Tampa Electric | Florida Public Service Commission | Range, Minimum | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 9.25% | 9.25% | 9.25% | 9.25% | |||||||||
Tampa Electric | Florida Public Service Commission | Range, Minimum | Subsequent Event | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 9.00% | ||||||||||||
Storm Damage Provision | $ 191 | ||||||||||||
Tampa Electric | Florida Public Service Commission | Range, Maximum | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 11.00% | 11.00% | |||||||||||
Tampa Electric | Florida Public Service Commission | Range, Maximum | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 11.25% | 11.25% | 11.25% | 11.25% | |||||||||
Tampa Electric | Florida Public Service Commission | Range, Maximum | Subsequent Event | Florida Electric Utility | Operating | |||||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||||
Approved regulated return on equity | 11.00% |
Regulatory Assets and Liabili_7
Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) $ in Millions | Jan. 18, 2022CAD ($) | Dec. 31, 2022CAD ($) | Dec. 31, 2022 | Dec. 31, 2024CAD ($) | Dec. 31, 2023CAD ($) | Dec. 31, 2022CAD ($) | Dec. 31, 2021CAD ($)km | Dec. 31, 2020CAD ($) | Feb. 16, 2022CAD ($) | Feb. 09, 2022CAD ($) |
Public Utilities, General Disclosures [Line Items] | ||||||||||
Regulatory Liabilities | $ 2,055 | $ 1,961 | ||||||||
Utilities Operating Expense, Depreciation and Amortization | 902 | 881 | ||||||||
Contractual Obligation, to be Paid, Year One | 2,195 | |||||||||
Contractual Obligation, to be Paid, Year Two | 942 | |||||||||
Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Utilities Operating Expense, Depreciation and Amortization | 246 | 236 | ||||||||
Regulated fuel adjustment mechanism | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Regulatory Liabilities | $ 0 | 21 | ||||||||
NSPI | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Recovery Period | 3 years | |||||||||
Regulatory Asset Recovery Assessments | . | |||||||||
NSPI | NSP Maritime Link Inc. | Subsequent Event [Member] | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Holdback payable | $ 10 | |||||||||
NSPI | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Recovery Period | 3 years | |||||||||
NSPI | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Recovery Period | 3 years | |||||||||
Regulatory Liabilities | $ 172 | 145 | ||||||||
Approved payment in period | 139 | 135 | ||||||||
Holdback payable | 10 | $ 4 | ||||||||
Utilities Operating Expense, Depreciation and Amortization | 23 | |||||||||
Phase-in Plan, Amount of Capitalized Costs Recovered | 40 | |||||||||
Contractual Obligation, to be Paid, Year One | 164 | |||||||||
Contractual Obligation, to be Paid, Year Two | $ 162 | |||||||||
Energy Delivery Commitments and Contracts, Term | 35 years | |||||||||
NSPI | Range, Minimum | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Approved regulated return on equity | 8.75% | 8.75% | ||||||||
NSPI | Range, Maximum | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Approved regulated return on equity | 9.25% | 9.25% | ||||||||
Regulated common equity component | 40.00% | 40.00% | ||||||||
NSPI | Scenario Plan | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 21 | $ 56 | $ 54 | $ 52 | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 2.90% | |||||||||
NSPI | Scenario Plan | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Regulatory Liabilities | $ 1,800 | |||||||||
Holdback payable | $ 10 | |||||||||
Phase-in Plan, Amount of Capitalized Costs Recovered | $ 12 | |||||||||
Contractual Obligation, to be Paid, Year One | $ 168 | |||||||||
Interim cost assessment, holdback | 2 | |||||||||
Loss Contingency, Estimate of Possible Loss | $ 10 | |||||||||
NSPI | Regulated fuel adjustment mechanism | Scenario Plan | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 0.80% | |||||||||
NSPI | Regulated fuel adjustment mechanism | Scenario Plan | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Regulatory Asset Recovery Assessments | The UARB’s decision to approve NSPI’s 2020 through 2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. NSPI refunded approximately $40 million plus interest to customers, and the remaining $12 million plus interest will be returned to customers subsequent to 2022. | |||||||||
NSPI | Public Utilities Act | Canadian Electric Utilities | Operating | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 1.50% | |||||||||
Emera Newfoundland and Labrador Holdings Inc. | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Equipment, Transmission and Distribution | $ 1,800 | |||||||||
Length Of Pipeline | km | 170 | |||||||||
Interim cost assessment, holdback | The approved interim cost assessment payments are subject to a holdback of up to $10 million pending UARB agreement that benefits from the Maritime Link are realized for NSPI customers | |||||||||
Emera Newfoundland and Labrador Holdings Inc. | Range, Minimum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Approved regulated return on equity | 8.75% | |||||||||
Emera Newfoundland and Labrador Holdings Inc. | Range, Maximum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Approved regulated return on equity | 9.25% | |||||||||
Regulated common equity component | 30.00% | |||||||||
Emera Newfoundland and Labrador Holdings Inc. | Regulated fuel adjustment mechanism | Scenario Plan | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes | $ 52 | |||||||||
Regulatory Asset Recovery Assessments | In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being developed by Nalcor Energy, the approved Maritime Link interim assessment payment in 2019 reflected a reduction in NSPML’s assessment, related to depreciation and amortization expenses. The UARB’s decision to approve NSPI’s 2020 through 2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. |
Regulatory Assets and Liabili_8
Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jan. 31, 2022USD ($) | Jun. 30, 2022USD ($) | Dec. 31, 2021CAD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2014 | |
Public Utilities, General Disclosures [Line Items] | ||||||
Income tax expense (recovery) | $ 6 | $ (341) | ||||
Other Electric Utilities | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Income tax expense (recovery) | $ (1) | $ 8 | ||||
Barbados Light and Power Company Limited | Other Electric Utilities | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 10.00% | 10.00% | ||||
Income tax expense (recovery) | $ (10) | |||||
Deferred Tax Liabilities, Regulatory Assets and Liabilities | $ 7 | |||||
Cost sharing ratio | 50.00% | |||||
Barbados Light and Power Company Limited | Other Electric Utilities | Operating | Dispatch License | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Recovery Period | 5 years | |||||
Barbados Light and Power Company Limited | Range, Minimum | Operating | Transmission, Distribution & Supply License and a Generation License | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Recovery Period | 25 years | |||||
Barbados Light and Power Company Limited | Range, Maximum | Operating | Transmission, Distribution & Supply License and a Generation License | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Recovery Period | 30 years | |||||
Barbados Light and Power Company Limited | Fair Trading Commission | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 12.50% | |||||
Allowed equity capital structure | 65.00% | |||||
Barbados Light and Power Company Limited | Fair Trading Commission | Operating | Scenario Plan | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 23 | |||||
GBPC | GBPA | Other Electric Utilities | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 8.37% | 8.34% | ||||
GBPC | GBPA | Other Electric Utilities | Operating | Subsequent Event [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 3.5 | |||||
GBPC | GBPA | Other Electric Utilities | Operating | Scenario Plan | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 12.84% | |||||
Domlec | Independent Regulatory Commission, Dominica | Other Electric Utilities | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 15.00% | 15.00% | ||||
Domlec | Independent Regulatory Commission, Dominica | Other Electric Utilities | Operating | Transmission, Distribution & Supply License and a Generation License | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Finite-Lived Intangible Asset, Useful Life | 25 years |
Regulatory Assets and Liabili_9
Regulatory Assets and Liabilities - Gas Utilities and Infrastructure (Narrative) (Details) $ in Millions | Dec. 13, 2021USD ($) | Dec. 16, 2020USD ($) | Feb. 28, 2021USD ($) | Jan. 31, 2021USD ($) | Dec. 31, 2021USD ($)km | Dec. 31, 2020 |
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Length Of Pipeline | km | 145 | |||||
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Length Of Pipeline | km | 145 | |||||
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life | 25 years | |||||
NMGC | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Incremental gas cost | $ 108 | |||||
NMGC | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 9.375% | 9.10% | ||||
Allowed equity capital structure | 52.00% | 52.00% | ||||
NMGC | New Mexico Public Regulatory | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Incremental gas cost | $ 108 | |||||
Recovery period of approved costs | 30 months | |||||
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 5 | |||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 41 | |||||
PGS | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 10.75% | |||||
Allowed equity capital structure | 54.70% | 54.70% | ||||
Length Of Pipeline, percentage | 5.00% | |||||
Length Of Pipeline | km | 800 | |||||
Replacement program | $ 80 | |||||
Regulatory Asset Amortization Period | 10 years | |||||
Public Utilities, Disclosure of Rate Matters | On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. | |||||
PGS | Gas Utilities and Infrastructure | Operating | Scenario Plan | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease) | $ 34 | |||||
Phase-in Plan, Amount of Capitalized Costs Recovered | 34 | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 58 | |||||
PGS | Gas Utilities and Infrastructure | Operating | Cast Iron/Bare Steel Pipe Replacement | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Length Of Pipeline | km | 880 | |||||
PGS | Gas Utilities and Infrastructure | Operating | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Phase-in Plan, Amount of Capitalized Costs Recovered | $ 24 | |||||
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 8.90% | 9.25% | ||||
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | Scenario Plan | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 8.90% | |||||
Allowed equity capital structure | 54.70% | |||||
PGS | Range, Maximum | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 11.00% | 11.75% | ||||
PGS | Mid Point | Gas Utilities and Infrastructure | Operating | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Approved regulated return on equity | 9.90% |
Investments Subject to Signif_3
Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2015 | |
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 1,382 | $ 1,346 | |
Income (loss) from equity investments and subsidiaries | 143 | 149 | |
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Other long-term liabilities | 868 | 781 | |
Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 1,382 | 1,346 | |
Income (loss) from equity investments and subsidiaries | 143 | 149 | |
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 8 | ||
LIL | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 682 | 629 | |
Income (loss) from equity investments and subsidiaries | $ 54 | 49 | |
Percentage of Ownership | 37.40% | ||
LIL | Equity Method Investee | Class B units | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 100.00% | ||
LIL | Equity Method Investee | Total Units Issued [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 24.90% | ||
NSPML | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 533 | 547 | |
Income (loss) from equity investments and subsidiaries | $ 49 | 47 | |
Percentage of Ownership | 100.00% | ||
M&NP | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 123 | 129 | |
Income (loss) from equity investments and subsidiaries | $ 20 | 20 | |
Percentage of Ownership | 12.90% | ||
Lucelec | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 44 | 41 | |
Income (loss) from equity investments and subsidiaries | $ 4 | 4 | |
Percentage of Ownership | 19.50% | ||
Bear Swamp | |||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Other long-term liabilities | $ 104 | 118 | $ 179 |
Bear Swamp | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 0 | 0 | |
Income (loss) from equity investments and subsidiaries | $ 16 | $ 29 | |
Percentage of Ownership | 50.00% | ||
Maritime Link And LIL | Plan, subject to approval | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 49.00% |
Investments Subject to Signif_4
Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Balance Sheets | |||
Current assets | $ 3,136 | $ 2,178 | |
Property, plant and equipment | 20,353 | 19,535 | |
Regulatory assets | 2,313 | 1,419 | |
Non-current assets | 10,755 | 9,521 | |
Total assets | 34,244 | 31,234 | |
Current liabilities | 4,878 | 4,875 | |
Non-current liabilities | 19,216 | 17,121 | |
Equity | 10,150 | 9,238 | $ 8,601 |
Total liabilities and equity | 34,244 | 31,234 | |
Variable Interest Entity, Not Primary Beneficiary | NSPML | |||
Balance Sheets | |||
Current assets | 25 | 57 | |
Property, plant and equipment | 1,587 | 1,629 | |
Regulatory assets | 247 | 210 | |
Non-current assets | 31 | 32 | |
Total assets | 1,890 | 1,928 | |
Current liabilities | 50 | 56 | |
Long-term debt | 1,189 | 1,228 | |
Non-current liabilities | 118 | 97 | |
Equity | 533 | 547 | |
Total liabilities and equity | $ 1,890 | $ 1,928 |
Other Income, Net (Components o
Other Income, Net (Components of other income (expenses), net) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
9. Other Income (Expenses), Net | ||
Allowance for equity funds used during construction | $ 61 | $ 45 |
Gain on sale of Emera Maine, net of transaction costs | 0 | 585 |
TECO Guatemala Holdings award | 0 | 49 |
Other | 32 | 29 |
Other income (expenses), net | $ 93 | $ 708 |
Income Taxes (Reconiliation of
Income Taxes (Reconiliation of Income tax provision) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Income before provision for income taxes | $ 555 | $ 1,325 |
Statutory income tax rate | 29.00% | 29.50% |
Income taxes, at statutory income tax rates | $ 161 | $ 391 |
Additional impact from the sale of Emera Maine | 0 | 102 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (62) | (48) |
Foreign tax rate variance | (42) | (45) |
Amortization of deferred income tax regulatory liabilities | (33) | (44) |
Tax effect of equity earnings | (16) | (15) |
Tax credits | (13) | (12) |
Revaluation of deferred income taxes due to change in Nova Scotia tax rate | 0 | 12 |
Other | (1) | 0 |
Income tax (recovery) expense | $ (6) | $ 341 |
Effective income tax rate | (1.00%) | 0.26% |
Effect of Tax Cuts and Jobs Act [Abstract] | ||
Reduction to net deferred income tax liabilities | $ (52) | |
Income Tax Uncertainties [Abstract] | ||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 145 | |
Minimum [Member] | ||
Statutory income tax rate | 29.50% | |
Maximum [Member] | ||
Statutory income tax rate | 31.00% |
Income Taxes (Composition of ta
Income Taxes (Composition of taxes on income from continuing operations) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | $ (37) | $ 381 |
Income tax expense (recovery) | (6) | 341 |
Supplemental Tax Information [Abstract] | ||
Income (loss) before provision for income taxes | 555 | 1,325 |
Canada | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 20 | 18 |
Deferred income taxes | (33) | 20 |
Operating loss carry forwards | (64) | (46) |
Supplemental Tax Information [Abstract] | ||
Income (loss) before provision for income taxes | 244 | 176 |
United States | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 11 | (58) |
Deferred income taxes | 118 | 426 |
Investment tax credits | (11) | (10) |
Operating loss carry forwards | (49) | 0 |
Supplemental Tax Information [Abstract] | ||
Income (loss) before provision for income taxes | 289 | 1,142 |
Other | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | 2 | (9) |
Supplemental Tax Information [Abstract] | ||
Income (loss) before provision for income taxes | $ 22 | $ 7 |
Income Taxes (Deferred income t
Income Taxes (Deferred income tax assets and liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred income tax assets: | ||
Tax loss carryforwards | $ 873 | $ 724 |
Tax credit carryforwards | 375 | 319 |
Regulatory liabilities - cost of removal | 170 | 184 |
Derivative instruments | 188 | 108 |
Other | 434 | 375 |
Total deferred income tax assets before valuation allowance | 2,040 | 1,710 |
Valuation allowance | (256) | (202) |
Total deferred income tax assets after valuation allowance | 1,784 | 1,508 |
Deferred income tax (liabilities): | ||
Property, plant and equipment | (2,622) | (2,450) |
Derivative instruments | (197) | (93) |
Other | (538) | (385) |
Total deferred income tax liabilities | (3,357) | (2,928) |
Consolidated Balance Sheets presentation: | ||
Long-term deferred income tax assets | 295 | 209 |
Long-term deferred income tax liabilities | (1,868) | (1,629) |
Net deferred income tax liabilities | $ (1,573) | $ (1,420) |
Income Taxes (Net operating los
Income Taxes (Net operating loss, capital loss and tax credit carryforwards and their expiration periods) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021CAD ($) | |
Canada | Capital loss | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 75 |
Unrecognized Amounts | (75) |
Net Tax Credit Carryforwards | $ 0 |
Expiration period | Indefinite |
Canada | NOL | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 1,776 |
Unrecognized Amounts | (791) |
Net Tax Credit Carryforwards | $ 985 |
Expiration period | 2026 - 2041 |
United States | NOL | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 1,521 |
Unrecognized Amounts | 0 |
Net Tax Credit Carryforwards | $ 1,521 |
Expiration period | 2032 - Indefinite |
United States | Tax credit | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 375 |
Unrecognized Amounts | 0 |
Net Tax Credit Carryforwards | $ 375 |
Expiration period | 2025 - 2041 |
State | NOL | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 817 |
Unrecognized Amounts | 0 |
Net Tax Credit Carryforwards | $ 817 |
Expiration period | 2032 - Indefinite |
Other | NOL | |
Tax Credit Carryforward [Line Items] | |
Gross Tax Carryforwards | $ 52 |
Unrecognized Amounts | (38) |
Net Tax Credit Carryforwards | $ 14 |
Expiration period | 2022 - 2028 |
Income Taxes (Change in unrecog
Income Taxes (Change in unrecognized tax benefits) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning, January 1 | $ 30 | $ 29 |
Increases due to tax positions related to current year | 4 | 1 |
Increases due to tax positions related to a prior year | 1 | 2 |
Decreases due to tax positions related to a prior year | (1) | (2) |
Decreases due to settlement with tax authorities | (6) | 0 |
Balance, December 31 | $ 28 | $ 30 |
Income Taxes (Unrecognized tax
Income Taxes (Unrecognized tax benefits) (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Temporary Differences/Potential change | $ 2,900,000,000 | $ 2,700,000 |
Deferred Tax Assets, Allowance | 256,000,000 | 202,000,000 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract] | ||
Amount that could affect effective tax rate | 28,000,000 | 30,000,000 |
Accrued interest | 6,000,000 | 6,000,000 |
Income Tax Examination, Interest Expense | $ 1,000,000 | |
Accrued penalties | 0 | |
Nova Scotia Power Inc. | ||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Net amount in dispute | 62,000,000 | |
Prepaid amount in dispute | $ 23,000,000 |
Common Stock (Common Stock Roll
Common Stock (Common Stock Rollfoward) (Details) - CAD ($) shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Beginning Balance | $ 6,705 | |
Issuance of common stock | 284 | $ 251 |
Options exercised under senior management share option plan | 14 | 19 |
Ending Balance | $ 7,242 | $ 6,705 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Beginning Balance | 251,430 | 242,480 |
Issuance of common stock | 4,990 | 4,540 |
Issued under Purchase Plans at market rate | 4,320 | 3,990 |
Discount on shares purchased under Dividend Reinvestment Plan | 0 | 0 |
Options exercised under senior management share option plan | 330 | 420 |
Employee Share Purchase Plan | 0 | 0 |
Ending Balance | 261,070 | 251,430 |
Common Stock | ||
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Beginning Balance | $ 6,705 | $ 6,216 |
Issuance of common stock | 284 | 251 |
Issued under Purchase Plans at market rate | 239 | 219 |
Discount on shares purchased under Dividend Reinvestment Plan Value | (4) | (4) |
Options exercised under senior management share option plan | 14 | 20 |
Employee Share Purchase Plan | 4 | 3 |
Ending Balance | $ 7,242 | $ 6,705 |
Common Stock (Narrative) (Detai
Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Debt Instrument [Line Items] | ||
Issuance of common stock | 4,990,000 | 4,540,000 |
Gross proceeds from Issuance of Common Stock | $ 317 | $ 285 |
ATM Program | ||
Debt Instrument [Line Items] | ||
Stock Repurchase Program, Authorized Amount | 600 | |
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $ 457 | |
ATM Program | Common Stock | ||
Debt Instrument [Line Items] | ||
Issuance of common stock | 4,987,123 | |
Shares, Issued | 4,544,025 | |
Gross proceeds from Issuance of Common Stock | $ 287 | $ 255 |
Net proceeds from issuance of common stock | $ 284 | $ 251 |
Average price per share, issued | $ 57.63 | |
ATM Program | Average | Common Stock | ||
Debt Instrument [Line Items] | ||
Shares Issued, Price Per Share | $ 56.04 | |
Employee Stock Option Plan | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 6,200,000 | 3,500,000 |
Share Unit Plans | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 3,100,000 | 3,500,000 |
Dividend Reinvestment | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 14,200,000 | 5,100,000 |
Earnings Per Share (Computation
Earnings Per Share (Computation of basic and diluted earnings per share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Numerator | ||
Net income attributable to common shareholders | $ 510.5 | $ 937.6 |
Diluted numerator | $ 510.5 | $ 937.6 |
Denominator | ||
Weighted average shares of common stock outstanding | 255.9 | 246.5 |
Weighted average deferred share units outstanding | 1.3 | 1.3 |
Weighted average shares of common stock outstanding - basic | 257.2 | 247.8 |
Stock-based compensation | 0.4 | 0.4 |
Weighted average shares of common stock outstanding- diluted | 257.6 | 248.2 |
Earnings per common share | ||
Basic | $ 1.98 | $ 3.78 |
Diluted | $ 1.98 | $ 3.78 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | $ 9,238 | $ 8,601 |
Net current period other comprehensive income (loss) | 104 | (174) |
Ending Balance | 10,150 | 9,238 |
Accumulated Other Comprehensive Income (Loss) | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (79) | 95 |
Other comprehensive income (loss) before reclassifications | (19) | (175) |
Amounts reclassified from accumulated other comprehensive income loss | 123 | 1 |
Net current period other comprehensive income (loss) | 104 | (174) |
Ending Balance | 25 | (79) |
Unrealized (loss) gain on translation of self-sustaining foreign operations | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 52 | 253 |
Other comprehensive income (loss) before reclassifications | (42) | (201) |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | (42) | (201) |
Ending Balance | 10 | 52 |
Net change in net investment hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 30 | 4 |
Other comprehensive income (loss) before reclassifications | 5 | 26 |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | 5 | 26 |
Ending Balance | 35 | 30 |
(Losses) gains on derivatives recognized as cash flow hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 1 | (1) |
Other comprehensive income (loss) before reclassifications | 18 | 0 |
Amounts reclassified from accumulated other comprehensive income loss | (1) | 2 |
Net current period other comprehensive income (loss) | 17 | 2 |
Ending Balance | 18 | 1 |
Net change on available-for-sale investments | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (1) | (1) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | 0 | 0 |
Ending Balance | (1) | (1) |
Net change in unrecognized pension and post-retirement benefit costs | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (161) | (160) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Amounts reclassified from accumulated other comprehensive income loss | 124 | (1) |
Net current period other comprehensive income (loss) | 124 | (1) |
Ending Balance | $ (37) | $ (161) |
Accumulated Other Comprehensi_4
Accumulated Other Comprehensive Income (Loss) (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Total operating revenues | $ 5,765 | $ 5,506 |
Interest expense, net | 611 | 679 |
Other income net (note 9) | 93 | 708 |
Income tax expense (recovery) | (6) | 341 |
Net income | 561 | 984 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Net income | 123 | 1 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Net income | (1) | 2 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | Foreign exchange forwards | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Total operating revenues | 0 | 2 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | Interest rate hedge | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Interest expense, net | (1) | 0 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in unrecognized pension and post-retirement benefit costs | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Total before tax | 126 | (2) |
Income tax expense (recovery) | (2) | 1 |
Net income | 124 | (1) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial losses (gains) | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Other income net (note 9) | 24 | 15 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Past service costs (gains) | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Other income net (note 9) | 0 | (1) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amounts reclassified into obligations | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Pension and post-retirement benefits | $ 102 | $ (16) |
Inventory (Details)
Inventory (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
14. Inventory | ||
Fuel | $ 255 | $ 199 |
Raw Materials | 283 | 254 |
Inventory Total | $ 538 | $ 453 |
Derivatives Instruments (Deriva
Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
HFT derivatives | ||
Derivative Assets | $ 241 | $ 152 |
Derivative Liabilities | 850 | 359 |
Other derivatives | ||
Other, Derivative Assets | 11 | 15 |
Other, Derivative Liabilities | 0 | 1 |
Derivative Assets | ||
Total gross current derivative assets | 493 | 184 |
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | (192) | (86) |
Derivative Asset, Total | 301 | 98 |
Derivative Liabilities | ||
Total gross current derivative liabilities | 874 | 424 |
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | (192) | (86) |
Derivative Liabilities, Total | 682 | 338 |
Equity derivatives | ||
Other derivatives | ||
Other, Derivative Assets | 11 | 0 |
Other, Derivative Liabilities | 0 | 1 |
Foreign exchange forwards | ||
Other derivatives | ||
Other, Derivative Assets | 0 | 15 |
Other, Derivative Liabilities | 0 | 0 |
Interest rate swaps | ||
Cash flow hedges | ||
Cash flow hedges, Derivative Assets | 0 | 1 |
Cash flow hedges, Derivative Liabilities | 0 | 0 |
Power swaps and physical contracts | ||
HFT derivatives | ||
Derivative Assets | 33 | 13 |
Derivative Liabilities | 32 | 13 |
Natural gas swaps, futures, forwards, physical contracts and related transportation | ||
HFT derivatives | ||
Derivative Assets | 208 | 139 |
Derivative Liabilities | 818 | 346 |
Regulatory deferral | ||
HFT derivatives | ||
Derivative Assets | 241 | 16 |
Derivative Liabilities | 24 | 64 |
Derivative Assets | ||
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | (4) | (2) |
Derivative Liabilities | ||
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | (4) | (2) |
Regulatory deferral | Commodity swaps and forwards | Power | ||
HFT derivatives | ||
Derivative Assets | 83 | 10 |
Derivative Liabilities | 8 | 34 |
Regulatory deferral | Commodity swaps and forwards | Coal | ||
HFT derivatives | ||
Derivative Assets | 22 | 1 |
Derivative Liabilities | 1 | 6 |
Regulatory deferral | Commodity swaps and forwards | Natural gas | ||
HFT derivatives | ||
Derivative Assets | 20 | 4 |
Derivative Liabilities | 7 | 2 |
Regulatory deferral | Commodity swaps and forwards | Heavy fuel oil purchases | ||
HFT derivatives | ||
Derivative Assets | 21 | 1 |
Derivative Liabilities | 0 | 5 |
Regulatory deferral | Foreign exchange forwards | ||
HFT derivatives | ||
Derivative Assets | 7 | 0 |
Derivative Liabilities | 8 | 17 |
Regulatory deferral | Physical natural gas purchases and sales [Member] | ||
HFT derivatives | ||
Derivative Assets | 88 | 0 |
Derivative Liabilities | 0 | 0 |
HFT derivatives | ||
Derivative Assets | ||
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | (188) | (84) |
Derivative Liabilities | ||
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | $ (188) | $ (84) |
Derivatives Instruments (Master
Derivatives Instruments (Master Netting Agreements) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Derivatives, Fair Value [Line Items] | ||
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | $ 192 | $ 86 |
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | 192 | 86 |
Regulatory deferral | ||
Derivatives, Fair Value [Line Items] | ||
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | 4 | 2 |
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | 4 | 2 |
HFT derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets | 188 | 84 |
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities | $ 188 | $ 84 |
Derivatives Instruments (Deri_2
Derivatives Instruments (Derivative Cash Flow Hedges Recorded in Income and AOCI and Notional Volumes of Outstanding Derivatives Designated as Cash Flow Hedges) (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2021CAD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021CAD ($) | May 26, 2021USD ($) | |
Foreign exchange forwards | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | $ 3 | $ 13 | |||
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ 52,000,000 | ||||
Cash flow hedges | |||||
Cash Flow Hedges | |||||
Unrealized losses currently in AOCI to be reclassified into net income within the next twelve months | 2 | ||||
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ 0 | ||||
Cash flow hedges | Interest rate swaps | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | 1 | ||||
Total unrealized gain (loss) in AOCI - effective portion, net of tax | $ 18 | ||||
Cash flow hedges | Interest rate swaps | Regulated | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | $ 0 | ||||
Cash flow hedges | Interest rate swaps | Power | Non-Regulated | |||||
Cash Flow Hedges | |||||
Total unrealized gain (loss) in AOCI - effective portion, net of tax | $ 1 | ||||
Cash flow hedges | Foreign exchange forwards | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | (2) | ||||
Total unrealized gain (loss) in AOCI - effective portion, net of tax | 1 | ||||
Cash flow hedges | Foreign exchange forwards | Non-Regulated | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | 0 | ||||
Cash flow hedges | Foreign exchange forwards | Regulated | |||||
Cash Flow Hedges | |||||
Total gains (losses) in net income | $ (2) | ||||
Cash flow hedges | Treasury Lock [Member] | |||||
Cash Flow Hedges | |||||
Total unrealized gain (loss) in AOCI - effective portion, net of tax | $ 18,000,000 | ||||
Derivative gain loss amortization period | 10 years |
Derivatives Instruments (Change
Derivatives Instruments (Changes in Realized and Unrealized Gains (Losses) with Respect to Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | $ (404) | $ 36 |
Foreign exchange forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 3 | 13 |
Regulatory deferral | Natural gas | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | 88 | 0 |
Regulatory deferral | Natural gas | Fuel for generation and purchased power | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Natural gas | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 0 | 0 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | |
Regulatory deferral | Natural gas | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 88 | 0 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Natural gas | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Commodity swaps and forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | 161 | 15 |
Regulatory deferral | Commodity swaps and forwards | Fuel for generation and purchased power | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 24 | |
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (7) | (36) |
Realized (gain) loss on derivatives receiving regulatory deferral | 2 | |
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 218 | 3 |
Realized (gain) loss on derivatives receiving regulatory deferral | (3) | 14 |
Regulatory deferral | Commodity swaps and forwards | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (8) | 8 |
Regulatory deferral | Commodity swaps and forwards | Regulated | Fuel for generation and purchased power | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (39) | |
Regulatory deferral | Foreign exchange forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | 16 | (13) |
Regulatory deferral | Foreign exchange forwards | Fuel for generation and purchased power | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (3) | |
Regulatory deferral | Foreign exchange forwards | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 9 | (11) |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | |
Regulatory deferral | Foreign exchange forwards | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (3) | 3 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Foreign exchange forwards | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 5 | $ (2) |
Regulatory deferral | Foreign exchange forwards | Regulated | Fuel for generation and purchased power | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | $ 5 |
Derivatives Instruments (Notion
Derivatives Instruments (Notional Volumes of Commodity Swaps and Forward Contracts Designated for Regulatory Deferral) (Details) - Regulatory deferral - Commodity swaps and forwards - Purchases MWh in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2021MWhMMBTU | |
Natural gas | 2022 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MMBTU | 17 |
Natural gas | 2023-2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MMBTU | 22 |
Power | 2022 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh | 1 |
Power | 2023-2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh | 2 |
Derivatives Instruments (Noti_2
Derivatives Instruments (Notional Volumes of Foreign Exchange Swaps and Forward Contracts Related to Commodity Contracts) (Details) - Foreign Exchange Swaps and Forward Contracts $ in Millions | Dec. 31, 2021USD ($) |
2022 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ 170 |
Weighted average rate | 0.013047 |
% of USD requirements | 0.65% |
2023-2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ 150 |
Weighted average rate | 0.012413 |
% of USD requirements | 0.29% |
Derivatives Instruments (Realiz
Derivatives Instruments (Realized and Unrealized Gains (Losses) with Respect to HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ (138) | $ 200 |
Operating revenues | Power | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | 4 | (1) |
Operating revenues | Natural gas | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | (142) | 205 |
Fuel for generation and purchased power | Power | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ 0 | $ (4) |
Derivatives Instruments (Noti_3
Derivatives Instruments (Notional Volumes of Outstanding HFT Derivatives) (Details) - HFT derivatives MWh in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2021MWhMMBTU | |
Power | Purchases | 2022 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 1 |
Power | Purchases | 2023-2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2023 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2022 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 2 |
Power | Sales | 2023-2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2023 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Natural gas | Purchases | 2022 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 308 |
Natural gas | Purchases | 2023-2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 91 |
Natural gas | Purchases | 2023 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 56 |
Natural gas | Purchases | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 26 |
Natural gas | Purchases | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 26 |
Natural gas | Sales | 2022 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 335 |
Natural gas | Sales | 2023-2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 103 |
Natural gas | Sales | 2023 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 30 |
Natural gas | Sales | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 2 |
Natural gas | Sales | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 2 |
Derivatives Instruments (Real_2
Derivatives Instruments (Realized and Unrealized Gains (Losses) with Respect to Other derivatives) (Details) shares in Millions, $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021CAD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2021USD ($)shares | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Equity derivative hedges, return of shares | shares | 2.8 | ||
Foreign exchange forwards | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) in net income | $ 3 | $ 13 | |
Combined notional amount | $ 52 | ||
Foreign exchange forwards | Operating, maintenance and general expense | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain on equity derivatives | 0 | 0 | |
Total gains (losses) in net income | 0 | 0 | |
Foreign exchange forwards | Other income (expense), net | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain on equity derivatives | (15) | 15 | |
Total gains (losses) in net income | 18 | (2) | |
Equity derivatives | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) in net income | 26 | (4) | |
Equity derivatives | Operating, maintenance and general expense | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain on equity derivatives | 11 | (1) | |
Total gains (losses) in net income | 15 | (3) | |
Equity derivatives | Other income (expense), net | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain on equity derivatives | 0 | 0 | |
Total gains (losses) in net income | $ 0 | $ 0 |
Derivatives Instruments (Credit
Derivatives Instruments (Credit Risk) (Narrative) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2021CAD ($)Days | Dec. 31, 2020CAD ($) | |
Credit Derivatives [Line Items] | ||
Concentration Risk, maximum exposure | $ 1,631 | $ 1,056 |
Total cash deposits/collateral on hand | 212 | 69 |
Receivables, net | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, maximum exposure | 1,330 | 958 |
Credit Concentration Risk | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, maximum exposure | 1,300 | 805 |
Total cash deposits/collateral on hand | 341 | 251 |
Credit Concentration Risk | Receivables, net | ||
Credit Derivatives [Line Items] | ||
Fair Value, Financial assets, considered to be past due | $ 93 | 101 |
Average number of days financial asset outstanding | Days | 57 | |
Credit Concentration Risk | Receivables, net | Financial Asset, Past Due [Member] | ||
Credit Derivatives [Line Items] | ||
Financial assets, considered to be past due | $ 114 | $ 123 |
Derivatives Instruments (Concen
Derivatives Instruments (Concentration Risk) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 1,631 | $ 1,056 |
Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 301 | 98 |
Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 1,300 | 805 |
Credit rating of A- or above | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 155 | 60 |
Credit rating of BBB- to BBB+ | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 22 | 13 |
Not rated | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 124 | 25 |
Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 1,330 | 958 |
Accounts Receivable [Member] | Other accounts receivable | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | 329 | 159 |
Accounts Receivable [Member] | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 305 | $ 170 |
Accounts Receivable [Member] | Credit Concentration Risk | Receivables, net | ||
Concentration Risk [Line Items] | ||
% of total exposure | 82.00% | 91.00% |
Accounts Receivable [Member] | Credit Concentration Risk | Other accounts receivable | ||
Concentration Risk [Line Items] | ||
% of total exposure | 20.00% | 15.00% |
Accounts Receivable [Member] | Credit Concentration Risk | Trading group | ||
Concentration Risk [Line Items] | ||
% of total exposure | 19.00% | 16.00% |
Accounts Receivable [Member] | Credit rating of A- or above | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 66 | $ 54 |
Accounts Receivable [Member] | Credit rating of A- or above | Credit Concentration Risk | Trading group | ||
Concentration Risk [Line Items] | ||
% of total exposure | 4.00% | 5.00% |
Accounts Receivable [Member] | Credit rating of BBB- to BBB+ | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 107 | $ 41 |
Accounts Receivable [Member] | Credit rating of BBB- to BBB+ | Credit Concentration Risk | Trading group | ||
Concentration Risk [Line Items] | ||
% of total exposure | 7.00% | 4.00% |
Accounts Receivable [Member] | Not rated | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 132 | $ 75 |
Accounts Receivable [Member] | Not rated | Credit Concentration Risk | Trading group | ||
Concentration Risk [Line Items] | ||
% of total exposure | 8.00% | 7.00% |
Derivative Instruments [Member] | Credit Concentration Risk | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
% of total exposure | 18.00% | 9.00% |
Derivative Instruments [Member] | Credit rating of A- or above | Credit Concentration Risk | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
% of total exposure | 9.00% | 6.00% |
Derivative Instruments [Member] | Credit rating of BBB- to BBB+ | Credit Concentration Risk | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
% of total exposure | 1.00% | 1.00% |
Derivative Instruments [Member] | Not rated | Credit Concentration Risk | Derivative Instruments (current and long-term) | ||
Concentration Risk [Line Items] | ||
% of total exposure | 8.00% | 2.00% |
Accounts Receivable and Derivatives [Member] | Credit Concentration Risk | Receivables, net | ||
Concentration Risk [Line Items] | ||
% of total exposure | 100.00% | 100.00% |
Regulated utilities | Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 696 | $ 629 |
Regulated utilities | Accounts Receivable [Member] | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
% of total exposure | 43.00% | 60.00% |
Regulated utilities | Accounts Receivable [Member] | Residential | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 384 | $ 341 |
Regulated utilities | Accounts Receivable [Member] | Residential | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
% of total exposure | 24.00% | 32.00% |
Regulated utilities | Accounts Receivable [Member] | Commercial | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 167 | $ 143 |
Regulated utilities | Accounts Receivable [Member] | Commercial | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
% of total exposure | 10.00% | 14.00% |
Regulated utilities | Accounts Receivable [Member] | Industrial | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 54 | $ 49 |
Regulated utilities | Accounts Receivable [Member] | Industrial | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
% of total exposure | 3.00% | 5.00% |
Regulated utilities | Accounts Receivable [Member] | Other | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 91 | $ 96 |
Regulated utilities | Accounts Receivable [Member] | Other | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
% of total exposure | 6.00% | 9.00% |
Derivatives Instruments (Cash C
Derivatives Instruments (Cash Collateral) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
15. Derivative Instruments | ||
Cash collateral provided to others | $ 212 | $ 69 |
Cash collateral received from others | 100 | 6 |
Total fair value of these derivatives, in a liability position | $ 682 | $ 338 |
Fair Value Measurements (Deriva
Fair Value Measurements (Derivatives) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Assets | ||
Total assets | $ 301 | $ 98 |
Liabilities | ||
Total liabilities | 682 | 338 |
Level 3 | Regulatory deferral | ||
Assets | ||
Total assets | 88 | |
Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 301 | 98 |
Liabilities | ||
Total liabilities | 682 | 338 |
Net assets (liabilities) | (381) | (240) |
Fair Value, Measurements, Recurring | Cash flow hedges | ||
Assets | ||
Total assets | 1 | |
Fair Value, Measurements, Recurring | Interest rate hedges | Cash flow hedges | ||
Assets | ||
Total assets | 1 | |
Fair Value, Measurements, Recurring | Equity derivatives | ||
Liabilities | ||
Total liabilities | 1 | |
Fair Value, Measurements, Recurring | Other | ||
Liabilities | ||
Total liabilities | 1 | |
Fair Value, Measurements, Recurring | Regulatory deferral | ||
Assets | ||
Total assets | 237 | 14 |
Liabilities | ||
Total liabilities | 20 | 62 |
Fair Value, Measurements, Recurring | Regulatory deferral | Coal | ||
Assets | ||
Total assets | 22 | |
Liabilities | ||
Total liabilities | 4 | |
Fair Value, Measurements, Recurring | Regulatory deferral | Power | ||
Assets | ||
Total assets | 83 | 9 |
Liabilities | ||
Total liabilities | 7 | 33 |
Fair Value, Measurements, Recurring | Regulatory deferral | Heavy fuel oil purchases | ||
Assets | ||
Total assets | 21 | 2 |
Liabilities | ||
Total liabilities | 6 | |
Fair Value, Measurements, Recurring | Regulatory deferral | Natural gas | ||
Assets | ||
Total assets | 16 | 3 |
Liabilities | ||
Total liabilities | 5 | 2 |
Fair Value, Measurements, Recurring | Regulatory deferral | Foreign exchange forwards | ||
Assets | ||
Total assets | 7 | |
Liabilities | ||
Total liabilities | 8 | 17 |
Fair Value, Measurements, Recurring | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 88 | |
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument | ||
Assets | ||
Total assets | 15 | |
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument | Foreign exchange forwards | ||
Assets | ||
Total assets | 15 | |
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument | Equity derivatives | ||
Assets | ||
Total assets | 11 | |
Fair Value, Measurements, Recurring | HFT derivatives | ||
Assets | ||
Total assets | 53 | 68 |
Liabilities | ||
Total liabilities | 662 | 275 |
Fair Value, Measurements, Recurring | HFT derivatives | Power | ||
Assets | ||
Total assets | 13 | 7 |
Liabilities | ||
Total liabilities | 12 | 7 |
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas | ||
Assets | ||
Total assets | 40 | 61 |
Liabilities | ||
Total liabilities | 650 | 268 |
Fair Value, Measurements, Recurring | Level 1 | ||
Assets | ||
Total assets | 115 | 16 |
Liabilities | ||
Total liabilities | 24 | 42 |
Net assets (liabilities) | 91 | (26) |
Fair Value, Measurements, Recurring | Level 1 | Cash flow hedges | ||
Assets | ||
Total assets | 1 | |
Fair Value, Measurements, Recurring | Level 1 | Interest rate hedges | Cash flow hedges | ||
Assets | ||
Total assets | 1 | |
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives | ||
Liabilities | ||
Total liabilities | 1 | |
Fair Value, Measurements, Recurring | Level 1 | Other | ||
Liabilities | ||
Total liabilities | 1 | |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | ||
Assets | ||
Total assets | 101 | 11 |
Liabilities | ||
Total liabilities | 7 | 36 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Coal | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Power | ||
Assets | ||
Total assets | 83 | 9 |
Liabilities | ||
Total liabilities | 7 | 33 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Heavy fuel oil purchases | ||
Assets | ||
Total assets | 3 | 0 |
Liabilities | ||
Total liabilities | 3 | |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Natural gas | ||
Assets | ||
Total assets | 15 | 2 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Foreign exchange forwards | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument | Foreign exchange forwards | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument | Equity derivatives | ||
Assets | ||
Total assets | 11 | |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | ||
Assets | ||
Total assets | 3 | 4 |
Liabilities | ||
Total liabilities | 17 | 5 |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power | ||
Assets | ||
Total assets | 4 | 3 |
Liabilities | ||
Total liabilities | 4 | 4 |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas | ||
Assets | ||
Total assets | (1) | 1 |
Liabilities | ||
Total liabilities | 13 | 1 |
Fair Value, Measurements, Recurring | Level 2 | ||
Assets | ||
Total assets | 82 | 68 |
Liabilities | ||
Total liabilities | 140 | 38 |
Net assets (liabilities) | (58) | 30 |
Fair Value, Measurements, Recurring | Level 2 | Cash flow hedges | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Interest rate hedges | Cash flow hedges | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives | ||
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Other | ||
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | ||
Assets | ||
Total assets | 48 | 3 |
Liabilities | ||
Total liabilities | 13 | 26 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Coal | ||
Assets | ||
Total assets | 22 | |
Liabilities | ||
Total liabilities | 4 | |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Power | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Heavy fuel oil purchases | ||
Assets | ||
Total assets | 18 | 2 |
Liabilities | ||
Total liabilities | 3 | |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Natural gas | ||
Assets | ||
Total assets | 1 | 1 |
Liabilities | ||
Total liabilities | 5 | 2 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Foreign exchange forwards | ||
Assets | ||
Total assets | 7 | |
Liabilities | ||
Total liabilities | 8 | 17 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument | ||
Assets | ||
Total assets | 15 | |
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument | Foreign exchange forwards | ||
Assets | ||
Total assets | 15 | |
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument | Equity derivatives | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | ||
Assets | ||
Total assets | 34 | 50 |
Liabilities | ||
Total liabilities | 127 | 12 |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power | ||
Assets | ||
Total assets | 5 | 2 |
Liabilities | ||
Total liabilities | 5 | 2 |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas | ||
Assets | ||
Total assets | 29 | 48 |
Liabilities | ||
Total liabilities | 122 | 10 |
Fair Value, Measurements, Recurring | Level 3 | ||
Assets | ||
Total assets | 104 | 14 |
Liabilities | ||
Total liabilities | 518 | 258 |
Net assets (liabilities) | (414) | (244) |
Fair Value, Measurements, Recurring | Level 3 | Cash flow hedges | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Interest rate hedges | Cash flow hedges | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Equity derivatives | ||
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Other | ||
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | ||
Assets | ||
Total assets | 88 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Coal | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Power | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Heavy fuel oil purchases | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Natural gas | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Foreign exchange forwards | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 88 | |
Fair Value, Measurements, Recurring | Level 3 | Not Designated as Hedging Instrument | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Not Designated as Hedging Instrument | Foreign exchange forwards | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Not Designated as Hedging Instrument | Equity derivatives | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | ||
Assets | ||
Total assets | 16 | 14 |
Liabilities | ||
Total liabilities | 518 | 258 |
Net assets (liabilities) | (414) | (244) |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power | ||
Assets | ||
Total assets | 4 | 2 |
Liabilities | ||
Total liabilities | 3 | 1 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas | ||
Assets | ||
Total assets | 20 | 18 |
Liabilities | ||
Total liabilities | 458 | 226 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | ||
Assets | ||
Total assets | 1 | |
Liabilities | ||
Total liabilities | 1 | 1 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | Power | ||
Assets | ||
Total assets | 4 | 1 |
Liabilities | ||
Total liabilities | 2 | 1 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | Natural gas | ||
Assets | ||
Total assets | (8) | (6) |
Liabilities | ||
Total liabilities | 57 | 30 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas | ||
Assets | ||
Total assets | 12 | 12 |
Liabilities | ||
Total liabilities | $ 515 | $ 257 |
Fair Value Measurements (Fair v
Fair Value Measurements (Fair value of the Level 3 financial assets) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions | 12 Months Ended |
Dec. 31, 2021CAD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 14 |
Unrealized gains included in regulatory assets or liabilities | 88 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 2 |
Ending Balance | 104 |
Physical natural gas purchases and sales | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Unrealized gains included in regulatory assets or liabilities | 88 |
Ending Balance | 88 |
Power | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 2 |
Unrealized gains included in regulatory assets or liabilities | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 2 |
Ending Balance | 4 |
Natural gas | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 12 |
Unrealized gains included in regulatory assets or liabilities | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Ending Balance | $ 12 |
Fair Value Measurements (Fair_2
Fair Value Measurements (Fair value of the Level 3 financial Liabilities) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions | 12 Months Ended |
Dec. 31, 2021CAD ($) | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 258 |
Total realized and unrealized gains included in non-regulated operating revenues | 260 |
Ending Balance | 518 |
Power | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 1 |
Total realized and unrealized gains included in non-regulated operating revenues | 2 |
Ending Balance | 3 |
Natural gas | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 257 |
Total realized and unrealized gains included in non-regulated operating revenues | 258 |
Ending Balance | $ 515 |
Fair Value Measurements (Quanti
Fair Value Measurements (Quantitative Information Significant Unobservable Inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy) (Details) $ in Millions | Dec. 31, 2021CAD ($)$ / Unit | Dec. 31, 2020CAD ($)$ / Unit |
Assets | ||
Total assets | $ 301 | $ 98 |
Liabilities | ||
Total liabilities | 682 | 338 |
Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 301 | 98 |
Liabilities | ||
Total liabilities | 682 | 338 |
Net assets (liabilities) | (381) | (240) |
Regulatory deferral | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 237 | 14 |
Liabilities | ||
Total liabilities | 20 | 62 |
Regulatory deferral | Power | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 83 | 9 |
Liabilities | ||
Total liabilities | 7 | 33 |
Regulatory deferral | Natural gas | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 16 | 3 |
Liabilities | ||
Total liabilities | 5 | 2 |
Not Designated as Hedging Instrument | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 15 | |
HFT derivatives | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 53 | 68 |
Liabilities | ||
Total liabilities | 662 | 275 |
HFT derivatives | Power | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 13 | 7 |
Liabilities | ||
Total liabilities | 12 | 7 |
Level 3 | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 104 | 14 |
Liabilities | ||
Total liabilities | 518 | 258 |
Net assets (liabilities) | (414) | (244) |
Level 3 | Regulatory deferral | ||
Assets | ||
Total assets | 88 | |
Level 3 | Regulatory deferral | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 88 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Level 3 | Regulatory deferral | Power | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Level 3 | Regulatory deferral | Natural gas | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | $ 0 | 0 |
Level 3 | Regulatory deferral | Range, Minimum | Third-party pricing | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 4.51 | |
Level 3 | Regulatory deferral | Range, Minimum | Probability of default | ||
Assets | ||
Unobservable Input, Assets | 0.000252 | |
Level 3 | Regulatory deferral | Range, Minimum | Discount rate | ||
Assets | ||
Unobservable Input, Assets | 0.000001 | |
Level 3 | Regulatory deferral | Range, Maximum | Third-party pricing | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 26.09 | |
Level 3 | Regulatory deferral | Range, Maximum | Probability of default | ||
Assets | ||
Unobservable Input, Assets | 0.00044 | |
Level 3 | Regulatory deferral | Range, Maximum | Discount rate | ||
Assets | ||
Unobservable Input, Assets | 0.00016 | |
Level 3 | Regulatory deferral | Weighted average | Third-party pricing | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 9.74 | |
Level 3 | Regulatory deferral | Weighted average | Probability of default | ||
Assets | ||
Unobservable Input, Assets | 0.000331 | |
Level 3 | Regulatory deferral | Weighted average | Discount rate | ||
Assets | ||
Unobservable Input, Assets | 0.000048 | |
Level 3 | Not Designated as Hedging Instrument | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 0 | |
Level 3 | HFT derivatives | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | $ 16 | 14 |
Liabilities | ||
Total liabilities | 518 | 258 |
Net assets (liabilities) | (414) | (244) |
Level 3 | HFT derivatives | Power | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 4 | 2 |
Liabilities | ||
Total liabilities | 3 | 1 |
Level 3 | HFT derivatives | Natural gas | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 20 | 18 |
Liabilities | ||
Total liabilities | 458 | 226 |
Level 3 | HFT derivatives | Energy Related derivative | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 1 | |
Liabilities | ||
Total liabilities | 1 | 1 |
Level 3 | HFT derivatives | Energy Related derivative | Power | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 4 | 1 |
Liabilities | ||
Total liabilities | 2 | 1 |
Level 3 | HFT derivatives | Energy Related derivative | Natural gas | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | (8) | (6) |
Liabilities | ||
Total liabilities | $ 57 | $ 30 |
Level 3 | HFT derivatives | Range, Minimum | Third-party pricing | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 1.13 | |
Level 3 | HFT derivatives | Range, Minimum | Discount rate | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0001 | |
Level 3 | HFT derivatives | Range, Minimum | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0002 | |
Level 3 | HFT derivatives | Range, Minimum | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 25.7 | |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 37.8 | |
Level 3 | HFT derivatives | Range, Minimum | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0036 | |
Level 3 | HFT derivatives | Range, Minimum | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0006 | |
Liabilities | ||
Unobservable Input, Liabilities | 0.000001 | |
Level 3 | HFT derivatives | Range, Minimum | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 1 | |
Level 3 | HFT derivatives | Range, Minimum | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.000001 | |
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 2.18 | 1.66 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 1.9 | 1.44 |
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0001 | 0.0002 |
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0 | 0 |
Liabilities | ||
Unobservable Input, Liabilities | 0 | 0 |
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0001 | 0.0002 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 37.05 | 20.5 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 37.46 | 37.25 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0001 | 0.0002 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0 | 0.0001 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0001 | 0.0001 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 1 | 1 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0001 | 0.0036 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 2.83 | 1.82 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 2.83 | 1.54 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0001 | 0.0002 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0 | 0 |
Liabilities | ||
Unobservable Input, Liabilities | 0 | 0 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 0 | 0 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 0 | 0 |
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0001 | 0.0003 |
Level 3 | HFT derivatives | Range, Maximum | Third-party pricing | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 62.45 | |
Level 3 | HFT derivatives | Range, Maximum | Discount rate | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0073 | |
Level 3 | HFT derivatives | Range, Maximum | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0685 | |
Level 3 | HFT derivatives | Range, Maximum | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 36.05 | |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 145.8 | |
Level 3 | HFT derivatives | Range, Maximum | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0085 | |
Level 3 | HFT derivatives | Range, Maximum | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0041 | |
Liabilities | ||
Unobservable Input, Liabilities | 0.000186 | |
Level 3 | HFT derivatives | Range, Maximum | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 1 | |
Level 3 | HFT derivatives | Range, Maximum | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.000148 | |
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 20.42 | 6.22 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 20.42 | 6.57 |
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0738 | 0.0252 |
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.1198 | 0.1036 |
Liabilities | ||
Unobservable Input, Liabilities | 0.1459 | 0.0879 |
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0738 | 0.0252 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 213 | 62.45 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 126.75 | 62.45 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0252 | 0.0974 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0186 | 0.0073 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0186 | 0.0040 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 1 | 1 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.1116 | 0.0128 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 20.86 | 8.44 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 21.53 | 8.44 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0417 | 0.1258 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0173 | 0.0067 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0173 | 0.0067 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 0.44 | 1.33 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 1.11 | 1.33 |
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0049 | 0.1258 |
Level 3 | HFT derivatives | Weighted average | Third-party pricing | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 36.90 | |
Level 3 | HFT derivatives | Weighted average | Discount rate | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0034 | |
Level 3 | HFT derivatives | Weighted average | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0202 | |
Level 3 | HFT derivatives | Weighted average | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 29.53 | |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 111.15 | |
Level 3 | HFT derivatives | Weighted average | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.006 | |
Level 3 | HFT derivatives | Weighted average | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0028 | |
Liabilities | ||
Unobservable Input, Liabilities | 0.0031 | |
Level 3 | HFT derivatives | Weighted average | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 1 | |
Level 3 | HFT derivatives | Weighted average | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0012 | |
Level 3 | HFT derivatives | Weighted average | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 3.75 | 2.52 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 9.12 | 3.68 |
Level 3 | HFT derivatives | Weighted average | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0013 | 0.004 |
Level 3 | HFT derivatives | Weighted average | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0037 | 0.0075 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0154 | 0.0043 |
Level 3 | HFT derivatives | Weighted average | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0008 | 0.0010 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 93.60 | 31.14 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 95.02 | 55 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0045 | 0.0252 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0019 | 0.0025 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0021 | 0.0031 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 1 | 1 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0007 | 0.0083 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 10.85 | 4.66 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 12.03 | 4.69 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0046 | 0.0195 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | 0.0021 | 0.0013 |
Liabilities | ||
Unobservable Input, Liabilities | 0.0013 | 0.0016 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring | ||
Assets | ||
Unobservable Input, Assets | $ / Unit | 0.42 | 0.44 |
Liabilities | ||
Unobservable Input, Liabilities | $ / Unit | 0.28 | 0.87 |
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Unobservable Input, Liabilities | 0.0002 | 0.0010 |
Fair Value Measurements (Assets
Fair Value Measurements (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Fair Value Measurement [Domain] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | $ 16,775 | $ 16,487 |
Fair Value Measurement [Domain] | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 0 | 0 |
Fair Value Measurement [Domain] | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 16,308 | 16,020 |
Fair Value Measurement [Domain] | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 467 | 467 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 14,658 | 13,721 |
Financial assets and liabilities | $ 16,775 | $ 16,487 |
Fair Value Measurements (Hybrid
Fair Value Measurements (Hybrid Notes) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,700 | $ 1,800 |
Net investment in United States dollar denominated operations | ||
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | 1,200 | |
After-tax foreign currency gain (loss) | $ 5 | $ 26 |
Related Paty Transactions (Narr
Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
NSPML | Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 149 | $ 139 |
M&NP | Non-Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 19 | $ 18 |
Receivables And Other Current_3
Receivables And Other Current Assets (Summary of Receivables And Other Current Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
18. Receivables and Other Current Assets | ||
Customer accounts receivable - billed | $ 767 | $ 570 |
Customer accounts receivable - unbilled | 318 | 286 |
Allowance for credit losses | (21) | (22) |
Capitalized transportation capacity | 316 | 200 |
Income taxes receivable | 8 | 11 |
Prepaid expenses | 65 | 50 |
Other current assets | 280 | 138 |
Receivables and other current assets | $ 1,733 | $ 1,233 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Lessee, Operating Leases | ||
Lessee, Operating Lease, Description | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 64 years, some of which include options to extend the leases for up to 64 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised. | |
Lease, Expense | $ 150 | $ 160 |
Variable costs for power generation facility finance leases | $ 142 | $ 149 |
Lessee, Operating Lease, Existence of Option to Extend [true false] | true | |
Lessee, Operating Lease, Option to Extend | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 64 years, some of which include options to extend the leases for up to 64 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised | |
Lessor, Direct finance and sales-type leases | ||
Lessor, Direct Financing Lease, Description | The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, compressed natural gas (“CNG”) stations and heat pumps. | |
Lessor, Sales-type Lease, Description | The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, compressed natural gas (“CNG”) stations and heat pumps. | |
Lessor, Sales-type Lease, Existence of Lessee Option to Purchase Underlying Asset [true false] | true | |
Lessor, Sales-type Lease, Lessee Option to Purchase Underlying Asset | Customers have the option to purchase CNG station assets at any time after 2021 by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee. | |
Minimum | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Renewal Term | 1 year | |
Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Renewal Term | 64 years |
Leases (Operating Leases) (Deta
Leases (Operating Leases) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Assets and Liabilities, Lessee | ||
Right-of-use asset | $ 58 | $ 61 |
Lease liabilities, Current | 3 | 3 |
Lease liabilities, Long-term | 59 | 60 |
Total lease liabilities | 62 | 63 |
Cash paid for amounts included in the measurement of lease liabilities: | ||
Operating cash flows for operating leases | 7 | 7 |
Right-of-use assets obtained in exchange for lease obligations: Operating leases | $ 0 | $ 7 |
Weighted average remaining lease term (years) | 44 years | 43 years |
Weighted average discount rate - operating leases | 0.0398% | 0.0396% |
Leases (Future minimum lease pa
Leases (Future minimum lease payments under non-cancellable operating leases) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter | ||
2022 | $ 5 | |
2023 | 6 | |
2024 | 5 | |
2025 | 4 | |
2026 | 3 | |
Thereafter | 112 | |
Minimum lease payments, Total | 135 | |
Less imputed interest | (73) | |
Total | $ 62 | $ 63 |
Leases (Direct Finance and Sale
Leases (Direct Finance and Sales-type Leases) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Net investment in direct finance and sales-type leases | ||
Total minimum lease payments to be received | $ 947 | $ 1,018 |
Less: amounts representing estimated executory costs | (165) | (179) |
Minimum lease payments receivable | 782 | 839 |
Estimated residual value of leased property (unguaranteed) | 183 | 183 |
Less: unearned finance lease income | (443) | (487) |
Net investment in direct finance and sales-type leases | 522 | 535 |
Principal due within one year (included in "Receivables and other current assets") | 19 | 18 |
Net investment in sales-type leases - long-term (included in "Other long-term assets") | 41 | 42 |
Net Investment in direct finance leases - long-term | 462 | 475 |
Future minimum lease payments to be received for each of the next five years and in aggregate thereafter | ||
2022 | 78 | |
2023 | 77 | |
2024 | 79 | |
2025 | 80 | |
2026 | 78 | |
Thereafter | 555 | |
Total minimum lease payments to be received | 947 | 1,018 |
Less: executory costs | (165) | (179) |
Minimum lease payments receivable | $ 782 | $ 839 |
Property, plant and equipment_2
Property, plant and equipment (Regulated and Non-regulated Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Property, Plant and Equipment, Net | ||
Total cost | $ 26,868 | $ 25,891 |
Less: Accumulated depreciation | (8,739) | (8,714) |
Total cost less: Accumulated depreciation | 18,129 | 17,177 |
Construction work in progress | 2,224 | 2,358 |
Property, Plant and Equipment, Net | 20,353 | 19,535 |
Generation | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 11,173 | 11,474 |
Generation | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 3 years | |
Generation | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 131 years | |
Transmission | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 2,532 | 2,414 |
Transmission | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 11 years | |
Transmission | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 80 years | |
Distribution | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 6,305 | 5,997 |
Distribution | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 4 years | |
Distribution | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 80 years | |
Gas transmission and distribution | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 4,385 | 3,879 |
Gas transmission and distribution | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 7 years | |
Gas transmission and distribution | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 85 years | |
General plant and other | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 2,473 | $ 2,127 |
General plant and other | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 2 years | |
General plant and other | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 60 years |
Property, plant and equipment_3
Property, plant and equipment (Regulated and Non-regulated Assets) (Narrative) (Details) - Pipleline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions | 12 Months Ended | |
Dec. 31, 2021CAD ($)km | Dec. 31, 2020CAD ($) | |
Jointly Owned Pipleline lateral | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | |
Length of pipeline, in miles | km | 26 | |
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | $ 27 | $ 34 |
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | $ 1 |
Employee Benefit Plans (Changes
Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and the Funded Status) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined benefit pension plans | ||
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") | ||
Benefit Obligation, Beginning Balance | $ 2,759 | $ 2,822 |
Service cost | 43 | 46 |
Plan participant contributions | 6 | 7 |
Interest cost | 67 | 84 |
Benefits Paid | (160) | (135) |
Actuarial (gains) losses | (89) | 189 |
Settlement, curtailments | 0 | (229) |
Foreign currency translation adjustment | (2) | (25) |
Benefit Obligation, Ending Balance | 2,624 | 2,759 |
Change in plan assets | ||
Plan Assets, Beginning Balance | 2,605 | 2,593 |
Employer contributions | 42 | 41 |
Plan participant contributions | 6 | 7 |
Benefits paid | (160) | (135) |
Actual return on assets, net of expenses | 214 | 310 |
Settlements and curtailments | 0 | (191) |
Foreign currency translation adjustment | (5) | (20) |
Plan Assets, Ending Balance | 2,702 | 2,605 |
Funded Status | ||
Funded status, end of year | 78 | (154) |
Non-pension Benefit Plans | ||
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") | ||
Benefit Obligation, Beginning Balance | 339 | 353 |
Service cost | 5 | 5 |
Plan participant contributions | 4 | 5 |
Interest cost | 8 | 10 |
Benefits Paid | (27) | (27) |
Actuarial (gains) losses | (10) | 52 |
Settlement, curtailments | 0 | (52) |
Foreign currency translation adjustment | (1) | (7) |
Benefit Obligation, Ending Balance | 318 | 339 |
Change in plan assets | ||
Plan Assets, Beginning Balance | 52 | 56 |
Employer contributions | 21 | 21 |
Plan participant contributions | 4 | 5 |
Benefits paid | (27) | (27) |
Actual return on assets, net of expenses | 2 | 5 |
Settlements and curtailments | 0 | (7) |
Foreign currency translation adjustment | (1) | (1) |
Plan Assets, Ending Balance | 51 | 52 |
Funded Status | ||
Funded status, end of year | $ (267) | $ (287) |
Employee Benefit Plans (Plans w
Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Defined benefit pension plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | $ 140 | $ 2,736 |
Fair value of plan assets | 35 | 2,568 |
Funded Status | (105) | (168) |
Non-pension Benefit Plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | 290 | 308 |
Fair value of plan assets | 0 | 0 |
Funded Status | $ (290) | $ (308) |
Employee Benefit Plans (Accumul
Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO for the defined benefit pension plans | $ 2,507 | $ 2,639 |
Defined benefit pension plans | ||
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO | 133 | 1,519 |
Fair value of plan assets | 35 | 1,419 |
Funded Status | $ (98) | $ (100) |
Employee Benefit Plans (Amounts
Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Balance Sheet | ||
Other current liabilities | $ (27) | $ (23) |
Long-term liabilities | (370) | (453) |
Defined benefit pension plans | ||
Balance Sheet | ||
Other current liabilities | (7) | (4) |
Long-term liabilities | (100) | (163) |
Other long-term assets | 185 | 13 |
Amount included in deferred income tax | (8) | (4) |
AOCI, net of tax and regulatory assets | 230 | 443 |
Net amount recognized | 300 | 285 |
Non-pension Benefit Plans | ||
Balance Sheet | ||
Other current liabilities | (20) | (19) |
Long-term liabilities | (270) | (290) |
Other long-term assets | 23 | 20 |
Amount included in deferred income tax | 1 | (1) |
AOCI, net of tax and regulatory assets | 90 | 107 |
Net amount recognized | $ (176) | $ (183) |
Employee Benefit Plans (Change
Employee Benefit Plans (Change in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined benefit pension plans | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | $ 439 | |
Amortized in current period | 21 | $ 15 |
Ending Balance | 222 | 439 |
Defined benefit pension plans | Regulatory | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 279 | |
Amortized in current period | (24) | |
Current year addition to AOCI or regulatory assets | (61) | |
Change in foreign exchange rate | (2) | |
Ending Balance | 192 | 279 |
Defined benefit pension plans | Actuarial losses (gains) | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 160 | |
Amortized in current period | (21) | |
Current year addition to AOCI or regulatory assets | (109) | |
Change in foreign exchange rate | 0 | |
Ending Balance | 30 | 160 |
Non-pension Benefit Plans | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 106 | |
Amortized in current period | 3 | 0 |
Ending Balance | 91 | 106 |
Non-pension Benefit Plans | Regulatory | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 110 | |
Amortized in current period | (2) | |
Current year addition to AOCI or regulatory assets | (16) | |
Change in foreign exchange rate | (1) | |
Ending Balance | 91 | 110 |
Non-pension Benefit Plans | Actuarial losses (gains) | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | (4) | |
Amortized in current period | (3) | |
Current year addition to AOCI or regulatory assets | 7 | |
Change in foreign exchange rate | 0 | |
Ending Balance | $ 0 | $ (4) |
Employee Benefit Plans (Net amo
Employee Benefit Plans (Net amount in AOCI and regulatory assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Defined Benefit Plan Disclosure [Line Items] | ||
Regulatory assets | $ 2,566 | $ 1,584 |
Defined benefit pension plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses (gains) | 30 | 160 |
Regulatory assets | 192 | 279 |
Total AOCI and regulatory assets before deferred income taxes | 222 | 439 |
Amount included in deferred income tax | 8 | 4 |
Net amount in AOCI after tax adjustment | 230 | 443 |
Non-pension Benefit Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses (gains) | 0 | (4) |
Regulatory assets | 91 | 110 |
Total AOCI and regulatory assets before deferred income taxes | 91 | 106 |
Amount included in deferred income tax | (1) | 1 |
Net amount in AOCI after tax adjustment | $ 90 | $ 107 |
Employee Benefit Plans (Net Per
Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Expected return on plan assets | $ (2,151) | $ (2,476) |
Defined benefit pension plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 43 | 46 |
Interest cost | 67 | 84 |
Expected return on plan assets | (132) | (141) |
Current year amortization of: Actuarial losses | 21 | 15 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | (1) |
Regulatory assets (liability) | 24 | 25 |
Net Periodic Benefit Cost, Total | 23 | 28 |
Non-pension Benefit Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 5 | 5 |
Interest cost | 8 | 10 |
Expected return on plan assets | (1) | (1) |
Current year amortization of: Actuarial losses | 3 | 0 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | 0 |
Regulatory assets (liability) | 2 | 0 |
Net Periodic Benefit Cost, Total | $ 17 | $ 14 |
Employee Benefit Plans (Asset C
Employee Benefit Plans (Asset Class) (Details) - Defined benefit pension plans | Dec. 31, 2021 |
Short-term securities | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 0.00% |
Short-term securities | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 5.00% |
Fixed income | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 35.00% |
Fixed income | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 50.00% |
Fixed income | Non-Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 30.00% |
Fixed income | Non-Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 50.00% |
Equities: Canadian | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 12.00% |
Equities: Canadian | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 22.00% |
Equities: Non-Canadian | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 30.00% |
Equities: Non-Canadian | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 55.00% |
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 50.00% |
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 70.00% |
Employee Benefit Plans (Fair Va
Employee Benefit Plans (Fair Value of Investments) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 100.00% | ||
Defined benefit pension plans | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 2,702 | $ 2,605 | $ 2,593 |
Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 3.00% | ||
Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | (4.00%) | ||
Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 6.00% | ||
US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 15.00% | ||
Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 8.00% | 9.00% | |
Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 5.00% | 5.00% | |
Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 5.00% | ||
Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 0.00% | ||
Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 3.00% | ||
Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 0.00% | ||
Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 35.00% | 31.00% | |
Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Percentage | 28.00% | 27.00% | |
Total | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 2,702 | $ 2,605 | |
Percentage | 100.00% | ||
Total | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 60 | 68 | |
Percentage | 2.00% | ||
Total | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ (84) | (99) | |
Percentage | (3.00%) | ||
Total | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 97 | 154 | |
Percentage | 4.00% | ||
Total | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 366 | 380 | |
Percentage | 14.00% | ||
Total | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 215 | 243 | |
Percentage | 8.00% | ||
Total | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 132 | 119 | |
Percentage | 5.00% | ||
Total | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 117 | 141 | |
Percentage | 4.00% | ||
Total | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 11 | 13 | |
Percentage | 0.00% | ||
Total | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 86 | 88 | |
Percentage | 3.00% | ||
Total | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 0 | (7) | |
Percentage | 0.00% | ||
Total | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 952 | 801 | |
Percentage | 35.00% | ||
Total | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 750 | 704 | |
Percentage | 28.00% | ||
NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 1,702 | 1,505 | |
NAV | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 952 | 801 | |
NAV | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 750 | 704 | |
Level 1 | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 749 | 841 | |
Level 1 | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 60 | 68 | |
Level 1 | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | (84) | (99) | |
Level 1 | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 97 | 154 | |
Level 1 | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 366 | 380 | |
Level 1 | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 215 | 243 | |
Level 1 | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 8 | 10 | |
Level 1 | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 86 | 88 | |
Level 1 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 1 | (3) | |
Level 1 | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 251 | 259 | |
Level 2 | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 132 | 119 | |
Level 2 | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 117 | 141 | |
Level 2 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 3 | 3 | |
Level 2 | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | (1) | (4) | |
Level 2 | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 0 | $ 0 |
Employee Benefit Plans (Expecte
Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) $ in Millions | Dec. 31, 2021CAD ($) |
Defined benefit pension plans | |
Expected employer contributions | |
Expected employer contributions, 2022 | $ 41 |
Expected benefit payments | |
Expected benefit payments, 2022 | 153 |
Expected benefit payments, 2023 | 162 |
Expected benefit payments, 2024 | 162 |
Expected benefit payments, 2025 | 165 |
Expected benefit payments, 2026 | 169 |
Expected benefit payments, 2027 - 2031 | 872 |
Non-pension Benefit Plans | |
Expected employer contributions | |
Expected employer contributions, 2022 | 20 |
Expected benefit payments | |
Expected benefit payments, 2022 | 21 |
Expected benefit payments, 2023 | 22 |
Expected benefit payments, 2024 | 22 |
Expected benefit payments, 2025 | 22 |
Expected benefit payments, 2026 | 22 |
Expected benefit payments, 2027 - 2031 | $ 104 |
Employee Benefit Plans (Assumpt
Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined benefit pension plans | ||
Benefit obligation - December 31: | ||
Discount rate - past service | 3.05% | 2.49% |
Discount rate - future service | 3.18% | 2.64% |
Rate of compensation increase | 3.31% | 2.89% |
Health care trend - initial (next year) | 0.00% | 0.00% |
Health care trend - ultimate | 0.00% | 0.00% |
Benefit cost for year ended December 31: | ||
Discount rate - past service | 2.49% | 3.17% |
Discount rate - future service | 2.64% | 3.21% |
Expected long-term return on plan assets | 5.86% | 6.29% |
Rate of compensation increase | 2.89% | 3.34% |
Health care trend - initial (next year) | 0.00% | 0.00% |
Health care trend - ultimate | 0.00% | 0.00% |
Non-pension Benefit Plans | ||
Benefit obligation - December 31: | ||
Discount rate - past service | 2.81% | 2.48% |
Discount rate - future service | 2.92% | 2.51% |
Rate of compensation increase | 3.29% | 3.04% |
Health care trend - initial (next year) | 5.09% | 5.64% |
Health care trend - ultimate | 3.77% | 4.35% |
Health care trend - year ultimate reached | 2042 | 2038 |
Benefit cost for year ended December 31: | ||
Discount rate - past service | 2.48% | 3.28% |
Discount rate - future service | 2.51% | 3.28% |
Expected long-term return on plan assets | 0.00% | 3.25% |
Rate of compensation increase | 3.04% | 3.70% |
Health care trend - initial (next year) | 5.64% | 5.91% |
Health care trend - ultimate | 4.35% | 4.37% |
Health care trend - year ultimate reached | 2038 | 2038 |
Employee Benefit Plans (Narrati
Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Description | Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. | |
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description | The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. | |
Defined Benefit Plan, Plan Assets, Expected Long-term Rate-of-Return, Description | The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. | |
Defined Benefit Plan, Expected Return on Plan Assets | $ 2,151 | $ 2,476 |
Contribution Amount | $ 45 | 45 |
Plan assets recognition period | 5 years | |
Defined benefit pension plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 132 | 141 |
Non-pension Benefit Plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 1 | $ 1 |
Goodwill (Details)
Goodwill (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Goodwill [Roll Forward] | ||
Balance, January 1 | $ 5,720 | $ 5,835 |
Change in foreign exchange rate | (24) | (115) |
Balance, December 31 | 5,696 | 5,720 |
GBPC | ||
Goodwill [Roll Forward] | ||
Balance, January 1 | 68 | |
Balance, December 31 | $ 68 | $ 68 |
Goodwill, percentage by which fair value exceeded carrying value | 12.00% |
Short Term Debt (Short-term deb
Short Term Debt (Short-term debt and the related weighted-average interest rates) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 1,742 | $ 1,625 |
Weighted average interest rate | 0.83% | 1.01% |
Advances on revolving credit and term facilities | TECO Finance | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 355 | $ 205 |
Weighted average interest rate | 1.20% | 1.46% |
Advances on accounts receivable and revolving credit facilities | TEC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 945 | $ 987 |
Weighted average interest rate | 0.58% | 0.89% |
Non-revolving credit agreement | Emera Inc. | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 400 | $ 400 |
Weighted average interest rate | 0.96% | 0.94% |
Bank indebtedness | Emera Inc. | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 6 | $ 0 |
Weighted average interest rate | 0.00% | 0.00% |
Bank indebtedness | NSPI | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 1 | $ 1 |
Weighted average interest rate | 0.00% | 0.00% |
Advances on revolving credit facilities | GBPC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 10 | $ 11 |
Weighted average interest rate | 5.25% | 5.25% |
Advances on revolving credit facilities | NMGC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 25 | $ 21 |
Weighted average interest rate | 1.20% | 1.22% |
Short Term Debt (Short-term rev
Short Term Debt (Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2021CAD ($) | Dec. 17, 2021USD ($) | Dec. 03, 2021CAD ($) | Dec. 31, 2020CAD ($) | |
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Total available capacity | $ 2,729 | $ 2,677 | ||
Advances under revolving credit and term facilities | 1,735 | 1,624 | ||
Letters of credit issued within the credit facilities | 4 | 4 | ||
Total advances under available facilities | 1,739 | 1,628 | ||
Available capacity under existing agreements | $ 990 | 1,049 | ||
Term credit facility | TEC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | 2022 | |||
Total available capacity | $ 634 | 382 | ||
Revolving credit facility | TECO Energy/TECO Finance | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | 2026 | |||
Total available capacity | $ 507 | $ 400 | 509 | |
Revolving credit facility | TEC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | 2026 | |||
Total available capacity | $ 1,014 | 800 | 1,019 | |
Revolving credit facility | NMGC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | 2026 | |||
Total available capacity | $ 158 | 125 | 159 | |
Revolving credit facility | GBPC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | on demand | |||
Total available capacity | $ 16 | 17 | ||
Non-revolving credit agreement | TEC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Total available capacity | $ 500 | |||
Non-revolving credit agreement | Emera Inc. | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Maturity | 2022 | |||
Total available capacity | $ 400 | $ 400 | 400 | |
Accounts receivable revolving credit facility | TEC | ||||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||||
Total available capacity | $ 0 | $ 191 |
Short Term Debt (Narrative) (De
Short Term Debt (Narrative) (Details) $ in Millions, $ in Millions | Dec. 17, 2021USD ($) | Mar. 23, 2021USD ($) | Dec. 31, 2021CAD ($) | Dec. 03, 2021CAD ($) | May 25, 2021USD ($) | Dec. 31, 2020CAD ($) |
Line of Credit Facility [Line Items] | ||||||
Weighted average interest rate | 0.83% | 1.01% | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,729 | $ 2,677 | ||||
Proceeds from senior notes issuance | $ 800 | |||||
TEC | ||||||
Line of Credit Facility [Line Items] | ||||||
Commercial paper program | $ 800 | |||||
Revolving credit facility | TEC | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 800 | 1,014 | 1,019 | |||
Debt Instrument, Maturity Date | Mar. 22, 2023 | |||||
Debt Instrument, Maturity Date Extended | Dec. 17, 2026 | |||||
Revolving credit facility | NMGC | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 125 | $ 158 | 159 | |||
Debt Instrument, Maturity Date | Mar. 22, 2023 | |||||
Debt Instrument, Maturity Date Extended | Dec. 17, 2026 | |||||
Revolving credit facility | TECO Energy/TECO Finance | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 400 | $ 507 | 509 | |||
Debt Instrument, Maturity Date | Mar. 22, 2023 | |||||
Debt Instrument, Maturity Date Extended | Dec. 17, 2026 | |||||
Term loan credit facility | TEC | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 634 | $ 382 | ||||
Non-revolving credit agreement | ||||||
Line of Credit Facility [Line Items] | ||||||
Repayments of credit facility | 300 | |||||
Non-revolving credit agreement | TEC | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 500 | |||||
Debt Instrument, Maturity Date | Dec. 16, 2022 | |||||
Non-revolving credit agreement | Emera Inc. | ||||||
Line of Credit Facility [Line Items] | ||||||
Weighted average interest rate | 0.96% | 0.94% | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | $ 400 | $ 400 | |||
Debt Instrument, Maturity Date | Dec. 16, 2021 | |||||
Debt Instrument, Maturity Date Extended | Dec. 16, 2022 | |||||
Accounts receivable collateralized borrowing facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Repayments of credit facility | $ 150 |
Other Current Liabilities (Deta
Other Current Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Other Current Liabilities | ||
Accrued charges | $ 157 | $ 141 |
Accrued interest on long-term debt | 75 | 71 |
Pension and post-retirement liabilities (note 19) | 27 | 23 |
Sales and other taxes payable | 6 | 6 |
Income taxes payable | 6 | 1 |
Other | 95 | 98 |
Other current liabilities, Total | $ 366 | $ 340 |
Long Term Debt (Details)
Long Term Debt (Details) - CAD ($) $ in Millions | Jul. 16, 2021 | Dec. 31, 2021 | Dec. 31, 2020 |
Debt Instrument [Line Items] | |||
Debt issuance costs | $ (121) | $ (110) | |
Amount due within one year | (462) | (1,382) | |
Long Term Debt, Adjustments | (580) | (1,487) | |
Long-Term Debt | 14,196 | 12,339 | |
Interest expense | 102 | 109 | |
Emera | |||
Debt Instrument [Line Items] | |||
Long-term debt | 2,399 | 2,291 | |
NMGC | |||
Debt Instrument [Line Items] | |||
Long-term debt | 589 | 465 | |
NSPI | |||
Debt Instrument [Line Items] | |||
Long-term debt | 3,041 | 2,956 | |
EBP | |||
Debt Instrument [Line Items] | |||
Maturity | May 17, 2023 | ||
ECI | |||
Debt Instrument [Line Items] | |||
Long-term debt | 478 | 476 | |
TECO Energy | |||
Debt Instrument [Line Items] | |||
Fair market value adjustment | $ 3 | 5 | |
Bankers acceptances | LIBOR loans | Emera | |||
Debt Instrument [Line Items] | |||
Maturity | 2026 | ||
Long-term debt | $ 378 | $ 263 | |
Unsecured fixed rate notes | Emera | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 2.90% | 2.90% | |
Maturity | 2023 | ||
Long-term debt | $ 500 | $ 500 | |
Unsecured fixed rate notes | Emera Finance | |||
Debt Instrument [Line Items] | |||
Maturity | 2024 - 2046 | ||
Fixed to floating subordinated notes | Emera | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 6.75% | 6.75% | |
Maturity | 2076 | ||
Long-term debt | $ 1,521 | $ 1,528 | |
Unsecured senior notes | Emera Finance | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.65% | 3.86% | |
Long-term debt | $ 3,487 | $ 3,501 | |
Fixed rate notes and bonds | TEC | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 4.15% | 4.53% | |
Maturity | 2022 - 2051 | ||
Long-term debt | $ 3,683 | $ 3,268 | |
Fixed rate notes and bonds | PGS | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.78% | 4.58% | |
Maturity | 2022 - 2051 | ||
Long-term debt | $ 660 | $ 429 | |
Fixed rate notes and bonds | NMGC | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.11% | 4.30% | |
Maturity | 2026 - 2051 | ||
Long-term debt | $ 488 | $ 465 | |
Fixed rate notes and bonds | NMGI | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.64% | 3.64% | |
Maturity | 2024 | ||
Long-term debt | $ 190 | $ 191 | |
Discount notes | NSPI | |||
Debt Instrument [Line Items] | |||
Maturity | 2026 | ||
Long-term debt | $ 376 | $ 291 | |
Medium term fixed rate notes | NSPI | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 5.14% | 5.14% | |
Maturity | 2025 - 2097 | ||
Long-term debt | $ 2,665 | $ 2,665 | |
Senior secured credit facility | EBP | |||
Debt Instrument [Line Items] | |||
Maturity | 2025 | ||
Long-term debt | $ 249 | $ 249 | |
Amortizing fixed rate notes | ECI | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.97% | 3.92% | |
Maturity | 2022 - 2026 | ||
Long-term debt | $ 104 | $ 100 | |
Secured senior notes | ECI | |||
Debt Instrument [Line Items] | |||
Maturity | 2026 | ||
Long-term debt | $ 84 | $ 106 | |
Secured fixed rate senior notes | ECI | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 4.43% | 4.39% | |
Maturity | 2022 - 2035 | ||
Long-term debt | $ 161 | $ 174 | |
Non-revolving term facility, floating rate | NMGC | |||
Debt Instrument [Line Items] | |||
Maturity | 2022 | ||
Long-term debt | $ 101 | ||
Non-revolving term facility, floating rate | ECI | |||
Debt Instrument [Line Items] | |||
Maturity | 2025 | ||
Long-term debt | $ 28 | $ 28 | |
Non-revolving term facility, fixed rate | ECI | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 2.36% | 2.60% | |
Maturity | 2025 - 2026 | ||
Long-term debt | $ 101 | $ 68 |
Long Term Debt (Revolving credi
Long Term Debt (Revolving credit facilities, outstanding borrowings and available capacity) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 2,729 | $ 2,677 |
Letters of credit issued inside credit facilities | 4 | 4 |
Use of available facilities | 1,739 | 1,628 |
Available capacity under existing agreements | 990 | 1,049 |
Advances on the revolving credit facility | 1,735 | 1,624 |
NSPI | ||
Debt Instrument [Line Items] | ||
Letters of credit issued inside credit facilities | 64 | 63 |
Revolving credit facility | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | 1,527 | 1,528 |
Borrowings under credit facilities | 770 | 569 |
Letters of credit issued inside credit facilities | 124 | 31 |
Use of available facilities | 894 | 600 |
Available capacity under existing agreements | 633 | 928 |
Advances on the revolving credit facility | 50 | |
Revolving credit facility | Emera | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 900 | 900 |
Maturity | Jun. 30, 2026 | |
Revolving credit facility | NSPI | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 600 | 600 |
Maturity | Dec. 31, 2026 | |
Revolving credit facility | ECI | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 27 | $ 28 |
Revolving credit facility | Minimum | ECI | ||
Debt Instrument [Line Items] | ||
Maturity | Dec. 31, 2022 | |
Revolving credit facility | Maximum | ECI | ||
Debt Instrument [Line Items] | ||
Maturity | Jan. 1, 2032 |
Long Term Debt (Debt Covenants)
Long Term Debt (Debt Covenants) (Details) | Dec. 31, 2021 |
Maximum | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.0070 |
Syndicated credit facilities | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.0057 |
Long Term Debt (Long Term Matur
Long Term Debt (Long Term Maturities) (Details) $ in Millions | Dec. 31, 2021CAD ($) |
Subsidiaries | |
Debt Instrument [Line Items] | |
2022 | $ 462 |
2023 | 590 |
2024 | 827 |
2025 | 504 |
2026 | 3,479 |
Thereafter | 8,914 |
Total, long-term debt maturities, including capital lease obligations | 14,776 |
Emera | |
Debt Instrument [Line Items] | |
2022 | 0 |
2023 | 500 |
2024 | 0 |
2025 | 0 |
2026 | 1,899 |
Thereafter | 0 |
Total, long-term debt maturities, including capital lease obligations | 2,399 |
Emera US Finance LP | |
Debt Instrument [Line Items] | |
2022 | 0 |
2023 | 0 |
2024 | 571 |
2025 | 0 |
2026 | 951 |
Thereafter | 1,965 |
Total, long-term debt maturities, including capital lease obligations | 3,487 |
Tampa Electric | |
Debt Instrument [Line Items] | |
2022 | 285 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 3,398 |
Total, long-term debt maturities, including capital lease obligations | 3,683 |
PGS | |
Debt Instrument [Line Items] | |
2022 | 32 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 628 |
Total, long-term debt maturities, including capital lease obligations | 660 |
NMGC | |
Debt Instrument [Line Items] | |
2022 | 101 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 89 |
Thereafter | 399 |
Total, long-term debt maturities, including capital lease obligations | 589 |
NMGI | |
Debt Instrument [Line Items] | |
2022 | 0 |
2023 | 0 |
2024 | 190 |
2025 | 0 |
2026 | 0 |
Thereafter | 0 |
Total, long-term debt maturities, including capital lease obligations | 190 |
NSPI | |
Debt Instrument [Line Items] | |
2022 | 0 |
2023 | 0 |
2024 | 0 |
2025 | 125 |
2026 | 416 |
Thereafter | 2,500 |
Total, long-term debt maturities, including capital lease obligations | 3,041 |
EBP | |
Debt Instrument [Line Items] | |
2022 | 0 |
2023 | 0 |
2024 | 0 |
2025 | 249 |
2026 | 0 |
Thereafter | 0 |
Total, long-term debt maturities, including capital lease obligations | 249 |
ECI | |
Debt Instrument [Line Items] | |
2022 | 44 |
2023 | 90 |
2024 | 66 |
2025 | 130 |
2026 | 124 |
Thereafter | 24 |
Total, long-term debt maturities, including capital lease obligations | $ 478 |
Long Term Debt (Narrative) (Det
Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions | Dec. 16, 2021USD ($) | Dec. 03, 2021 | Jul. 23, 2021CAD ($) | Jul. 16, 2021CAD ($) | Jun. 04, 2021USD ($) | May 15, 2021USD ($) | Mar. 25, 2021USD ($) | Mar. 18, 2021USD ($) | Feb. 05, 2021USD ($) | Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020CAD ($) |
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,729 | $ 2,677 | ||||||||||
Proceeds from issuance of long-term debt | 2,554 | 428 | ||||||||||
Repayments of Long-term Debt | 1,660 | 513 | ||||||||||
Emera | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,399 | 2,291 | ||||||||||
TEC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Proceeds from issuance of long-term debt | $ 800 | |||||||||||
NSPI | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 3,041 | 2,956 | ||||||||||
NSPI | Canadian Electric Utilities | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Oct. 1, 2024 | |||||||||||
Debt Instrument, Maturity Date Extended | Dec. 1, 2026 | |||||||||||
EBP | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | May 17, 2023 | |||||||||||
Debt Instrument, Maturity Date Extended | Jun. 30, 2025 | |||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 250 | |||||||||||
NMGC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Proceeds from issuance of long-term debt | $ 220 | |||||||||||
Long-term Debt, Gross | $ 589 | $ 465 | ||||||||||
Repayments of Long-term Debt | $ 200 | |||||||||||
Emera US Finance LP [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Proceeds from issuance of long-term debt | $ 750 | $ 750 | ||||||||||
Repayments of Long-term Debt | $ 750 | |||||||||||
Non-revolving term loan at 4% interest rate | GBPC | Other Electric Utilities [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt instrument, available for issuance under this prospectus | $ 75 | |||||||||||
Debt Instrument, Maturity Date | Dec. 31, 2026 | |||||||||||
Stated interest rate | 4.00% | |||||||||||
Repayments of Long-term Debt | $ 55 | |||||||||||
5.4 % notes | TEC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Stated interest rate | 5.40% | |||||||||||
Repayments of Long-term Debt | $ 278 | |||||||||||
Senior notes maturity date of March 15, 2031 | TEC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Mar. 15, 2031 | |||||||||||
Stated interest rate | 2.40% | |||||||||||
Senior notes | $ 400 | |||||||||||
Senior notes maturity date of March 15, 2051 | TEC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Mar. 15, 2051 | |||||||||||
Stated interest rate | 3.45% | |||||||||||
Senior notes | $ 400 | |||||||||||
Unsecured, non-revolving credit facility [Member] | NMGC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Sep. 23, 2022 | |||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 100 | |||||||||||
Senior note maturity date of February 5, 2036 | NMGC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Feb. 5, 2036 | |||||||||||
Stated interest rate | 2.51% | |||||||||||
Senior notes | $ 65 | |||||||||||
Senior note maturity date of February 5, 2031 | NMGC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Feb. 5, 2031 | |||||||||||
Stated interest rate | 2.26% | |||||||||||
Senior notes | $ 70 | |||||||||||
Senior note maturity date of February 5, 2051 | NMGC | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Feb. 5, 2051 | |||||||||||
Stated interest rate | 3.34% | |||||||||||
Senior notes | $ 85 | |||||||||||
Senior notes maturity date of June 15, 2031 | Emera US Finance LP [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Jun. 15, 2031 | |||||||||||
Stated interest rate | 2.64% | |||||||||||
Senior notes | $ 450 | |||||||||||
Senior notes maturity date of June 15, 2024 | Emera US Finance LP [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Jun. 15, 2024 | |||||||||||
Stated interest rate | 0.83% | |||||||||||
Senior notes | $ 300 | |||||||||||
Unsecured committed revolving credit facility | Emera | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Jun. 30, 2024 | |||||||||||
Debt Instrument, Maturity Date Extended | Jun. 30, 2026 | |||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 900 |
Asset Retirement Obligation (Ch
Asset Retirement Obligation (Change in ARO) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Change in ARO | ||
Balance, January 1 | $ 178 | $ 185 |
Additions | 1 | 10 |
Liabilities settled | (13) | (25) |
Accretion included in depreciation expense | 10 | 9 |
Accretion deferred to regulatory asset (included in property, plant and equipment) | (2) | (3) |
Other | 1 | 1 |
Change in foreign exchange rate | (1) | 1 |
Balance, December 31 | $ 174 | $ 178 |
Commitments and Contingencies_2
Commitments and Contingencies (Contractual Commitments) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 09, 2022 | Dec. 31, 2020 | |
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | $ 2,195 | ||
2023 | 942 | ||
2024 | 726 | ||
2025 | 650 | ||
2026 | 588 | ||
Thereafter | 4,793 | ||
Contractual Commitments | 9,894 | ||
NSPI Contractual obligation for use of the Maritime Link | |||
Regulatory Liabilities | 2,055 | $ 1,961 | |
Revenue, Remaining Performance Obligation, Amount | $ 437 | $ 464 | |
Nalcor Energy | |||
NSPI Contractual obligation for use of the Maritime Link | |||
Long-term Purchase Commitment, Period | 50 years | ||
SeaCoast Gas Transmission, LLC | PGS | |||
NSPI Contractual obligation for use of the Maritime Link | |||
Revenue, Remaining Performance Obligation, Amount | $ 142 | ||
Maritime Link Project | NSPI | NSPML | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 164 | ||
2023 | $ 162 | ||
NSPI Contractual obligation for use of the Maritime Link | |||
Long-term Purchase Commitment, Period | 38 years | ||
Maritime Link Project | NSPI | Scenario Plan | NSPML | Canadian Electric Utilities | |||
NSPI Contractual obligation for use of the Maritime Link | |||
Regulatory Liabilities | $ 1,800 | ||
Purchased power | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | $ 563 | ||
2023 | 437 | ||
2024 | 372 | ||
2025 | 323 | ||
2026 | 297 | ||
Thereafter | 2,627 | ||
Contractual Commitments | 4,619 | ||
Transportation | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 231 | ||
2023 | 227 | ||
2024 | 244 | ||
2025 | 242 | ||
2026 | 235 | ||
Thereafter | 1,967 | ||
Contractual Commitments | 3,146 | ||
Fuel, gas supply and storage | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 694 | ||
2023 | 104 | ||
2024 | 45 | ||
2025 | 40 | ||
2026 | 25 | ||
Thereafter | 0 | ||
Contractual Commitments | 908 | ||
Capital projects | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 359 | ||
2023 | 93 | ||
2024 | 3 | ||
2025 | 1 | ||
2026 | 1 | ||
Thereafter | 0 | ||
Contractual Commitments | 457 | ||
Long-term service agreements | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 49 | ||
2023 | 66 | ||
2024 | 47 | ||
2025 | 32 | ||
2026 | 26 | ||
Thereafter | 83 | ||
Contractual Commitments | 303 | ||
Equity investment commitments | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 240 | ||
2023 | 0 | ||
2024 | 0 | ||
2025 | 0 | ||
2026 | 0 | ||
Thereafter | 0 | ||
Contractual Commitments | 240 | ||
Leases and other | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 15 | ||
2023 | 14 | ||
2024 | 14 | ||
2025 | 12 | ||
2026 | 4 | ||
Thereafter | 116 | ||
Contractual Commitments | 175 | ||
Demand side management | |||
Recorded Unconditional Purchase Obligation [Line Items] | |||
2022 | 44 | ||
2023 | 1 | ||
2024 | 1 | ||
2025 | 0 | ||
2026 | 0 | ||
Thereafter | 0 | ||
Contractual Commitments | $ 46 |
Commitments and Contingencies_3
Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions, $ in Millions | Oct. 16, 2020USD ($) | May 13, 2020USD ($) | Nov. 30, 2020USD ($) | Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2021USD ($) |
Loss Contingencies [Line Items] | |||||||
Litigation Settlement, Amount | $ 0 | $ 49 | |||||
Prime Rate [Member] | Tampa Electric | |||||||
Loss Contingencies [Line Items] | |||||||
Loss Contingency, Estimate of Possible Loss | $ 18 | $ 14 | |||||
United States Free Trade Agreement Award One [Member] | TGH | |||||||
Loss Contingencies [Line Items] | |||||||
Proceeds from settlement of claims | $ 38 | ||||||
United States Free Trade Agreement Award two [Member] | TGH | |||||||
Loss Contingencies [Line Items] | |||||||
Litigation Settlement, Amount | $ 35 | $ 62 | |||||
Litigation Settlement Interest | $ 2 |
Commitments and Contingencies_4
Commitments and Contingencies (Guarantees and Letters of Credit) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2021CAD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | |
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | $ 4 | $ 4 | ||
Nova Scotia Power Inc. [Member] | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | $ 118 | $ 18 | ||
Letters of Credit Outstanding, Amount | $ 64 | $ 63 | ||
Emera Reinsurance Limited | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | 35 | |||
Guarantor Obligations, Origin and Purpose | relating to outstanding notes of GBPC | |||
Guarantor Obligations, Term | expire in May 2023 | |||
TECO Energy | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 45 | |||
Payment Guarantee | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 27 | |||
Surety Bonds | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 148 | $ 55 | ||
NSPEMI | Nova Scotia Power Inc. [Member] | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | 15 | |||
Transportation Agreement | Nova Scotia Power Inc. [Member] | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | $ 85 | |||
Guarantor Obligations, Term | P15Y |
Commitments and Contingencies_5
Commitments and Contingencies (Collaborative Arrangements) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | ||
Regulated fuel for generation and purchased power | $ 18 | $ 19 |
Operating, maintenance and general (OM&G) | $ 3 | $ 3 |
Cumulative Preferred Stock (Aut
Cumulative Preferred Stock (Authorized) (Details) - CAD ($) $ / shares in Units, $ in Millions | Aug. 15, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Aug. 17, 2020 |
Class of Stock [Line Items] | ||||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 58,000,000 | 41,000,000 | ||
Net Proceeds | $ 1,422 | $ 1,004 | ||
Series A Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 0.5456 | $ 0.5456 | ||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 4,866,814 | 4,866,814 | 3,864,636 | |
Net Proceeds | $ 119 | $ 119 | ||
Series B Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 1,133,186 | 1,133,186 | 2,135,364 | |
Net Proceeds | $ 28 | $ 28 | ||
Preferred Stock Dividend Payment Rate Variable | Floating | |||
Series C Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | 1.1802 | $ 1.1802 | ||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 10,000,000 | 10,000,000 | ||
Net Proceeds | $ 245 | $ 245 | ||
Series E Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 1.1250 | |||
Preferred Stock, Redemption Price Per Share | $ 25.25 | |||
Issued and Outstanding | 5,000,000 | 5,000,000 | ||
Net Proceeds | $ 122 | $ 122 | ||
Series F Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 1.0505 | $ 1.0505 | ||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 8,000,000 | 8,000,000 | ||
Net Proceeds | $ 195 | $ 195 | ||
Series H Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 1.2250 | |||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 12,000,000 | 12,000,000 | ||
Net Proceeds | $ 295 | $ 295 | ||
Series J Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 1.0625 | |||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 8,000,000 | |||
Net Proceeds | $ 196 | |||
Series L Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Annual Dividend Per Share | $ 1.1500 | |||
Preferred Stock, Redemption Price Per Share | $ 25 | |||
Issued and Outstanding | 9,000,000 | |||
Net Proceeds | $ 222 |
Cumulative Preferred Stock (Cha
Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - $ / shares | Sep. 24, 2021 | Apr. 06, 2021 | Aug. 15, 2020 | Jul. 16, 2020 | Dec. 31, 2021 |
Class of Stock [Line Items] | |||||
Redemption Value | $ 25 | ||||
Series A Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 2.182% | 4.40% | |||
Current Annual Dividend | $ 0.5456 | $ 0.5456 | |||
Earliest Redemption and/or Conversion Option Date | August 15, 2025 | ||||
Redemption Value | $ 25 | ||||
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | ||||
Conversion of Stock, Type of Stock Converted | Series B | ||||
Series A Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 1.84% | ||||
Series C Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.10% | ||||
Current Annual Dividend | 1.1802 | $ 1.1802 | |||
Earliest Redemption and/or Conversion Option Date | August 15, 2023 | ||||
Redemption Value | $ 25 | ||||
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | ||||
Conversion of Stock, Type of Stock Converted | Series D | ||||
Series C Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 2.65% | ||||
Series F Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.202% | ||||
Current Annual Dividend | $ 1.0505 | $ 1.0505 | |||
Earliest Redemption and/or Conversion Option Date | February 15, 2025 | ||||
Redemption Value | $ 25 | ||||
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | ||||
Conversion of Stock, Type of Stock Converted | Series G | ||||
Series F Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 2.63% | ||||
Series B Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 2.021% | 2.393% | |||
Earliest Redemption and/or Conversion Option Date | August 15, 2025 | ||||
Redemption Value | $ 25 | ||||
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | ||||
Conversion of Stock, Type of Stock Converted | Series A | ||||
Series B Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 1.84% | ||||
Series H Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.90% | ||||
Current Annual Dividend | $ 1.2250 | ||||
Earliest Redemption and/or Conversion Option Date | August 15, 2023 | ||||
Redemption Value | $ 25 | ||||
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | ||||
Conversion of Stock, Type of Stock Converted | Series I | ||||
Series H Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.90% | ||||
Series J Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.25% | 4.25% | |||
Current Annual Dividend | $ 1.0625 | ||||
Earliest Redemption and/or Conversion Option Date | May 15, 2026 | ||||
Redemption Value | $ 25 | ||||
Right to Convert on a one for one basis | Series K | ||||
Series J Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.25% | ||||
Series E Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.50% | ||||
Current Annual Dividend | $ 1.1250 | ||||
Redemption Value | 25.25 | ||||
Series E Preferred Stock | After August 15, 2022 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | $ 25 | ||||
Series L Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 4.60% | 4.60% | |||
Current Annual Dividend | $ 1.1500 | ||||
Earliest Redemption and/or Conversion Option Date | November 15, 2026 | ||||
Redemption Value | $ 25 | ||||
Series L Preferred Stock | On Or After November 15, 2026 to November 15, 2027 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 26 | ||||
Series L Preferred Stock | After November 15, 2027 To November 15, 2030 | |||||
Class of Stock [Line Items] | |||||
Preferred Stock, Redemption Price, Annual Decrease | 0.25 | ||||
Series L Preferred Stock | After November 15, 2030 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 25 | ||||
Series D Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 25 | ||||
Series D Preferred Stock | After August 15, 2023 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 25.50 | ||||
Series G Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 25 | ||||
Series G Preferred Stock | After February 15, 2025 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | 25.5 | ||||
Series I Preferred Stock | |||||
Class of Stock [Line Items] | |||||
Redemption Value | $ 25 | ||||
Series I Preferred Stock | Minimum | |||||
Class of Stock [Line Items] | |||||
Initial Yield | 2.54% | ||||
Series I Preferred Stock | After August 15, 2023 | |||||
Class of Stock [Line Items] | |||||
Redemption Value | $ 25.5 |
Cumulative Preferred Stock (Nar
Cumulative Preferred Stock (Narrative) (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions | Sep. 24, 2021 | Apr. 06, 2021 | Dec. 31, 2021 | Dec. 31, 2020 |
Class of Stock [Line Items] | ||||
Issuance of common stock | 4,990 | 4,540 | ||
Proceeds from issuance of preferred stock, net of issuance costs | $ 416 | $ 0 | ||
First Preferred Shares | ||||
Class of Stock [Line Items] | ||||
Preferred Stock Dividend Preference Or Restrictions | First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends is deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and is shown on the Consolidated Statement of Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. | |||
Series J Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Issuance of common stock | 8,000 | |||
Percentage rate used to determine dividend rate | 4.25% | 4.25% | ||
Price of preferred shares issued | $ 25 | |||
Proceeds from issuance of preferred stock | $ 200 | |||
Proceeds from issuance of preferred stock, net of issuance costs | $ 196 | |||
Series L Preferred Stock | ||||
Class of Stock [Line Items] | ||||
Issuance of common stock | 9,000 | |||
Percentage rate used to determine dividend rate | 4.60% | 4.60% | ||
Price of preferred shares issued | $ 25 | |||
Proceeds from issuance of preferred stock | $ 225 | |||
Proceeds from issuance of preferred stock, net of issuance costs | $ 222 |
Non-controlling Interest In S_3
Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 34 | $ 34 |
Domlec | ||
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | 20 | 20 |
GBPC | ||
Noncontrolling Interest [Line Items] | ||
Noncontrolling Interest, Amount Represented by Preferred Stock | $ 14 | $ 14 |
Non-controlling Interest In S_4
Non-controlling Interest In Subsidiaries (Preferred shares of GBPC) (Details) - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Noncontrolling Interest [Line Items] | ||
Number of shares issued and outstanding | 58,000,000 | 41,000,000 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized | 10,000 | |
Number of shares issued and outstanding | 10,000 | 10,000 |
Outstanding as at December 31 | $ 14 | $ 14 |
Non-controlling Interest In S_5
Non-controlling Interest In Subsidiaries (Narrative) (Details) | 12 Months Ended | |
Dec. 31, 2021$ / shares | Dec. 31, 2021$ / shares | |
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Redemption Price Per Share | $ 25 | |
GBPC | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Redemption Terms | The preferred shares are redeemable by GBPC after June 17, 2021 | |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Redemption Price Per Share | $ 1,000 | |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC | USD preferred shares | ||
Noncontrolling Interest [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.00% | 6.00% |
Supplementary Information To Co
Supplementary Information To Condensed Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Changes in non-cash working capital | ||
Inventory | $ (84) | $ 6 |
Receivables and other current assets | (364) | 187 |
Accounts payable | 289 | 55 |
Other current liabilities | 7 | (31) |
Total non-cash working capital | (152) | 217 |
Supplemental disclosure of cash paid: | ||
Interest | 603 | 679 |
Income Taxes | 24 | (148) |
Supplemental disclosure of non-cash activities: | ||
Common share dividends reinvested | 214 | 199 |
Reclassification of long-term debt from current to non-current | 0 | 256 |
(Decrease) Increase in accrued capital expenditures | $ (45) | $ 17 |
Stock-based Compensation (Emplo
Stock-based Compensation (Employee Common Share Purchase Plan and Dividend Reinvestment Plan) (Details) shares in Millions | 12 Months Ended | ||
Dec. 31, 2021CAD ($)shares | Dec. 31, 2021USD ($)shares | Dec. 31, 2020CAD ($)shares | |
Employee Common Share Purchase Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2021, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. | Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2021, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. | |
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount | $ 25 | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount | $ 20,000 | $ 15,000 | |
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 20.00% | 20.00% | |
Compensation cost for shares issued | $ 3,000,000 | $ 2,000,000 | |
Dividend Reinvestment Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2021. | The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2021. | |
Maximum aggregate number of common shares reserved for issuance | shares | 7 | 7 | 7 |
Discount from Market Price, Purchase Date | 2.00% | 2.00% | |
Dividend Reinvestment Plan | Maximum | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Discount from Market Price, Purchase Date | 5.00% | 5.00% |
Stock-based Compensation (Narra
Stock-based Compensation (Narrative) (Details) $ / shares in Units, $ in Thousands, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021CAD ($)$ / sharesshares | Dec. 31, 2020USD ($) | Dec. 31, 2020CAD ($)$ / sharesshares | |
Stock option plan, Additional information | |||
Percentage of outstanding stock maximum | 10.00% | ||
Dividend Reinvestment Plan | |||
Stock option plan, Additional information | |||
Maximum aggregate number of common shares reserved for issuance | shares | 7 | 7 | |
Share Unit Plans | |||
Maximum aggregate number of common shares reserved for issuance | shares | 7 | 7 | |
DSU Plan | |||
Share Unit Plans | |||
Cash payments made during the year | $ 11,000 | $ 11,000 | |
DSU Plan | Executive and senior management | Minimum | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 50.00% | ||
Employee Stock Option Plan | |||
Stock option plan, Additional information | |||
Maximum aggregate number of common shares reserved for issuance | shares | 6.2 | 3.5 | |
Terms of award | P10Y | ||
Share Unit Plans | |||
Maximum aggregate number of common shares reserved for issuance | shares | 6.2 | 3.5 | |
Share Unit Plans | |||
Stock option plan, Additional information | |||
Maximum aggregate number of common shares reserved for issuance | shares | 3.1 | 3.5 | |
Share Unit Plans | |||
Maximum aggregate number of common shares reserved for issuance | shares | 3.1 | 3.5 | |
First Anniversary | DSU Plan | Executive and senior management | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 25.00% | ||
Vesting Period After Date Of Retirement Or Termination For Other Than Just Cause | Employee Stock Option Plan | |||
Stock option plan, Additional information | |||
Vesting period | 27 months | ||
Vesting Period After Date Of Termination For Just Cause | Employee Stock Option Plan | |||
Stock option plan, Additional information | |||
Vesting period | 60 days | ||
Stock Option Plan | |||
Stock option plan, Additional information | |||
Share-based payment award, description | The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2021, Emera is in compliance with this requirement. Stock options vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | ||
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | ||
Vesting rights | The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. | ||
Percentage of outstanding stock maximum | 5.00% | ||
Policy for issuing shares upon exercise | The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | ||
Cash received for options exercised | $ 14,000 | $ 19,000 | |
Total intrinsic value of options exercised | $ 6,000 | $ 6,000 | |
Exercise price range, lower range limit | $ / shares | $ 32.35 | $ 32.06 | |
Exercise price range, upper range limit | $ / shares | $ 60.03 | $ 60.03 | |
Fair value assumptions, method used | The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. | ||
Share Unit Plans | |||
Compensation cost recognized for employee and director | $ 2,000 | $ 1,000 | |
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | ||
Stock Option Plan | First Anniversary | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 25.00% | ||
Stock Option Plan | Second Anniversary | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 25.00% | ||
Stock Option Plan | Third Anniversary | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 25.00% | ||
Stock Option Plan | Fourth Anniversary | |||
Stock option plan, Additional information | |||
Vesting rights, percentage | 25.00% | ||
Share Unit Plans | Share Unit Plans | |||
Stock option plan, Additional information | |||
Share-based payment award, description | The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. | ||
Deferred Share Unit Plans | |||
Share Unit Plans | |||
Compensation cost recognized for employee and director | $ 9,000 | 2,000 | |
Tax Benefit related to compensation costs for share units realized | 3,000 | 1,000 | |
Deferred Share Unit Plans | Employee | |||
Share Unit Plans | |||
Share Unit Plans: Aggregate intrinsic value | $ 39,000 | 36,000 | |
Deferred Share Unit Plans | Director | |||
Share Unit Plans | |||
Share Unit Plans: Aggregate intrinsic value | 32,000 | ||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | |||
Share Unit Plans | |||
Deferred share unit plan, description | When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares. In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. | ||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management | |||
Share Unit Plans | |||
Deferred share unit plan, description | Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. | ||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Director | |||
Share Unit Plans | |||
Deferred share unit plan, description | Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. | ||
Performance Share Unit Plan | |||
Stock option plan, Additional information | |||
Award service period | 3 years | ||
Share Unit Plans | |||
Tax Benefit related to compensation costs for share units realized | $ 3,000 | 7,000 | |
Cash payments made during the year | 29,000 | 29,000 | |
Performance Share Unit Plan | Employee | |||
Share Unit Plans | |||
Share Unit Plans: Aggregate intrinsic value | $ 66,000 | 68,000 | |
Performance Share Unit Plan | Share Unit Plans | |||
Stock option plan, Additional information | |||
Share-based payment award, description | Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. | ||
Compensation cost recognized for stock options | $ 12,000 | 27,000 | |
Restricted Share Unit Plan | |||
Stock option plan, Additional information | |||
Award service period | 3 years | ||
Share Unit Plans | |||
Tax Benefit related to compensation costs for share units realized | $ 1 | ||
Share Unit Plans: Aggregate intrinsic value | $ 24,000 | ||
Cash payments made during the year | |||
Restricted Share Unit Plan | Employee | |||
Share Unit Plans | |||
Share Unit Plans: Aggregate intrinsic value | $ 10,000 | ||
Restricted Share Unit Plan | Share Unit Plans | |||
Stock option plan, Additional information | |||
Share-based payment award, description | Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. | ||
Compensation cost recognized for stock options | $ 8,000 | $ 4 |
Stock-based Compensation (Weigh
Stock-based Compensation (Weighted Average Fair Values, Assumptions in Valuation Models for Options Granted) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
31. Stock-Based Compensation | ||
Weighted average fair value per option | $ 3.63 | $ 3.58 |
Expected term | 5 years | 5 years |
Risk-free interest rate | 0.60% | 1.33% |
Expected dividend yield | 5.00% | 4.09% |
Expected volatility | 19.14% | 14.10% |
Stock-based Compensatin (Stock
Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Total Options, Number of Options | ||
Total Options: Number of Options, Exercised | (330,000) | (420,000) |
Non-Vested Options: Weighted average exercise price per share | ||
Non-Vested Options: Weighted average exercise price per share, Granted | $ 3.63 | $ 3.58 |
Stock option plan, Additional information | ||
Non-Vested options: Unrecognized compensation | $ 3 | $ 2 |
Non-vested options: Weighted average recognition period | 3 years | 3 years |
Vested Options: Weighted average remaining term | 6 years | 6 years |
Vested Options: Aggregate intrinsic value | $ 21 | $ 12 |
Vested Options: Fair value | $ 1 | $ 2 |
Employee Stock Option Plan | ||
Total Options, Number of Options | ||
Total Options: Number of Options, Outstanding, Beginning Balance | 2,267,782 | |
Granted | 653,600 | |
Total Options: Number of Options, Exercised | (331,078) | |
Total Options: Number of Options, Outstanding, Ending Balance | 2,590,304 | 2,267,782 |
Total Options: Number of Options, Options exercisable | 1,137,829 | |
Total Options, Weighted average exercise price per share | ||
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance | $ 46.62 | |
Total Options: Weighted average exercise price per share, Granted | 51.12 | |
Total Options: Weighted average exercise price per share, Exercised | 40.97 | |
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance | 48.48 | $ 46.62 |
Total Options: Weighted average exercise price per share, Options exercisable | $ 44.86 | |
Non-Vested Options, Number of Options | ||
Non-Vested Options: Number of Options, Outstanding, Beginning Balance | 1,293,850 | |
Granted | 653,600 | |
Non-Vested Options: Number of Options, Vested | 494,975 | |
Non-Vested Options: Number of Options, Ending Balance | 1,452,475 | 1,293,850 |
Non-Vested Options: Weighted average exercise price per share | ||
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance | $ 2.69 | |
Non-Vested Options: Weighted average exercise price per share, Granted | 3.63 | |
Non-Vested Options: Weighted average exercise price per share, Vested | 2.49 | |
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance | $ 3.18 | $ 2.69 |
Stock-based Compensation (Defer
Stock-based Compensation (Deferred Share Unit Plans) (Details) - DSU Plan - Deferred Share Unit Plans | 12 Months Ended |
Dec. 31, 2021$ / sharesshares | |
Employee | |
Share Unit Plans: Units | |
Share Unit Plans: Outstanding, Beginning Balance | shares | 661,998 |
Share Unit Plans: Granted including DRIP | shares | 93,710 |
Share Unit Plans: Exercised | shares | (145,107) |
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares | 610,601 |
Share Unit Plans: Weighted Average Grant Date Fair Value | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares | $ 37.17 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares | 49.64 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares | 36.61 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares | $ 39.22 |
Director | |
Share Unit Plans: Units | |
Share Unit Plans: Outstanding, Beginning Balance | shares | 591,124 |
Share Unit Plans: Granted including DRIP | shares | 101,403 |
Share Unit Plans: Exercised | shares | (78,162) |
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares | 614,365 |
Share Unit Plans: Weighted Average Grant Date Fair Value | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares | $ 41.69 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares | 51.25 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares | 37.57 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares | $ 43.80 |
Stock-based Compensation (Perfo
Stock-based Compensation (Performance Share Unit Plan) (Details) - Performance Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Share Unit Plans: Units | ||
Share Unit Plans: Outstanding, Beginning Balance | 1,126,529 | |
Share Unit Plans: Granted including DRIP | 323,610 | |
Share Unit Plans: Exercised | (464,290) | |
Share Unit Plans: Forfeited | (33,914) | |
Share Unit Plans: Outstanding and exercisable, Ending Balance | 951,935 | |
Share Unit Plans: Weighted Average Grant Date Fair Value | ||
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ 47.16 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | 52.83 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | 48.13 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited | 47.78 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ 48.60 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 66 | $ 68 |
Stock-based Compensation (Restr
Stock-based Compensation (Restricted Share Unit Plan) (Details) - Restricted Share Unit Plan - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 24 | |
Employee | ||
Share Unit Plans: Units | ||
Share Unit Plans: Outstanding, Beginning Balance | 166,275 | |
Share Unit Plans: Granted including DRIP | 184,498 | |
Share Unit Plans: Exercised | (232) | |
Share Unit Plans: Forfeited | (6,589) | |
Share Unit Plans: Outstanding and exercisable, Ending Balance | 343,952 | |
Share Unit Plans: Weighted Average Grant Date Fair Value | ||
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ 54.62 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | 54.66 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | 54.62 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited | 54.63 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ 54.64 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 10 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - NSPML - NSPML - CAD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Variable Interest Entity [Line Items] | ||
Equity Method Investment, Underlying Equity in Net Assets | $ 533 | $ 547 |
Maximum exposure to losss | $ 11 | $ 16 |