Emera (EMRAF) 40-F 14 Feb 22 2021 FY Annual report (Canada) Financial data

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