Emera (EMRAF) 40-F 31 Mar 21 2020 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2020shares
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, 2020
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
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 Address, Address Line One	5151 Terminal Road
Entity Address, City or Town	Halifax
Entity Address, State or Province	DE
Entity Address, Country	CA
Entity Address, Postal Zip Code	B3J 1A1
City Area Code	902
Local Phone Number	428-6096
Entity Listings [Line Items]
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Common Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	251,430,226
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

Consolidated Statements of Inco

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating revenues
Total operating revenues (note 6)	$ 5,506	$ 6,111
Operating expenses
Operating, maintenance and general	1,419	1,464
Provincial, state, and municipal taxes	317	342
Depreciation and amortization	881	903
Impairment charges	25	34
Total operating expenses	4,359	4,768
Income from operations	1,147	1,343
Income from equity investments (note 8)	149	154
Other income net (note 9)	708	12
Interest expense, net	679	738
Income before provision for income taxes	1,325	771
Income tax expense (note 10)	341	61
Net income	984	710
Non-controlling interest in subsidiaries	1	2
Preferred stock dividends	45	45
Net income attributable to common shareholders	$ 937.6	$ 662.8
Earnings per common share (note 12)
Basic	$ 3.78	$ 2.76
Diluted	$ 3.78	$ 2.76
Weighted average shares of common stock outstanding (in millions) (note 12)
Basic	247.8	239.9
Diluted	248.2	240.5
Dividends per common share declared	$ 2.475	$ 2.375
Regulated | Electric
Operating revenues
Total operating revenues (note 6)	$ 4,442	$ 4,769
Operating expenses
Fuel for generation and purchased power (notes 17 and 19)	1,420	1,609
Regulated | Gas
Operating revenues
Total operating revenues (note 6)	1,034	1,081
Operating expenses
Fuel for generation and purchased power (notes 17 and 19)	293	350
Non-Regulated
Operating revenues
Total operating revenues (note 6)	30	261
Non-Regulated | Electric
Operating expenses
Fuel for generation and purchased power (notes 17 and 19)	$ 4	$ 66

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Consolidated Statements of Comprehensive Income
Net income		$ 984	$ 710
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment	[1]	(201)	(402)
Unrealized gains on net investment hedges	[2],[3]	26	78
Cash flow hedges
Net derivative gains		0	3
Less: reclassification adjustment for losses included in income		2	3
Net effects of cash flow hedges		2	6
Net change in unrecognized pension and post-retirement benefit obligation	[4]	(1)	74
Other comprehensive income (loss)	[5]	(174)	(244)
Comprehensive income (loss)		810	466
Comprehensive income (loss) attributable to non-controlling interest		1	1
Comprehensive Income (loss) of Emera Incorporated		$ 809	$ 465
[1]	1) Net of tax recovery of $1 million (2019 - nil) for the year ended December 31, 2020.
[2]	2) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.
[3]	3) Net of tax expense of $4 million (2019 - $1 million tax expense) for the year ended December 31, 2020.
[4]	4) Net of tax recovery of $1 million (2019 - $9 million expense) for the year ended December 31, 2020.
[5]	5) Net of tax expense of $2 million (2019 - $10 million expense) for the year ended December 31, 2020.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Consolidated Statements of Comprehensive Income
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	$ 1	$ 0
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	4	1
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	1	(9)
Other Comprehensive Income (Loss), Tax, Total	2	$ 10
Net investment in United States dollar denominated operations
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 220	$ 222
Restricted cash (note 32)	34	51
Inventory (note 14)	453	467
Derivative instruments (notes 15 and 16)	73	54
Regulatory assets (note 7)	165	121
Receivables and other current assets (note 18)	1,233	1,486
Assets held for sale (note 4)	0	85
Total current assets	2,178	2,486
Property, plant and equipment, net of accumulated depreciation and amortization of $8,714 and $8,317 respectively (note 20)	19,535	18,167
Other assets
Deferred income taxes (note 10)	209	186
Derivative instruments (notes 15 and 16)	25	33
Regulatory assets (note 7)	1,419	1,431
Net investment in direct financing lease (note 19)	475	473
Goodwill (note 22)	5,720	5,835
Other long term assets	327	300
Assets held for sale (note 4)	0	1,619
Total other assets	9,521	11,189
Total assets	31,234	31,842
Current liabilities
Short-term debt (note 23)	1,625	1,537
Current portion of long-term debt (note 25)	1,382	501
Accounts payable	1,148	1,118
Derivative instruments (notes 15 and 16)	251	268
Regulatory liabilities (note 7)	129	295
Other current liabilities (note 24)	340	333
Liabilities associated with assets held for sale (note 4)	0	114
Total current liabilities	4,875	4,166
Long-term liabilities
Long-term debt (note 25)	12,339	13,679
Deferred income taxes (note 9)	1,629	1,285
Derivative instruments (notes 15 and 16)	87	102
Regulatory liabilities (note 7)	1,832	1,886
Pension and post-retirement liabilities (note 21)	453	460
Long-term liabilities associated with assets held for sale (note 4)	0	899
Total long-term liabilities	17,121	19,075
Equity
Common stock (note 11)	6,705	6,216
Cumulative preferred stock (note 28)	1,004	1,004
Contributed surplus	79	78
Accumulated other comprehensive income (loss) (note 13)	(79)	95
Retained earnings	1,495	1,173
Total Emera Incorporated equity	9,204	8,566
Non-controlling interest in subsidiaries (note 29)	34	35
Total equity	9,238	8,601
Total liabilities and equity	31,234	31,842
Commitments and contingencies (note 27)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Consolidated Balance Sheets
Accumulated depreciation and amortization on property, plant and equipment	$ 8,714	$ 8,317

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net income	$ 984	$ 710
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	899	911
Income from equity investments, net of dividends	(76)	(83)
Allowance for equity funds used during construction	(45)	(21)
Deferred income taxes, net	381	125
Net change in pension and post-retirement obligations	(23)	(17)
Regulated fuel adjustment mechanism	(94)	(46)
Net changes in fair value of derivative instruments	(36)	(39)
Net change in regulatory assets and liabilities	(87)	44
Net change in capitalized transportation capacity	52	(55)
Impairment charges	25	34
Gain on sale, net of transaction costs	(603)	0
Other operating activities, net	43	35
Changes in non-cash working capital (note 30)	217	(73)
Net cash provided by operating activities	1,637	1,525
Investing activities
Additions to property, plant and equipment	(2,623)	(2,495)
Proceeds from dispositions (note 4)	1,401	875
Other investing activities	(2)	3
Net cash used in investing activities	(1,224)	(1,617)
Financing activities
Change in short-term debt, net	385	413
Proceeds from short-term debt with maturities greater than 90 days	399	0
Repayment of short-term debt with maturities greater than 90 days	(688)	0
Proceeds from long-term debt, net of issuance costs	428	1,066
Retirement of long-term debt	(513)	(1,103)
Net repayments under committed credit facilities	(203)	(118)
Issuance of common stock, net of issuance costs	285	203
Dividends on common stock	(409)	(378)
Dividends on preferred stock	(45)	(45)
Other financing activities	(11)	(24)
Net cash (used in) provided by financing activities	(372)	14
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(61)	(20)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	(20)	(98)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	274	372
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	$ 254	$ 274

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Cash, cash equivalents, restricted cash and assets held for sale consists of:
Cash	$ 220	$ 222
Restricted cash	34	51
Assets held for sale	0	1
Cash, cash equivalents, and restricted cash	$ 254	$ 274

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total		Cumulative Effect, Period of Adoption, Adjustment	Common Stock	Common StockCumulative 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)	[1]	Accumulated Other Comprehensive Income (Loss)Cumulative Effect, Period of Adoption, Adjustment	[1]	Retained Earnings	Retained EarningsCumulative Effect, Period of Adoption, Adjustment	Non-Controlling Interest	Non-Controlling InterestCumulative Effect, Period of Adoption, Adjustment
Beginning Balance at Dec. 31, 2018	$ 8,358			$ 5,816		$ 1,004		$ 84		$ 338				$ 1,075		$ 41
Net income from operations of Emera Incorporated	710			0		0		0		0				708		2
Other comprehensive loss, net of tax	(244)	[2]		0		0		0		(243)				0		(1)
Dividends declared on preferred stock (note 28)	(45)			0		0		0		0				(45)		0
Dividends declared on common stock	(565)			0		0		0		0				(565)		0
Common stock issued under purchase plan	195			195		0		0		0				0		0
Issuance of common stock, net of after-tax issuance costs	99			99		0		0		0				0		0
Senior management stock options exercised	97			104		0		(7)		0				0		0
Issuance of preferred shares of GBPC, net of issuance costs (note 29)	14			0		0		0		0				0		14
Redemption of preferred shares of GBPC (note 29)	(19)			0		0		0		0				0		(19)
Other	1			2		0		1		0				0		(2)
Ending Balance at Dec. 31, 2019	8,601			6,216		1,004		78		95				1,173		35
Net income from operations of Emera Incorporated	984			0		0		0		0				983		1
Other comprehensive loss, net of tax	(174)	[2]		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		$ (7)	$ 6,705	$ 0	$ 1,004	$ 0	$ 79	$ 0	$ (79)		$ 0		$ 1,495	$ (7)	$ 34	$ 0
Accounting Standards Update [Extensible List]	Accounting Standards Update 2016-13 [Member]
[1]	(1) Accumulated Other Comprehensive Income (Loss) ("AOCI") ("AOCL")
[2]	5) Net of tax expense of $2 million (2019 - $10 million expense) for the year ended December 31, 2020.

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Consolidated Statements of Changes in Equity
Other comprehensive loss, tax expense/recovery	$ 2	$ 10
Dividends per common share declared	$ 2.475	$ 2.375

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
1. Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	1 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution. At December 31, 2020, Emera’s reportable segments include the following:  Florida Electric Utility , which consists of Tampa Electric , a vertically integrated regulated electric utility, serving approximately 792,500 customers in West Central Florida ;  Canadian Electric Utilities, which includes:  Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving a pproximately 529,000 customers ; and  Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consis ting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy . ENL’s two investments are:  a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $ 1.6 billion transmission project, including two 170 -kilometre sub - sea cables, connecting the island of Newfoundland and Nova Scotia. This project went i n service on January 15, 2018; and  a 45.6 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $ 3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmis sion of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioni ng the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced that it had paused construction activities at the Muskrat Falls site and resumed work in May 2020. Nalcor achieved first power on the first of four generators at Muskrat F alls on September 22, 2020 and continues to work toward completing project commissioning in 2021 . Refer to note 27 for further details.  Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:  The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados, serving approximately 131,000 customers;  Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island, serving approximately 19,000 customers;  a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertic ally integrated regulated electric utility on the island of Dominica, serving approximately 34,000 customers; and  a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integra ted regulated electric utility on the island of St. Lucia. On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the Other Electric Utilities segment. Refer to note 4 for further information.  Gas Utilities and Infrastructure, which includes:  Peoples Gas System (“PGS”), a regulated gas distribution utility, serving approximately 426,000 customers across Florida;  New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving a pproximately 540,000 customers in New Mexico;  SeaCoast Gas Transmission , LLC (“SeaCoast ”), a regulated intrastate natural gas transmission company offering services in Florida ;  Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145 -kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New B runswick to the United States border under a 25 -year firm service agreement with Repsol Energy Canada, which expires in 2034 ; and  a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400 -kilometre pipeline, which transpor ts natural gas throughout markets in Atlantic Canada and the northeastern United States.  Emera’s other reportable segment includes investments in energy-related non-regulated companies which includes:  Emera Energy, which consists of:  Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;  Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn , Nova Scotia; and  a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.  Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera;  Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera;  Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and  other investments. In 2019, the Company completed the sale of assets previously included in the Other segment, including Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services (“EUS”) equipment and inventory. In 2020, the outbr eak of the novel strain of coronavirus, specifically identified as COVID-19, has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of COVID-19 in the Company’s estimates and results, the financial statements as of and for the year ended December 31, 2020 were not materially impacted by COVID-19. However, it is not possible to reliably estimate the length and severity of the COVID-19 pandemic and the impact on the financial results and condition of the Company in future periods. Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Acc ounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless othe rwise indicated. Principles of Consolidation The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Ref er to note 32 for further details. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary . The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leas es, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general (“OM&G”), depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, allowance for credit losses, accumulated reserve for cost of removal , pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Mana gement evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the ye ar they arise. During the year ended December 31, 2020 , the ongoing COVID-19 pandemic has affected all service territories in which Emera operates . The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings primarily due to a favourable change to the mix of sales across customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. Favourable weather in 202 0, particular in Florida, has further reduced the consolidated impact . Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These m easures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter - in - place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility. Governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions. Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and concluded that no material adjustments are required for the year ended December 31, 2020 . Refer to Asset Impairment: Long-Lived Assets, Asset Impairment: Goodwill and Employee Benefits below for additional details on area’s that could be more significantly impacted . The extent of future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic , timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these e stimates. Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an opportunity for a reasonable rate of return on the equity invested or assets, as applicable (refer to n ote 7 for additional details). Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to Canadian dollars at the rates of exchange prevail ing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en ominat ed debt held in Canadian dollar functional currency companies as hedges of net investments in United States dollar d enominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balan ce sheet date is recorded in Other Comprehensive Income (“OCI”). Revenue Recognition Regulated Electric Revenue Electric revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity is delivered to customers over time as t he customer simultaneously receives and consumes the benefits of the electricity . Electric revenues are recognized on an accrual basi s and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi- monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calcul ated by estimating the number of m egawatt hour (“MWh”) delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-p eriod changes to customer classes. Regulated Gas Revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, whi ch is when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expecte d to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Non-regulated Revenue Marketing and trading margi ns are comprised of Emera Energy’s corresp onding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of a contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Capacity payments are recognized when obligations under the terms of a contract are satisfied, whic h is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an auction process held annually, three years in advance, through the forward capacity market. Other non- regulated revenues are recorded when obligations under terms of a contract are satisfied. Other Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Leases The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys t he right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense ass ociated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets are recognized on the Consolidated Balance Sheets based on t he present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type l ease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cos t of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leas es, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. 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 Electric and PGS recover from customers certain costs i ncurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” r evenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consoli dated Statements of Income. Property, Plant and Equipment Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of cons truction. The cost of additions, including betterments and replacements of units of property, plant and equipment are included in “P roperty, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gai n or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are inc luded in income as the dispositions occur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement oblig ations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs , along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance proj ects are expensed as incurred. Planned major maintenance projects that do not increase th e overall life of the related as sets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of de preciable property. For some of Emera’s rate- regulated subsidiaries depreciation is calculated using the group remaining life method , which is applied to the average investment , adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and equip ment” consist primarily of computer software and land rights . Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate- regulated subsidiaries, amortization is calculated using the amortizable life method which is app lied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the e stimated fair values of identifiable assets acquired and liabilities as sumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairmen t at the reporting unit level annually or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value . Refer to note 22 for further de tail. Income Taxes and Investment Tax Credits Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial sta tements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differ ences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted unless required to be offset to a regulatory asset or liability by law or by order of the regulator . Emera recognizes the effect of income tax positions only when it is more likely than not that they will be rea lized. Management reviews all readily available current and historical information, including forward-l ooking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax as sets and liabilities are made. If management subsequently d etermines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are rec orded as a reduction to income tax expense in the current or future periods to the extent that realization of such be nefit is more likely than not. Investment tax credits earned by Tampa Electric, PGS and NMGC on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by regulatory practices. Tampa Electric, PGS, NMGC, BLPC and Domlec collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSP I, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective i ncome tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax ass ets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 10 for further details. Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange , interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures , options, forwards and swaps. In addition, the Company has contracts for the physical pur chase and sale of natural gas. These physical and financial contracts are classifie d as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are co nsidered derivatives. The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and no rmal sales (“NPNS”) exception. A physical contract generally qualifies for t he NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodi ty, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet string ent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the re lated hedged item is realized. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the repor ting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item wh en the hedged item is settled. Management believes any gains or losses resulting from settlement of these deriv atives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a Florida Public Service Commission approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period . The Company h as not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inve ntory and property, operating maintenance and general and plant and equipment, depending on the nature of the i tem being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an a sset in “ Receivables and other current asset s” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolid ated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collater al with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”. Cash , Cash Equivalents and Restricted Ca sh Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Receivables and Allowance for Credit Losses Utility c ustomer receivables are recorded at the invoiced am ount and do not bear interest. Standard payment terms for electricity and gas sa les are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company is exposed to credit risk with respect to amounts receivable from cu stomers. Credit assessments may be conducted on new customers. Deposits are requested on accounts in accordance with the Company’s policy. The Company also maintains provisions for expected credit losses, which are assessed on a regular basis. Management estimates credit losses related to accounts receivable after considering historical loss experience, customer deposits, current events , the charact eristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount . Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adeq uate to cover expected losses. Receivables are written off agai nst the allowance when they are deemed uncollectible. The economic impact of COVID-19, in the service territories in which Emera operates, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables however it has not had a material impact on earnings . Inventory Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realiza

Change in Accounting Policy

Change in Accounting Policy	12 Months Ended
	Dec. 31, 2020
2. Change in Accounting Policy
Change in Accounting Policy	2 . C HANGE IN ACCOUNTING POLICY The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2020, are described as follows: Measurement of Credit Losses on Financial Instruments The Company adopted Accounting Standard Update (“ASU”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain othe r instruments that are not accounted for at fair value through net income . These include trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the curr ent incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requ irements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $ 7 million decrease to retained earnings in the consolidated financial statements as of January 1, 2020 . Simp lifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 relate d to the approach for intraperiod tax allocation. It also simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard is applied on both a prospective and retrospective basis. The Company earl y adopted the standard effective January 1, 2020 . There was no impact on the consolidated financial statements as a result of the adoption of this standard. Facilitation of the Effects of Reference Rate Reform on Financial Reporting The Company adopted A SU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting in Q4 2020. The standard provides option s and exceptions for applying USGAAP to contract modifications and hedging relationships that reference the London Inter-Bank Offered Rate (“LIBOR”) or any other reference rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2 022. The Company’s transition from reference rates will not have a material impact on the consolidated financial statements. In November 2020, the Federal Reserve extended the phase-out of LIBOR until June 2023. The Company will continue to monitor the impact this may have on application of the standard.

Future Accounting Pronouncement

Future Accounting Pronouncements	12 Months Ended
	Dec. 31, 2020
3. Future Accounting Pronouncements
Future Accounting Pronouncements	3 . FU TURE ACCOUNTING PRONOUNC E MENTS The Company considers the applicability and impact of all ASUs issued by the FASB. The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applica ble to the Company or have an insignificant impact on the consolidated financial statements. Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity In August 2020, the FASB issued ASU 2020-06, Debt - Debt with Conversion and Oth er Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40). The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to a mending 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. The guidance will be effective for annual reporting periods, includi ng interim reporting within those periods, beginning after December 15, 2021. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020. The standard can be applied through either a modified retrospective method of tr ansition or a fully retrospective method of transition. The Company early adopted the standard effective January 1, 2021 using the modified retrospective method . There was no material impact on the consolidated financial statements as a result of the adoption of this standard. Guaranteed Debt Securities Disclosure Requirements In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in the standard aligns with new SEC rules relating to change s to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying disclosure , enhancing certain narrative disclosures and permitting the disclosures to be made outside of th e financial statements. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated fin ancial statements .

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2020
4. Dispositions
Dispositions	4 . DISPOSITIONS On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of approximately $ 2.0 billion including cash proceeds of $ 1.4 billion, transferred debt and working capital adjustments. A gain on disposition of $ 585 million ($ 309 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Consolidated Statements of Income . Emera Maine’s assets and liabilities were classified as held for sale at March 25, 2019. The Company continued recording depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates a nd was reflected in the carryover basis of the assets on completion of the sale. A total of $ 53 million of depreciation and amortization was recorded on these assets from March 25 , 2019, the date they were classified as held for sale, until the date of the sale. $ 39 million of the $ 5 3 million was recorded in 2019. Emera Maine’s assets and liabilities were included in the Company’s Other Electric Utilities segment.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2020
5. Segment Information
Segment Information	5 . SEGMENT INFORMATION 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 a nd total assets, as reported to the Company’s chief operating decision maker. Emera’s five reportable segments are Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other . 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) - Total operating revenues 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 - - - - 585 - 585 Impairment charges - - - - 25 - 25 Income tax expense (recovery) 89 17 (8) 51 192 - 341 Net income (loss) 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) (3) 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 have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs. (3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax 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, 2019 Operating revenues from external customers (1) $ 2,596 $ 1,429 $ 744 $ 1,097 $ 245 $ - $ 6,111 Inter-segment revenues (1) 11 1 - 22 37 (71) - Total operating revenues 2,607 1,430 744 1,119 282 (71) 6,111 Regulated fuel for generation and purchased power 772 573 286 - - (22) 1,609 Regulated cost of natural gas - - - 350 - - 350 OM&G 554 313 195 319 130 (47) 1,464 Depreciation and amortization 445 231 107 109 11 - 903 Income from equity investments - 91 5 22 36 - 154 AFUDC - debt and equity 20 6 5 2 - - 33 Interest expense, net 154 142 52 59 331 - 738 Internally allocated interest (2) - - - 14 (14) - - Impairment charges - - 34 - - - 34 Income tax expense (recovery) 79 (10) 11 48 (67) - 61 Net income (loss) attributable to common shareholders 419 229 45 183 (213) - 663 Capital expenditures 1,393 384 195 448 63 - 2,483 As at December 31, 2019 Total assets 16,214 6,717 3,069 5,489 1,459 (1,106) (3) 31,842 Investments subject to significant influence - 1,133 41 138 - - 1,312 Goodwill 4,544 - 70 1,218 3 - 5,835 (1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs. (3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation. Geographical Information Revenues (1) : For the Year ended December 31 millions of Canadian dollars 2020 2019 Canada $ 1,569 $ 1,497 United States 3,522 4,140 Barbados 263 320 The Bahamas 112 112 Dominica 40 42 $ 5,506 $ 6,111 (1) Revenues are based on country of origin of the product or service sold. Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2020 2019 Canada $ 4,304 $ 4,248 United States 14,353 13,095 Barbados 510 462 The Bahamas 289 282 Dominica 79 80 $ 19,535 $ 18,167

Revenue

Revenue	12 Months Ended
	Dec. 31, 2020
6. Revenue
Revenue	6 . REVENUE The following disaggregates the Company’s revenue by major source: 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 Regulated electric revenue 2,480 1,494 474 1 - (7) 4,442 Gas Revenue Residential - - - 495 - - 495 Commercial - - - 275 - - 275 Industrial - - - 54 - - 54 Finance income (2)(3) - - - 61 - - 61 Other - - - 156 - (7) 149 Regulated gas revenue - - - 1,041 - (7) 1,034 Non-Regulated Marketing and trading margin (4) - - - - 38 - 38 Energy sales (4) - - - - 16 (16) - Capacity - - - - - - - Other - - - 16 21 - 37 Mark-to-market (3) - - - - (46) 1 (45) Non-regulated revenue - - - 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 represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with 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, 2019 Regulated Electric Revenue Residential $ 1,387 $ 746 $ 276 $ - $ - $ - $ 2,409 Commercial 745 400 339 - - - 1,484 Industrial 207 210 44 - - - 461 Other electric and regulatory deferrals 246 45 13 - - - 304 Other (1) 22 29 72 - - (12) 111 Regulated electric revenue 2,607 1,430 744 - - (12) 4,769 Gas Revenue Residential - - - 502 - - 502 Commercial - - - 298 - - 298 Industrial - - - 50 - - 50 Finance income (2)(3) - - - 60 - - 60 Other - - - 193 - (22) 171 Regulated gas revenue - - - 1,103 - (22) 1,081 Non-Regulated Marketing and trading margin (4) - - - - 31 - 31 Energy sales (4) - - - - 80 (12) 68 Capacity - - - - 38 - 38 Other - - - 16 31 (25) 22 Mark-to-market (3) - - - - 102 - 102 Non-regulated revenue - - - 16 282 (37) 261 Total operating revenues $ 2,607 $ 1,430 $ 744 $ 1,119 $ 282 $ (71) $ 6,111 (1) Other includes rental revenues, which do not represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers. Remaining Performance Obligations Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of December 31, 2020 , the aggregate amount of the transaction price allocated to remaining performance obligations was $ 464 million ( 2019 – $ 347 million). This amount includes $ 149 million of future performance obligations related to a gas transportation contract between SeaC oast and PGS through 2040. T his amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining perf ormance obligations through 2040 .

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2020
7. Regulatory Assets and Liabilities
Regulatory Assets and Liabilities	16 . REGULATORY ASSETS AND LIABILITIES Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or t olls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the app licable regulator, or due to regulatory precedent establis hed for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charge d to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future reve nues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognize d in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. Regulatory Assets and Liabilities As at December 31 December 31 millions of Canadian dollars 2020 2019 Regulatory assets Deferred income tax regulatory assets $ 887 $ 862 Pension and post-retirement medical plan 394 380 Deferrals related to derivative instruments 65 81 Cost recovery clauses 49 13 Storm restoration regulatory asset 41 38 Environmental remediations 28 26 Stranded cost recovery 26 27 Demand side management ("DSM") deferral 15 19 Unamortized defeasance costs 13 19 Other 66 87 $ 1,584 $ 1,552 Current $ 165 $ 121 Long-term 1,419 1,431 Total regulatory assets $ 1,584 $ 1,552 Regulatory liabilities Deferred income tax regulatory liabilities 933 985 Accumulated reserve - cost of remova l 865 891 Storm reserve 62 62 Cost recovery clauses 31 53 Self-insurance fund (note 32) 28 29 Regulated fuel adjustment mechanism 21 115 Deferrals related to derivative instruments 15 42 Other 6 4 $ 1,961 $ 2,181 Current $ 129 $ 295 Long-term 1,832 1,886 Total regulatory liabilities $ 1,961 $ 2,181 Deferred Income Tax Regulatory Assets and Liabilities To the extent deferred income taxes are expected to be recovered from or returned to customers in future year s, a regulatory asset or liability is recognized as appropriate . Pension and Post-Retirement Medical Plan This asset is primarily related to th e deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC . It is included in rate base and earns a rate of return as permitted by the FPSC and New Mexico Public Regulation Commission (“NMPRC”) as applicable. It is amortized over the remaining service life of plan participants. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in fair value of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by its regulator. The realized gain or loss is recognized when the hedged item settles in regulated fuel for genera tion and purchased power, inventory, operating, maintenance or general or property, plant and equipment, depending on the nature of the item being economically hedged. Cost Recovery Clauses These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in a subsequent period . Storm Restoration Regulatory Asset This asset represents storm restoration costs, primarily incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are self-insured. On September 1, 2019, Hurricane Dori an struck Grand Bahama Island as a Category 5 hurricane, with sustained winds of approximately 285 kilometres per hour. The hurricane stalled over the island for several days, causing significant damage to, or destruction of, homes and businesses served by GBPC. GBPC’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $ 1 5 million USD of costs related to the storm over a five -year period. The recovery was implemented through rates on January 1, 2021. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge over a five -year period. Additional details on the recovery are included under the Grand Bahama Power Company Limited section below. The balance of the regulatory asset as at December 31, 2020 is $ 18 million USD . Environmental Remediations This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites . The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. T he timing of recovery is based on a settlement agreement approved by the FPSC. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $ 21 million USD stranded cost through electricity rates; it is included in rate base and is expected to be included in rates in future years. DSM Deferral The Nova Scotia Utility and Review Board (“ 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 appointed by the Province of Nova Scotia to provide NSPI wit h electricity efficiency and conservation activities under the Public Utilities Act , to review financing options through which EfficiencyOne would borrow the 2015 deferral amount from a commercial lender in order to repay NSPI the amount it expended on beh alf of its customers in 2015. In December 2016, EfficiencyOne secured financing and $ 31 million was advanced to NSPI to finance the 2015 DSM deferral. In February 2017, EfficiencyOne advanced an additional $ 2 million to NSPI. As NSPI collects the associate d amounts from customers over the remaining three years , it will repay the balance to EfficiencyOne. This has been set up as a liability in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on t he Consolidated Balance Sheets. Unamortized Defeasance Costs Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and inte rest streams to match the related defeased debt, which as at December 31, 2020 , totalled $ 582 million ( 2019 – $ 740 million). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amorti zed over 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 in Tampa Electric , PGS, NMGC and NSPI. AROs are costs for legally required removal of property, plant and equipment. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equ ipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. Storm Reserve The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a re gulatory asset. Tampa Electric and PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. In September 2019, Tampa Electric incurred approximately $ 8 m illion USD in storm restoration preparation costs for Hurricane Dorian. These costs were charged to the storm reserve regulatory liability. Regulated Fuel Adjustment Mechanism This regulated liability is the difference between actual fu el costs and amounts recovered from NSPI customers through electricity rates in a given year, and deferred to a fuel adjustment mechanism (“FAM”) regulatory asset or liability and recovered from or returned to customers in a subsequent year. As approved on December 6, 2019 as part of NSPI’s three-year Fuel Stability Plan, differences between actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be recovered or returned to customers after 2022. The UARB’s decision to a pprove the Fuel Stability Plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM. Regulatory Environments Florida Electric Utility Tampa Electric is regulated by the FPSC. Tampa Electric 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’s approved regul ated return on equity (“ROE”) range for 2020 and 2019 is 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.25 per cent is used for the calculation of the return on investments for clauses. Fuel Recovery Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in a subsequent year. Base rates On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting incremental revenue requirements of approximately $ 280 million USD to $ 295 million USD, effective January 2022. Tampa Electric’s proposed rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investm ent, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $ 130 million USD to recover the costs of the second phase of the Big Bend modernization p roject and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes and files its detailed case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and a decision by the FPSC is expected by the end of 2021. On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs as a result of Hurricane Irma in 2017, which was approved by the FPSC on May 21, 20 19. As a result, Tampa Electric refunded $ 12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income. On August 20, 2018, the FPSC approved a reduction in base rates of $ 103 million USD annually begin ning in 2019 as a result of lower tax expense due to 2018 US tax reform benefits. Solar Base Rate Adjustments Included in Base Rates As of December 31, 2020, Tampa Electric has invested $ 820 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). Tampa Electric expects to invest an additional $ 30 million USD in these projects through 202 1 . AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $ 104 million USD annually in estimated revenue requirements for in-service projects. The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $ 5 million USD true-up was returned to customers in 2020. The true-up s for SoBRA tranche s 3 and 4 will be filed in 2021 and 2022, respectively . Storm Protection Cost Recovery Clause and Settlement Agreement On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“ SPP”) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tam pa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $ 15 million USD base rate reduction for SPP program costs previously recover ed in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $ 39 millio n USD in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $ 15 million USD of costs removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery beg a n in Janu ary 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024 , and 2025. The June 9, 2020 settlement agreement approved by the FPSC disclosed abov e also included approval of Tampa Electric’s petition to eliminate its $ 16 million USD accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. Big Bend Modernization Project Tampa Electric has invested approximately $ 526 million USD through December 31, 2020 to modernize the Big Bend Power Station. The modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’ s fuel. On June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 1, 2020 and December 31, 2020 , the balance sheet included $ 304 million ($ 223 million USD) and $ 255 million ($ 200 million USD) respe ctively, in electric utility plant and $ 123 million ($ 90 million USD) and $ 112 million ($ 88 million USD) respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the F PSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric was not required to request an asset recovery schedule for retired assets until the next depreciation study. On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedules with the FPSC. Tampa Electric plans to retire Big Bend Unit 3 in 2023. Similar to the retirement plan for Unit 1 and Unit 2, Tampa Electric will continue to account for its existing investment in Unit 3 in electric utility plant and depreciate the assets using the curren t depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study . Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject t o UARB approval. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2020 and 2019 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, approved by UARB which enables it to seek recovery of its fuel costs from customers through regularly scheduled fuel rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. NSPI is currently operating under a three -year f uel s tability p lan which results in an average annual overall rate increase of 1.5 per cent to recover f uel c osts for the period of 2020 through 2022. These rates include recovery of Maritime Link costs. The Maritime Link is a $ 1.6 billion transmission project including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments to NSPML at that time. The UARB approved 2020 interim cost assessment recovery payment to NSPML was $ 145 million and as of December 31, 2020 $ 135 million has been paid. The payments were subject to a holdback of $ 10 million pending UARB agreement that a minim um of $ 10 million in benefits from the Maritime Link are realized for NSPI customers. If the $ 10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pa y to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. For 2020, NSPI has recorded a $ 4 million holdback payable to NSPML. On December 16 , 2020, the UARB approved NSPML’s 2021 interim cost assessmen t recovery from NSPI of Maritime Link costs of approximately $ 172 million subject to a holdback of $ 10 million on similar terms as previously approved by the UARB . It also includes a potential long-term deferral of up to $ 23 million in depreciation expense dependent upon the timing of commencement of the Nova Scotia Block (“NS Block”) . Refer to the NSPML section below for further detail. As part of a three -year f uel s tability p lan, electricity rates have been set to include the $ 145 million approved Maritime Link assessment for 2020 and estimate amounts of $ 164 million and $ 162 million for 2021 and 2022, respectively. Any difference between the amounts included in the Fuel Stability Plan and those approved by the UARB through the NSP ML interim assessment application will be addressed through the 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 payments re flected a reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. NSPI refunded the reduced 2018 NSPML assessment to customers in 2018 and 2019, by providing a credit to customers of $ 17 million and $ 35 million, respectively. The UARB’s decision to approve NSPI’s 2020-2022 f uel s tability p lan outlined the treatment of the reduced 2019 NSPML assessment of $ 52 million plus interest. The majority of the reduced assessment was refunded to most customers through a reduction incorporated into their 2020 rates and the remaining customers received a one-time on bill credit in 2020 . As at December 31, 2020, $ 40 million plus interest has been refunded to cu stomers, with the remaining $ 12 million plus interest to be returned to customers subsequent to 2022 . Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On August 21, 2020, the FAM audit results for 2018 and 2 019 were filed with the UARB. A hearing was held in January 2021 and a decision is expected in Q 2 2021 . On March 13, 2020, the UARB’s decision on the FAM audit findings and recommendations relating to fiscal 2016 and 2017 was released. The final recommendations did not include any disallowances. NSPML Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent. On December 16, 2020 the UARB approved NSPML’s 2021 interim assessment for recovery of Maritime Link costs from NSPI of approximately $ 172 million (2020 - $ 145 million). This payment is subject to a holdback of $ 10 million on similar terms as previously approved by the UARB. Recovery of $ 115 million of operating and maintenance, debt financing and equity financing costs began on January 1, 2 021. Recovery of $57 million of depreciation and amortization will commence the sooner of the delivery of the NS Block or May 1, 2021. With cooperation of the Government of Canada, NSPML may also utilize up to $ 2 3 million of cash in a debt related reserve account to reduce the recovery of costs from NSPI in 2021, depending upon when the NS Block commences. NSPML will file a final cost assessment with the UARB after the commencement of the NS Block which is anticipated to take place in 2021 . Other Electric Utilities The Barbados Light & Power Company Limited BLPC is regulated by the Fair Trading Commission (“FTC”) , an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated licen se which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is currently negotiating the terms of the new licenses under the amended legislation. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide an appropriate return to investors. BLPC’s approved regulated return on rate base was 10 per cent for 2020 and 2019 . On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC in Q1 2021. BLPC has a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The approved calculation of the fuel charge is adjusted monthly and reported to the regulator. In December 2018, the Government of Barbados signed the Income Tax Amendment Act into law. This legislation , which was effective January 1, 2019, created a new corporate income tax rate schedule and eliminated certain tax credits. At the date of enactment, BLPC was required to remeasure its deferred income tax liability at the new lower corporate in come tax rate, resulting in recognition of an income tax recovery of $ 9.6 million USD of which $ 6.9 million USD was deferred as a regulatory liability, all of which was recognized in earnings in Q1 2020. Grand Bahama Power Company Limited GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. GBPC’s approved regulated return on rate base was 8.34 per cent for 2020 (2019 - 8.5 per cent). In January 202 1 , the GBPA approved GBPC’s regulated return on rate base of 8.37 per cent for 2021. In December 2016, the GBPA appr oved that the all-in rate for electricity (fuel and base rates) would be held at 2016 levels over the five -year period from 2017 through 2021. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of five ye ars, GBPC will have the opportunity to request recovery from customers in future rates. Dominica Electricity Services Ltd Domlec is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1 , 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base was 1 5 per cent for 2020 and 2019. Domlec has a fuel pass-through mechanism which provides opportunity to recover substantially all prudently incurred fuel costs in a timely manner . Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. PGS’s approved ROE r ange for 2020 and 2019 was 9.25 per cent to 11.75 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 10.75 per cent was used for the calculation of return on investments for clauses. PGS recovers the costs it pays for gas s upply and interstate transportation for system supply through its purchased gas adjustment clause. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers . These charges may be adjusted monthly based on a cap approved annually by the FPSC. The FPSC annually approves cost-recovery rates for conservation costs a nd Cast Iron/Bare Steel Pipe Replacement costs, including a return on capital invested incurred in developing and implementing energy conservation programs. The Cast Iron/Bare Steel Pipe Replacement clause is to recover the cost of accelerating the replace ment of cast iron and bare steel distribution lines in the PGS system. The FPSC approved a replacement program of approximately 5 per cent, or 800 kilometres, of the PGS system at a cost of approximately $ 80 million USD over a 10 -year period beginning in 2013 . In February 2017, the FPSC approved an amendment to the cast iron bare steel rider to include certain plastic materials and pipe deemed obsolete by Pipeline and Hazardous Materials Safety Administration, totaling approximately 880 kilomet re s . PGS estimates that all cast iron and bare steel pipe will be removed from its system by 2022, with the replacement of obsolete plastic pipe continuing until 2028 under the rider . PGS was permitted to initiate a general base rate proceeding during 2020 , provided the new rates do not become effective before January 1, 2021. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. T he settlement agreement allows for an increase to base rates by $ 58 million USD annually effective January 2021, which is a $ 34 million USD increase in revenue and $ 24 million USD increase of revenues previously recovered through the cast iron and bare ste el replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint. It provides PGS the ability to reverse a total of $ 34 million USD of accumulated depreciation through 20 23 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’ s current overall average depreciation rate. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were t o fall below 8.9 per cent before that time with an allowed equity in the capital structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. NMGC’s approved ROE for 2020 was 9.10 per cent and for 2019 ranged from 9.10 - 10.0 per cent . Beginning January 1, 2021, t he approved ROE is 9.375 per cent, on an allowed equity capital structure of 52 per cent. NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. On a m onthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must fil e a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024 . NMGC filed a rate case in December 2019. NMGC reached an unopposed stipulated settlement of the case which was approved by the NMPRC in December 2020. The new rates reflect the recovery of capital investment in pipelines and related infrastructure and r esults in an increase in revenue of approximately $ 5 million USD annually effective January 2021.The stipulated settlement agreement includes an allowed regulatory ROE 9.375 per cent on an allowed equity capital structure of 52 per cent. Under the agreemen t base rates are frozen from January 1, 2021 to December 31, 2022, unless new federal tax rates are enacted, in which case NMGC can file for new rates to be effective earlier than January 1, 2023. On July 17, 2019, the NMPRC approved a rate increase for N MGC effective August 2019 and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates were phased in over two years , resulting in an annual revenue increase of approximately $ 3 million USD. The deferred income tax regulatory liability of $ 11 million ($ 8 million USD) recorded at December 31, 2018 to reflect deferred tax benefits was recognized in revenue in Q2 2019. The NMPRC also approved the utility’s weather adjustment mechanism. This clause is designed to lower the variability of weather impacts during the heating season period of October through April annually. The Weather Normalization Mechanism will make customer rates and Company revenue more predictable by minimizing the impact of warmer than usual or colder than usual weather. Revenue increases or decreases captured in the weather normalization mechanism from October to April will be adjusted annually in October of the following heating season. Beginning in August 2019, the NMPRC approved a change in the treatment of net operating loss carryforwards. As a result of this change, a tax benefit of approximately $ 7 million ($ 5 million USD) was recognized in earnings in Q3 2019. Brunswick Pipeline Brunswick Pipeline is a 145 -k ilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to market

Investments Subject to Signific

Investments Subject to Significant Influence and Equity Income	12 Months Ended
	Dec. 31, 2020
8. Investments Subject to Significant Influence and Equity Income
Investments Subject to Significant Influence and Equity Income	7 . INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2020 2019 2020 2019 2020 LIL (1) $ 629 $ 579 $ 49 $ 45 45.6 NSPML 547 554 47 46 100.0 M&NP (2) 129 138 20 22 12.9 Lucelec (2) 41 41 4 3 19.5 Bear Swamp (3) - - 29 35 50.0 Other Investments - - - 3 $ 1,346 $ 1,312 $ 149 $ 154 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL ‎is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp's credit investment balance of $118 million (2019 - $137 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Equity investments include a $ 12 million difference between the cost and the underlying fair value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 32 ). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2020 2019 Balance Sheets Current assets $ 57 $ 69 Property, plant and equipment 1,629 1,671 Regulatory assets 210 177 Non-current assets 32 32 Total assets $ 1,928 $ 1,949 Current liabilities $ 56 $ 23 Long-term debt (1) 1,228 1,288 Non-current liabilities 97 84 Equity 547 554 Total liabilities and equity $ 1,928 $ 1,949 (1) The project debt has been guaranteed by the Government of Canada.

Other Income (Expenses), Net

Other Income (Expenses), Net	12 Months Ended
	Dec. 31, 2020
9. Other Income (Expenses), Net
Other Income (Expenses), Net	8 . OTHER INCOME (EXPENSES), NET Other income (expenses), net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2020 2019 Allowance for equity funds used during construction $ 45 $ 21 Gain on sale of Emera Maine, net of transaction costs (1) 585 - TECO Guatemala Holdings award (2) 49 - Other 29 (9) $ 708 $ 12 (1) Refer to note 4 for further detail related to the gain on sale of Emera Maine. (2) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
10. Income Taxes
Income Taxes	9 . INCOME TAXES The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of Canadian dollars 2020 2019 Income before provision for income taxes $ 1,325 $ 771 Statutory income tax rate 29.5% 31% Income taxes, at statutory income tax rate 391 239 Additional impact from the sale of Emera Maine 102 - Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (48) (66) Foreign tax rate variance (45) (49) Amortization of deferred income tax regulatory liabilities (44) (36) Tax effect of equity earnings (15) (15) Other - (12) Income tax expense $ 341 $ 61 Effective income tax rate 26% 8% The increase in the effective income tax rate was primarily due to the sale of Emera Maine. On March 10, 2020, Bill 243 of the Nova Scotia Financial Measures (2020) Act ("the Financial Measures Act") was enacted, which included a reduction in the Nova Scotia provincial corporate income tax rate from 16 per cent to 14 per cent. As a result, the Company's combined Canadian federal and provincial statutory income tax rate w as reduced from 31 per cent to 29.5 per cent for 2020 and further reduced to 29 per cent for subsequent years. As a result of this , the Company , in Q1 2020, was required to revalue certain of its Canadian deferred income tax assets and liabilities based o n the new tax rates. The Company recorded a reduction of $ 52 million to its net deferred income tax liabilities and an offsetting reduction to its net deferred income tax regulatory asset, as the benefit of lower net deferred income tax liabilities is expe cted to be returned to customers in future years. The Company also recognized a $ 12 million income tax expense in Q1 2020 as a result of the revaluation of certain net deferred income tax assets. On March 25, 2020, Bill C-13, the Canadian COVID-19 Emergen cy Response Act (“the COVID-19 Act”) was enacted, guaranteeing rapid implementation and administration of measures to protect Canadians’ health and safety, and stabilize the economy. In addition, the Government of Canada announced the opportunity for busin esses to defer certain tax payments. There have been no material impacts to Emera’s financial position from the COVID-19 Act or the Government of Canada’s announcements. On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security ( CARES) Act (“the CARES Act”) was signed into law. The CARES Act includes several business provisions including deferral of employer payroll taxes, an employee retention payroll tax credit, temporary changes to business interest expense disallowance rules, changes to net operating loss carryback and limitation rules and corporate alternative minimum tax (“AMT”) relief. Under the new AMT provisions, companies can accelerate the refund of AMT credit carryforwards. As a result, in Q1 2020, the Company reclassif ied $ 77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets. The Company received $ 145 million of refundable AMT credit carryforwards in Q4 2020. The Company has not had any other material impacts fr om the CARES Act. The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2020 2019 Current income taxes Canada $ 18 $ (19) United States (58) (46) Other - 1 Deferred income taxes Canada 20 45 United States 426 137 Other (9) - Investment tax credits United States (10) (9) Operating loss carryforwards Canada (46) (48) Income tax expense $ 341 $ 61 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2020 2019 Canada $ 176 $ 98 United States 1,142 682 Other 7 (9) Income before provision for income taxes $ 1,325 $ 771 The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of Canadian dollars 2020 2019 Deferred income tax assets: Tax loss carryforwards $ 724 $ 908 Tax credit carryforwards 319 311 Regulatory liabilities - cost of removal 184 195 Derivative instruments 108 145 Other 375 413 Total deferred income tax assets before valuation allowance 1,710 1,972 Valuation allowance (202) (193) Total deferred income tax assets after valuation allowance $ 1,508 $ 1,779 Deferred income tax (liabilities): Property, plant and equipment $ (2,450) $ (2,382) Derivative instruments (93) (148) Other (385) (348) Total deferred income tax liabilities $ (2,928) $ (2,878) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 209 $ 186 Long-term deferred income tax liabilities (1,629) (1,285) Net deferred income tax liabilities $ (1,420) $ (1,099) Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and unrealiz ed capital losses on investments. A valuation allowance of $ 202 million has been recorded as at December 31, 2020 (2019 - $ 193 million) related to the loss carryforwards and investments. The Company intends to indefinitely reinvest earnings from certain forei gn operations. Accordingly, $ 2.7 billion as at December 31, 2020 ( 2019 - $ 1.9 billion) in cumulative temporary differences for which deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2020 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 1,370 $ (619) $ 751 2027 - 2040 Capital loss 61 (61) - Indefinite United States Federal NOL $ 1,412 $ - $ 1,412 2030 - 2040 State NOL 563 - 563 2032 - 2040 Tax credit 319 - 319 2025 - 2040 Other NOL $ 39 $ (39) $ - 2021 - 2027 The following table provides details of the change in unrecogni zed tax benefits for the years ended December 31 as follows: millions of Canadian dollars 2020 2019 Balance, January 1 $ 29 $ 26 Increases due to tax positions related to current year 1 2 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (2) - Balance, December 31 $ 30 $ 29 The total amount of unrecognized tax benefits as at December 31, 2020 was $ 30 million ( 2019 - $ 29 million), which would affect the eff ective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $ 6 million ( 2019 - $ 5 million) with $ 1 million of interest expense recognized in the Consolidated Statements of Income (2019 - $ 1 million). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and I nternal Revenue Service audits. A reasonable estimate of any change cannot be made at this time. NSPI and the CRA are currently in a dispute with respect to th e timing of certain tax deductions for NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $ 62 million, including interest. NSPI has prepaid $ 23 million of the amount in dispute, as required by CRA. On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute. Should NSPI be successful in defending its positio n, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years. Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Appeal process is not determinable at this time. Eme ra files a Canadian federal income tax return, which includes its Nova Scotia and New B runswick provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income tax return s. As at December 31, 2020 , the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2020
11. Common Stock
Common Stock	10 . COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2020 2019 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2019 242.48 $ 6,216 234.12 $ 5,816 Conversion of Convertible Debentures - - 0.03 1 Issuance of common stock (1) (2) 4.54 251 1.77 99 Issued under Purchase Plans at market rate 3.99 219 3.99 202 Discount on shares purchased under Dividend Reinvestment Plan - (4) - (7) Options exercised under senior management share option plan 0.42 20 2.57 104 Employee Share Purchase Plan - 3 - 1 Balance, December 31, 2020 251.43 $ 6,705 242.48 $ 6,216 (1) As at December 31, 2019, a total of 1,768,120 common shares were issued under Emera's at-the-market program ("ATM program") at an average price of $56.56 per share for gross proceeds of $100 million ($99 million net of issuance costs). (2) For the year ended December 31, 2020, 4,544,025 common shares were issued under Emera's ATM program at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs). On July 11, 2019, Emera established an ATM Program that allows the Company to issue up to $ 600 million of common shares to the public from time to time, at the Company's discretion, at the prevailing market price. The ATM Program was established under a prospectus supplement to the Company’s short-form base shelf prospectus which expires on July 14, 2021. As at Decem ber 3 1 , 20 20 , an aggregate gross sales limit of $ 245 million remains available for issuance under the ATM program. On November 17, 2020, Emera filed an amendment to its July 11, 2019 prospectus supplement which established its ATM program. This amendment reflected changes in securities regulations related to ATM programs which were effective August 31, 2020. The amendment includes removal of the daily trading limit which previously provided that the number of shares sold could not exceed 25 per cent of the daily trading volume of the shares. As at December 31, 2020 , the following common shares were reserved for issuance: 3.5 million ( 2019 – 3.9 million) under the senior management stock option plan, 3.5 million ( 2019 – 0.9 million) under the employee commo n share purchase plan and 5.1 million ( 2019 – 8.8 million) under the dividend reinvestment plan (“DRIP”). The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 per cent of Emera's outstandin g common shares . As at December 31, 2020 , Emera is in compliance with this requirement.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
12. Earnings Per Share
Earnings Per Share	11 . EARNINGS PER SHARE Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all po tentially dilutive securities. Such dilutive items include Company contributions to the sen ior management stock option plan, convertible debentures and shares issued under the dividend reinvestment plan. The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2020 2019 Numerator Net income attributable to common shareholders $ 937.6 $ 662.8 Diluted numerator 937.6 662.8 Denominator Weighted average shares of common stock outstanding 246.5 238.5 Weighted average deferred share units outstanding 1.3 1.4 Weighted average shares of common stock outstanding – basic 247.8 239.9 Stock-based compensation 0.4 0.6 Weighted average shares of common stock outstanding – diluted 248.2 240.5 Earnings per common share Basic $ 3.78 $ 2.76 Diluted $ 3.78 $ 2.76

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2020
13. Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	12 . ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of accumulated other comprehensive income are as follows: 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 AOCI 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 (gain) - - 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) For the year ended December 31, 2019 Balance, January 1, 2019 (1) $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 Other comprehensive income (loss) before reclassifications (401) 78 3 - - (320) Amounts reclassified from accumulated other comprehensive income loss - - 3 - 74 77 Net current period other comprehensive income (loss) (401) 78 6 - 74 (243) Balance, December 31, 2019 $ 253 $ 4 $ (1) $ (1) $ (160) $ 95 The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2020 2019 Affected line item in the Consolidated Financial Statements Losses on derivatives recognized as cash flow hedges Foreign exchange forwards Operating revenue - regulated $ 2 $ 3 Total before tax 2 3 Total net of tax $ 2 $ 3 Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Other income, net $ 15 $ 17 Past service costs (gains) Other income, net (1) (1) Amounts reclassified into obligations Pension and post-retirement benefits (16) 39 Amounts reclassified into obligations Regulatory assets - 28 Total before tax (2) 83 Income tax recovery (expense) 1 (9) Total net of tax $ (1) $ 74 Total reclassifications out of AOCI, net of tax, for the period $ 1 $ 77

Inventory

Inventory	12 Months Ended
	Dec. 31, 2020
14. Inventory
Inventory	13 . INVENTORY As at December 31 December 31 millions of Canadian dollars 2020 2019 Fuel $ 199 $ 232 Materials 254 235 $ 453 $ 467

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2020
15. Derivative Instruments
Derivative Instruments	14 . DERIVATIVE INSTRUMENTS Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2020 2019 2020 2019 Cash flow hedges Interest rate hedge $ 1 $ - $ - $ - Foreign exchange forwards - - - 1 1 - - 1 Regulatory deferral Commodity swaps and forwards Coal purchases 1 8 6 39 Power purchases 10 23 34 36 Natural gas purchases and sales 4 2 2 5 Heavy fuel oil purchases 1 1 5 - Foreign exchange forwards - 2 17 6 16 36 64 86 HFT derivatives Power swaps and physical contracts 13 19 13 22 Natural gas swaps, futures, forwards, physical contracts 139 151 346 381 152 170 359 403 Other derivatives Equity derivatives - 1 1 - Foreign exchange forwards 15 - - - 15 1 1 - Total gross current derivatives 184 207 424 490 Impact of master netting agreements with intent to settle net or simultaneously (86) (120) (86) (120) 98 87 338 370 Current 73 54 251 268 Long-term 25 33 87 102 Total derivatives $ 98 $ 87 $ 338 $ 370 Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts. Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2020 2019 2020 2019 Regulatory deferral $ 2 $ 8 $ 2 $ 8 HFT derivatives 84 112 84 112 Total impact of master netting agreements with intent to settle net or simultaneously $ 86 $ 120 $ 86 $ 120 Cash Flow Hedges As at December 31, 2020 the Company ha d a t reasury l ock in place to hedge the interest rate risk associated with the refinancing of long-term debt due in June 2021. During 2020 the Company also had foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign c urrency for Brunswick Pipeline. The foreign exchange forwards designated as cash flow hedges settled in 2020 . The amounts related to cash flow hedges recorded in income and AOCI consisted of the following: For the Year ended December 31 millions of Canadian dollars 2020 2019 Foreign Interest Foreign exchange rate exchange forwards hedge forwards Realized gain (loss) in operating revenue – regulated $ (2) $ - $ (3) Total gains (losses) in net income $ (2) $ - $ (3) As at December 31 millions of Canadian dollars 2020 2019 Foreign Interest Foreign exchange rate exchange forwards hedge forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ - $ 1 $ (1) The Company expects $1 million of unrealized gains currently in AOCI to be reclassified into net income within the next 12 months, as the underlying hedged transactions settle. As at December 31, 2020, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2021 U.S. Treasury lock (USD) $ 350 Regulatory Deferral The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral: For the Year ended December 31 millions of Canadian dollars 2020 2019 Commodity swaps and forwards Foreign exchange forwards Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (36) $ (11) $ (89) $ (6) Unrealized gain (loss) in regulatory liabilities 3 3 9 (8) Realized gain (loss) in regulatory assets 2 - - - Realized (gain) loss in regulatory liabilities 14 - (2) - Realized (gain) loss in inventory (1) 8 (2) (36) (11) Realized (gain) loss in regulated fuel for generation and purchased power (2) 24 (3) 3 (8) Total change derivative instruments $ 15 $ (13) $ (115) $ (33) (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. Commodity Swaps and Forwards As at December 31, 2020 , the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below: 2021 2022-2023 millions Purchases Purchases Natural Gas (Mmbtu) 5 7 Power (MWh) 2 2 Heavy fuel oil (bbls) - 1 Coal (metric tonnes) - 1 Foreign Exchange Swaps and Forwards As at December 31, 2020 , the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below: 2021 2022-2023 Foreign exchange contracts (millions of US dollars) $ 160 $ 135 Weighted average rate 1.3339 1.3266 % of USD requirements 78% 37% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required. Held-for-Trading Derivatives In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT. The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: For the Year ended December 31 millions of Canadian dollars 2020 2019 Power swaps and physical contracts in non-regulated operating revenues $ (1) $ 1 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 205 281 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (4) (6) $ 200 $ 276 As at December 31, 2020 , the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: millions 2021 2022 2023 2024 2025 Natural gas purchases (Mmbtu) 387 61 45 26 26 Natural gas sales (Mmbtu) 412 50 17 2 2 Power purchases (MWh) 2 - - - - Power sales (MWh) 1 - - - - Other Derivatives As at December 31, 2020 , the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and foreign exchange forwards in place to manage cash flow risk associated with forecasted US d ollar cash inflows. The equity derivative hedges th e return on 2.8 million shares and extends until December of 202 1. The foreign exchange forwards have a combined notional amount of $ 100 million USD and expire in 2021. For the Year ended December 31 millions of Canadian dollars 2020 2019 Foreign Foreign Exchange Equity Exchange Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in operating, maintenance and general $ - $ (1) $ - $ 1 Unrealized gain (loss) in other income (expense), net 15 - - - Realized gain (loss) in operating, maintenance and general - (3) - 27 Realized gain (loss) in other income (expense) (2) - - - Total gains (losses) in net income $ 13 $ (4) $ - $ 28 Credit Risk The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company man ages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts. The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probabi lity rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated. As at December 31, 2020 , the maximum exposure the Company has to credit risk is $ 805 million ( 2019 - $ 860 million) , which includes accounts receivable n et of collateral/deposits and assets related to derivatives. It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterpa rties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2020 was $ 251 mill ion ( 2019 - $ 259 million) , which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Co mpany. The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISD A”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default. As at December 31, 2020 , the Company had $ 123 million ( 2019 - $ 11 5 million) in financial assets, considered to be past due, which have been outstanding for an average 70 days. The fair value of these financial assets is $ 101 million ( 2019 - $ 106 million), the difference of which is included in the allowance for credit losses . These assets primarily relate to accounts receivable from electric and gas revenue. Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2020 December 31, 2019 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 341 32% $ 344 31% Commercial 143 14% 170 15% Industrial 49 5% 66 6% Other 96 9% 131 12% 629 60% 711 64% Trading group Credit rating of A- or above 54 5% 38 3% Credit rating of BBB- to BBB+ 41 4% 59 5% Not rated 75 7% 95 9% 170 16% 192 17% Other accounts receivable 159 15% 184 16% Classification as assets held for sale (1) - 0% (55) -5% 958 91% 1,032 92% Derivative Instruments (current and long-term) Credit rating of A- or above 60 6% 47 4% Credit rating of BBB- to BBB+ 13 1% 8 1% Not rated 25 2% 32 3% 98 9% 87 8% $ 1,056 100% $ 1,119 100% (1) Emera Maine’s assets and liabilities were classified as held for sale at December 31, 2019. On March 24, 2020, Emera completed the sale of Emera Maine. Refer to note 4 for further detail. Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of Canadian dollars 2020 2019 Cash collateral provided to others $ 69 $ 101 Cash collateral received from others 6 2 Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material advers e credit-related event occurs. If a material adverse event resulted in t he senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoin g full collateralization. As at December 31, 2020 , the total fair value of derivatives in a l iability position, wa s $ 338 million ( December 31, 2019 – $ 370 million). If the credit ratings of the Company were reduced below investment grade , the full value of the net liability position could be required to be posted as collateral for these derivatives.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
16. Fair Value Measurements
Fair Value Measurements	16 . FAIR VALUE MEASUREMENTS The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (s ee note 1 ) and us es a market approach to do so. The three levels of the fair value hierarchy are defined as follows: Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabi lities. Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment re lated to location differences. Also, c ertain derivatives are valued using quotes from over-the-counter clearing houses. Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:  While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.  The term of certain transactio ns extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.  The valuations of certain transactions were based on internal m odels, although quoted prices were utilized in the valuations. Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set out the class ification of the methodology used by the Company to fair value its derivatives: 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 Power purchases 9 - - 9 Natural gas purchases and sales 2 1 - 3 Heavy fuel oil purchases - 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 Coal purchases - 4 - 4 Power purchases 33 - - 33 Heavy fuel oil purchases 3 3 - 6 Natural gas purchases and sales - 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) As at December 31, 2019 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards Power purchases $ 23 $ - $ - $ 23 Natural gas purchases and sales - 2 - 2 Heavy fuel oil purchases - 1 - 1 Foreign exchange forwards - 2 - 2 23 5 - 28 HFT derivatives Power swaps and physical contracts 1 3 1 5 Natural gas swaps, futures, forwards, physical contracts and related transportation (7) 46 14 53 (6) 49 15 58 Other derivatives Equity derivatives 1 - - 1 1 - - 1 Total assets 18 54 15 87 Liabilities Cash flow hedges Foreign exchange forwards - 1 - 1 - 1 - 1 Regulatory deferral Commodity swaps and forwards Coal purchases - 31 - 31 Power purchases 36 - - 36 Natural gas purchased and sales 3 2 - 5 Foreign exchange forwards - 6 - 6 39 39 - 78 HFT derivatives Power swaps and physical contracts 5 2 - 7 Natural gas swaps, futures, forwards and physical contracts 2 33 249 284 7 35 249 291 Total liabilities 46 75 249 370 Net assets (liabilities) $ (28) $ (21) $ (234) $ (283) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2020 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2020 $ 1 $ 14 $ 15 Total realized and unrealized gains (losses) included in non-regulated operating revenues 3 (2) 1 Net transfers out of Level 3 (2) - (2) Balance, December 31, 2020 $ 2 $ 12 $ 14 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2020 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2020 $ - $ 249 $ 249 Total realized and unrealized gains included in non-regulated operating revenues 2 8 10 Net transfers out of Level 3 (1) - (1) Balance, December 31, 2020 $ 1 $ 257 $ 258 The Company evaluates observable inputs of market data on a quarterly basis to determine if transfers between levels is appropriate . For the year ended December 31, 2020 , transfers out of Level 3 were a result of an increase in observable inputs. Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis b ased on statistical analysis of the spot markets in the various illiquid term markets . Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy: 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% 0.60% 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% 0.40% forwards and physical contracts Discount rate 0.00% - 10.36% 0.75% (6) Modelled pricing Third-party pricing $1.82 - $8.44 $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 Own credit risk 0.02% - 6.85% 2.02% physical contracts 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 As at December 31, 2019 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 1 Modelled pricing Third-party pricing $21.40 - $74.05 $35.03 Power swaps and Probability of default 0.01% - 1.14% 0.21% physical contracts Discount rate 0.15% - 6.65% 2.78% HFT derivatives – 9 Modelled pricing Third-party pricing $1.63 - $7.45 $2.37 Natural gas swaps, futures, Probability of default 0.01% - 2.31% 0.09% forwards, and physical contracts Discount rate 0.01% - 20.93% 1.55% 5 Modelled pricing Third-party pricing $1.33 - $8.76 $5.05 Basis adjustment $0.00 - $1.31 $0.76 Probability of default 0.01% - 3.33% 0.28% Discount rate 0.01% - 4.71% 0.91% Total assets $ 15 Liabilities HFT derivatives – 228 Modelled pricing Third-party pricing $1.54 - $7.45 $4.07 Natural gas swaps, futures, Own credit risk 0.01% - 2.31% 0.12% forwards and physical contracts Discount rate 0.01% - 18.63% 1.89% 21 Modelled pricing Third-party pricing $1.36 - $9.75 $5.45 Basis adjustment $0.00 - $1.31 $0.91 Own credit risk 0.01% - 3.33% 0.06% Discount rate 0.01% - 3.76% 0.81% Total liabilities $ 249 Net assets (liabilities) $ (234) Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The balance consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2020 $ 13,721 $ 16,487 $ - $ 16,020 $ 467 $ 16,487 December 31, 2019 $ 14,180 $ 16,049 $ - $ 15,598 $ 451 $ 16,049 The Company has designated $ 1.2 billion United States dollar den ominated Hybrid Notes as a hedge of the foreign currency exposure of its ne t investment in United States dollar denominated oper ations. An after-tax foreign currency gain of $ 26 million was recorded in Other Comprehensive Income for the year ended December 31, 2020 ( 2019 – $ 7 8 million ).

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
17. Related Party Transactions
Related Party Transactions	17 . RELATED PARTY TRANSACTIONS In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and inter company transactions have been eliminated on consolidation, except for the net profit on ce rtain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms. Significant transaction s between Emera and its associat ed companies are as follow s :  Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $ 139 million for the year ended December 31, 2020 ( 2019 - $ 107 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $ 18 million for the year ended December 31, 2020 ( 2019 - $ 63 million). There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2020 and at December 31, 2019 .

Receivables and Other Current A

Receivables and Other Current Assets	12 Months Ended
	Dec. 31, 2020
18. Receivables and Other Current Assets
Receivables and Other Current Assets	18. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2020 2019 Customer accounts receivable – billed $ 570 $ 603 Customer accounts receivable – unbilled 286 265 Allowance for credit losses (22) (9) Capitalized transportation capacity (1) 200 272 Income tax receivable 11 118 Prepaid expenses 50 48 Other 138 189 $ 1,233 $ 1,486 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

Leases, Lessee

Leases, Lessee	12 Months Ended
	Dec. 31, 2020
19. Leases
Leases, Lessee	19 . LEASES 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 65 years, some of which include options to extend the leases for up to 65 years. These options are inclu ded 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 2020 2019 Right-of-use asset Other long-term assets $ 61 $ 64 Lease liabilities Current Other current liabilities 3 5 Long-term Other long-term liabilities 60 61 Total lease liabilities $ 63 $ 66 The Company has recorded lease expense of $ 1 60 million for the year ended December 31, 2020 ( 2019 – $ 172 million), of which $ 149 million ( 2019 – $ 156 million) relates to variable costs for power generation facility finance leases , recorded in “Regulated fuel for generation and purchased power” in the C onsolidated S tatements of I ncome . Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Minimum lease payments $ 6 $ 6 $ 6 $ 5 $ 4 $ 112 $ 139 Less imputed interest - - - - - - (76) Total $ 6 $ 6 $ 6 $ 5 $ 4 $ 112 $ 63 Additional information related to Emera's leases is as follows: Year ended December For the 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions of Canadian dollars) $ 7 $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases (millions of Canadian dollars) $ 7 $ 16 Weighted average remaining lease term (years) 43 39 Weighted average discount rate- operating leases 3.96% 4.07% L essor The Company’s ne t investment in direct finance and sales-type lease s primarily relates to Brunswick Pipeline , compressed natural gas (“CNG”) stations and heat pumps . Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other income (expense), net” on the Consoli dated Statements of Income . The Company manages its risk associated with the residual value of the Brunswick Pipeline lease 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. Ne t investment in direct finance and sales-type lease s consist of the following : As at December 31 December 31 millions of Canadian dollars 2020 2019 Total minimum lease payment to be received 1,018 $ 1,066 Less: amounts representing estimated executory costs (179) (189) Minimum lease payments receivable 839 $ 877 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (487) (532) Net investment in direct finance and sales-type leases 535 $ 528 Principal due within one year (included in "Receivables and other current assets") 18 17 Net investment in sales-type leases - long-term (included in "Other long-term assets") 42 38 Net Investment in direct finance leases - long-term 475 $ 473 As at December 31, 2020, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Minimum lease payments to be received $ 78 $ 77 $ 76 $ 77 $ 79 $ 631 $ 1,018 Less: executory costs (179) Minimum lease payments receivable $ 78 $ 77 $ 76 $ 77 $ 79 $ 631 $ 839

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
20. Property, Plant and Equipment
Property, Plant and Equipment	20 . PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of Canadian dollars Estimated useful life 2020 2019 Generation 3 to 131 $ 11,474 $ 11,181 Transmission 11 to 80 2,414 2,318 Distribution 4 to 80 5,997 5,820 Gas transmission and distribution 7 to 85 3,879 3,568 General plant and other (1) 2 to 60 2,127 2,006 Total cost 25,891 24,893 Less: Accumulated depreciation (1) (8,714) (8,317) 17,177 16,576 Construction work in progress (1) 2,358 1,591 Net book value $ 19,535 $ 18,167 (1) SeaCoast owns a 50% undivided ownership interest in a jointly owned 26-mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2020, SeaCoast’s share of plant in service was $34 million, accumulated depreciation of nil and construction work in progress of nil. At December 31, 2019, SeaCoast’s share of construction work in progress was $8 million. SeaCoast’s undivided ownership interest is financed with its funds and all operations are accounted for as if such participating interest was a wholly owned facility. SeaCoast’s share of direct expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2020
21. Employee Benefit Plans
Employee Benefit Plans	21 . EMPLOYEE BENEFIT PLANS 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, Newfou ndland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. Benefit Obligation and Plan Assets The changes in b enefit o bligation and p lan a ssets, and the f unded s tatus for all plans were as follows: For the Year ended December 31 millions of Canadian dollars 2020 2019 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 $ 2,822 $ 353 $ 2,650 $ 350 Service cost 46 5 47 4 Plan participant contributions 7 5 8 5 Interest cost 84 10 102 14 Benefits paid (135) (27) (130) (23) Actuarial losses 189 52 231 19 Settlements and curtailments (229) (52) (20) - Foreign currency translation adjustment (25) (7) (66) (16) Balance, December 31 2,759 339 2,822 353 Change in plan assets Balance, January 1 2,593 56 2,300 49 Employer contributions 41 21 52 19 Plan participant contributions 7 5 8 5 Benefits paid (135) (27) (130) (23) Actual return on assets, net of expenses 310 5 424 7 Settlements and curtailments (191) (7) (7) - Foreign currency translation adjustment (20) (1) (54) (1) Balance, December 31 2,605 52 2,593 56 Funded status, end of year $ (154) $ (287) $ (229) $ (297) Plans with PBO / APBO in E xcess of P lan A ssets T he aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeds the plan assets for the years ended December 31 is as follows: millions of Canadian dollars 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,736 $ 308 $ 2,797 $ 323 Fair value of plan assets 2,568 - 2,557 7 Funded status $ (168) $ (308) $ (240) $ (316) Plans with Accumulated Benefit Obligation (“ABO”) in E xcess of P lan A ssets The ABO for the defined benefit pension plans was $ 2,639 million as at December 31, 2020 ( 2019 – $ 2,687 million). T he aggregate financial position for those plan s with an ABO in excess of the p lan assets for the years ended December 31 is as follows : millions of Canadian dollars 2020 2019 Defined benefit pension plans Defined benefit pension plans ABO $ 1,519 $ 2,665 Fair value of plan assets 1,419 2,557 Funded status $ (100) $ (108) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (4) $ (19) $ (4) $ (18) Long-term liabilities (163) (290) (206) (254) Long-term liabilities associated with assets held for sale (1) - - (30) (44) Other long-term assets 13 20 11 19 Amount included in deferred income tax (4) (1) (7) 1 AOCI and regulatory assets, net of tax 443 107 524 72 Net amount recognized $ 285 $ (183) $ 288 $ (224) (1) On March 24, 2020, Emera sold Emera Maine, refer to note 4 for further details. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Amounts R ecognized in AOCI and Regulatory A ssets Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets . The following table summarizes the change in AOCI and regulatory assets: Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2020 $ 358 $ 160 $ (1) Amortized in current period (25) (15) 1 Current year addition to AOCI or regulatory assets (12) 14 - Change in current year related to sale of Emera Maine (39) - - Change in foreign exchange rate (3) 1 - Balance, December 31, 2020 $ 279 $ 160 $ - Non-pension benefits plans Balance, January 1, 2020 $ 78 $ (5) $ - Amortized in current period - - - Current year addition to AOCI or regulatory assets 48 2 - Change in current year related to sale of Emera Maine (13) - - Change in foreign exchange rate (3) (1) - Balance, December 31, 2020 $ 110 $ (4) $ - 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 160 $ (4) $ 160 $ (5) Past service (gains) costs - - (1) - Regulatory assets 279 110 358 78 Total AOCI and regulatory assets before deferred income taxes 439 106 517 73 Amount included in deferred income tax assets 4 1 7 (1) Net amount in AOCI and regulatory assets $ 443 $ 107 $ 524 $ 72 Benefit C ost C omponents Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 46 $ 5 $ 47 $ 4 Interest cost 84 10 102 14 Expected return on plan assets (141) (1) (147) (2) Current year amortization of: Actuarial losses (gains) 15 - 16 - Past service costs (gains) (1) - (1) - Regulatory assets (liability) 25 - 20 (5) Settlement, curtailments - - 1 - Total $ 28 $ 14 $ 38 $ 11 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,476 million as at January 1, 2020 ( 2019 – $ 2,401 million) , adjusted for interest on certa in cash flows during the year . The market-related value of assets is based on a f ive-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 ove r a five-year period. Pension Plan Asset Allocations Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a br oad range of investment and non-investme nt grade securities. Emera’s target asset allocation is as follows: Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 5% Fixed income 35% to 50% Equities: Canadian 12% to 22% Non-Canadian 30% to 55% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Fixed income 30% to 50% Equities 50% to 70% Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies . All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company . The following tables set out the classification 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, 2020 Cash and cash equivalents $ - $ 68 $ - $ 68 3 % Net in-transits - (99) - (99) (4) % Equity Securities: Canadian equity - 154 - 154 6 % US equity - 380 - 380 15 % Other equity - 243 - 243 9 % Fixed income securities: Government - - 119 119 5 % Corporate - - 141 141 5 % Other - 10 3 13 - % Mutual funds - 88 - 88 3 % Other - (3) (4) (7) - % Open-ended investments measured at NAV (1) 801 - - 801 31 % Common collective trusts measured at NAV (2) 704 - - 704 27 % Total $ 1,505 $ 841 $ 259 $ 2,605 100 % December 31, 2019 Cash and cash equivalents $ - $ 44 $ - $ 44 2 % Net in-transits - (48) - (48) (2) % Equity securities: Canadian equity - 210 - 210 8 % US equity - 388 - 388 15 % Other equity - 176 - 176 7 % Fixed Income securities: Government - - 93 93 3 % Corporate - - 126 126 5 % Other - 5 9 14 - Mutual funds - 199 - 199 8 % Other - (5) 1 (4) - % Open-ended investments measured at NAV (1) 860 - - 860 33 % Common collective trusts measured at NAV (2) 535 - - 535 21 % Total $ 1,395 $ 969 $ 229 $ 2,593 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value. Post-Retirement Benefit Plans There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exceptions to this is the NMGC Retiree Medical Plan, which is fully funded Investments in Emera As at December 31, 2020 and 2019 , the assets related to the pension funds and post-retirement benefit plans do not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities. Cash Flows The following table shows the 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 2021 $ 41 $ 19 Expected benefit payments 2021 140 21 2022 154 22 2023 154 22 2024 162 22 2025 170 22 2026 – 2030 914 105 Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2020 2019 (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 2.49 % 2.48 % 3.17 % 3.27 % Discount rate - future service 2.64 % 2.51 % 3.21 % 3.28 % Rate of compensation increase 2.89 % 3.04 % 3.32 % 3.70 % Health care trend - initial (next year) - 5.64 % - 6.15 % - ultimate - 4.35 % - 4.38 % - year ultimate reached 2038 2038 Benefit cost for year ended December 31: Discount rate - past service 3.17 % 3.28 % 4.05 % 4.30 % Discount rate - future service 3.21 % 3.28 % 4.05 % 4.30 % Expected long-term return on plan assets 6.29 % 3.25 % 6.50 % 2.81 % Rate of compensation increase 3.34 % 3.70 % 3.30 % 3.67 % Health care trend - initial (current year) - 5.91 % - 6.39 % - ultimate - 4.37 % - 4.45 % - year ultimate reached 2038 2035 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 bonds, with maturities matching the estimated cash flows from the pension plan . millions of Canadian dollars Increase Decrease Service cost and interest cost $ - $ - Accumulated post-retirement benefit obligation, December 31 - - millions of Canadian dollars Increase Decrease Discount rate assumption $ - $ - Asset rate assumption - - Amounts to be Amortized in the Next Fiscal Year The following table shows the amounts from the AOCL and regulatory assets, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2021: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ - $ - Past service gains - - Regulatory assets - - Total $ - $ - Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2020 was $ 45 million ( 2019 – $ 34 million) .

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2020
22. Goodwill
Goodwill	22. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2020 2019 Balance, January 1 $ 5,835 $ 6,313 Additions - 3 GBPC i mpairment charge - (30) Classified as assets held for sale (1) - (148) Change in foreign exchange rate (115) (303) Balance, December 31 $ 5,720 $ 5,835 (1) On March 25, 2019, Emera announced the sale of Emera Maine. Emera Maine’s assets and liabilities were classified as held for sale. Refer to note 4 for further detail. Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated Balance Sheets at December 31, 2020 , primarily relates to TECO Energy and GBPC. Emera’s reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC. In 2020 , Emera performed a qualitative impairment assessment for Tampa Electric, PGS and NMGC, concluding that the fair value of the reporting units exceeded thei r respective carrying amounts, and as such, no quantitative assessment were performed and no impairment charges were recognized. Goodwill on Emera’s Consolidated Balance Sheets at December 31, 2020 , included $ 68 million ( 2019 - $ 70 million) relate d to GBPC. In 2019 Emera recognized an impairment charge of $ 30 million based on the excess of GBPC’s carrying amount over its fair value. The 2019 impairment charge is included in “ I mpairment charge s ” in the Consolidated Statements of Inco me . In 2020 , due to the limited excess of fair value over carrying value as a result of the 2019 impairment charge, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a discounted cash flow analysis . This assessment estimated that the fair value of the reporting unit exceeded its carrying value, including goodwill, by approximately five per cent. Adverse changes in significant assumptions used could result in a future impairment .

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2020
23. Short-Term Debt
Short-Term Debt	23 . SHORT-TERM DEBT Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following: millions of Canadian dollars 2020 Weighted average interest rate 2019 Weighted average interest rate Tampa Electric Company ("TEC") Advances on accounts receivable and revolving credit facilities $ 987 0.89 % $ 452 2.56 % Emera Non-revolving term facility 400 0.94 % 399 2.69 % Bank indebtedness - - % 6 - % TECO Finance Advances on revolving credit and term facilities 205 1.46 % 656 2.39 % NMGC Advances on revolving credit facilities 21 1.22 % 8 2.70 % GBPC Advances on revolving credit facilities 11 5.25 % 10 5.25 % NSPI Bank indebtedness 1 - % 6 - % Short-term debt $ 1,625 $ 1,537 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2020 2019 Tampa Electric Company - revolving credit facility 2023 $ 1,019 $ 520 TECO Energy/TECO Finance - revolving credit facility 2023 509 520 Emera - non-revolving term facility 2021 400 400 TEC - term loan 2021 382 - TEC - accounts receivable revolving credit facility 2021 191 195 NMGC - revolving credit facility 2023 159 162 GBPC - revolving credit facility on demand 17 17 TECO Energy/TECO Finance - term credit facility - 649 Total 2,677 2,463 Less: Advances under revolving credit and term facilities 1,624 1,525 Letters of credit issued within the credit facilities 4 3 Total advances under available facilities 1,628 1,528 Available capacity under existing agreements $ 1,049 $ 935 The weighted average interest rate on outstanding short-term debt at December 31, 2020 was 1.01 per cent ( 2019 – 2.54 per cent ). Recent Significant Financing Activity by Segment Florida Electric Utilities On February 6, 2020, TEC entered into a $ 300 million USD non-revolving credit agreement with a maturity date of February 4, 2021 . The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at the London interbank deposit rate (“LIBOR”), prime rate or the federal funds rate, plus a margin. On January 29 , 2021, TEC extended the maturity date of the agreement to April 29, 2021 with no other changes in terms. On December 18, 2020, TEC amended and restated its bank credit facility. The amendment extended the maturity date of the credit facility from March 22, 2022 to March 22, 2023 and increased the amount of the commitment by the lenders to $ 800 million USD fro m $ 400 million USD . The credit facility bears interest based on either the LIBOR, the Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. The amended facility now includes a $ 80 million USD letter of credit facility. There were no othe r significant changes in commercial terms from the prior agreement . Gas Utilities and Infrastructure On December 18, 2020, NMGC amended and restated its $ 125 million USD bank credit facility. The amendment extended the maturity date of the credit facility from March 22, 2022 to March 22, 2023 . The credit facility bears interest based on either the LIBOR, JP Morgan Chase Bank’s prime rate, or the federal funds rate, plus a margin. The amended facility now includes a $ 30 million USD letter of credit facility. There were no other significant changes in commercial terms from the prior agreement . Other On February 28, 2020, TECO Finance extended the maturity date of its $ 500 million USD credit facility from March 5, 2020 to July 3, 2020 . There were no other significant changes in commercial terms from the prior agreement. Using funds from the sale of Emera Maine, on April 3, 2020, TECO Finance repaid $ 200 million U SD of the term loan and the remaining $ 300 million USD was repaid on June 30, 2020. On December 1, 2020, Emera extended the maturity date of its $ 400 million non-revolving term loan from December 15, 2020 to December 16, 2021 . There were no other significant changes in commercial terms from the prior agreemen t. On December 18, 2020, TECO Finance amended and restated its $ 400 million USD bank credit facility. The amendment extended the maturity date of the credit facility from March 22, 2022 to Ma rch 22, 2023 . The credit facility bears interest based on either the LIBOR, JP Morgan Chase Bank’s prime rate, or the federal funds rate, plus a margin. The facility now includes a $ 50 million USD letter of credit facility. There were no other significant changes in commercial terms from the prior agreement .

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2020
24. Other Current Liabilities
Other Current Liabilities	24 . OTHER CURRENT LIABILITIES As at December 31 December 31 millions of Canadian dollars 2020 2019 Accrued charges $ 141 $ 147 Accrued interest on long-term debt 71 77 Pension and post-retirement liabilities (note 21 ) 23 22 Sales and other taxes payable 6 13 Income tax payable 1 1 Other 98 73 $ 340 $ 333

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
25. Long-term Debt
Long-term Debt	25 . L ONG-TERM DEBT Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. I ncluded are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the fo llowing: Weighted average interest rate (1) millions of Canadian dollars 2020 2019 Maturity 2020 2019 Emera Bankers acceptances, LIBOR loans Variable Variable 2024 $ 263 $ 437 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,528 1,559 $ 2,291 $ 2,496 Emera Finance Unsecured senior notes (USD) 3.86% 3.86% 2021 - 2046 $ 3,501 $ 3,572 TECO Finance Fixed rate notes and bonds (USD) - 5.15% - $ - 390 Tampa Electric (2) Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2050 $ 3,268 $ 3,334 PGS Fixed rate notes and bonds (USD) 4.58% 4.58% 2021 - 2050 $ 429 $ 437 NMGC Fixed rate notes and bonds (USD) 4.30% 4.30% 2021 - 2049 $ 465 $ 474 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 191 $ 195 NSPI Discount notes Variable Variable 2024 $ 291 $ 308 Medium term fixed rate notes 5.14% 5.37% 2025 - 2097 2,665 2,365 $ 2,956 $ 2,673 Emera Maine LIBOR loans and demand loans Variable $ - $ 11 Secured fixed rate mortgage bonds (USD) - 9.74% - - 65 Unsecured senior fixed rate notes (USD) - 4.15% - - 442 $ - $ 518 EBP Senior secured credit facility Variable Variable 2023 $ 249 $ 248 ECI Secured senior notes (USD) Variable Variable 2021 - 2031 $ 106 $ 130 Amortizing fixed rate notes (USD) 3.92% 3.89% 2021 - 2022 100 $ 122 Non-revolving term facility, floating rate Variable - 2025 28 $ - Non-revolving term facility, fixed rate 2.60% - 2025 68 $ - Secured fixed rate senior notes (3) 4.39% 4.84% 2022 - 2035 174 $ 218 $ 476 $ 470 Adjustments Fair market value adjustment - TECO Energy acquisition (4) $ 5 $ 8 Debt issuance costs (110) (119) Classification as liabilities held for sale (5) - (516) Amount due within one year (1,382) (501) $ (1,487) $ (1,128) Long-Term Debt $ 12,339 $ 13,679 (1) Weighted average interest rate of fixed rate long-term debt. (2) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (3) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (4) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt. (5) On March 24,2020 Emera sold Emera Maine. Refer to note 4 for further detail. As at December 31, 2019, Emera Maine’s assets and liabilities are classified as held for sale. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2020 2019 Emera – revolving credit facility (1) June 2024 $ 900 $ 900 NSPI - revolving credit facility (1) October 2024 600 600 ECI – revolving credit facilities 2021-2023 28 25 Emera Maine – revolving credit facility - 104 Total 1,528 1,629 Less: Borrowings under credit facilities 569 771 Letters of credit issued inside credit facilities 31 65 Use of available facilities 600 836 Available capacity under existing agreements $ 928 $ 793 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. Debt Covenants Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significa nt covenants are listed below: As at Financial Covenant Requirement December 31, 2020 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.56 : 1 Recent Significant Financing Activity by Segment Canadian Electric Utilities On April 24, 2020, NSPI completed a $ 300 million 30-year unsecured notes issuance. The notes bear interest at a rate of 3.31 per cent and have a maturity date of April 25, 2050 . Other Electric Utilities On May 20, 2020, GBPC entered into a $ 22 million USD non-revolving term loan with a maturit y date of May 20, 2025 . The loan bears interest at a rate of 90-day LIBOR plus a margin . On May 22, 2020, proceeds from this loan were used to repay $ 22 million USD senior notes upon maturity. On May 20, 2020, GBPC entered into a $ 15 million BSD ($ 15 mill ion USD) non-revolving term loan with a maturity date of May 20, 2025 . The loan bears interest at a rate of 4.00 per cent. At December 31, 2020, BLPC had drawn $ 77 million BBD ($ 38 million USD) against a $ 110 million BBD ($ 55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term. Gas Utilities and Infrastructure On February 5, 2021, NMGC completed an issuance of $ 220 million USD senior notes. The issuance included $ 70 million USD senior notes that bear interest at a rate of 2.26 per cent with a maturity date of February 5, 2031 , $ 65 million USD senior notes that bear interest at a rate of 2.51 per cent and with a maturity date of February 5, 2036 , and $ 85 million USD se nior notes that bear interest at a rate of 3.34 per cent with a maturity date of February 5, 2051 . Proceeds from this issuance were used to repay a $ 200 million USD note, due in 2021 and for general corporate purposes. These notes were classified as long-t erm debt at December 31, 2020. Other On March 13, 2020, TECO Finance repaid a $ 300 million USD note upon maturity. The note was repaid using existing credit facilities. Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follow s: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Emera $ - $ - $ 500 $ 263 $ - $ 1,528 $ 2,291 Emera US Finance LP 955 - - - - 2,546 3,501 Tampa Electric 295 286 - - - 2,687 3,268 PGS 59 33 - - - 337 429 NMGC - - - - - 465 465 NMGI - - - 191 - - 191 NSPI - - - 291 125 2,540 2,956 EBP - - 249 - - - 249 ECI 73 88 60 75 101 79 476 Total $ 1,382 $ 407 $ 809 $ 820 $ 226 $ 10,182 $ 13,826

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
26. Asset Retirement Obligations
Asset Retirement Obligations	26 . ASSET RETIREMENT OBLIGATIONS AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution ass ets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made. The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2020 2019 Balance, January 1 $ 185 $ 205 Additions 10 - Liabilities settled (1) (25) (25) Accretion included in depreciation expense 9 7 Accretion deferred to regulatory asset (included in property, plant and equipment) (3) - Other 1 3 Change in foreign exchange rate 1 (5) Balance, December 31 $ 178 $ 185 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The decreases in ARO in 2020 and 2019 are due to the closure of CCR management facilities.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
27. Commitments and Contingencies Disclosure
Commitments and Contingencies	27 . COMMITMENTS AND CONTINGENCIES A. Commitments As at December 31, 2020 , contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Purchased power (1) $ 231 $ 218 $ 216 $ 218 $ 224 $ 2,242 $ 3,349 Transportation (2) 518 393 339 306 282 2,704 4,542 Capital projects 394 98 76 - - - 568 Fuel, gas supply and storage 494 91 6 1 - - 592 Long-term service agreements (3) 43 41 36 33 34 92 279 Equity investment commitments (4) - 240 - - - - 240 Leases and other (5) 16 17 16 15 8 118 190 Demand side management 40 45 - - - - 85 $ 1,736 $ 1,143 $ 689 $ 573 $ 548 $ 5,156 $ 9,845 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $149 million related to a gas transportation contract between PGS and SeaCoast through 2040. (3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. (4) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (5) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments. On March 17, 2020, Nalcor announced that it had paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor declared force majeure under various project contracts, including form al notification to NSPML. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward completing project commissioning in 2021. NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls, which is anticipated to take place in 2021. On December 16, 2020, the UARB approved NSPML’s 2021 interim assessment for recovery from NSPI of Maritime Link costs of approximately $ 172 million subject to a holdback of $ 10 million with similar terms as previously approved by the UARB and potential long-term deferral of up to $ 23 million in depreciation expense dependent upon the timing of commencement of the NS Block. NSPI has a contractual obl igation to pay NSPML for the use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and amounts of $ 164 million and $ 162 million for 2021 and 2022, respectively. On December 16, 2020, the UARB approved the 2021 interim cost assessment of approximately $172 million. Any difference between the amounts included in the NSPI fuel stability plan an d those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are dependent on regulatory filings with the UARB. Once Muskrat Falls and LIL have achieved full power, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL. Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Scotia. This energy could be transmitted from Nova Scotia to New England energy markets beginning at first co mmercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years . As transmission rights are contracted, the obligations are included within “L eases and other” in the above table. Legal Proceedings TECO Guatemala Holdings (“TGH”) Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy, divested of its indirect investment that resided in Guatemala. In 2013, the ICSID tribunal hearing an arbitration claim of TGH against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award. The ar bitration concerned TGH’s allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed TGH’s investment in that company. The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of app roximately $ 21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2 per cent. Subsequent proceedings resulted in Guatemala awards of additional interest and certain costs to TGH (in aggregate, the “First Award”). I n November 2020, Guatemala withdrew its appeal in U.S. courts against the enforcement of the First Award and made a payment of approximately $ 38 million USD in full and final satisfaction of the First Award. This amount was recognized in “Other Income, net ” on the Consolidated Statements of Income. On September 23, 2016, TGH had filed a separate request for resubmission to arbitration seeking damages in addition to those awarded in the First Award. On May 13, 2020, a second tribunal awarded TGH additional damages and costs against Guatemala of more than $ 35 million USD plus interest (the “Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in connection with this Second Award. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount is approximately $ 2 million USD. Guatemala now has until February 13, 2021 to seek annulment of the Second Award before ICSID. To date, the total of the Second Award, with intere st, is approximately $ 59 million USD. Results to date do not reflect any benefit of the Second Award. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certa in superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31 , 2020 , TEC has esti mated its financial liability to be $ 2 2 million ($ 17 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs a ttributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discou nted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings. Emera Main e On March 24, 2020, the Company completed the sale of Emera Maine. Emera has no remaining obligations with respect to the legal proceedings previously disclosed in note 26 of Emera’s 2019 annual audited consolidated f inancial statements. No new or additional reserves were made in 2020 with respect to any of the four complaints filed with the FERC. Other Legal Proceedings Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business . Risks associated with derivative instruments and fair value measurements are discussed in note 15 and note 16 . Sound risk manag ement is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management . Public Health Risk An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company , including causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company’s operations. Any a dverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business. The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and b usiness contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees . Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exc hange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may ent er into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the C ompany’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange . The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI. Liquidity and Capital Market Risk Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed throu gh internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs. Emera’s access to capital and cost of borrowing is subject to s everal risk factors, including financial market conditions, market disruptions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The i nability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions including those related to public health th reats, such as the COVID-19 pandemic. Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these ri sks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturit ies. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Interest rates may be impacted by market disruptions related to public health thre ats, including the COVID-19 pandemic. For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such t hat regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively aff ect the economic viability of project development and acquisition initiatives. Commodity Price Risk The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements. The Company manages this risk through established processes a nd practices to identify, monitor, report and mitigate these risks. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging in struments are all used to manage and mitigate this risk. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this r isk. Regulated Utilities A large portion of the Company’s utility fuel supply comes from international suppliers and therefore may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted te rms. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. The majority of Emera’s regulated utilities have adopted and implemented fuel adjustment mechanisms which has further helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs. Emera Energy Marketing and Trading Emera Energy h as employed further measures to manage commodity risk. The majority of Emera’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoid ing any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the event of an operational issue or counterparty default. T o measure commodity price risk exposure, Emera employs a number of controls and processes, including an estimated value-at-risk (“ VaR ”) analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas a nd power positions. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensur e that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results . D. Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2020: TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $ 45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expi res five years after the gas transportation precedent agreement termination date, which is expected to terminate on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $ 27 million USD. Emera Inc. has issued a guarantee of up to $ 35 million USD relating to outstanding notes of GBPC . The guarantee for the no tes will expire in May 202 3 . In 2020, NSPI issued guarantees in the amount of $ 18 million USD on behalf of its subsidiary, NS Power Energy Marketing Incorporate (“ NSPEMI ”) , to secure obligations under purchase agreements with third - party suppliers. The guarantees have terms of varying lengths and will be renewed as required. The Company has standby letters of credit and surety bonds in the amount of $ 55 million USD ( Decemb er 31, 201 9 - $ 82 milli on USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one - year term and are renewed annually as required . Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2021 . The amount committed as at December 31, 2020 was $ 63 million (Decembe r 31, 2019 - $ 52 million). Collaborative Arrangement s For the years ended December 31, 2020 and 2019 , the Company has identified the following material collaborative arrangements: Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G expenses. In 2020 , NSPI recognized $ 19 million net expense ( 2019 - $ 1 9 million) in “Regulated fuel for generation and purchased power” and $ 3 million ( 2019 - $ 3 million) in OM&G .

Cumulative Preferred Stock

Cumulative Preferred Stock	12 Months Ended
	Dec. 31, 2020
28. Cumulative Preferred Stock
Cumulative Preferred Stock	28 . CUMULATIVE PREFERRED STOCK Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2020 December 31, 2019 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 4,866,814 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 1,133,186 $ 52 2,135,364 $ 52 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.75 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0625 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Total 41,000,000 $ 1,004 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) Series A (5)(6) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B Series C 4.100 1.1802 2.65 August 15, 2023 25.00 Series D Series F (7)(8) 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) Series B (9) 2.393 Floating 1.84 August 15, 2025 25.00 Series A Series H 4.900 1.2250 4.90 August 15, 2023 25.00 Series I Perpetual fixed rate Series E (10) 4.500 1.1250 25.75 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent. (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2023, February 15, 2020 and August 15, 2023, respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent. (5) The annual fixed dividend per share for First Preferred Shares, Series A was reset from $0.6388 to $0.5456 for the five-year period from and including August 15, 2020. (6) On July 9, 2020, Emera announced it would not redeem the Cumulative Rate Reset Preferred Shares, Series A or the Cumulative Floating Rate First Preferred Shares, Series B. On August 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A Shares were tendered for conversion into Series B Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B Shares were tendered for conversion into Series A Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A Shares and 1,133,186 Series B Shares issued and outstanding. (7) On January 7, 2020, Emera announced it would not redeem the 8,000,000 Cumulative Rate Reset First Preferred Shares, Series F Shares. The holders of the Series F Shares have the right, at their option, to convert all or any of their Series F Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series G of the Company on February 15, 2020, or to continue to hold their Series F Shares. On February 6, 2020, Emera announced that, after having taken into account all conversion notices received from holders, no First Preferred Shares, Series F Shares would be converted into Cumulative Floating Rate First Preferred Shares, Series G Shares. (8) The annual fixed dividend per share for First Preferred Shares, Series F was reset from $1.0625 to $1.0505 for the five-year period from and including February 15, 2020. (9)Emera announced a dividend rate of 2.021 per cent on the Series B Shares for the three-month period which commenced on August 15, 2020 and ended on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter (10) First Preferred Shares, Series E are redeemable at $25.75 to August 15, 2020, decreasing $0.25 each year until August 15, 2022 and $25.00 per share thereafter. First Prefer red 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 earnings attributa ble 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, fo r 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, 2020
29. Non-Controlling Interest in Subsidiaries
Non-Controlling Interest in Subsidiaries	29. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of Canadian dollars 2020 2019 Preferred shares of GBPC $ 14 $ 14 Domlec 20 21 $ 34 $ 35 Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual preferred shares. 2020 2019 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 Cumulative Variable Perpetual Preferred Stock: The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 Bahamian per share plus accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually . The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of 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, 2020
30. Supplementary Information to Consolidated Statements of Cash Flows
Supplementary Information to Consolidated Statements of Cash Flows	30 . SUPPLEMENTARY INFORMATIO N TO CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year ended December 31 millions of Canadian dollars 2020 2019 Changes in non-cash working capital: Inventory $ 6 $ (19) Receivables and other current assets 187 154 Accounts payable 55 (137) Other current liabilities (31) (71) Total non-cash working capital $ 217 $ (73) Supplemental disclosure of cash paid (received): Interest $ 679 $ 750 Income taxes $ (148) $ (107) Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 199 $ 187 Reclassification of long-term debt from current to non-current 256 - Increase in accrued capital expenditures $ 17 $ 33

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2020
31. Stock-Based Compensation
Stock-based Compensation	31 . S TOCK-BASED COMPENSATION Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan Eligible employees may participate in Emera’s Employee Common Share Purchase Plan . As of December 31, 2020, the plan allows employees to make cash contributions of a minimum of $ 25 to a maximum of $ 20 ,000 Canadian dollars or $ 15,000 US dollars per year for the purpose of purc hasing 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 l aw. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 7 million common shares (2019 – 4 million common shares) . As at December 31 , 2020 , Emera is in compliance with this requirement. Compensation cost for shar es issued by Emera for the year ended December 31, 2020 under the Employee Common Share Purchase Plan was $ 2 million ( 2019 – $ 1 million) and is included in OM&G on 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 2020 . Effective with the dividend payment of August 15, 2019 , the discount change d from 5 per cent to 2 per cent . Stock-Based Compensation Plans Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company f or a maximum term of 10 years . The option price of the stock options is the closing market price of the stocks on the da y before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares. As at December 31, 2020 , Emera is in compli ance 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 be exercised within the 24 months following the option holders date of retirement or termination for other than just cause, and within six months following the date of termination for just cause, resignation or death. If stock options are not exercised within such time, they expire. The Company uses the Black-Schole s 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 fol lowing table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted , for the year-ended December 31 : 2020 2019 Weighted average fair value per option $ 3.58 $ 2.41 Expected term (1) 5 years 6 years Risk-free interest rate (2) 1.33 % 1.82 % Expected dividend yield (3) 4.09 % 5.10 % Expected volatility (4) 14.10 % 14.32 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility. The following table summarizes stock option information for 2020 : Total Options Non-Vested Options (1) Number of Options Weighted average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2019 2,286,550 $ 43.31 1,549,025 $ 2.22 Granted 501,900 60.03 501,900 3.58 Exercised (417,968) 44.74 N/A N/A Vested N/A N/A (654,375) 2.32 Forfeited (102,700) 45.94 (102,700) 2.33 Options outstanding December 31, 2020 2,267,782 $ 46.62 1,293,850 $ 2.69 Options exercisable December 31, 2020 (2)(3) 973,932 $ 42.08 (1) As at December 31, 2020, there was $2 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 3 years (2019 - $2 million, 2 years). (2) As at December 31, 2020, the weighted average remaining term of vested options was 6 years with an aggregate intrinsic value of $12 million (2019 - 6 years, $11 million). (3) As at December 31, 2020, the fair value of options that vested in the year was $2 million (2019 - $2 million). Compensation cost recognized for stock options for the year ended December 31, 2020 was $ 1 million ( 2019 – $ 1 million), which is included in OM&G on the Consolidated Statements of Income. As at December 31, 2020 , cash received from option exercises was $ 19 million ( 2019 – $ 97 million). The total intrinsic value of options exercised for the year ended December 31, 2020 was $ 6 million ( 2019 – $ 32 million). The range of exercise prices for the options outstanding as at December 31, 2020 was $ 32.06 to $ 60.03 ( 2019 – $ 32.06 to $ 46.39 ). Share Unit Plans The Company has Deferred Share Unit Plan (“DSU”), Performance Share Unit Plan (“PSU”) and Restricted Share Unit Plan (“RSU”) 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 thei r 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 con verted 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 otherw ise 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 acco unt 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 percenta ge 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 cal endar 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 pr ior 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 directo r DSUs for the year ended December 31, 2020 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, 2019 704,597 $ 34.69 531,454 $ 39.96 Granted including DRIP 84,790 47.74 93,008 51.65 Exercised (127,389) 30.50 (33,338) 41.89 Outstanding and exercisable as at December 31, 2020 661,998 $ 37.17 591,124 $ 41.69 Compensation cost recognized for employee and director DSU ’s for the year ended December 31, 2020 was $ 2 million ( 2019 – $ 24 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2020 were $ 1 million ( 2019 – $ 7 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2020 for employees was $ 36 million ( 2019 - $ 40 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2020 for directors was $ 32 million ( 2019 - $ 30 million). Cash payments made during the year ended December 31, 2020 associated with the DSU plan was $ 11 million (2019 - $ 22 million). 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-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 P SUs. 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 MRC C early in the following year. The value of the payout considers actual service over th e performance cycle and may be pro-rated in certain departure scenarios . A summary of the activity related to employee PSUs for the year ended December 31, 2020 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2019 1,381,100 $ 45.37 $ 88 Granted including DRIP 271,185 53.14 Exercised (445,066) 45.41 Forfeited (80,690) 46.25 Outstanding as at December 31, 2020 1,126,529 $ 47.16 $ 68 Compensation cost recognized for the PSU plan for the year ended December 31, 2020 was $ 27 million ( 2019 – $ 34 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2020 were $ 7 million ( 2019 – $ 9 million). Cash payments made during the year ended December 31, 2020 associated with the PSU plan was $ 29 million (2019 – $ 7 million ). Restricted Share Unit Plan In 2020, Emera introduced an RSU plan, where certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. R SUs 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. A summary of the activity related to employee RSUs for the year ended December 31, 2020 is presented in the following table: Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2019 - $ - $ - Granted including DRIP 171,908 54.62 Forfeited (5,633) 54.62 Outstanding as at December 31, 2020 166,275 $ 54.62 $ 10 Compensation cost recognized for the R SU plan for the year ended December 31, 2020 was $ 4 million ( 2019 – nil ). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2020 were $ 1 million ( 2019 – nil ). Cash payments made during the year ended December 31, 2020 associated with the RSU plan was nil (2019 – n il).

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2020
32. Variable Interest Entities
Variable Interest Entities	32 . VARIABLE INTEREST ENTITIES Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since i t does not have the controllin g financial interest of NSPML. W hen the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as i t ha s authority over the majority of the direct acti vities that are expected to most significantly impact the economic per formance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment. BLPC has established a Self-Insurance Fund (“ SIF ”) , primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, acco rdingly, the SI F must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits f rom the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. A ny withdrawal of SIF fund assets by the Company would be subject to existin g regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on th e Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF. The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. Howeve r, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2020 December 31, 2019 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets exposure to loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 547 $ 16 $ 554 $ 23

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
34. Subsequent Events
Subsequent Events	34 . SUBSEQUENT EVENTS These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date throu gh February 12 , 2021 , the date the financial statements were issued.

Comparative Information

Comparative Information	12 Months Ended
	Dec. 31, 2020
33. Comparative Information
Comparative Information	33 . COMPARATIVE INFORMATION These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

Supplemental Financial Informat

Supplemental Financial Information	12 Months Ended
	Dec. 31, 2020
35. Supplemental Financial Information
Supplemental Financial Information	35 . SUPPLEMENTAL FINANCIAL INFORMATION On June 16, 2016, Emera US Finance LP, (in such capacity, the “Issuer”), issued $ 3.25 billion USD senior unsecured notes (“U.S. Notes”). The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera (in such capacity, the “Parent Company”) and Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP. The following condensed consolidated financial statements present the results of operations, financial position and cash flows of the Parent Company, Subsidiary Issuer, Guarantor Subsidiaries and all other Non-guarantor Subsidiaries independently and on a consolidated basis. Our guarantors were not d etermined using geographic, service line or other similar criteria, and as a result, the “Parent”, “Subsidiary Issuer”, “Guarantor Subsidiaries” and “Non-guarantor Subsidiaries” columns each include portions of our domestic and international operations. Ac cordingly, this basis of presentation is not intended to present our financial condition, results of operations or cash flows for any purpose other than to comply with the specific requirements for guarantor reporting . Emera Incorporated C ondensed C o nsolidated Statements of Income Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars For the year ended December 31, 2020 Operating revenues $ (1) $ - $ 3,456 $ 2,070 $ (19) $ 5,506 Operating expenses 51 - 2,640 1,688 (20) 4,359 Income (loss) from equity investments and subsidiaries 1,049 - 1 147 (1,048) 149 Other income (expenses), net 20 - 687 1 - 708 Interest expense, net (1) 48 (37) 448 220 - 679 Income (loss) before provision for income taxes 969 37 1,056 310 (1,047) 1,325 Income tax expense (recovery) (14) (1) 348 7 1 341 Net income (loss) 983 38 708 303 (1,048) 984 Non-controlling interest in subsidiaries - - - - 1 1 Preferred stock dividends 45 - - 1 (1) 45 Net income (loss) attributable to common shareholders $ 938 $ 38 $ 708 $ 302 $ (1,048) $ 938 Comprehensive income (loss) of Emera Incorporated $ 809 $ 35 $ 575 $ 257 $ (867) $ 809 For the year ended December 31, 2019 Operating revenues $ - $ - $ 4,125 $ 2,029 $ (43) $ 6,111 Operating expenses 31 - 3,084 1,695 (42) 4,768 Income (loss) from equity investments and subsidiaries 753 - 2 151 (752) 154 Other income (expenses), net 21 - 22 (11) (20) 12 Interest expense, net (1) 75 (40) 481 222 - 738 Income (loss) before provision for income taxes 668 40 584 252 (773) 771 Income tax expense (recovery) (40) 11 60 30 - 61 Net income (loss) 708 29 524 222 (773) 710 Non-controlling interest in subsidiaries - - - - 2 2 Preferred stock dividends 45 - 19 3 (22) 45 Net income (loss) attributable to common shareholders $ 663 $ 29 $ 505 $ 219 $ (753) $ 663 Comprehensive income (loss) of Emera Incorporated $ 465 $ 14 $ 102 $ 205 $ (321) $ 465 (1) Interest expense is net of interest revenue. Emera Incorporated Condensed Consolidated Balance Sheets Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2020 Assets Current assets $ 121 $ 10 1,216 $ 1,010 $ (179) $ 2,178 Property, plant and equipment 21 - 14,356 5,164 (6) 19,535 Other assets Regulatory assets - - 520 899 - 1,419 Goodwill 3 - 5,648 69 - 5,720 Other long-term assets 12,522 4,591 130 3,254 (18,115) 2,382 Total other assets 12,525 4,591 6,298 4,222 (18,115) 9,521 Total assets $ 12,667 $ 4,601 $ 21,870 $ 10,396 $ (18,300) $ 31,234 Liabilities and Equity Current liabilities $ 554 $ 2,024 $ 4,121 $ 723 $ (2,547) $ 4,875 Long-term liabilities Long-term debt 2,210 2,513 4,026 3,590 - 12,339 Deferred income taxes - 2 852 761 14 1,629 Regulatory liabilities - - 1,747 85 - 1,832 Other long-term liabilities 700 - 4,510 1,666 (5,555) 1,321 Total long-term liabilities 2,910 2,515 11,135 6,102 (5,541) 17,121 Total Emera Incorporated equity 9,203 62 6,614 3,550 (10,225) 9,204 Non-controlling interest in subsidiaries - - - 21 13 34 Total equity 9,203 62 6,614 3,571 (10,212) 9,238 Total liabilities and equity $ 12,667 $ 4,601 $ 21,870 $ 10,396 $ (18,300) $ 31,234 As at December 31, 2019 Assets Current assets $ 96 $ 27 1,486 $ 1,171 $ (294) $ 2,486 Property, plant and equipment 23 - 13,099 5,040 5 18,167 Other assets Regulatory assets - - 519 912 - 1,431 Goodwill 3 - 5,762 70 - 5,835 Other long-term assets 11,994 3,856 1,739 3,289 (16,955) 3,923 Total other assets 11,997 3,856 8,020 4,271 (16,955) 11,189 Total assets $ 12,116 $ 3,883 $ 22,605 $ 10,482 $ (17,244) $ 31,842 Liabilities and Equity Current liabilities $ 542 $ 12 $ 3,699 $ 992 $ (1,079) $ 4,166 Long-term liabilities Long-term debt 2,978 3,534 8,829 4,547 (6,209) 13,679 Deferred income taxes - 3 515 767 - 1,285 Regulatory liabilities - - 1,793 93 - 1,886 Other long-term liabilities 38 - 1,697 511 (21) 2,225 Total long-term liabilities 3,016 3,537 12,834 5,918 (6,230) 19,075 Total Emera Incorporated equity 8,558 334 6,072 3,551 (9,949) 8,566 Non-controlling interest in subsidiaries - - - 21 14 35 Total equity 8,558 334 6,072 3,572 (9,935) 8,601 Total liabilities and equity $ 12,116 $ 3,883 $ 22,605 $ 10,482 $ (17,244) $ 31,842 Emera Incorporated Condensed Consolidated Statements of Cash Flows Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2020 Net cash provided by (used in) by operating activities $ 365 $ 36 $ 1,277 $ 486 $ (527) $ 1,637 Investing activities Additions to property, plant and equipment (1) - (2,150) (472) - (2,623) Proceeds on disposal of assets - - 1,401 - - 1,401 Other investing activities (118) 265 546 100 (795) (2) Net cash provided by (used in) investing activities (119) 265 (203) (372) (795) (1,224) Financing activities Change in short-term debt, net (6) - 107 (5) - 96 Proceeds from long-term debt - - 173 429 (174) 428 Retirement of long-term debt - - (705) (87) 279 (513) Net borrowings (repayments) under committed credit facilities (82) - 8 (157) 28 (203) Issuance of common and preferred stock 285 (241) (3) 53 191 285 Dividends paid (454) (66) (80) (379) 525 (454) Other financing activities (18) (4) (494) 32 473 (11) Net cash provided by (used in) financing activities (275) (311) (994) (114) 1,322 (372) Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale 18 (8) (70) (1) - (61) Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale (11) (18) 10 (1) - (20) Cash, cash equivalents, and restricted cash, beginning of year 1 19 87 167 - 274 Cash, cash equivalents, restricted cash and assets held for sale, end of year $ (10) $ 1 $ 97 $ 166 $ - $ 254 Emera Incorporated Condensed Consolidated Statements of Cash Flows (Continued) Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2019 Net cash provided by (used in) operating activities $ 133 $ 33 $ 1,100 $ 279 $ (20) $ 1,525 Investing activities Additions to property, plant and equipment (2) - (1,973) (520) - (2,495) Net purchase of investments subject to significant influence - - (3) - - (3) Proceeds on disposal of assets significant influence and held-for-trading common shares - - 818 57 - 875 Other investing activities (402) 595 774 (1) (960) 6 Net cash provided by (used in) investing activities (404) 595 (384) (464) (960) (1,617) Financing activities Change in short-term debt, net 399 - (9) 23 - 413 Proceeds from long-term debt - - (6) 552 520 1,066 Retirement of long-term debt (225) (664) (65) (166) 17 (1,103) Net borrowings (repayments) under committed credit facilities 146 - (11) (225) (28) (118) Issuance of common and preferred stock 203 - (620) 58 562 203 Dividends paid (423) - (19) (138) 157 (423) Other financing activities (1) - 138 87 (248) (24) Net cash provided by (used in) financing activities 99 (664) (592) 191 980 14 Effect of exchange rate changes on cash, cash equivalents and restricted cash 147 (3) (141) (23) - (20) Net increase (decrease) in cash, cash equivalents, and restricted cash (25) (39) (17) (17) - (98) Cash, cash equivalents and restricted cash, beginning of year 20 58 104 190 - 372 Cash, cash equivalents and restricted cash, end of year $ (5) $ 19 $ 87 $ 173 $ - $ 274

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
1. Summary of Significant Accounting Policies
Basis of Presentation	Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Acc ounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless othe rwise indicated.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Ref er to note 32 for further details. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary . The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leas es, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general (“OM&G”), depending on the nature of the transaction.
Use of Management Estimates	Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, allowance for credit losses, accumulated reserve for cost of removal , pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Mana gement evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the ye ar they arise. During the year ended December 31, 2020 , the ongoing COVID-19 pandemic has affected all service territories in which Emera operates . The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings primarily due to a favourable change to the mix of sales across customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. Favourable weather in 202 0, particular in Florida, has further reduced the consolidated impact . Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These m easures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter - in - place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility. Governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions. Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and concluded that no material adjustments are required for the year ended December 31, 2020 . Refer to Asset Impairment: Long-Lived Assets, Asset Impairment: Goodwill and Employee Benefits below for additional details on area’s that could be more significantly impacted . The extent of future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic , timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these e stimates.
Regulatory Matters	Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an opportunity for a reasonable rate of return on the equity invested or assets, as applicable (refer to n ote 7 for additional details).
Foreign Currency Translation	Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to Canadian dollars at the rates of exchange prevail ing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en ominat ed debt held in Canadian dollar functional currency companies as hedges of net investments in United States dollar d enominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balan ce sheet date is recorded in Other Comprehensive Income (“OCI”).
Revenue Recognition	Revenue Recognition Regulated Electric Revenue Electric revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity is delivered to customers over time as t he customer simultaneously receives and consumes the benefits of the electricity . Electric revenues are recognized on an accrual basi s and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi- monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calcul ated by estimating the number of m egawatt hour (“MWh”) delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-p eriod changes to customer classes. Regulated Gas Revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, whi ch is when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expecte d to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Non-regulated Revenue Marketing and trading margi ns are comprised of Emera Energy’s corresp onding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of a contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Capacity payments are recognized when obligations under the terms of a contract are satisfied, whic h is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an auction process held annually, three years in advance, through the forward capacity market. Other non- regulated revenues are recorded when obligations under terms of a contract are satisfied. Other Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue.
Lessor, Leases	Leases The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys t he right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense ass ociated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets are recognized on the Consolidated Balance Sheets based on t he present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type l ease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cos t of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leas es, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. 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 a lease at inception by evaluating if the contract conveys t he right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense ass ociated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use (“ROU”) assets are recognized on the Consolidated Balance Sheets based on t he present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type l ease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cos t of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leas es, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. 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 Electric and PGS recover from customers certain costs i ncurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” r evenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consoli dated Statements of Income.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of cons truction. The cost of additions, including betterments and replacements of units of property, plant and equipment are included in “P roperty, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gai n or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are inc luded in income as the dispositions occur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement oblig ations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs , along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance proj ects are expensed as incurred. Planned major maintenance projects that do not increase th e overall life of the related as sets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of de preciable property. For some of Emera’s rate- regulated subsidiaries depreciation is calculated using the group remaining life method , which is applied to the average investment , adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and equip ment” consist primarily of computer software and land rights . Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate- regulated subsidiaries, amortization is calculated using the amortizable life method which is app lied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval.
Goodwill	Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the e stimated fair values of identifiable assets acquired and liabilities as sumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairmen t at the reporting unit level annually or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value . Refer to note 22 for further de tail.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial sta tements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differ ences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted unless required to be offset to a regulatory asset or liability by law or by order of the regulator . Emera recognizes the effect of income tax positions only when it is more likely than not that they will be rea lized. Management reviews all readily available current and historical information, including forward-l ooking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax as sets and liabilities are made. If management subsequently d etermines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are rec orded as a reduction to income tax expense in the current or future periods to the extent that realization of such be nefit is more likely than not. Investment tax credits earned by Tampa Electric, PGS and NMGC on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by regulatory practices. Tampa Electric, PGS, NMGC, BLPC and Domlec collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSP I, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective i ncome tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax ass ets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 10 for further details.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange , interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures , options, forwards and swaps. In addition, the Company has contracts for the physical pur chase and sale of natural gas. These physical and financial contracts are classifie d as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are co nsidered derivatives. The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and no rmal sales (“NPNS”) exception. A physical contract generally qualifies for t he NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodi ty, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet string ent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the re lated hedged item is realized. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the repor ting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item wh en the hedged item is settled. Management believes any gains or losses resulting from settlement of these deriv atives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a Florida Public Service Commission approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period . The Company h as not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inve ntory and property, operating maintenance and general and plant and equipment, depending on the nature of the i tem being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an a sset in “ Receivables and other current asset s” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolid ated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collater al with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”.
Cash, Cash Equivalents and Restricted Cash	Cash , Cash Equivalents and Restricted Ca sh Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition.
Receivables	Receivables and Allowance for Credit Losses Utility c ustomer receivables are recorded at the invoiced am ount and do not bear interest. Standard payment terms for electricity and gas sa les are approximately 30 days. A late payment fee may be assessed on account balances after the due date.
Allowance for Credit Losses	Receivables and Allowance for Credit Losses Utility c ustomer receivables are recorded at the invoiced am ount and do not bear interest. Standard payment terms for electricity and gas sa les are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company is exposed to credit risk with respect to amounts receivable from cu stomers. Credit assessments may be conducted on new customers. Deposits are requested on accounts in accordance with the Company’s policy. The Company also maintains provisions for expected credit losses, which are assessed on a regular basis. Management estimates credit losses related to accounts receivable after considering historical loss experience, customer deposits, current events , the charact eristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount . Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adeq uate to cover expected losses. Receivables are written off agai nst the allowance when they are deemed uncollectible. The economic impact of COVID-19, in the service territories in which Emera operates, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables however it has not had a material impact on earnings .
Inventory	Inventory Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the we ighted-average cost will be recovered in future customer rate s.
Asset Impairment	Asset Impairment Long-Lived Assets Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs , such as a significant market disruption or sale of a business. The review of long-lived assets for impairment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indi cates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value. The Company’s assumptions relating to future results of opera tions or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are ba sed on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at December 31, 2020 , there are no indicatio ns of impairment of Emera’s long-lived assets. The impact of COVID-19 could cause the Company to impair long-lived assets in the future; however, there is currently no indication that future cash flows would be impacted to a point where the Company’s long- lived assets would not be recoverable. Impairment charges of $ 25 million ($ 26 million after tax) were recognized on certain assets during the year ended December 31, 2020 and recorded in Impairment Charge in the Consolidated Income Statement. In 2019, as a result of Hurricane Dorian, Grand Bahama recognized an impairment of $ 18 million USD which has been fully recovered through insurance . Goodwill Goodwill is not amortized but is subject to an annual assessment for impairment at the reporting unit level with interim impairment tests performed when impairment indicators are present . Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill . When a ssessing goodwill for impairment the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount or if the Company chooses to bypass the qualitative assessment , a q uantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carryi ng amount, including goodwill. If the carrying amount of the reporting unit exceeds i ts fair value, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Management estimates the fair value of the reporting unit by using the income approach or a combination of the income and market approach. The incom e approach is applied using a discounted cash flow analysis which relies on management’s best estimate of the reporting units’ projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted a verage cost of capital of comparable companies. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include di scount and growth rates, rate case assumptions, valuation of the reporting unit’s net operating loss (“ NOL ”) , utility sector market performance and transactions, projected operating and capital cash flows and the fair value of debt. Adverse changes in assu mptions described above could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill. As part of the 2020 goodwill impairment assessment management considered the potential impacts of the COVID-19 pandemic on the future earnings of the reporting units. As of December 31, 2020 , $ 5 ,649 m illion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Qualitative assessments were performed for these reporting units given the significant excess of fair value over carrying amounts calculated during the last qua ntitative test in Q4 2019. Management concluded that it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. A GBPC goodwill im pairment charge of $ 30 million was recorded in 2019 due to a decrease in expected future cash flows resulting from the impacts of Hurricane Dorian storm recovery and changes in the anticipated long term regulated capital structure of GBPC. As of December 3 1, 2020, $ 68 million of Emera’s goodwill was related to GBPC. In Q4 2020, the Company performed a quantitative impairment assessment for GBPC as this reporting unit is more sensitive to changes in forecasted future earnings due to limited excess of fair va lue over the carrying value. The assessment estimated that the fair value of the reporting unit exceeded its carrying value, including goodwill, by approximately five per cent. Adverse changes in significant assumptions could result in a future impairment . Refer to note 22 for further details. Equity Method Investments The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of imp airment indicators , i ncluding the impact of COVID-19 . If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value. No impairment of equity method investments was required for either 201 9 or 20 20 . Financial Assets Equity investments, other than those accounted for under the equity method of accounting, are measured at fair value with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required for either 201 9 or 20 20 .
Asset Retirement Obligations and Cost of Removal	Asset Retirement Obligation s An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or stat ute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s c redit adjusted risk-free rate . The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governm ental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and a ccretion expense is included as part of “D epreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant a nd equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional ARO’s which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that ma y or may not be wit hin the control of the entity. Management monitors these obligations and a liability is recognized at fair value in the period in which an amount can be determined. Cost of Removal Tampa Electric, PGS, NMGC and NSPI recognize non-ARO c osts of removal (“COR”) as regulatory liabilities. The non-ARO costs of removal represent funds received from customers through depreciation rates to cover estimated future non-legally required cost of removal of property, plant and equipment upon retireme nt. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays.
Stock-Based Compensation	Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the gr ant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially me asured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income.
Employee Benefits	Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over t he periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recogn izes the unamortized gains and losses and past service costs in AOCI or regulatory assets. The components of net periodic benefit cost other than the service cost component are included in “Other income (expense), net” on the Consolidated Statements of Inc ome. The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements.
Future accounting pronoucements	The Company considers the applicability and impact of all ASUs issued by the FASB. The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applica ble to the Company or have an insignificant impact on the consolidated financial statements. Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity In August 2020, the FASB issued ASU 2020-06, Debt - Debt with Conversion and Oth er Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40). The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to a mending 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. The guidance will be effective for annual reporting periods, includi ng interim reporting within those periods, beginning after December 15, 2021. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020. The standard can be applied through either a modified retrospective method of tr ansition or a fully retrospective method of transition. The Company early adopted the standard effective January 1, 2021 using the modified retrospective method . There was no material impact on the consolidated financial statements as a result of the adoption of this standard. Guaranteed Debt Securities Disclosure Requirements In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in the standard aligns with new SEC rules relating to change s to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying disclosure , enhancing certain narrative disclosures and permitting the disclosures to be made outside of th e financial statements. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated fin ancial statements .

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2020
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, 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) - Total operating revenues 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 - - - - 585 - 585 Impairment charges - - - - 25 - 25 Income tax expense (recovery) 89 17 (8) 51 192 - 341 Net income (loss) 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) (3) 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 have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs. (3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax 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, 2019 Operating revenues from external customers (1) $ 2,596 $ 1,429 $ 744 $ 1,097 $ 245 $ - $ 6,111 Inter-segment revenues (1) 11 1 - 22 37 (71) - Total operating revenues 2,607 1,430 744 1,119 282 (71) 6,111 Regulated fuel for generation and purchased power 772 573 286 - - (22) 1,609 Regulated cost of natural gas - - - 350 - - 350 OM&G 554 313 195 319 130 (47) 1,464 Depreciation and amortization 445 231 107 109 11 - 903 Income from equity investments - 91 5 22 36 - 154 AFUDC - debt and equity 20 6 5 2 - - 33 Interest expense, net 154 142 52 59 331 - 738 Internally allocated interest (2) - - - 14 (14) - - Impairment charges - - 34 - - - 34 Income tax expense (recovery) 79 (10) 11 48 (67) - 61 Net income (loss) attributable to common shareholders 419 229 45 183 (213) - 663 Capital expenditures 1,393 384 195 448 63 - 2,483 As at December 31, 2019 Total assets 16,214 6,717 3,069 5,489 1,459 (1,106) (3) 31,842 Investments subject to significant influence - 1,133 41 138 - - 1,312 Goodwill 4,544 - 70 1,218 3 - 5,835 (1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs. (3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation. Geographical Information Revenues (1) : For the Year ended December 31 millions of Canadian dollars 2020 2019 Canada $ 1,569 $ 1,497 United States 3,522 4,140 Barbados 263 320 The Bahamas 112 112 Dominica 40 42 $ 5,506 $ 6,111 (1) Revenues are based on country of origin of the product or service sold. Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2020 2019 Canada $ 4,304 $ 4,248 United States 14,353 13,095 Barbados 510 462 The Bahamas 289 282 Dominica 79 80 $ 19,535 $ 18,167

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
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, 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 Regulated electric revenue 2,480 1,494 474 1 - (7) 4,442 Gas Revenue Residential - - - 495 - - 495 Commercial - - - 275 - - 275 Industrial - - - 54 - - 54 Finance income (2)(3) - - - 61 - - 61 Other - - - 156 - (7) 149 Regulated gas revenue - - - 1,041 - (7) 1,034 Non-Regulated Marketing and trading margin (4) - - - - 38 - 38 Energy sales (4) - - - - 16 (16) - Capacity - - - - - - - Other - - - 16 21 - 37 Mark-to-market (3) - - - - (46) 1 (45) Non-regulated revenue - - - 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 represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with 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, 2019 Regulated Electric Revenue Residential $ 1,387 $ 746 $ 276 $ - $ - $ - $ 2,409 Commercial 745 400 339 - - - 1,484 Industrial 207 210 44 - - - 461 Other electric and regulatory deferrals 246 45 13 - - - 304 Other (1) 22 29 72 - - (12) 111 Regulated electric revenue 2,607 1,430 744 - - (12) 4,769 Gas Revenue Residential - - - 502 - - 502 Commercial - - - 298 - - 298 Industrial - - - 50 - - 50 Finance income (2)(3) - - - 60 - - 60 Other - - - 193 - (22) 171 Regulated gas revenue - - - 1,103 - (22) 1,081 Non-Regulated Marketing and trading margin (4) - - - - 31 - 31 Energy sales (4) - - - - 80 (12) 68 Capacity - - - - 38 - 38 Other - - - 16 31 (25) 22 Mark-to-market (3) - - - - 102 - 102 Non-regulated revenue - - - 16 282 (37) 261 Total operating revenues $ 2,607 $ 1,430 $ 744 $ 1,119 $ 282 $ (71) $ 6,111 (1) Other includes rental revenues, which do not represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
7. Regulatory Assets and Liabilities
Regulatory Assets	As at December 31 December 31 millions of Canadian dollars 2020 2019 Regulatory assets Deferred income tax regulatory assets $ 887 $ 862 Pension and post-retirement medical plan 394 380 Deferrals related to derivative instruments 65 81 Cost recovery clauses 49 13 Storm restoration regulatory asset 41 38 Environmental remediations 28 26 Stranded cost recovery 26 27 Demand side management ("DSM") deferral 15 19 Unamortized defeasance costs 13 19 Other 66 87 $ 1,584 $ 1,552 Current $ 165 $ 121 Long-term 1,419 1,431 Total regulatory assets $ 1,584 $ 1,552 Regulatory liabilities Deferred income tax regulatory liabilities 933 985 Accumulated reserve - cost of remova l 865 891 Storm reserve 62 62 Cost recovery clauses 31 53 Self-insurance fund (note 32) 28 29 Regulated fuel adjustment mechanism 21 115 Deferrals related to derivative instruments 15 42 Other 6 4 $ 1,961 $ 2,181 Current $ 129 $ 295 Long-term 1,832 1,886 Total regulatory liabilities $ 1,961 $ 2,181
Regulatory Liabilities	As at December 31 December 31 millions of Canadian dollars 2020 2019 Regulatory assets Deferred income tax regulatory assets $ 887 $ 862 Pension and post-retirement medical plan 394 380 Deferrals related to derivative instruments 65 81 Cost recovery clauses 49 13 Storm restoration regulatory asset 41 38 Environmental remediations 28 26 Stranded cost recovery 26 27 Demand side management ("DSM") deferral 15 19 Unamortized defeasance costs 13 19 Other 66 87 $ 1,584 $ 1,552 Current $ 165 $ 121 Long-term 1,419 1,431 Total regulatory assets $ 1,584 $ 1,552 Regulatory liabilities Deferred income tax regulatory liabilities 933 985 Accumulated reserve - cost of remova l 865 891 Storm reserve 62 62 Cost recovery clauses 31 53 Self-insurance fund (note 32) 28 29 Regulated fuel adjustment mechanism 21 115 Deferrals related to derivative instruments 15 42 Other 6 4 $ 1,961 $ 2,181 Current $ 129 $ 295 Long-term 1,832 1,886 Total regulatory liabilities $ 1,961 $ 2,181

Investments Subject to Signif_2

Investments Subject to Significant Influence and Equity Income (Tables)	12 Months Ended
	Dec. 31, 2020
Variable Interest Entity [Line Items]
Investments subject to significant influence	Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2020 2019 2020 2019 2020 LIL (1) $ 629 $ 579 $ 49 $ 45 45.6 NSPML 547 554 47 46 100.0 M&NP (2) 129 138 20 22 12.9 Lucelec (2) 41 41 4 3 19.5 Bear Swamp (3) - - 29 35 50.0 Other Investments - - - 3 $ 1,346 $ 1,312 $ 149 $ 154 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL ‎is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp's credit investment balance of $118 million (2019 - $137 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets.
NSPML
Variable Interest Entity [Line Items]
Investments subject to significant influence	Emera accounts for its variable interest investment in NSPML as an equity investment (note 32 ). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2020 2019 Balance Sheets Current assets $ 57 $ 69 Property, plant and equipment 1,629 1,671 Regulatory assets 210 177 Non-current assets 32 32 Total assets $ 1,928 $ 1,949 Current liabilities $ 56 $ 23 Long-term debt (1) 1,228 1,288 Non-current liabilities 97 84 Equity 547 554 Total liabilities and equity $ 1,928 $ 1,949 (1) The project debt has been guaranteed by the Government of Canada.

Other Income (Expenses), Net (T

Other Income (Expenses), Net (Table)	12 Months Ended
	Dec. 31, 2020
9. Other Income (Expenses), Net
Components of other income (expense), net	Other income (expenses), net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2020 2019 Allowance for equity funds used during construction $ 45 $ 21 Gain on sale of Emera Maine, net of transaction costs (1) 585 - TECO Guatemala Holdings award (2) 49 - Other 29 (9) $ 708 $ 12 (1) Refer to note 4 for further detail related to the gain on sale of Emera Maine. (2) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
10. Income Taxes
Income tax provision	The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of Canadian dollars 2020 2019 Income before provision for income taxes $ 1,325 $ 771 Statutory income tax rate 29.5% 31% Income taxes, at statutory income tax rate 391 239 Additional impact from the sale of Emera Maine 102 - Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (48) (66) Foreign tax rate variance (45) (49) Amortization of deferred income tax regulatory liabilities (44) (36) Tax effect of equity earnings (15) (15) Other - (12) Income tax expense $ 341 $ 61 Effective income tax rate 26% 8%
Composition of taxes on income from continuing operations	millions of Canadian dollars 2020 2019 Current income taxes Canada $ 18 $ (19) United States (58) (46) Other - 1 Deferred income taxes Canada 20 45 United States 426 137 Other (9) - Investment tax credits United States (10) (9) Operating loss carryforwards Canada (46) (48) Income tax expense $ 341 $ 61 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2020 2019 Canada $ 176 $ 98 United States 1,142 682 Other 7 (9) Income before provision for income taxes $ 1,325 $ 771
Deferred income tax assets and liabilities	The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of Canadian dollars 2020 2019 Deferred income tax assets: Tax loss carryforwards $ 724 $ 908 Tax credit carryforwards 319 311 Regulatory liabilities - cost of removal 184 195 Derivative instruments 108 145 Other 375 413 Total deferred income tax assets before valuation allowance 1,710 1,972 Valuation allowance (202) (193) Total deferred income tax assets after valuation allowance $ 1,508 $ 1,779 Deferred income tax (liabilities): Property, plant and equipment $ (2,450) $ (2,382) Derivative instruments (93) (148) Other (385) (348) Total deferred income tax liabilities $ (2,928) $ (2,878) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 209 $ 186 Long-term deferred income tax liabilities (1,629) (1,285) Net deferred income tax liabilities $ (1,420) $ (1,099)
Net operating loss ("NOL"), capital loss and tax credit carryforwards and their expiration periods	Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2020 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 1,370 $ (619) $ 751 2027 - 2040 Capital loss 61 (61) - Indefinite United States Federal NOL $ 1,412 $ - $ 1,412 2030 - 2040 State NOL 563 - 563 2032 - 2040 Tax credit 319 - 319 2025 - 2040 Other NOL $ 39 $ (39) $ - 2021 - 2027
Details of the change in unrecognized tax benefits	millions of Canadian dollars 2020 2019 Balance, January 1 $ 29 $ 26 Increases due to tax positions related to current year 1 2 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (2) - Balance, December 31 $ 30 $ 29

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2020
11. Common Stock
Common Stock	Authorized : Unlimited number of non-par value common shares. 2020 2019 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2019 242.48 $ 6,216 234.12 $ 5,816 Conversion of Convertible Debentures - - 0.03 1 Issuance of common stock (1) (2) 4.54 251 1.77 99 Issued under Purchase Plans at market rate 3.99 219 3.99 202 Discount on shares purchased under Dividend Reinvestment Plan - (4) - (7) Options exercised under senior management share option plan 0.42 20 2.57 104 Employee Share Purchase Plan - 3 - 1 Balance, December 31, 2020 251.43 $ 6,705 242.48 $ 6,216 (1) As at December 31, 2019, a total of 1,768,120 common shares were issued under Emera's at-the-market program ("ATM program") at an average price of $56.56 per share for gross proceeds of $100 million ($99 million net of issuance costs). (2) For the year ended December 31, 2020, 4,544,025 common shares were issued under Emera's ATM program at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs).

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
12. Earnings Per Share
Computation of basic and diluted earnings per share	The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2020 2019 Numerator Net income attributable to common shareholders $ 937.6 $ 662.8 Diluted numerator 937.6 662.8 Denominator Weighted average shares of common stock outstanding 246.5 238.5 Weighted average deferred share units outstanding 1.3 1.4 Weighted average shares of common stock outstanding – basic 247.8 239.9 Stock-based compensation 0.4 0.6 Weighted average shares of common stock outstanding – diluted 248.2 240.5 Earnings per common share Basic $ 3.78 $ 2.76 Diluted $ 3.78 $ 2.76

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2020
13. Accumulated Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income	The components of accumulated other comprehensive income are as follows: 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 AOCI 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 (gain) - - 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) For the year ended December 31, 2019 Balance, January 1, 2019 (1) $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 Other comprehensive income (loss) before reclassifications (401) 78 3 - - (320) Amounts reclassified from accumulated other comprehensive income loss - - 3 - 74 77 Net current period other comprehensive income (loss) (401) 78 6 - 74 (243) Balance, December 31, 2019 $ 253 $ 4 $ (1) $ (1) $ (160) $ 95
Reclassifications out of accumulated other comprehensive income (loss)	The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2020 2019 Affected line item in the Consolidated Financial Statements Losses on derivatives recognized as cash flow hedges Foreign exchange forwards Operating revenue - regulated $ 2 $ 3 Total before tax 2 3 Total net of tax $ 2 $ 3 Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Other income, net $ 15 $ 17 Past service costs (gains) Other income, net (1) (1) Amounts reclassified into obligations Pension and post-retirement benefits (16) 39 Amounts reclassified into obligations Regulatory assets - 28 Total before tax (2) 83 Income tax recovery (expense) 1 (9) Total net of tax $ (1) $ 74 Total reclassifications out of AOCI, net of tax, for the period $ 1 $ 77

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2020
14. Inventory
Inventory	As at December 31 December 31 millions of Canadian dollars 2020 2019 Fuel $ 199 $ 232 Materials 254 235 $ 453 $ 467

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
15. Derivative Instruments
Derivative assets and liabilities	Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2020 2019 2020 2019 Cash flow hedges Interest rate hedge $ 1 $ - $ - $ - Foreign exchange forwards - - - 1 1 - - 1 Regulatory deferral Commodity swaps and forwards Coal purchases 1 8 6 39 Power purchases 10 23 34 36 Natural gas purchases and sales 4 2 2 5 Heavy fuel oil purchases 1 1 5 - Foreign exchange forwards - 2 17 6 16 36 64 86 HFT derivatives Power swaps and physical contracts 13 19 13 22 Natural gas swaps, futures, forwards, physical contracts 139 151 346 381 152 170 359 403 Other derivatives Equity derivatives - 1 1 - Foreign exchange forwards 15 - - - 15 1 1 - Total gross current derivatives 184 207 424 490 Impact of master netting agreements with intent to settle net or simultaneously (86) (120) (86) (120) 98 87 338 370 Current 73 54 251 268 Long-term 25 33 87 102 Total derivatives $ 98 $ 87 $ 338 $ 370 Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Details of master netting agreements	Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2020 2019 2020 2019 Regulatory deferral $ 2 $ 8 $ 2 $ 8 HFT derivatives 84 112 84 112 Total impact of master netting agreements with intent to settle net or simultaneously $ 86 $ 120 $ 86 $ 120
Cash flow hedges recorded in income and AOCI	For the Year ended December 31 millions of Canadian dollars 2020 2019 Foreign Interest Foreign exchange rate exchange forwards hedge forwards Realized gain (loss) in operating revenue – regulated $ (2) $ - $ (3) Total gains (losses) in net income $ (2) $ - $ (3) As at December 31 millions of Canadian dollars 2020 2019 Foreign Interest Foreign exchange rate exchange forwards hedge forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ - $ 1 $ (1) The Company expects $1 million of unrealized gains currently in AOCI to be reclassified into net income within the next 12 months, as the underlying hedged transactions settle. As at December 31, 2020, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2021 U.S. Treasury lock (USD) $ 350
Realized and unrealized gains (losses) with respect to derivatives	For the Year ended December 31 millions of Canadian dollars 2020 2019 Commodity swaps and forwards Foreign exchange forwards Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (36) $ (11) $ (89) $ (6) Unrealized gain (loss) in regulatory liabilities 3 3 9 (8) Realized gain (loss) in regulatory assets 2 - - - Realized (gain) loss in regulatory liabilities 14 - (2) - Realized (gain) loss in inventory (1) 8 (2) (36) (11) Realized (gain) loss in regulated fuel for generation and purchased power (2) 24 (3) 3 (8) Total change derivative instruments $ 15 $ (13) $ (115) $ (33) (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. For the Year ended December 31 millions of Canadian dollars 2020 2019 Power swaps and physical contracts in non-regulated operating revenues $ (1) $ 1 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 205 281 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (4) (6) $ 200 $ 276 For the Year ended December 31 millions of Canadian dollars 2020 2019 Foreign Foreign Exchange Equity Exchange Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in operating, maintenance and general $ - $ (1) $ - $ 1 Unrealized gain (loss) in other income (expense), net 15 - - - Realized gain (loss) in operating, maintenance and general - (3) - 27 Realized gain (loss) in other income (expense) (2) - - - Total gains (losses) in net income $ 13 $ (4) $ - $ 28
Notional volumes of derivatives designated for regulatory deferral that are expected to settle as outlined	2021 2022-2023 millions Purchases Purchases Natural Gas (Mmbtu) 5 7 Power (MWh) 2 2 Heavy fuel oil (bbls) - 1 Coal (metric tonnes) - 1 2021 2022-2023 Foreign exchange contracts (millions of US dollars) $ 160 $ 135 Weighted average rate 1.3339 1.3266 % of USD requirements 78% 37% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required. millions 2021 2022 2023 2024 2025 Natural gas purchases (Mmbtu) 387 61 45 26 26 Natural gas sales (Mmbtu) 412 50 17 2 2 Power purchases (MWh) 2 - - - - Power sales (MWh) 1 - - - -
Concentration Risk	Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2020 December 31, 2019 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 341 32% $ 344 31% Commercial 143 14% 170 15% Industrial 49 5% 66 6% Other 96 9% 131 12% 629 60% 711 64% Trading group Credit rating of A- or above 54 5% 38 3% Credit rating of BBB- to BBB+ 41 4% 59 5% Not rated 75 7% 95 9% 170 16% 192 17% Other accounts receivable 159 15% 184 16% Classification as assets held for sale (1) - 0% (55) -5% 958 91% 1,032 92% Derivative Instruments (current and long-term) Credit rating of A- or above 60 6% 47 4% Credit rating of BBB- to BBB+ 13 1% 8 1% Not rated 25 2% 32 3% 98 9% 87 8% $ 1,056 100% $ 1,119 100% (1) Emera Maine’s assets and liabilities were classified as held for sale at December 31, 2019. On March 24, 2020, Emera completed the sale of Emera Maine. Refer to note 4 for further detail.
Cash Collateral	As at December 31 December 31 millions of Canadian dollars 2020 2019 Cash collateral provided to others $ 69 $ 101 Cash collateral received from others 6 2

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
16. Fair Value Measurements
Classification of the methodology used by the Company to fair value its derivatives	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 Power purchases 9 - - 9 Natural gas purchases and sales 2 1 - 3 Heavy fuel oil purchases - 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 Coal purchases - 4 - 4 Power purchases 33 - - 33 Heavy fuel oil purchases 3 3 - 6 Natural gas purchases and sales - 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) As at December 31, 2019 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards Power purchases $ 23 $ - $ - $ 23 Natural gas purchases and sales - 2 - 2 Heavy fuel oil purchases - 1 - 1 Foreign exchange forwards - 2 - 2 23 5 - 28 HFT derivatives Power swaps and physical contracts 1 3 1 5 Natural gas swaps, futures, forwards, physical contracts and related transportation (7) 46 14 53 (6) 49 15 58 Other derivatives Equity derivatives 1 - - 1 1 - - 1 Total assets 18 54 15 87 Liabilities Cash flow hedges Foreign exchange forwards - 1 - 1 - 1 - 1 Regulatory deferral Commodity swaps and forwards Coal purchases - 31 - 31 Power purchases 36 - - 36 Natural gas purchased and sales 3 2 - 5 Foreign exchange forwards - 6 - 6 39 39 - 78 HFT derivatives Power swaps and physical contracts 5 2 - 7 Natural gas swaps, futures, forwards and physical contracts 2 33 249 284 7 35 249 291 Total liabilities 46 75 249 370 Net assets (liabilities) $ (28) $ (21) $ (234) $ (283)
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 for the year ended December 31, 2020 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2020 $ 1 $ 14 $ 15 Total realized and unrealized gains (losses) included in non-regulated operating revenues 3 (2) 1 Net transfers out of Level 3 (2) - (2) Balance, December 31, 2020 $ 2 $ 12 $ 14 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2020 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2020 $ - $ 249 $ 249 Total realized and unrealized gains included in non-regulated operating revenues 2 8 10 Net transfers out of Level 3 (1) - (1) Balance, December 31, 2020 $ 1 $ 257 $ 258 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% 0.60% 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% 0.40% forwards and physical contracts Discount rate 0.00% - 10.36% 0.75% (6) Modelled pricing Third-party pricing $1.82 - $8.44 $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 Own credit risk 0.02% - 6.85% 2.02% physical contracts 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 As at December 31, 2019 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 1 Modelled pricing Third-party pricing $21.40 - $74.05 $35.03 Power swaps and Probability of default 0.01% - 1.14% 0.21% physical contracts Discount rate 0.15% - 6.65% 2.78% HFT derivatives – 9 Modelled pricing Third-party pricing $1.63 - $7.45 $2.37 Natural gas swaps, futures, Probability of default 0.01% - 2.31% 0.09% forwards, and physical contracts Discount rate 0.01% - 20.93% 1.55% 5 Modelled pricing Third-party pricing $1.33 - $8.76 $5.05 Basis adjustment $0.00 - $1.31 $0.76 Probability of default 0.01% - 3.33% 0.28% Discount rate 0.01% - 4.71% 0.91% Total assets $ 15 Liabilities HFT derivatives – 228 Modelled pricing Third-party pricing $1.54 - $7.45 $4.07 Natural gas swaps, futures, Own credit risk 0.01% - 2.31% 0.12% forwards and physical contracts Discount rate 0.01% - 18.63% 1.89% 21 Modelled pricing Third-party pricing $1.36 - $9.75 $5.45 Basis adjustment $0.00 - $1.31 $0.91 Own credit risk 0.01% - 3.33% 0.06% Discount rate 0.01% - 3.76% 0.81% Total liabilities $ 249 Net assets (liabilities) $ (234)
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 on the Consolidated Balance Sheets. The balance consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2020 $ 13,721 $ 16,487 $ - $ 16,020 $ 467 $ 16,487 December 31, 2019 $ 14,180 $ 16,049 $ - $ 15,598 $ 451 $ 16,049

Receivables and Other Current_2

Receivables and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2020
18. Receivables and Other Current Assets
Summary of Receivables And Other Current Assets	18. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2020 2019 Customer accounts receivable – billed $ 570 $ 603 Customer accounts receivable – unbilled 286 265 Allowance for credit losses (22) (9) Capitalized transportation capacity (1) 200 272 Income tax receivable 11 118 Prepaid expenses 50 48 Other 138 189 $ 1,233 $ 1,486 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
20. Property, Plant and Equipment
Regulated and Non-Regulated Assets	Property, plant and equipment consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of Canadian dollars Estimated useful life 2020 2019 Generation 3 to 131 $ 11,474 $ 11,181 Transmission 11 to 80 2,414 2,318 Distribution 4 to 80 5,997 5,820 Gas transmission and distribution 7 to 85 3,879 3,568 General plant and other (1) 2 to 60 2,127 2,006 Total cost 25,891 24,893 Less: Accumulated depreciation (1) (8,714) (8,317) 17,177 16,576 Construction work in progress (1) 2,358 1,591 Net book value $ 19,535 $ 18,167 (1) SeaCoast owns a 50% undivided ownership interest in a jointly owned 26-mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2020, SeaCoast’s share of plant in service was $34 million, accumulated depreciation of nil and construction work in progress of nil. At December 31, 2019, SeaCoast’s share of construction work in progress was $8 million. SeaCoast’s undivided ownership interest is financed with its funds and all operations are accounted for as if such participating interest was a wholly owned facility. SeaCoast’s share of direct expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 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 $ 2,822 $ 353 $ 2,650 $ 350 Service cost 46 5 47 4 Plan participant contributions 7 5 8 5 Interest cost 84 10 102 14 Benefits paid (135) (27) (130) (23) Actuarial losses 189 52 231 19 Settlements and curtailments (229) (52) (20) - Foreign currency translation adjustment (25) (7) (66) (16) Balance, December 31 2,759 339 2,822 353 Change in plan assets Balance, January 1 2,593 56 2,300 49 Employer contributions 41 21 52 19 Plan participant contributions 7 5 8 5 Benefits paid (135) (27) (130) (23) Actual return on assets, net of expenses 310 5 424 7 Settlements and curtailments (191) (7) (7) - Foreign currency translation adjustment (20) (1) (54) (1) Balance, December 31 2,605 52 2,593 56 Funded status, end of year $ (154) $ (287) $ (229) $ (297)
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 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,736 $ 308 $ 2,797 $ 323 Fair value of plan assets 2,568 - 2,557 7 Funded status $ (168) $ (308) $ (240) $ (316) millions of Canadian dollars 2020 2019 Defined benefit pension plans Defined benefit pension plans ABO $ 1,519 $ 2,665 Fair value of plan assets 1,419 2,557 Funded status $ (100) $ (108)
Amounts recognized in the Consolidated Balance Sheets	As at December 31 December 31 millions of Canadian dollars 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (4) $ (19) $ (4) $ (18) Long-term liabilities (163) (290) (206) (254) Long-term liabilities associated with assets held for sale (1) - - (30) (44) Other long-term assets 13 20 11 19 Amount included in deferred income tax (4) (1) (7) 1 AOCI and regulatory assets, net of tax 443 107 524 72 Net amount recognized $ 285 $ (183) $ 288 $ (224) (1) On March 24, 2020, Emera sold Emera Maine, refer to note 4 for further details. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale.
Amounts Recognized in AOCI and Regulatory Assets	Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2020 $ 358 $ 160 $ (1) Amortized in current period (25) (15) 1 Current year addition to AOCI or regulatory assets (12) 14 - Change in current year related to sale of Emera Maine (39) - - Change in foreign exchange rate (3) 1 - Balance, December 31, 2020 $ 279 $ 160 $ - Non-pension benefits plans Balance, January 1, 2020 $ 78 $ (5) $ - Amortized in current period - - - Current year addition to AOCI or regulatory assets 48 2 - Change in current year related to sale of Emera Maine (13) - - Change in foreign exchange rate (3) (1) - Balance, December 31, 2020 $ 110 $ (4) $ - 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 160 $ (4) $ 160 $ (5) Past service (gains) costs - - (1) - Regulatory assets 279 110 358 78 Total AOCI and regulatory assets before deferred income taxes 439 106 517 73 Amount included in deferred income tax assets 4 1 7 (1) Net amount in AOCI and regulatory assets $ 443 $ 107 $ 524 $ 72
Benefit Cost Components	As at Year ended December 31 millions of Canadian dollars 2020 2019 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 46 $ 5 $ 47 $ 4 Interest cost 84 10 102 14 Expected return on plan assets (141) (1) (147) (2) Current year amortization of: Actuarial losses (gains) 15 - 16 - Past service costs (gains) (1) - (1) - Regulatory assets (liability) 25 - 20 (5) Settlement, curtailments - - 1 - Total $ 28 $ 14 $ 38 $ 11
Pension Plan Asset Allocations	Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 5% Fixed income 35% to 50% Equities: Canadian 12% to 22% Non-Canadian 30% to 55% Non-Canadian Pension Plans Asset Class Target Range at Market 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, 2020 Cash and cash equivalents $ - $ 68 $ - $ 68 3 % Net in-transits - (99) - (99) (4) % Equity Securities: Canadian equity - 154 - 154 6 % US equity - 380 - 380 15 % Other equity - 243 - 243 9 % Fixed income securities: Government - - 119 119 5 % Corporate - - 141 141 5 % Other - 10 3 13 - % Mutual funds - 88 - 88 3 % Other - (3) (4) (7) - % Open-ended investments measured at NAV (1) 801 - - 801 31 % Common collective trusts measured at NAV (2) 704 - - 704 27 % Total $ 1,505 $ 841 $ 259 $ 2,605 100 % December 31, 2019 Cash and cash equivalents $ - $ 44 $ - $ 44 2 % Net in-transits - (48) - (48) (2) % Equity securities: Canadian equity - 210 - 210 8 % US equity - 388 - 388 15 % Other equity - 176 - 176 7 % Fixed Income securities: Government - - 93 93 3 % Corporate - - 126 126 5 % Other - 5 9 14 - Mutual funds - 199 - 199 8 % Other - (5) 1 (4) - % Open-ended investments measured at NAV (1) 860 - - 860 33 % Common collective trusts measured at NAV (2) 535 - - 535 21 % Total $ 1,395 $ 969 $ 229 $ 2,593 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor 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 2021 $ 41 $ 19 Expected benefit payments 2021 140 21 2022 154 22 2023 154 22 2024 162 22 2025 170 22 2026 – 2030 914 105
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 used in accounting for defined benefit pension and other post-retirement benefit plans: 2020 2019 (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 2.49 % 2.48 % 3.17 % 3.27 % Discount rate - future service 2.64 % 2.51 % 3.21 % 3.28 % Rate of compensation increase 2.89 % 3.04 % 3.32 % 3.70 % Health care trend - initial (next year) - 5.64 % - 6.15 % - ultimate - 4.35 % - 4.38 % - year ultimate reached 2038 2038 Benefit cost for year ended December 31: Discount rate - past service 3.17 % 3.28 % 4.05 % 4.30 % Discount rate - future service 3.21 % 3.28 % 4.05 % 4.30 % Expected long-term return on plan assets 6.29 % 3.25 % 6.50 % 2.81 % Rate of compensation increase 3.34 % 3.70 % 3.30 % 3.67 % Health care trend - initial (current year) - 5.91 % - 6.39 % - ultimate - 4.37 % - 4.45 % - year ultimate reached 2038 2035 Actual assumptions used differ by plan.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
19. Leases
Lessee, Operating Lease and additional information	As at December 31 December 31 millions of Canadian dollars Classification 2020 2019 Right-of-use asset Other long-term assets $ 61 $ 64 Lease liabilities Current Other current liabilities 3 5 Long-term Other long-term liabilities 60 61 Total lease liabilities $ 63 $ 66 Additional information related to Emera's leases is as follows: Year ended December For the 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions of Canadian dollars) $ 7 $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases (millions of Canadian dollars) $ 7 $ 16 Weighted average remaining lease term (years) 43 39 Weighted average discount rate- operating leases 3.96% 4.07%
Future minimum lease payments under non-cancellable operating leases	Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Minimum lease payments $ 6 $ 6 $ 6 $ 5 $ 4 $ 112 $ 139 Less imputed interest - - - - - - (76) Total $ 6 $ 6 $ 6 $ 5 $ 4 $ 112 $ 63
Net Investment in direct finance leases	As at December 31 December 31 millions of Canadian dollars 2020 2019 Total minimum lease payment to be received 1,018 $ 1,066 Less: amounts representing estimated executory costs (179) (189) Minimum lease payments receivable 839 $ 877 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (487) (532) Net investment in direct finance and sales-type leases 535 $ 528 Principal due within one year (included in "Receivables and other current assets") 18 17 Net investment in sales-type leases - long-term (included in "Other long-term assets") 42 38 Net Investment in direct finance leases - long-term 475 $ 473
Future minimum lease payments to be received for the next five years	As at December 31, 2020, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Minimum lease payments to be received $ 78 $ 77 $ 76 $ 77 $ 79 $ 631 $ 1,018 Less: executory costs (179) Minimum lease payments receivable $ 78 $ 77 $ 76 $ 77 $ 79 $ 631 $ 839

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
22. Goodwill
Change in goodwill	22. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2020 2019 Balance, January 1 $ 5,835 $ 6,313 Additions - 3 GBPC i mpairment charge - (30) Classified as assets held for sale (1) - (148) Change in foreign exchange rate (115) (303) Balance, December 31 $ 5,720 $ 5,835 (1) On March 25, 2019, Emera announced the sale of Emera Maine. Emera Maine’s assets and liabilities were classified as held for sale. Refer to note 4 for further detail.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
23. Short-Term Debt
Short-term debt and the related weighted-average interest rates	millions of Canadian dollars 2020 Weighted average interest rate 2019 Weighted average interest rate Tampa Electric Company ("TEC") Advances on accounts receivable and revolving credit facilities $ 987 0.89 % $ 452 2.56 % Emera Non-revolving term facility 400 0.94 % 399 2.69 % Bank indebtedness - - % 6 - % TECO Finance Advances on revolving credit and term facilities 205 1.46 % 656 2.39 % NMGC Advances on revolving credit facilities 21 1.22 % 8 2.70 % GBPC Advances on revolving credit facilities 11 5.25 % 10 5.25 % NSPI Bank indebtedness 1 - % 6 - % Short-term debt $ 1,625 $ 1,537 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2020 2019 Tampa Electric Company - revolving credit facility 2023 $ 1,019 $ 520 TECO Energy/TECO Finance - revolving credit facility 2023 509 520 Emera - non-revolving term facility 2021 400 400 TEC - term loan 2021 382 - TEC - accounts receivable revolving credit facility 2021 191 195 NMGC - revolving credit facility 2023 159 162 GBPC - revolving credit facility on demand 17 17 TECO Energy/TECO Finance - term credit facility - 649 Total 2,677 2,463 Less: Advances under revolving credit and term facilities 1,624 1,525 Letters of credit issued within the credit facilities 4 3 Total advances under available facilities 1,628 1,528 Available capacity under existing agreements $ 1,049 $ 935

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
24. Other Current Liabilities
Other Current Liabilities	As at December 31 December 31 millions of Canadian dollars 2020 2019 Accrued charges $ 141 $ 147 Accrued interest on long-term debt 71 77 Pension and post-retirement liabilities (note 21 ) 23 22 Sales and other taxes payable 6 13 Income tax payable 1 1 Other 98 73 $ 340 $ 333

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Maturity 2020 2019 Emera Bankers acceptances, LIBOR loans Variable Variable 2024 $ 263 $ 437 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,528 1,559 $ 2,291 $ 2,496 Emera Finance Unsecured senior notes (USD) 3.86% 3.86% 2021 - 2046 $ 3,501 $ 3,572 TECO Finance Fixed rate notes and bonds (USD) - 5.15% - $ - 390 Tampa Electric (2) Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2050 $ 3,268 $ 3,334 PGS Fixed rate notes and bonds (USD) 4.58% 4.58% 2021 - 2050 $ 429 $ 437 NMGC Fixed rate notes and bonds (USD) 4.30% 4.30% 2021 - 2049 $ 465 $ 474 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 191 $ 195 NSPI Discount notes Variable Variable 2024 $ 291 $ 308 Medium term fixed rate notes 5.14% 5.37% 2025 - 2097 2,665 2,365 $ 2,956 $ 2,673 Emera Maine LIBOR loans and demand loans Variable $ - $ 11 Secured fixed rate mortgage bonds (USD) - 9.74% - - 65 Unsecured senior fixed rate notes (USD) - 4.15% - - 442 $ - $ 518 EBP Senior secured credit facility Variable Variable 2023 $ 249 $ 248 ECI Secured senior notes (USD) Variable Variable 2021 - 2031 $ 106 $ 130 Amortizing fixed rate notes (USD) 3.92% 3.89% 2021 - 2022 100 $ 122 Non-revolving term facility, floating rate Variable - 2025 28 $ - Non-revolving term facility, fixed rate 2.60% - 2025 68 $ - Secured fixed rate senior notes (3) 4.39% 4.84% 2022 - 2035 174 $ 218 $ 476 $ 470 Adjustments Fair market value adjustment - TECO Energy acquisition (4) $ 5 $ 8 Debt issuance costs (110) (119) Classification as liabilities held for sale (5) - (516) Amount due within one year (1,382) (501) $ (1,487) $ (1,128) Long-Term Debt $ 12,339 $ 13,679 (1) Weighted average interest rate of fixed rate long-term debt. (2) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (3) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (4) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt. (5) On March 24,2020 Emera sold Emera Maine. Refer to note 4 for further detail. As at December 31, 2019, Emera Maine’s assets and liabilities are classified as held for sale. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2020 2019 Emera – revolving credit facility (1) June 2024 $ 900 $ 900 NSPI - revolving credit facility (1) October 2024 600 600 ECI – revolving credit facilities 2021-2023 28 25 Emera Maine – revolving credit facility - 104 Total 1,528 1,629 Less: Borrowings under credit facilities 569 771 Letters of credit issued inside credit facilities 31 65 Use of available facilities 600 836 Available capacity under existing agreements $ 928 $ 793 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. As at Financial Covenant Requirement December 31, 2020 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.56 : 1
Long-Term Debt Maturities	millions of Canadian dollars 2021 2022 2023 2024 2025 Thereafter Total Emera $ - $ - $ 500 $ 263 $ - $ 1,528 $ 2,291 Emera US Finance LP 955 - - - - 2,546 3,501 Tampa Electric 295 286 - - - 2,687 3,268 PGS 59 33 - - - 337 429 NMGC - - - - - 465 465 NMGI - - - 191 - - 191 NSPI - - - 291 125 2,540 2,956 EBP - - 249 - - - 249 ECI 73 88 60 75 101 79 476 Total $ 1,382 $ 407 $ 809 $ 820 $ 226 $ 10,182 $ 13,826

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
26. Asset Retirement Obligations
Change in ARO	The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2020 2019 Balance, January 1 $ 185 $ 205 Additions 10 - Liabilities settled (1) (25) (25) Accretion included in depreciation expense 9 7 Accretion deferred to regulatory asset (included in property, plant and equipment) (3) - Other 1 3 Change in foreign exchange rate 1 (5) Balance, December 31 $ 178 $ 185 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The decreases in ARO in 2020 and 2019 are due to the closure of CCR management facilities.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
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 2021 2022 2023 2024 2025 Thereafter Total Purchased power (1) $ 231 $ 218 $ 216 $ 218 $ 224 $ 2,242 $ 3,349 Transportation (2) 518 393 339 306 282 2,704 4,542 Capital projects 394 98 76 - - - 568 Fuel, gas supply and storage 494 91 6 1 - - 592 Long-term service agreements (3) 43 41 36 33 34 92 279 Equity investment commitments (4) - 240 - - - - 240 Leases and other (5) 16 17 16 15 8 118 190 Demand side management 40 45 - - - - 85 $ 1,736 $ 1,143 $ 689 $ 573 $ 548 $ 5,156 $ 9,845 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $149 million related to a gas transportation contract between PGS and SeaCoast through 2040. (3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. (4) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (5) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

Cumulative Preferred Stock (Tab

Cumulative Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2020
28. Cumulative Preferred Stock
Cumulative Preferred Stock	Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2020 December 31, 2019 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 4,866,814 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 1,133,186 $ 52 2,135,364 $ 52 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.75 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0625 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Total 41,000,000 $ 1,004 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) Series A (5)(6) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B Series C 4.100 1.1802 2.65 August 15, 2023 25.00 Series D Series F (7)(8) 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) Series B (9) 2.393 Floating 1.84 August 15, 2025 25.00 Series A Series H 4.900 1.2250 4.90 August 15, 2023 25.00 Series I Perpetual fixed rate Series E (10) 4.500 1.1250 25.75 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent. (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2023, February 15, 2020 and August 15, 2023, respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent. (5) The annual fixed dividend per share for First Preferred Shares, Series A was reset from $0.6388 to $0.5456 for the five-year period from and including August 15, 2020. (6) On July 9, 2020, Emera announced it would not redeem the Cumulative Rate Reset Preferred Shares, Series A or the Cumulative Floating Rate First Preferred Shares, Series B. On August 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A Shares were tendered for conversion into Series B Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B Shares were tendered for conversion into Series A Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A Shares and 1,133,186 Series B Shares issued and outstanding. (7) On January 7, 2020, Emera announced it would not redeem the 8,000,000 Cumulative Rate Reset First Preferred Shares, Series F Shares. The holders of the Series F Shares have the right, at their option, to convert all or any of their Series F Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series G of the Company on February 15, 2020, or to continue to hold their Series F Shares. On February 6, 2020, Emera announced that, after having taken into account all conversion notices received from holders, no First Preferred Shares, Series F Shares would be converted into Cumulative Floating Rate First Preferred Shares, Series G Shares. (8) The annual fixed dividend per share for First Preferred Shares, Series F was reset from $1.0625 to $1.0505 for the five-year period from and including February 15, 2020. (9)Emera announced a dividend rate of 2.021 per cent on the Series B Shares for the three-month period which commenced on August 15, 2020 and ended on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter (10) First Preferred Shares, Series E are redeemable at $25.75 to August 15, 2020, decreasing $0.25 each year until August 15, 2022 and $25.00 per share thereafter.

Non-Controlling Interest in S_2

Non-Controlling Interest in Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2020
29. Non-Controlling Interest in Subsidiaries
Non-controlling Interest	29. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of Canadian dollars 2020 2019 Preferred shares of GBPC $ 14 $ 14 Domlec 20 21 $ 34 $ 35
Preferred shares of GBPC	Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual preferred shares. 2020 2019 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, 2020
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 2020 2019 Changes in non-cash working capital: Inventory $ 6 $ (19) Receivables and other current assets 187 154 Accounts payable 55 (137) Other current liabilities (31) (71) Total non-cash working capital $ 217 $ (73) Supplemental disclosure of cash paid (received): Interest $ 679 $ 750 Income taxes $ (148) $ (107) Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 199 $ 187 Reclassification of long-term debt from current to non-current 256 - Increase in accrued capital expenditures $ 17 $ 33

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
31. Stock-Based Compensation
Weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted	2020 2019 Weighted average fair value per option $ 3.58 $ 2.41 Expected term (1) 5 years 6 years Risk-free interest rate (2) 1.33 % 1.82 % Expected dividend yield (3) 4.09 % 5.10 % Expected volatility (4) 14.10 % 14.32 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility.
Stock option information	Total Options Non-Vested Options (1) Number of Options Weighted average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2019 2,286,550 $ 43.31 1,549,025 $ 2.22 Granted 501,900 60.03 501,900 3.58 Exercised (417,968) 44.74 N/A N/A Vested N/A N/A (654,375) 2.32 Forfeited (102,700) 45.94 (102,700) 2.33 Options outstanding December 31, 2020 2,267,782 $ 46.62 1,293,850 $ 2.69 Options exercisable December 31, 2020 (2)(3) 973,932 $ 42.08 (1) As at December 31, 2020, there was $2 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 3 years (2019 - $2 million, 2 years). (2) As at December 31, 2020, the weighted average remaining term of vested options was 6 years with an aggregate intrinsic value of $12 million (2019 - 6 years, $11 million). (3) As at December 31, 2020, the fair value of options that vested in the year was $2 million (2019 - $2 million).
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, 2019 704,597 $ 34.69 531,454 $ 39.96 Granted including DRIP 84,790 47.74 93,008 51.65 Exercised (127,389) 30.50 (33,338) 41.89 Outstanding and exercisable as at December 31, 2020 661,998 $ 37.17 591,124 $ 41.69
Activity related to the Performance Share Unit Plan	Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2019 1,381,100 $ 45.37 $ 88 Granted including DRIP 271,185 53.14 Exercised (445,066) 45.41 Forfeited (80,690) 46.25 Outstanding as at December 31, 2020 1,126,529 $ 47.16 $ 68 Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2019 - $ - $ - Granted including DRIP 171,908 54.62 Forfeited (5,633) 54.62 Outstanding as at December 31, 2020 166,275 $ 54.62 $ 10

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2020
32. Variable Interest Entities
NSPML's consolidated summarized balance sheets	As at December 31, 2020 December 31, 2019 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets exposure to loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 547 $ 16 $ 554 $ 23

Supplemental Financial Inform_2

Supplemental Financial Information (Tables)	12 Months Ended
	Dec. 31, 2020
35. Supplemental Financial Information
Condensed Consolidated Statements of Income	Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars For the year ended December 31, 2020 Operating revenues $ (1) $ - $ 3,456 $ 2,070 $ (19) $ 5,506 Operating expenses 51 - 2,640 1,688 (20) 4,359 Income (loss) from equity investments and subsidiaries 1,049 - 1 147 (1,048) 149 Other income (expenses), net 20 - 687 1 - 708 Interest expense, net (1) 48 (37) 448 220 - 679 Income (loss) before provision for income taxes 969 37 1,056 310 (1,047) 1,325 Income tax expense (recovery) (14) (1) 348 7 1 341 Net income (loss) 983 38 708 303 (1,048) 984 Non-controlling interest in subsidiaries - - - - 1 1 Preferred stock dividends 45 - - 1 (1) 45 Net income (loss) attributable to common shareholders $ 938 $ 38 $ 708 $ 302 $ (1,048) $ 938 Comprehensive income (loss) of Emera Incorporated $ 809 $ 35 $ 575 $ 257 $ (867) $ 809 For the year ended December 31, 2019 Operating revenues $ - $ - $ 4,125 $ 2,029 $ (43) $ 6,111 Operating expenses 31 - 3,084 1,695 (42) 4,768 Income (loss) from equity investments and subsidiaries 753 - 2 151 (752) 154 Other income (expenses), net 21 - 22 (11) (20) 12 Interest expense, net (1) 75 (40) 481 222 - 738 Income (loss) before provision for income taxes 668 40 584 252 (773) 771 Income tax expense (recovery) (40) 11 60 30 - 61 Net income (loss) 708 29 524 222 (773) 710 Non-controlling interest in subsidiaries - - - - 2 2 Preferred stock dividends 45 - 19 3 (22) 45 Net income (loss) attributable to common shareholders $ 663 $ 29 $ 505 $ 219 $ (753) $ 663 Comprehensive income (loss) of Emera Incorporated $ 465 $ 14 $ 102 $ 205 $ (321) $ 465 (1) Interest expense is net of interest revenue.
Condensed Consolidated Balance Sheets	Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2020 Assets Current assets $ 121 $ 10 1,216 $ 1,010 $ (179) $ 2,178 Property, plant and equipment 21 - 14,356 5,164 (6) 19,535 Other assets Regulatory assets - - 520 899 - 1,419 Goodwill 3 - 5,648 69 - 5,720 Other long-term assets 12,522 4,591 130 3,254 (18,115) 2,382 Total other assets 12,525 4,591 6,298 4,222 (18,115) 9,521 Total assets $ 12,667 $ 4,601 $ 21,870 $ 10,396 $ (18,300) $ 31,234 Liabilities and Equity Current liabilities $ 554 $ 2,024 $ 4,121 $ 723 $ (2,547) $ 4,875 Long-term liabilities Long-term debt 2,210 2,513 4,026 3,590 - 12,339 Deferred income taxes - 2 852 761 14 1,629 Regulatory liabilities - - 1,747 85 - 1,832 Other long-term liabilities 700 - 4,510 1,666 (5,555) 1,321 Total long-term liabilities 2,910 2,515 11,135 6,102 (5,541) 17,121 Total Emera Incorporated equity 9,203 62 6,614 3,550 (10,225) 9,204 Non-controlling interest in subsidiaries - - - 21 13 34 Total equity 9,203 62 6,614 3,571 (10,212) 9,238 Total liabilities and equity $ 12,667 $ 4,601 $ 21,870 $ 10,396 $ (18,300) $ 31,234 As at December 31, 2019 Assets Current assets $ 96 $ 27 1,486 $ 1,171 $ (294) $ 2,486 Property, plant and equipment 23 - 13,099 5,040 5 18,167 Other assets Regulatory assets - - 519 912 - 1,431 Goodwill 3 - 5,762 70 - 5,835 Other long-term assets 11,994 3,856 1,739 3,289 (16,955) 3,923 Total other assets 11,997 3,856 8,020 4,271 (16,955) 11,189 Total assets $ 12,116 $ 3,883 $ 22,605 $ 10,482 $ (17,244) $ 31,842 Liabilities and Equity Current liabilities $ 542 $ 12 $ 3,699 $ 992 $ (1,079) $ 4,166 Long-term liabilities Long-term debt 2,978 3,534 8,829 4,547 (6,209) 13,679 Deferred income taxes - 3 515 767 - 1,285 Regulatory liabilities - - 1,793 93 - 1,886 Other long-term liabilities 38 - 1,697 511 (21) 2,225 Total long-term liabilities 3,016 3,537 12,834 5,918 (6,230) 19,075 Total Emera Incorporated equity 8,558 334 6,072 3,551 (9,949) 8,566 Non-controlling interest in subsidiaries - - - 21 14 35 Total equity 8,558 334 6,072 3,572 (9,935) 8,601 Total liabilities and equity $ 12,116 $ 3,883 $ 22,605 $ 10,482 $ (17,244) $ 31,842
Condensed Consolidated Statements of Cash Flows	Emera Incorporated Condensed Consolidated Statements of Cash Flows Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2020 Net cash provided by (used in) by operating activities $ 365 $ 36 $ 1,277 $ 486 $ (527) $ 1,637 Investing activities Additions to property, plant and equipment (1) - (2,150) (472) - (2,623) Proceeds on disposal of assets - - 1,401 - - 1,401 Other investing activities (118) 265 546 100 (795) (2) Net cash provided by (used in) investing activities (119) 265 (203) (372) (795) (1,224) Financing activities Change in short-term debt, net (6) - 107 (5) - 96 Proceeds from long-term debt - - 173 429 (174) 428 Retirement of long-term debt - - (705) (87) 279 (513) Net borrowings (repayments) under committed credit facilities (82) - 8 (157) 28 (203) Issuance of common and preferred stock 285 (241) (3) 53 191 285 Dividends paid (454) (66) (80) (379) 525 (454) Other financing activities (18) (4) (494) 32 473 (11) Net cash provided by (used in) financing activities (275) (311) (994) (114) 1,322 (372) Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale 18 (8) (70) (1) - (61) Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale (11) (18) 10 (1) - (20) Cash, cash equivalents, and restricted cash, beginning of year 1 19 87 167 - 274 Cash, cash equivalents, restricted cash and assets held for sale, end of year $ (10) $ 1 $ 97 $ 166 $ - $ 254 Emera Incorporated Condensed Consolidated Statements of Cash Flows (Continued) Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars As at December 31, 2019 Net cash provided by (used in) operating activities $ 133 $ 33 $ 1,100 $ 279 $ (20) $ 1,525 Investing activities Additions to property, plant and equipment (2) - (1,973) (520) - (2,495) Net purchase of investments subject to significant influence - - (3) - - (3) Proceeds on disposal of assets significant influence and held-for-trading common shares - - 818 57 - 875 Other investing activities (402) 595 774 (1) (960) 6 Net cash provided by (used in) investing activities (404) 595 (384) (464) (960) (1,617) Financing activities Change in short-term debt, net 399 - (9) 23 - 413 Proceeds from long-term debt - - (6) 552 520 1,066 Retirement of long-term debt (225) (664) (65) (166) 17 (1,103) Net borrowings (repayments) under committed credit facilities 146 - (11) (225) (28) (118) Issuance of common and preferred stock 203 - (620) 58 562 203 Dividends paid (423) - (19) (138) 157 (423) Other financing activities (1) - 138 87 (248) (24) Net cash provided by (used in) financing activities 99 (664) (592) 191 980 14 Effect of exchange rate changes on cash, cash equivalents and restricted cash 147 (3) (141) (23) - (20) Net increase (decrease) in cash, cash equivalents, and restricted cash (25) (39) (17) (17) - (98) Cash, cash equivalents and restricted cash, beginning of year 20 58 104 190 - 372 Cash, cash equivalents and restricted cash, end of year $ (5) $ 19 $ 87 $ 173 $ - $ 274

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, 2020CAD ($)MWCustomerskm
Emera Maine | Disposition
Nature of operations [Line items]
Disposition, Name	Emera Maine
Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera’s other reportable segment includes investments in energy-related non-regulated companies which includes: Emera Energy, which consists of: Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera; Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and
Operating | Other Electric Utilities
Nature of operations [Line items]
Disposition, Name		Other Electric Utilities
Operating | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera’s other reportable segment includes investments in energy-related non-regulated companies which includes: Emera Energy, which consists of: Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera; Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and
Maritimes and Northeast Pipline | Gas Utilities and Infrastructure
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		12.90%
Maritimes and Northeast Pipline | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Length Of Pipeline | km		1,400
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		19.50%
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		51.90%
Tampa Electric | Operating | Florida Electric Utility
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Tampa Electric, a vertically integrated regulated electric utility, serving approximately 792,500 customers in West Central Florida
Number of Customers		792,500
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 529,000 customers
Number of Customers		529,000
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera Newfoundland & Labrador Holdings Inc. ("ENL"), consisteny of two transmission investments related to an 824 megawatt ("MW") hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two investments are: a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.6 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and a 45.6 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced that it had paused construction activities at the Muskrat Falls site and resumed work in May 2020. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward completing project commissioning in 2021. Refer to note 27 for further details.
Public Utilities Property Plant And Equipment Generation Capacity | MW		824
Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		100.00%
Public Utilities, Equipment, Transmission and Distribution | $		$ 1.6
Length Of Pipeline | km		170
Emera Newfoundland and Labrador Holdings Inc. | Labrador-Island Link Limited Partnership | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		45.60%
Public Utilities, Equipment, Transmission and Distribution | $		$ 3.7
Emera (Caribbean) Incorporated | Operating | Other Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados, serving approximately 131,000 customers; Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island, serving approximately 19,000 customers; a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated electric utility on the island of Dominica, serving approximately 34,000 customers; and a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the Other Electric Utilities segment. Refer to note 4 for further information.
Barbados Light and Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers		131,000
Grand Bahama Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers		19,000
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers		34,000
Peoples Gas System Division | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers		426,000
Peoples Gas System Division | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Peoples Gas System (“PGS”), a regulated gas distribution utility, serving approximately 426,000 customers across Florida;
Length Of Pipeline | km		800
New Mexico Gas Company | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers		540,000
New Mexico Gas Company | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 540,000 customers in New Mexico;
SeaCoast Gas Transmission, LLC | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Nature of operations [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
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034
Length Of Pipeline | km		145
Emera Energy | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.
Emera Energy | Bear Swamp Power Company LLC | Other
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		50.00%
Public Utilities Property Plant And Equipment Generation Capacity | MW		600
Emera Energy Services | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;
Brooklyn Power Corporation | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia;
Brooklyn Power Corporation | Operating | Other
Nature of operations [Line items]
Public Utilities Property Plant And Equipment Generation Capacity | MW		30
Emera Reinsurance Limited | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera;
Emera US Finance LP | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		financing subsidiaries of Emera;
TECO Finance, Inc. | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		financing subsidiaries of Emera;
Emera US Holdings Inc. | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments		Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)
Asset Impairment Charges
Impairment charges	$ 25		$ 34
Asset Impairment Charges, net of tax	26
Goodwill
Goodwill	5,720		5,835		$ 6,313
Goodwill impairment charge	0		30
TECO Energy
Goodwill
Goodwill	5,649
GBPC
Asset Impairment Charges
Asset Impairment Charges, net of tax				$ 18
Proceeds from Insurance Settlement, Operating Activities		$ 18
Goodwill
Goodwill	$ 68		70
Goodwill impairment charge			$ 30
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	5.00%

Change in Accounting Policy (Na

Change in Accounting Policy (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 9,238	$ 8,601	$ 8,358
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	1,495	1,173	$ 1,075
Retained Earnings | Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ (7)
Accounting Standards Update 2016-13
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”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income. These include trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $7 million decrease to retained earnings in the consolidated financial statements as of January 1, 2020.
Change in Accounting Principle, Accounting Standards Update, Adopted [true false]	true
Change in Accounting Principle, Accounting Standards Update, Adoption Date	Jan. 1, 2020
Accounting Standards Update 2016-13 | Retained Earnings | Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity		$ (7)
Accounting Standards Update 2019-12
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intraperiod tax allocation. It also simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard is applied on both a prospective and retrospective basis. The Company early adopted the standard effective January 1, 2020. There was no 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, 2020
Change in Accounting Principle, Accounting Standards Update, Early Adoption [true false]	true
Accounting Standards Update 2020-04
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	The Company adopted ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting in Q4 2020. The standard provides options and exceptions for applying USGAAP to contract modifications and hedging relationships that reference the London Inter-Bank Offered Rate (“LIBOR”) or any other reference rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company’s transition from reference rates will not have a material impact on the consolidated financial statements. In November 2020, the Federal Reserve extended the phase-out of LIBOR until June 2023. The Company will continue to monitor the impact this may have on application of the standard.
Change in Accounting Principle, Accounting Standards Update, Adopted [true false]	true
Change in Accounting Principle, Accounting Standards Update, Immaterial Effect [true false]	true

Dispositions (Narrative) (Detai

Dispositions (Narrative) (Details) - Emera Maine - Disposition - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 24, 2020	Mar. 24, 2020	Dec. 31, 2019
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Name	Emera Maine
Disposition, Value	$ 2,000	$ 2,000
Proceeds on disposition of business	1,400
Disposition, Depreciation and Amortization		$ 53	$ 39
Disposition, gain on disposition	585
Disposition, gain on disposition, net of tax	$ 309

Segment Information (Reportable

Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 5,506	$ 6,111
OM&G	1,419	1,464
Depreciation and amortization	881	903
Income (loss) from equity investments and subsidiaries	149	154
AFUDC - debt and equity	68	33
Interest expense, net	679	738
Internally allocated interest	0	0
Gain on sale, net of transaction costs	585
Impairment charges	25	34
Income tax expense (recovery)	341	61
Net income (loss) attributable to common shareholders	937.6	662.8
Capital expenditures	2,600	2,483
Segment Reporting Information, As at December 31
Total assets	31,234	31,842
Investments subject to significant influence	1,346	1,312
Goodwill	5,720	5,835	$ 6,313
Regulated | Electric
Segment Reporting Information, For the year ended December 31
Total operating revenues	4,442	4,769
Fuel for generation and purchased power	1,420	1,609
Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,034	1,081
Fuel for generation and purchased power	293	350
Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	2,480	2,607
Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,494	1,430
Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	474	744
Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,058	1,119
Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	29	282
Operating
Segment Reporting Information, For the year ended December 31
Total operating revenues	5,506	6,111
Impairment charges		34
Operating | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	2,473	2,596
OM&G	552	554
Depreciation and amortization	455	445
Income (loss) from equity investments and subsidiaries	0	0
AFUDC - debt and equity	54	20
Interest expense, net	151	154
Internally allocated interest	0	0
Gain on sale, net of transaction costs	0
Impairment charges	0	0
Income tax expense (recovery)	89	79
Net income (loss) attributable to common shareholders	501	419
Capital expenditures	1,361	1,393
Segment Reporting Information, As at December 31
Total assets	16,889	16,214
Investments subject to significant influence	0	0
Goodwill	4,455	4,544
Operating | Florida Electric Utility | Regulated | Electric
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	574	772
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	1,494	1,429
OM&G	282	313
Depreciation and amortization	236	231
Income (loss) from equity investments and subsidiaries	96	91
AFUDC - debt and equity	4	6
Interest expense, net	139	142
Internally allocated interest	0	0
Gain on sale, net of transaction costs	0
Impairment charges	0	0
Income tax expense (recovery)	17	(10)
Net income (loss) attributable to common shareholders	221	229
Capital expenditures	338	384
Segment Reporting Information, As at December 31
Total assets	6,752	6,717
Investments subject to significant influence	1,176	1,133
Goodwill	0	0
Operating | Canadian Electric Utilities | Regulated | Electric
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	659	573
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	474	744
OM&G	151	195
Depreciation and amortization	71	107
Income (loss) from equity investments and subsidiaries	4	5
AFUDC - debt and equity	1	5
Interest expense, net	32	52
Internally allocated interest	0	0
Gain on sale, net of transaction costs	0
Impairment charges	0	34
Income tax expense (recovery)	(8)	11
Net income (loss) attributable to common shareholders	35	45
Capital expenditures	148	195
Segment Reporting Information, As at December 31
Total assets	1,365	3,069
Investments subject to significant influence	41	41
Goodwill	68	70
Operating | Other Electric Utilities | Regulated | Electric
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	194	286
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	1,051	1,097
OM&G	334	319
Depreciation and amortization	111	109
Income (loss) from equity investments and subsidiaries	20	22
AFUDC - debt and equity	9	2
Interest expense, net	56	59
Internally allocated interest	13	14
Gain on sale, net of transaction costs	0
Impairment charges	0	0
Income tax expense (recovery)	51	48
Net income (loss) attributable to common shareholders	162	183
Capital expenditures	749	448
Segment Reporting Information, As at December 31
Total assets	6,067	5,489
Investments subject to significant influence	129	138
Goodwill	1,194	1,218
Operating | Gas Utilities and Infrastructure | Regulated | Electric
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	293	350
Operating | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	14	245
OM&G	115	130
Depreciation and amortization	8	11
Income (loss) from equity investments and subsidiaries	29	36
AFUDC - debt and equity	0	0
Interest expense, net	301	331
Internally allocated interest	(13)	(14)
Gain on sale, net of transaction costs	585
Impairment charges	25	0
Income tax expense (recovery)	192	(67)
Net income (loss) attributable to common shareholders	19	(213)
Capital expenditures	4	63
Segment Reporting Information, As at December 31
Total assets	1,234	1,459
Investments subject to significant influence	0	0
Goodwill	3	3
Operating | Other | Regulated | Electric
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	(29)	(71)
OM&G	(15)	(47)
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
Gain on sale, net of transaction costs	0
Impairment charges	0	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	(1,073)	(1,106)
Investments subject to significant influence	0	0
Goodwill	0	0
Intersegment Eliminations | Regulated | Electric
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	(7)	(22)
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	(19)	(43)
Income (loss) from equity investments and subsidiaries	(1,048)	(752)
Income tax expense (recovery)	1	0
Net income (loss) attributable to common shareholders	(1,048)	(753)
Segment Reporting Information, As at December 31
Total assets	(18,300)	(17,244)
Goodwill	0	0
Eliminations | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	7	11
Eliminations | Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	0	1
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	7	22
Eliminations | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 15	$ 37

Segment Information (Geographic

Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 5,506	$ 6,111
Property, Plant and Equipment, Net	19,535	18,167
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	1,569	1,497
Property, Plant and Equipment, Net	4,304	4,248
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	3,522	4,140
Property, Plant and Equipment, Net	14,353	13,095
Barbados
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	263	320
Property, Plant and Equipment, Net	510	462
The Bahamas
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	112	112
Property, Plant and Equipment, Net	289	282
Dominica
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	40	42
Property, Plant and Equipment, Net	$ 79	$ 80

Segment Information (Narrative)

Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2020Segments
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) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 5,506	$ 6,111
Total operating revenues	5,506	6,111
Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	2,480	2,607
Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1,494	1,430
Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	474	744
Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1,058	1,119
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	29	282
Operating
Disaggregation of Revenue [Line Items]
Total operating revenues	5,506	6,111
Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,480	2,607
Total operating revenues	2,473	2,596
Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,494	1,430
Total operating revenues	1,494	1,429
Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	474	744
Total operating revenues	474	744
Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,058	1,119
Total operating revenues	1,051	1,097
Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	29	282
Total operating revenues	14	245
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(29)	(71)
Total operating revenues	(19)	(43)
Eliminations | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	7	11
Eliminations | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	1
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	7	22
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	15	37
Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	30	261
Total operating revenues	30	261
Non-Regulated | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	38
Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Florida Electric Utility | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Canadian Electric Utilities | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Other Electric Utilities | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	16	16
Non-Regulated | Operating | Gas Utilities and Infrastructure | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	29	282
Non-Regulated | Operating | Other | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	38
Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(15)	(37)
Non-Regulated | Eliminations | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Electric | Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	4,442	4,769
Total operating revenues	4,442	4,769
Electric | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,480	2,607
Electric | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,494	1,430
Electric | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	474	744
Electric | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1	0
Electric | Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(7)	(12)
Electric | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,350	2,409
Electric | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,365	1,387
Electric | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	806	746
Electric | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	179	276
Electric | Regulated | Residential | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Residential | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Residential | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,316	1,484
Electric | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	678	745
Electric | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	405	400
Electric | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	233	339
Electric | Regulated | Commercial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Commercial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Commercial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	434	461
Electric | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	178	207
Electric | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	224	210
Electric | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	32	44
Electric | Regulated | Industrial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Industrial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Industrial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Other Electric And Regulatory
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	281	304
Electric | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	242	246
Electric | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	31	45
Electric | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	8	13
Electric | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Other Electric And Regulatory | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Other Electric And Regulatory | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,034	1,081
Total operating revenues	1,034	1,081
Gas | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,041	1,103
Gas | Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(7)	(22)
Gas | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	495	502
Gas | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Residential | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	495	502
Gas | Regulated | Residential | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Residential | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	275	298
Gas | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Commercial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	275	298
Gas | Regulated | Commercial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Commercial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	54	50
Gas | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Industrial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	54	50
Gas | Regulated | Industrial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Industrial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	149	171
Gas | Regulated | Other | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	156	193
Gas | Regulated | Other | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Other | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(7)	(22)
Marketing and trading margin | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	38	31
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	38	31
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	68
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	16	80
Energy sales | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(16)	(12)
Finance Income | Regulated | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	61	60
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	61	60
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	61	111
Other | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	17	22
Other | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	28	29
Other | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	22	72
Other | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1	0
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	(7)	(12)
Other | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	37	22
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	16	16
Other | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	21	31
Other | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	(25)
Mark-To-Market | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	(45)	102
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	(46)	102
Mark-To-Market | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	$ 1	$ 0

Revenue (Remaining Performance

Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
6. Revenue
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Explanation	2040	2040
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 464	$ 347
SeaCoast Gas Transmission, LLC | PGS
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 149

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 165	$ 121
Regulatory Assets, Long-term	1,419	1,431
Total regulatory assets	1,584	1,552
Deferred income tax regulatory assets
Regulatory Assets [Line Items]
Total regulatory assets	887	862
Pension and post-retirement medical plan
Regulatory Assets [Line Items]
Total regulatory assets	394	380
Deferrals related to derivative instruments
Regulatory Assets [Line Items]
Total regulatory assets	65	81
Cost recovery clauses
Regulatory Assets [Line Items]
Total regulatory assets	49	13
Storm reserve
Regulatory Assets [Line Items]
Total regulatory assets	41	38
Environmental remediations
Regulatory Assets [Line Items]
Total regulatory assets	28	26
Stranded cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	26	27
Demand side management ("DSM") deferral
Regulatory Assets [Line Items]
Total regulatory assets	15	19
Unamortized defeasance costs
Regulatory Assets [Line Items]
Total regulatory assets	13	19
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 66	$ 87

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 129	$ 295
Regulatory Liability, Long-term	1,832	1,886
Total regulatory liabilities	1,961	2,181
Deferred income tax regulatory liabilities
Regulatory Liabilities [Line Items]
Total regulatory liabilities	933	985
Accumulated reserve - cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	865	891
Storm reserve
Regulatory Liabilities [Line Items]
Total regulatory liabilities	62	62
Cost recovery clauses
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31	53
Self-insurance fund
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	29
Regulated fuel adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	115
Deferrals related to derivative instruments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	42
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 6	$ 4

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2020USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Dec. 31, 2015CAD ($)
GBPC | Hurricane | Loss from Catastrophes
Public Utilities, General Disclosures [Line Items]
Storm cost	$ 15
Storm Reserve				$ 18
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			As approved on December 6, 2019 as part of NSPI’s three-year Fuel Stability Plan, differences between actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be recovered or returned to customers after 2022. The UARB’s decision to approve the Fuel Stability Plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.
NSPI | Renewable Energy Program
Public Utilities, General Disclosures [Line Items]
Recovery Period			8 years
Regulatory Asset Recovery Assessments			The Nova Scotia Utility and Review Board (“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				$ 582	$ 740
Tampa Electric | Hurricane
Public Utilities, General Disclosures [Line Items]
Storm cost		$ 8

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Florida Electric Utility (Narrative) (Details) $ in Millions, $ in Millions	Feb. 01, 2021USD ($)	Aug. 03, 2020USD ($)	Jun. 09, 2020USD ($)	Apr. 27, 2020USD ($)	Aug. 20, 2018USD ($)	Jan. 31, 2020USD ($)	Dec. 31, 2020CAD ($)MW	Dec. 31, 2020USD ($)MW	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)	Jun. 01, 2020CAD ($)	Jun. 01, 2020USD ($)
Public Utilities, General Disclosures [Line Items]
State income tax							26.00%	26.00%	8.00%
Utilities Operating Expense, Depreciation and Amortization							$ 881		$ 903
Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Utilities Operating Expense, Depreciation and Amortization							$ 455		$ 445
Tampa Electric | SoBRA | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Generation or Processing										$ 820
Estimated revenue in MW | MW							600	600
Tampa Electric | SoBRA | Scenario Plan | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Generation or Processing										30
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. Tampa Electric 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. Tampa Electric 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			$ 103			$ 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 | Cost recovery clauses | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity							10.25%	10.25%
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, Generation or Processing										526
Public Utilities, Property, Plant and Equipment, Plant in Service							$ 255			200	$ 304	$ 223
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation							$ 112			$ 88	$ 123	$ 90
Tampa Electric | Florida Public Service Commission | Big Bend Modernization Project | Subsequent Event | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 130
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%
Tampa Electric | Florida Public Service Commission | Range, Minimum | Subsequent Event | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Storm Damage Provision	280
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%
Tampa Electric | Florida Public Service Commission | Range, Maximum | Subsequent Event | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Storm Damage Provision	$ 295

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)km	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 16, 2020CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 1,961	$ 2,181
Utilities Operating Expense, Depreciation and Amortization		881	903
Contractual Obligation, to be Paid, Year One		1,736
Contractual Obligation, to be Paid, Year Two		1,143
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses		1,419	1,464
Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Utilities Operating Expense, Depreciation and Amortization		236	231
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses		282	313
Regulated fuel adjustment mechanism
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 21	115
NSPI
Public Utilities, General Disclosures [Line Items]
Recovery Period		3 years
Regulatory Asset Recovery Assessments		As approved on December 6, 2019 as part of NSPI’s three-year Fuel Stability Plan, differences between actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be recovered or returned to customers after 2022. The UARB’s decision to approve the Fuel Stability Plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.
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		$ 145			$ 172
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes					23
Approved payment in period		135
Holdback payable		4
Phase-in Plan, Amount of Capitalized Costs Recovered		40	$ 35	$ 17
Contractual Obligation, to be Paid, Year One		164
Contractual Obligation, to be Paid, Year Two		$ 162
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 | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Holdback payable		$ 10
Phase-in Plan, Amount of Capitalized Costs Recovered	$ 12
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 2020-2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The majority of the reduced assessment was refunded to most customers through a reduction incorporated into their 2020 rates and the remaining customers received a one-time on bill credit in 2020. As at December 31, 2020, $40 million plus interest has been refunded to customers, with the remaining $12 million plus interest to 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		$ 1,600
Length Of Pipeline | km		170
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes		$ 10
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses		$ 115
Interim cost assessment, holdback		The payments were subject to a holdback of $10 million pending UARB agreement that a minimum of $10 million in benefits from the Maritime Link are realized for NSPI customers. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM.
Cash and Securities Segregated under Federal and Other Regulations					$ 23
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 | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Holdback payable		$ 10
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 payments reflected a reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. NSPI refunded the reduced 2018 NSPML assessment to customers in 2018 and 2019, by providing a credit to customers of $17 million and $35 million, respectively. The UARB’s decision to approve NSPI’s 2020-2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The majority of the reduced assessment was refunded to most customers through a reduction incorporated into their 2020 rates and the remaining customers received a one-time on bill credit in 2020.

Regulatory Assets and Liabili_8

Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020USD ($)	Dec. 31, 2021	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)			$ (341)	$ (61)
Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)			$ 8	$ (11)
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)	$ 9.6
Deferred Tax Liabilities, Regulatory Assets and Liabilities	$ 6.9
GBPC | GBPA | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			8.34%	8.50%
Recovery Period		5 years
GBPC | GBPA | Other Electric Utilities | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		8.37%
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, $ in Millions	Jul. 17, 2019USD ($)	Jan. 31, 2021USD ($)	Sep. 30, 2019CAD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)km	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)					$ (341)	$ (61)
Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)					$ (51)	$ (48)
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 | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					9.10%
Public Utilities, Phase-in Plan Terms					On July 17, 2019, the NMPRC approved a rate increase for NMGC effective August 2019 and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates were phased in over two years, resulting in an annual revenue increase of approximately $3 million USD.
Deferred Tax Liabilities, Regulatory Assets and Liabilities								$ 11	$ 8
Income tax expense (recovery)			$ 7	$ 5
NMGC | Range, Minimum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						9.10%
NMGC | Range, Maximum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						10.00%
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Capitalized Costs Recovered	$ 3
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		9.375%
Allowed equity capital structure		52.00%
Phase-in Plan, Amount of Capitalized Costs Recovered		$ 5
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%
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					PGS was permitted to initiate a general base rate proceeding during 2020, provided the new rates do not become effective before January 1, 2021. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. 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					9.25%	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					11.75%	11.75%
PGS | Range, Maximum | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		11.00%
PGS | Mid Point | Gas Utilities and Infrastructure | Operating | Scenario Plan
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) - Entity [Domain] - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 1,346	$ 1,312
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	781	764
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	12
Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	1,346	1,312
Income (loss) from equity investments and subsidiaries	149	154
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	12
NSPML | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	547	554
Income (loss) from equity investments and subsidiaries	$ 47	46
Percentage of Ownership	100.00%
LIL | Class B units
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	100.00%
LIL | Total Units Issued [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	24.90%
LIL | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 629	579
Income (loss) from equity investments and subsidiaries	$ 49	45
Percentage of Ownership	45.60%
M&NP | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 129	138
Income (loss) from equity investments and subsidiaries	$ 20	22
Percentage of Ownership	12.90%
Lucelec | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 41	41
Income (loss) from equity investments and subsidiaries	$ 4	3
Percentage of Ownership	19.50%
Bear Swamp
Equity Method Investment, Summarized Financial Information [Abstract]
Distribution received			$ 179
Other long-term liabilities	$ 118	137
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	$ 29	35
Percentage of Ownership	50.00%
Other Investments | 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	$ 0	$ 3
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Balance Sheets
Current assets	$ 2,178	$ 2,486
Property, plant and equipment	19,535	18,167
Regulatory assets	1,419	1,431
Non-current assets	9,521	11,189
Total assets	31,234	31,842
Current liabilities	4,875	4,166
Non-current liabilities	17,121	19,075
Equity	9,238	8,601	$ 8,358
Total liabilities and equity	31,234	31,842
Variable Interest Entity, Not Primary Beneficiary | NSPML
Balance Sheets
Current assets	57	69
Property, plant and equipment	1,629	1,671
Regulatory assets	210	177
Non-current assets	32	32
Total assets	1,928	1,949
Current liabilities	56	23
Long-term debt	1,228	1,288
Non-current liabilities	97	84
Equity	547	554
Total liabilities and equity	$ 1,928	$ 1,949

Other Income (Expenses), Net (C

Other Income (Expenses), Net (Components of other income (expenses), net) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
9. Other Income (Expenses), Net
Allowance for equity funds used during construction	$ 45	$ 21
Gain on sale of Emera Maine, net of transaction costs	585	0
TECO Guatemala Holdings award	49	0
Other	29	(9)
Other income (expenses), net	$ 708	$ 12

Income Taxes (Reconiliation of

Income Taxes (Reconiliation of Income tax provision) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income before provision for income taxes	$ 1,325	$ 771
Statutory income tax rate	29.50%	31.00%
Income taxes, at statutory income tax rates	$ 391	$ 239
Additional impact from the sale of Emera Maine	102	0
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(48)	(66)
Foreign tax rate variance	(45)	(49)
Amortization of deferred income tax regulatory liabilities	(44)	(36)
Tax effect of equity earnings	(15)	(15)
Other	0	(12)
Income tax expense	$ 341	$ 61
Effective income tax rate	26.00%	8.00%

Income Taxes (Composition of ta

Income Taxes (Composition of taxes on income from continuing operations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ 381	$ 125
Income tax expense (recovery)	341	61
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	1,325	771
Canada
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	18	(19)
Deferred income taxes	20	45
Operating loss carry forwards	(46)	(48)
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	176	98
United States
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	(58)	(46)
Deferred income taxes	426	137
Investment tax credits	(10)	(9)
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	1,142	682
Other
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	0	1
Deferred income taxes	(9)	0
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	$ 7	$ (9)

Income Taxes (Deferred income t

Income Taxes (Deferred income tax assets and liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred income tax assets:
Tax loss carryforwards	$ 724	$ 908
Tax credit carryforwards	319	311
Regulatory liabilities - cost of removal	184	195
Derivative instruments	108	145
Other	375	413
Total deferred income tax assets before valuation allowance	1,710	1,972
Total deferred income tax assets after valuation allowance	1,508	1,779
Deferred income tax (liabilities):
Property, plant and equipment	(2,450)	(2,382)
Derivative instruments	(93)	(148)
Other	(385)	(348)
Total deferred income tax liabilities	(2,928)	(2,878)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets	209	186
Long-term deferred income tax liabilities	(1,629)	(1,285)
Net deferred income tax liabilities	$ (1,420)	$ (1,099)

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, 2020CAD ($)
Canada | Capital loss
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 61
Unrecognized Amounts	(61)
Net Tax Credit Carryforwards	$ 0
Expiration period	Indefinite
Canada | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,370
Unrecognized Amounts	(619)
Net Tax Credit Carryforwards	$ 751
Expiration period	2027 - 2040
United States | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,412
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 1,412
Expiration period	2030 - 2040
United States | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 319
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 319
Expiration period	2025 - 2040
State | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 563
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 563
Expiration period	2032 - 2040
Other | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 39
Unrecognized Amounts	(39)
Net Tax Credit Carryforwards	$ 0
Expiration period	2021 - 2027

Income Taxes (Change in unrecog

Income Taxes (Change in unrecognized tax benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 29	$ 26
Increases due to tax positions related to current year	1	2
Increases due to tax positions related to a prior year	2	1
Decreases due to tax positions related to a prior year	(2)	0
Balance, December 31	$ 30	$ 29

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - CAD ($)	Mar. 09, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019
Entity [Domain]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change			$ 2,700,000,000	$ 1,900,000,000
Decrease in deferred income tax liablities		$ 52,000,000
Income tax expense, revaluation of certain net deferred income tax assets		12,000,000
Deferred Tax Assets, Valuation Allowance			202,000,000	193,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Amount that could affect effective tax rate			30,000,000	29,000,000
Accrued interest			6,000,000	5,000,000
Income Tax Examination, Interest Expense			1,000,000	$ 1,000,000
Accrued penalties			0
Entity [Domain] | Deferred income tax assets | Revision of Prior Period, Adjustment for Reclassification
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
AMT credit carryforward		(77,000,000)
Entity [Domain] | Receivables and other current assets
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
AMT credit carryforward			$ 145,000,000
Entity [Domain] | Receivables and other current assets | Revision of Prior Period, Adjustment for Reclassification
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
AMT credit carryforward		$ 77,000,000
Entity [Domain] | Canada Revenue Agency
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Local income tax rate	31.00%		29.50%
Entity [Domain] | Canada Revenue Agency | Nova Scotia
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Local income tax rate	16.00%		14.00%
2005 and subsequent years | Entity [Domain]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Open Tax Year			2005
Subsequent years after 2020 | Entity [Domain] | Canada Revenue Agency
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Local income tax rate			29.00%
Settlement with Taxing Authority | 2006 through 2010 years | Nova Scotia Power Inc. | Canada Revenue Agency
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, 2020	Dec. 31, 2019
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 6,216
Issuance of common stock	251	$ 99
Options exercised under senior management share option plan	19	97
Ending Balance	$ 6,705	$ 6,216
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	242,480	234,120
Conversion of Convertible Debentures	0	30
Issuance of common stock	4,540	1,770
Issued under Purchase Plans at market rate	3,990	3,990
Discount on shares purchased under Dividend Reinvestment Plan	0	0
Options exercised under senior management share option plan	420	2,570
Employee Share Purchase Plan	0	0
Ending Balance	251,430	242,480
Common Stock
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 6,216	$ 5,816
Conversion of Convertible Debentures	0	1
Issuance of common stock	251	99
Issued under Purchase Plans at market rate	219	202
Discount on shares purchased under Dividend Reinvestment Plan Value	(4)	(7)
Options exercised under senior management share option plan	20	104
Employee Share Purchase Plan	3	1
Ending Balance	$ 6,705	$ 6,216

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions	Nov. 17, 2020	Dec. 31, 2020	Dec. 31, 2019	Jul. 11, 2019
Debt Instrument [Line Items]
Issuance of common stock		4,540,000	1,770,000
Gross proceeds from Issuance of Common Stock		$ 285	$ 203
Maximum daily trading limit of shares percent	25.00%
ATM Program
Debt Instrument [Line Items]
Stock Repurchase Program, Authorized Amount				$ 600
Stock Repurchase Program, Remaining Authorized Repurchase Amount		$ 245
ATM Program | Common Stock
Debt Instrument [Line Items]
Issuance of common stock		4,544,025
Shares, Issued			1,768,120
Gross proceeds from Issuance of Common Stock		$ 255	$ 100
Net proceeds from issuance of common stock		$ 251	$ 99
Average price per share, issued		$ 56.04
ATM Program | Average | Common Stock
Debt Instrument [Line Items]
Shares Issued, Price Per Share			$ 56.56
Employee Stock Option Plan
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance		3,500,000	3,900,000
Share Unit Plans
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance		3,500,000	900,000
Dividend Reinvestment
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance		5,100,000	8,800,000

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, 2020	Dec. 31, 2019
Numerator
Net income attributable to common shareholders	$ 937.6	$ 662.8
Diluted numerator	$ 937.6	$ 662.8
Denominator
Weighted average shares of common stock outstanding	246.5	238.5
Weighted average deferred share units outstanding	1.3	1.4
Weighted average shares of common stock outstanding - basic	247.8	239.9
Stock-based compensation	0.4	0.6
Weighted average shares of common stock outstanding- diluted	248.2	240.5
Earnings per common share
Basic	$ 3.78	$ 2.76
Diluted	$ 3.78	$ 2.76

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		$ 8,601	$ 8,358
Net current period other comprehensive income (loss)	[1]	(174)	(244)
Ending Balance		9,238	8,601
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[2]	95	338
Other comprehensive income (loss) before reclassifications		(175)	(320)
Amounts reclassified from accumulated other comprehensive income loss		1	77
Net current period other comprehensive income (loss)	[2]	(174)	(243)
Ending Balance	[2]	(79)	95
Unrealized (loss) gain on translation of self-sustaining foreign operations
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		253	654
Other comprehensive income (loss) before reclassifications		(201)	(401)
Amounts reclassified from accumulated other comprehensive income loss		0	0
Net current period other comprehensive income (loss)		(201)	(401)
Ending Balance		52	253
Net change in net investment hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		4	(74)
Other comprehensive income (loss) before reclassifications		26	78
Amounts reclassified from accumulated other comprehensive income loss		0	0
Net current period other comprehensive income (loss)		26	78
Ending Balance		30	4
(Losses) gains on derivatives recognized as cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(1)	(7)
Other comprehensive income (loss) before reclassifications		0	3
Amounts reclassified from accumulated other comprehensive income loss		2	3
Net current period other comprehensive income (loss)		2	6
Ending Balance		1	(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		(160)	(234)
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income loss		(1)	74
Net current period other comprehensive income (loss)		(1)	74
Ending Balance		$ (161)	$ (160)
[1]	5) Net of tax expense of $2 million (2019 - $10 million expense) for the year ended December 31, 2020.
[2]	(1) Accumulated Other Comprehensive Income (Loss) ("AOCI") ("AOCL")

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss) (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total operating revenues	$ 5,506		$ 6,111
Other income net (note 9)	708		12
Operating, maintenance and general	1,419		1,464
Income tax expense (recovery)	341		61
Net income	984		710
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	1		77
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]
Total operating revenues	2		3
Total before tax	2		3
Net income	2		3
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]
Pension and post-retirement benefits	(16)		39
Regulatory assets		$ 0		$ 28
Total before tax	(2)		83
Income tax expense (recovery)	1		(9)
Net income	$ (1)		$ 74
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)		15		17
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)		$ (1)		$ (1)

Inventory (Details)

Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
14. Inventory
Fuel	$ 199	$ 232
Raw Materials	254	235
Inventory Total	$ 453	$ 467

Derivatives Instruments (Deriva

Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Cash flow hedges
Cash flow hedges, Derivative Assets	$ 1	$ 0
Cash flow hedges, Derivative Liabilities	0	1
HFT derivatives
Derivative Assets	152	170
Derivative Liabilities	359	403
Other derivatives
Other, Derivative Assets	15	1
Other, Derivative Liabilities	1	0
Derivative Assets
Total gross current derivative assets	184	207
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(86)	(120)
Derivative Asset, Total	98	87
Derivative Liabilities
Total gross current derivative liabilities	424	490
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	(86)	(120)
Derivative Liabilities, Total	338	370
Equity derivatives
Other derivatives
Other, Derivative Assets	0	1
Other, Derivative Liabilities	1	0
Foreign exchange forwards
Cash flow hedges
Cash flow hedges, Derivative Assets	0	0
Cash flow hedges, Derivative Liabilities	0	1
Other derivatives
Other, Derivative Assets	15	0
Other, Derivative Liabilities	0	0
Power swaps and physical contracts
HFT derivatives
Derivative Assets	13	19
Derivative Liabilities	13	22
Natural gas swaps, futures, forwards, physical contracts and related transportation
HFT derivatives
Derivative Assets	139	151
Derivative Liabilities	346	381
Regulatory deferral
HFT derivatives
Derivative Assets	16	36
Derivative Liabilities	64	86
Derivative Assets
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(2)	(8)
Derivative Liabilities
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	(2)	(8)
Regulatory deferral | Commodity swaps and forwards | Power
HFT derivatives
Derivative Assets	10	23
Derivative Liabilities	34	36
Regulatory deferral | Commodity swaps and forwards | Coal
HFT derivatives
Derivative Assets	1	8
Derivative Liabilities	6	39
Regulatory deferral | Commodity swaps and forwards | Heavy fuel oil purchases
HFT derivatives
Derivative Assets	1	1
Derivative Liabilities	5	0
Regulatory deferral | Commodity swaps and forwards | Natural gas
HFT derivatives
Derivative Assets	4	2
Derivative Liabilities	2	5
Regulatory deferral | Foreign exchange forwards
HFT derivatives
Derivative Assets	0	2
Derivative Liabilities	17	6
HFT derivatives
Derivative Assets
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(84)	(112)
Derivative Liabilities
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	$ (84)	$ (112)

Derivatives Instruments (Master

Derivatives Instruments (Master Netting Agreements) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	$ 86	$ 120
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	86	120
Regulatory deferral
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	2	8
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	2	8
HFT derivatives
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	84	112
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	$ 84	$ 112

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, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)
Cash Flow Hedges
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle			$ 100
Foreign exchange forwards
Cash Flow Hedges
Total gains (losses) in net income	$ 13	$ 0
Cash flow hedges
Cash Flow Hedges
Unrealized losses currently in AOCI to be reclassified into net income within the next twelve months	1
Cash flow hedges | Interest rate swaps
Cash Flow Hedges
Total gains (losses) in net income	0
Total unrealized gain (loss) in AOCI - effective portion, net of tax	1
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	0
Cash flow hedges | Foreign exchange forwards
Cash Flow Hedges
Total gains (losses) in net income	(2)	(3)
Total unrealized gain (loss) in AOCI - effective portion, net of tax	0	(1)
Cash flow hedges | Foreign exchange forwards | 2021
Cash Flow Hedges
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle			$ 350
Cash flow hedges | Foreign exchange forwards | Non-Regulated
Cash Flow Hedges
Total gains (losses) in net income	0	0
Cash flow hedges | Foreign exchange forwards | Regulated
Cash Flow Hedges
Total gains (losses) in net income	$ (2)	$ (3)

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, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	$ 36	$ 39
Foreign exchange forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	13	0
Regulatory deferral | Commodity swaps and forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	15	(115)
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(36)	(89)
Realized (gain) loss on derivatives receiving regulatory deferral	2	0
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	3	9
Realized (gain) loss on derivatives receiving regulatory deferral	14	(2)
Regulatory deferral | Commodity swaps and forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	8	(36)
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	24	3
Regulatory deferral | Foreign exchange forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(13)	(33)
Regulatory deferral | Foreign exchange forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(11)	(6)
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Foreign exchange forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	3	(8)
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	(2)	(11)
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	$ (3)	$ (8)

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 bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2020MMBTUMWhTbbl
Coal | 2021
Derivative [Line Items]
Coal (metric tonnes) | T	0
Coal | 2022-2023
Derivative [Line Items]
Coal (metric tonnes) | T	1
Natural gas | 2021
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MMBTU	5
Natural gas | 2022-2023
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MMBTU	7
Heavy fuel oil | 2021
Derivative [Line Items]
Heavy fuel oil (bbls) | bbl	0
Heavy fuel oil | 2022-2023
Derivative [Line Items]
Heavy fuel oil (bbls) | bbl	1
Power | 2021
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	2
Power | 2022-2023
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) $ in Millions	Dec. 31, 2020USD ($)
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 100
Foreign Exchange Swaps and Forward Contracts | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 160
Weighted average rate	0.013339
% of USD requirements	78.00%
Foreign Exchange Swaps and Forward Contracts | 2022-2023
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 135
Weighted average rate	0.013266
% of USD requirements	37.00%

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, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 200	$ 276
Operating revenues | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	(1)	1
Operating revenues | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	205	281
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	$ (4)	$ (6)

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, 2020MMBTUMWh
Power | Purchases | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	2
Power | Purchases | 2022
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 | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Sales | 2022
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 | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	387
Natural gas | Purchases | 2022
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	61
Natural gas | Purchases | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	45
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 | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	412
Natural gas | Sales | 2022
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	50
Natural gas | Sales | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	17
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, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)shares
Derivative Instruments, Gain (Loss) [Line Items]
Equity derivative hedges, return of shares | shares			2.8
Combined notional amount			$ 100
Foreign exchange forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) in net income	$ 13	$ 0
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	0
Total gains (losses) in net income	(2)	0
Equity derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) in net income	(4)	28
Equity derivatives | Operating, maintenance and general expense
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain on equity derivatives	(1)	1
Total gains (losses) in net income	(3)	27
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, 2020CAD ($)Days	Dec. 31, 2019CAD ($)
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	$ 1,056	$ 1,119
Total cash deposits/collateral on hand	69	101
Receivables, net
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	958	1,032
Credit Concentration Risk
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	805	860
Total cash deposits/collateral on hand	251	259
Credit Concentration Risk | Receivables, net
Credit Derivatives [Line Items]
Financial assets, considered to be past due	123	115
Fair Value, Financial assets, considered to be past due	$ 101	$ 106
Average number of days financial asset outstanding | Days	70

Derivatives Instruments (Concen

Derivatives Instruments (Concentration Risk) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (1,056)	$ (1,119)
% of total exposure	(100.00%)	(100.00%)
Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (98)	$ (87)
% of total exposure	(9.00%)	(8.00%)
Credit Concentration Risk
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (805)	$ (860)
Credit rating of A- or above | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (60)	$ (47)
% of total exposure	(6.00%)	(4.00%)
Credit rating of BBB- to BBB+ | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (13)	$ (8)
% of total exposure	(1.00%)	(1.00%)
Not rated | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (25)	$ (32)
% of total exposure	(2.00%)	(3.00%)
Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (958)	$ (1,032)
% of total exposure	(91.00%)	(92.00%)
Receivables, net | Classification as assets held for sale
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 0	$ (55)
% of total exposure	0.00%	(5.00%)
Receivables, net | Other accounts receivable
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (159)	$ (184)
% of total exposure	(15.00%)	(16.00%)
Receivables, net | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (170)	$ (192)
% of total exposure	(16.00%)	(17.00%)
Receivables, net | Credit rating of A- or above | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (54)	$ (38)
% of total exposure	(5.00%)	(3.00%)
Receivables, net | Credit rating of BBB- to BBB+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (41)	$ (59)
% of total exposure	(4.00%)	(5.00%)
Receivables, net | Credit rating of CCC- to CCC+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 0	$ 0
% of total exposure	0.00%	0.00%
Receivables, net | Not rated | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (75)	$ (95)
% of total exposure	(7.00%)	(9.00%)
Regulated utilities | Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (629)	$ (711)
% of total exposure	(60.00%)	(64.00%)
Regulated utilities | Receivables, net | Residential
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (341)	$ (344)
% of total exposure	(32.00%)	(31.00%)
Regulated utilities | Receivables, net | Commercial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (143)	$ (170)
% of total exposure	(14.00%)	(15.00%)
Regulated utilities | Receivables, net | Industrial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (49)	$ (66)
% of total exposure	(5.00%)	(6.00%)
Regulated utilities | Receivables, net | Other
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ (96)	$ (131)
% of total exposure	(9.00%)	(12.00%)

Derivatives Instruments (Cash C

Derivatives Instruments (Cash Collateral) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
15. Derivative Instruments
Cash collateral provided to others	$ 69	$ 101
Cash collateral received from others	6	2
Total fair value of these derivatives, in a liability position	$ 338	$ 370

Fair Value Measurements (Deriva

Fair Value Measurements (Derivatives) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Assets
Total assets	$ 98	$ 87
Liabilities
Total liabilities	338	370
Fair Value, Measurements, Recurring
Assets
Total assets	98	87
Liabilities
Total liabilities	338	370
Net assets (liabilities)	(240)	(283)
Fair Value, Measurements, Recurring | Cash flow hedges
Assets
Total assets	1
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Foreign exchange forwards
Assets
Total assets	15
Fair Value, Measurements, Recurring | Foreign exchange forwards | Cash flow hedges
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Interest rate hedges | Cash flow hedges
Assets
Total assets	1
Fair Value, Measurements, Recurring | Equity derivatives
Assets
Total assets		1
Liabilities
Total liabilities	1
Fair Value, Measurements, Recurring | Other
Liabilities
Total liabilities	1
Fair Value, Measurements, Recurring | Regulatory deferral
Assets
Total assets	14	28
Liabilities
Total liabilities	62	78
Fair Value, Measurements, Recurring | Regulatory deferral | Coal
Liabilities
Total liabilities	4	31
Fair Value, Measurements, Recurring | Regulatory deferral | Power
Assets
Total assets	9	23
Liabilities
Total liabilities	33	36
Fair Value, Measurements, Recurring | Regulatory deferral | Heavy fuel oil purchases
Assets
Total assets	2	1
Liabilities
Total liabilities	6
Fair Value, Measurements, Recurring | Regulatory deferral | Natural gas
Assets
Total assets	3	2
Liabilities
Total liabilities	2	5
Fair Value, Measurements, Recurring | Regulatory deferral | Foreign exchange forwards
Assets
Total assets		2
Liabilities
Total liabilities	17	6
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument
Assets
Total assets	15	1
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument | Interest rate hedges
Assets
Total assets		1
Fair Value, Measurements, Recurring | HFT derivatives
Assets
Total assets	68	58
Liabilities
Total liabilities	275	291
Fair Value, Measurements, Recurring | HFT derivatives | Power
Assets
Total assets	7	5
Liabilities
Total liabilities	7	7
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas
Assets
Total assets	61	53
Liabilities
Total liabilities	268	284
Fair Value, Measurements, Recurring | Level 1
Assets
Total assets	16	18
Liabilities
Total liabilities	42	46
Net assets (liabilities)	(26)	(28)
Fair Value, Measurements, Recurring | Level 1 | Cash flow hedges
Assets
Total assets	1
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 1 | Foreign exchange forwards
Assets
Total assets	0
Fair Value, Measurements, Recurring | Level 1 | Foreign exchange forwards | Cash flow hedges
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 1 | Interest rate hedges | Cash flow hedges
Assets
Total assets	1
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives
Assets
Total assets		1
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	11	23
Liabilities
Total liabilities	36	39
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Coal
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Power
Assets
Total assets	9	23
Liabilities
Total liabilities	33	36
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Heavy fuel oil purchases
Assets
Total assets	0	0
Liabilities
Total liabilities	3
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Natural gas
Assets
Total assets	2	0
Liabilities
Total liabilities	0	3
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 | Not Designated as Hedging Instrument
Assets
Total assets	0	1
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument | Interest rate hedges
Assets
Total assets		1
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives
Assets
Total assets	4	(6)
Liabilities
Total liabilities	5	7
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power
Assets
Total assets	3	1
Liabilities
Total liabilities	4	5
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas
Assets
Total assets	1	(7)
Liabilities
Total liabilities	1	2
Fair Value, Measurements, Recurring | Level 2
Assets
Total assets	68	54
Liabilities
Total liabilities	38	75
Net assets (liabilities)	30	(21)
Fair Value, Measurements, Recurring | Level 2 | Cash flow hedges
Assets
Total assets	0
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Level 2 | Foreign exchange forwards
Assets
Total assets	15
Fair Value, Measurements, Recurring | Level 2 | Foreign exchange forwards | Cash flow hedges
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Level 2 | Interest rate hedges | Cash flow hedges
Assets
Total assets	0
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives
Assets
Total assets		0
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	3	5
Liabilities
Total liabilities	26	39
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Coal
Liabilities
Total liabilities	4	31
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	2	1
Liabilities
Total liabilities	3
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Natural gas
Assets
Total assets	1	2
Liabilities
Total liabilities	2	2
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Foreign exchange forwards
Assets
Total assets		2
Liabilities
Total liabilities	17	6
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument
Assets
Total assets	15	0
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument | Interest rate hedges
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives
Assets
Total assets	50	49
Liabilities
Total liabilities	12	35
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power
Assets
Total assets	2	3
Liabilities
Total liabilities	2	2
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas
Assets
Total assets	48	46
Liabilities
Total liabilities	10	33
Fair Value, Measurements, Recurring | Level 3
Assets
Total assets	14	15
Liabilities
Total liabilities	258	249
Net assets (liabilities)	(244)	(234)
Fair Value, Measurements, Recurring | Level 3 | Cash flow hedges
Assets
Total assets	0
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 3 | Foreign exchange forwards
Assets
Total assets	0
Fair Value, Measurements, Recurring | Level 3 | Foreign exchange forwards | Cash flow hedges
Liabilities
Total liabilities		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
Assets
Total assets		0
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	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Coal
Liabilities
Total liabilities	0	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 | Not Designated as Hedging Instrument
Assets
Total assets	0	0
Fair Value, Measurements, Recurring | Level 3 | Not Designated as Hedging Instrument | Interest rate hedges
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives
Assets
Total assets	14	15
Liabilities
Total liabilities	258	249
Net assets (liabilities)	(244)	(234)
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power
Assets
Total assets	2	1
Liabilities
Total liabilities	1	0
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas
Assets
Total assets	18	9
Liabilities
Total liabilities	226	228
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | Power
Assets
Total assets	1
Liabilities
Total liabilities	1
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | Natural gas
Assets
Total assets	(6)	5
Liabilities
Total liabilities	30	21
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts and related transportation | Natural gas
Assets
Total assets	12	14
Liabilities
Total liabilities	$ 257	$ 249

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, 2020CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 15
Total realized and unrealized gains (losses) included in non-regulated operating revenues	1
Net transfers out of Level 3	(2)
Ending Balance	14
Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	1
Total realized and unrealized gains (losses) included in non-regulated operating revenues	3
Net transfers out of Level 3	(2)
Ending Balance	2
Natural gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	14
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(2)
Net transfers out of Level 3	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, 2020CAD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 249
Total realized and unrealized gains included in non-regulated operating revenues	10
Net transfers out of Level 3	(1)
Ending Balance	258
Power
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	0
Total realized and unrealized gains included in non-regulated operating revenues	2
Net transfers out of Level 3	(1)
Ending Balance	1
Natural gas
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	249
Total realized and unrealized gains included in non-regulated operating revenues	8
Net transfers out of Level 3	0
Ending Balance	$ 257

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)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Assets
Total assets	$ 98,000,000	$ 87,000,000
Liabilities
Total liabilities	338,000,000	370,000,000
Fair Value, Measurements, Recurring
Assets
Total assets	98,000,000	87,000,000
Liabilities
Total liabilities	338,000,000	370,000,000
Net assets (liabilities)	(240,000,000)	(283,000,000)
Not Designated as Hedging Instrument | Fair Value, Measurements, Recurring
Assets
Total assets	15,000,000	1,000,000
HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	68,000,000	58,000,000
Liabilities
Total liabilities	275,000,000	291,000,000
HFT derivatives | Power | Fair Value, Measurements, Recurring
Assets
Total assets	7,000,000	5,000,000
Liabilities
Total liabilities	7,000,000	7,000,000
Level 3 | Fair Value, Measurements, Recurring
Assets
Total assets	14,000,000	15,000,000
Liabilities
Total liabilities	258,000,000	249,000,000
Net assets (liabilities)	(244,000,000)	(234,000,000)
Level 3 | Not Designated as Hedging Instrument | Fair Value, Measurements, Recurring
Assets
Total assets	0	0
Level 3 | HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	14,000,000	15,000,000
Liabilities
Total liabilities	258,000,000	249,000,000
Net assets (liabilities)	(244,000,000)	(234,000,000)
Level 3 | HFT derivatives | Power | Fair Value, Measurements, Recurring
Assets
Total assets	2,000,000	1,000,000
Liabilities
Total liabilities	1,000,000	0
Level 3 | HFT derivatives | Natural gas | Fair Value, Measurements, Recurring
Assets
Total assets	18,000,000	9,000,000
Liabilities
Total liabilities	226,000,000	228,000,000
Level 3 | HFT derivatives | Energy Related derivative | Power | Fair Value, Measurements, Recurring
Assets
Total assets	1,000,000
Liabilities
Total liabilities	1,000,000
Level 3 | HFT derivatives | Energy Related derivative | Natural gas | Fair Value, Measurements, Recurring
Assets
Total assets	(6,000,000)	5,000,000
Liabilities
Total liabilities	30,000,000	21,000,000
Level 3 | HFT derivatives | Range, Minimum | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 25.7	$ 24.31
Liabilities
Unobservable Input, Liabilities	1.13
Level 3 | HFT derivatives | Range, Minimum | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.36	0.0001
Level 3 | HFT derivatives | Range, Minimum | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.06	0.0015
Liabilities
Unobservable Input, Liabilities	0.01
Level 3 | HFT derivatives | Range, Minimum | Power | Correlation factor | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	100
Level 3 | HFT derivatives | Range, Minimum | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.02
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.66	$ 1.63
Liabilities
Total liabilities	$ 1.44	$ 1.54
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.02	0.0001
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0	0.0001
Liabilities
Unobservable Input, Liabilities	0	0.0001
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0002	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	20.5
Liabilities
Unobservable Input, Liabilities	37.25
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.02
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.01
Liabilities
Unobservable Input, Liabilities	0.01
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	100
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.36
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.82	$ 1.33
Liabilities
Total liabilities	$ 1.54	$ 1.36
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0002	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0	0.0001
Liabilities
Unobservable Input, Liabilities	0	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 0	$ 0
Liabilities
Total liabilities	$ 0	$ 0
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0003	0.0001
Level 3 | HFT derivatives | Range, Maximum | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 36.05	$ 74.05
Liabilities
Unobservable Input, Liabilities	62.45
Level 3 | HFT derivatives | Range, Maximum | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.85	0.0114
Level 3 | HFT derivatives | Range, Maximum | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.41	0.0665
Liabilities
Unobservable Input, Liabilities	0.73
Level 3 | HFT derivatives | Range, Maximum | Power | Correlation factor | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	100
Level 3 | HFT derivatives | Range, Maximum | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	6.85
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 6.22	$ 7.45
Liabilities
Total liabilities	$ 6.57	$ 7.45
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	2.52	0.0231
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	10.36	0.2093
Liabilities
Unobservable Input, Liabilities	0.0879	0.1863
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0252	0.0231
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	62.45
Liabilities
Unobservable Input, Liabilities	62.45
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	9.74
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.73
Liabilities
Unobservable Input, Liabilities	0.4
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	100
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	1.28
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 8.44	$ 8.76
Liabilities
Total liabilities	$ 8.44	$ 9.75
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.1258	0.0333
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0067	0.0471
Liabilities
Unobservable Input, Liabilities	0.0067	0.0376
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.33	$ 1.31
Liabilities
Total liabilities	$ 1.33	$ 1.31
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.1258	0.0333
Level 3 | HFT derivatives | Weighted average | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 29.53	$ 35.03
Liabilities
Unobservable Input, Liabilities	36.9
Level 3 | HFT derivatives | Weighted average | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.6	0.0021
Level 3 | HFT derivatives | Weighted average | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.28	0.0278
Liabilities
Unobservable Input, Liabilities	0.34
Level 3 | HFT derivatives | Weighted average | Power | Correlation factor | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	100
Level 3 | HFT derivatives | Weighted average | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	2.02
Level 3 | HFT derivatives | Weighted average | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 2.52	$ 2.37
Liabilities
Total liabilities	$ 3.68	$ 4.07
Level 3 | HFT derivatives | Weighted average | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.4	0.0009
Level 3 | HFT derivatives | Weighted average | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.75	0.0155
Liabilities
Unobservable Input, Liabilities	0.0043	0.0189
Level 3 | HFT derivatives | Weighted average | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.001	0.0012
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	31.14
Liabilities
Unobservable Input, Liabilities	55
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	2.52
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.25
Liabilities
Unobservable Input, Liabilities	0.31
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	100
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Power | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.83
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 4.66	$ 5.05
Liabilities
Total liabilities	$ 4.69	$ 5.45
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0195	0.0028
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0013	0.0091
Liabilities
Unobservable Input, Liabilities	0.0016	0.0081
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 0.44	$ 0.76
Liabilities
Total liabilities	$ 0.87	$ 0.91
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.001	0.0006

Fair Value Measurements (Assets

Fair Value Measurements (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	$ (16,487)	$ (16,049)
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	(16,020)	(15,598)
Fair Value Measurement [Domain] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	(467)	(451)
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	(13,721)	(14,180)
Financial assets and liabilities	$ (16,487)	$ (16,049)

Fair Value Measurements (Hybrid

Fair Value Measurements (Hybrid Notes) (Details) - Net investment in United States dollar denominated operations - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200
After-tax foreign currency gain (loss)	$ 26	$ 78

Related Paty Transactions (Narr

Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
NSPML | Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 139	$ 107
M&NP | Non-Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 18	$ 63

Receivables And Other Current_3

Receivables And Other Current Assets (Summary of Receivables And Other Current Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
18. Receivables and Other Current Assets
Customer accounts receivable - billed	$ 570	$ 603
Customer accounts receivable - unbilled	286	265
Allowance for credit losses	(22)	(9)
Capitalized transportation capacity	200	272
Income taxes receivable	11	118
Prepaid expenses	50	48
Other current assets	138	189
Receivables and other current assets	$ 1,233	$ 1,486

Leases (Narrative) (Details)

Leases (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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 65 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.
Lease, Expense	$ 160	$ 172
Variable costs for power generation facility finance leases	$ 149	$ 156
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 65 years, some of which include options to extend the leases for up to 65 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	65 years

Leases (Operating Leases) (Deta

Leases (Operating Leases) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Assets and Liabilities, Lessee
Right-of-use asset	$ 61	$ 64
Lease liabilities, Current	3	5
Lease liabilities, Long-term	60	61
Total lease liabilities	63	66
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	$ 7	$ 16
Weighted average remaining lease term (years)	43 years	39 years
Weighted average discount rate - operating leases	3.96%	4.07%

Leases (Future minimum lease pa

Leases (Future minimum lease payments under non-cancellable operating leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter
2021	$ 6
2022	6
2023	6
2024	5
2025	4
Thereafter	112
Minimum lease payments, Total	139
Less imputed interest	(76)
Total	$ 63	$ 66

Leases (Direct Finance and Sale

Leases (Direct Finance and Sales-type Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Net investment in direct finance and sales-type leases
Total minimum lease payments to be received	$ 1,018	$ 1,066
Less: amounts representing estimated executory costs	(179)	(189)
Minimum lease payments receivable	839	877
Estimated residual value of leased property (unguaranteed)	183	183
Less: unearned finance lease income	(487)	(532)
Net investment in direct finance and sales-type leases	535	528
Principal due within one year (included in "Receivables and other current assets")	18	17
Net investment in sales-type leases - long-term (included in "Other long-term assets")	42	38
Net Investment in direct finance leases - long-term	475	473
Future minimum lease payments to be received for each of the next five years and in aggregate thereafter
2021	78
2022	77
2023	76
2024	77
2025	79
Thereafter	631
Total minimum lease payments to be received	1,018	1,066
Less: executory costs	(179)	(189)
Minimum lease payments receivable	$ 839	$ 877

Property, plant and equipment_2

Property, plant and equipment (Regulated and Non-regulated Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment, Net
Total cost	$ 25,891	$ 24,893
Less: Accumulated depreciation	(8,714)	(8,317)
Total cost less: Accumulated depreciation	17,177	16,576
Construction work in progress	2,358	1,591
Property, Plant and Equipment, Net	19,535	18,167
Generation
Property, Plant and Equipment, Net
Total cost	$ 11,474	11,181
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	$ 2,414	2,318
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	$ 5,997	5,820
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	$ 3,879	3,568
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	$ 2,127	$ 2,006
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, 2020CAD ($)km	Dec. 31, 2019CAD ($)
Jointly Owned Pipleline lateral
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Jointly Owned Utility Plant, Name	Pipeline lateral
Length of pipeline, in miles | km	26
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 34
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	0
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0	$ 8

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, 2020	Dec. 31, 2019
Defined benefit pension plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	$ 2,822	$ 2,650
Service cost	46	47
Plan participant contributions	7	8
Interest cost	84	102
Benefits Paid	(135)	(130)
Actuarial (gains) losses	189	231
Settlement, curtailments	(229)	(20)
Foreign currency translation adjustment	(25)	(66)
Benefit Obligation, Ending Balance	2,759	2,822
Change in plan assets
Plan Assets, Beginning Balance	2,593	2,300
Employer contributions	41	52
Plan participant contributions	7	8
Benefits paid	(135)	(130)
Actual return on assets, net of expenses	310	424
Settlements and curtailments	(191)	(7)
Foreign currency translation adjustment	(20)	(54)
Plan Assets, Ending Balance	2,605	2,593
Funded Status
Funded status, end of year	(154)	(229)
Non-pension Benefit Plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	353	350
Service cost	5	4
Plan participant contributions	5	5
Interest cost	10	14
Benefits Paid	(27)	(23)
Actuarial (gains) losses	52	19
Settlement, curtailments	(52)	0
Foreign currency translation adjustment	(7)	(16)
Benefit Obligation, Ending Balance	339	353
Change in plan assets
Plan Assets, Beginning Balance	56	49
Employer contributions	21	19
Plan participant contributions	5	5
Benefits paid	(27)	(23)
Actual return on assets, net of expenses	5	7
Settlements and curtailments	(7)	0
Foreign currency translation adjustment	(1)	(1)
Plan Assets, Ending Balance	52	56
Funded Status
Funded status, end of year	$ (287)	$ (297)

Employee Benefit Plans (Plans w

Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined benefit pension plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	$ 2,736	$ 2,797
Fair value of plan assets	2,568	2,557
Funded Status	(168)	(240)
Non-pension Benefit Plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	308	323
Fair value of plan assets	0	7
Funded Status	$ (308)	$ (316)

Employee Benefit Plans (Accumul

Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO for the defined benefit pension plans	$ 2,639	$ 2,687
Defined benefit pension plans
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO	1,519	2,665
Fair value of plan assets	1,419	2,557
Funded Status	$ (100)	$ (108)

Employee Benefit Plans (Amounts

Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Balance Sheet
Other current liabilities	$ (23)	$ (22)
Long-term liabilities	(453)	(460)
Long-term liabilities associated with assets held for sale	0	(899)
Defined benefit pension plans
Balance Sheet
Other current liabilities	(4)	(4)
Long-term liabilities	(163)	(206)
Long-term liabilities associated with assets held for sale	0	(30)
Other long-term assets	13	11
Amount included in deferred income tax	(4)	(7)
AOCI, net of tax and regulatory assets	443	524
Net amount recognized	285	288
Non-pension Benefit Plans
Balance Sheet
Other current liabilities	(19)	(18)
Long-term liabilities	(290)	(254)
Long-term liabilities associated with assets held for sale	0	(44)
Other long-term assets	20	19
Amount included in deferred income tax	(1)	(1)
AOCI, net of tax and regulatory assets	107	72
Net amount recognized	$ (183)	$ (224)

Employee Benefit Plans (Change

Employee Benefit Plans (Change in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined benefit pension plans
Change in AOCI and Regulatory Assets
Beginning Balance	$ 517
Amortized in current period	15	$ 16
Ending Balance	439	517
Defined benefit pension plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	358
Amortized in current period	(25)
Current year addition to AOCI or regulatory assets	(12)
Current year change due to divestitures	(39)
Foreign currency translation adjustment	(3)
Ending Balance	279	358
Defined benefit pension plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	160
Amortized in current period	(15)
Current year addition to AOCI or regulatory assets	14
Foreign currency translation adjustment	1
Ending Balance	160	160
Defined benefit pension plans | Past service costs (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	(1)
Amortized in current period	1
Current year addition to AOCI or regulatory assets	0
Foreign currency translation adjustment	0
Ending Balance	0	(1)
Non-pension Benefit Plans
Change in AOCI and Regulatory Assets
Beginning Balance	73
Amortized in current period	0	0
Ending Balance	106	73
Non-pension Benefit Plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	78
Amortized in current period	0
Current year addition to AOCI or regulatory assets	48
Current year change due to divestitures	(13)
Foreign currency translation adjustment	(3)
Ending Balance	110	78
Non-pension Benefit Plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	(5)
Amortized in current period	0
Current year addition to AOCI or regulatory assets	2
Foreign currency translation adjustment	(1)
Ending Balance	(4)	(5)
Non-pension Benefit Plans | Past service costs (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year addition to AOCI or regulatory assets	0
Foreign currency translation adjustment	0
Ending Balance	$ 0	$ 0

Employee Benefit Plans (Net amo

Employee Benefit Plans (Net amount in AOCI and regulatory assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 1,584	$ 1,552
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	160	160
Past service (gains)	0	(1)
Regulatory assets	279	358
Accumulated Other Comprehensive Income (Loss), before Tax, Total	439	517
Amount included in deferred income tax	4	7
Net amount in AOCI after tax adjustment	443	524
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	(4)	(5)
Past service (gains)	0	0
Regulatory assets	110	78
Accumulated Other Comprehensive Income (Loss), before Tax, Total	106	73
Amount included in deferred income tax	1	1
Net amount in AOCI after tax adjustment	$ 107	$ 72

Employee Benefit Plans (Net Per

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (2,476)	$ (2,401)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	46	47
Interest cost	84	102
Expected return on plan assets	(141)	(147)
Current year amortization of: Actuarial losses	15	16
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(1)	(1)
Regulatory assets (liability)	25	20
Settlement, curtailments	0	1
Net Periodic Benefit Cost, Total	28	38
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	5	4
Interest cost	10	14
Expected return on plan assets	(1)	(2)
Current year amortization of: Actuarial losses	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Regulatory assets (liability)	0	(5)
Settlement, curtailments	0	0
Net Periodic Benefit Cost, Total	$ 14	$ 11

Employee Benefit Plans (Asset C

Employee Benefit Plans (Asset Class) (Details) - Defined benefit pension plans	Dec. 31, 2020
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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 2,605	$ 2,593	$ 2,300
Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Percentage		2.00%
Net in-transits
Classification of the methodology used by the Company to fair value its investments
Percentage		2.00%
Canadian equity
Classification of the methodology used by the Company to fair value its investments
Percentage		8.00%
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	9.00%	7.00%
Government
Classification of the methodology used by the Company to fair value its investments
Percentage	5.00%	3.00%
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		8.00%
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	31.00%	33.00%
Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Percentage	27.00%	21.00%
Total
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,605	$ 2,593
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	$ 68	44
Percentage	3.00%
Total | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (99)	(48)
Percentage	4.00%
Total | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 154	210
Percentage	6.00%
Total | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 380	388
Percentage	15.00%
Total | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 243	176
Percentage	9.00%
Total | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 119	93
Percentage	5.00%
Total | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 141	126
Percentage	5.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 13	14
Percentage
Total | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 88	199
Percentage	3.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (7)	(4)
Percentage
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	$ 801	860
Percentage	31.00%
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	$ 704	535
Percentage	27.00%
NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,505	1,395
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	801	860
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	704	535
Level 1
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	841	969
Level 1 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	68	44
Level 1 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(99)	(48)
Level 1 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	154	210
Level 1 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	380	388
Level 1 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	243	176
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	10	5
Level 1 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	88	199
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(3)	(5)
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	259	229
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	119	93
Level 2 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	141	126
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	3	9
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	(4)	1
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, 2020CAD ($)
Defined benefit pension plans
Expected employer contributions
Expected employer contributions, 2021	$ 41
Expected benefit payments
Expected benefit payments, 2021	140
Expected benefit payments, 2022	154
Expected benefit payments, 2023	154
Expected benefit payments, 2024	162
Expected benefit payments, 2025	170
Expected benefit payments, 2026 - 2030	914
Non-pension Benefit Plans
Expected employer contributions
Expected employer contributions, 2021	19
Expected benefit payments
Expected benefit payments, 2021	21
Expected benefit payments, 2022	22
Expected benefit payments, 2023	22
Expected benefit payments, 2024	22
Expected benefit payments, 2025	22
Expected benefit payments, 2026 - 2030	$ 105

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, 2020	Dec. 31, 2019
Defined benefit pension plans
Benefit obligation - December 31:
Discount rate - past service	2.49%	3.17%
Discount rate - future service	2.64%	3.21%
Rate of compensation increase	2.89%	3.32%
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	3.17%	4.05%
Discount rate - future service	3.21%	4.05%
Expected long-term return on plan assets	6.29%	6.50%
Rate of compensation increase	3.34%	3.30%
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	2.48%	3.27%
Discount rate - future service	2.51%	3.28%
Rate of compensation increase	3.04%	3.70%
Health care trend - initial (next year)	5.64%	6.15%
Health care trend - ultimate	4.35%	4.38%
Health care trend - year ultimate reached	2038	2038
Benefit cost for year ended December 31:
Discount rate - past service	3.28%	4.30%
Discount rate - future service	3.28%	4.30%
Expected long-term return on plan assets	3.25%	2.81%
Rate of compensation increase	3.70%	3.67%
Health care trend - initial (next year)	5.91%	6.39%
Health care trend - ultimate	4.37%	4.45%
Health care trend - year ultimate reached	2038	2035

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 2,476	$ 2,401
Contribution Amount	45	34
Defined benefit pension plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	141	147
Defined Benefit Plan, Fair Value of Plan Assets	2,605	2,593	$ 2,300
Non-pension Benefit Plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	1	2
Defined Benefit Plan, Fair Value of Plan Assets	$ 52	$ 56	$ 49

Goodwill (Details)

Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Roll Forward]
Balance, January 1	$ 5,835	$ 6,313
Additions	0	3
GBPC impairment charge	0	(30)
Classified as assets held for sale	0	(148)
Change in foreign exchange rate	(115)	(303)
Balance, December 31	5,720	5,835
GBPC
Goodwill [Roll Forward]
Balance, January 1	70
GBPC impairment charge		(30)
Balance, December 31	$ 68	$ 70

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, 2020	Dec. 31, 2019
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 1,625	$ 1,537
Weighted average interest rate	1.01%	2.54%
Advances on revolving credit and term facilities | TECO Finance
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 205	$ 656
Weighted average interest rate	1.46%	2.39%
Advances on accounts receivable and revolving credit facilities | TEC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 987	$ 452
Weighted average interest rate	0.89%	2.56%
Non-revolving credit agreement | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 400	$ 399
Weighted average interest rate	0.94%	2.69%
Bank indebtedness | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 0	$ 6
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	$ 6
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	$ 11	$ 10
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	$ 21	$ 8
Weighted average interest rate	1.22%	2.70%

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	Dec. 01, 2020CAD ($)	Feb. 06, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity			$ 2,677	$ 2,463
Advances under revolving credit and term facilities			1,624	1,525
Letters of credit issued within the credit facilities			4	3
Total advances under available facilities			1,628	1,528
Available capacity under existing agreements			1,049	935
TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity			$ 0	649
Term credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			2021
Total available capacity			$ 382	0
Revolving credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			2023
Total available capacity			$ 509	520
Revolving credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			2023
Total available capacity			$ 1,019	520
Revolving credit facility | NMGC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			2023
Total available capacity			$ 159	162
Revolving credit facility | GBPC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			on demand
Total available capacity			$ 17	17
Non-revolving credit agreement | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity		Feb. 4, 2021
Total available capacity		$ 300
Non-revolving credit agreement | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	Dec. 15, 2020
Maturity			2021
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
Maturity			2021
Total available capacity			$ 191	$ 195

Short Term Debt (Narrative) (De

Short Term Debt (Narrative) (Details) $ in Millions, $ in Millions	Jan. 29, 2021	Dec. 18, 2020USD ($)	Dec. 01, 2020CAD ($)	Jun. 30, 2020USD ($)	Apr. 03, 2020USD ($)	Feb. 28, 2020USD ($)	Feb. 06, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Line of Credit Facility [Line Items]
Weighted average interest rate								1.01%	2.54%
Line of Credit Facility, Maximum Borrowing Capacity								$ 2,677	$ 2,463
Letters of Credit Outstanding, Amount								4	3
TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								0	649
Revolving credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								1,019	520
Revolving credit facility | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								159	162
Revolving credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								509	520
Term loan credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								$ 382	$ 0
Non-revolving credit agreement | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 300
Line of Credit Facility, Expiration Date							Feb. 4, 2021
Non-revolving credit agreement | TEC | Extended Maturity [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Apr. 29, 2021
Non-revolving credit agreement | Emera Inc.
Line of Credit Facility [Line Items]
Weighted average interest rate								0.94%	2.69%
Line of Credit Facility, Maximum Borrowing Capacity			$ 400					$ 400	$ 400
Line of Credit Facility, Expiration Date			Dec. 15, 2020
Non-revolving credit agreement | Emera Inc. | Extended Maturity [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date			Dec. 16, 2021
Bank credit facility [Member] | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 400
Increased commitment		$ 800
Line of Credit Facility, Expiration Date		Mar. 22, 2022
Letters of Credit Outstanding, Amount		$ 80
Bank credit facility [Member] | TEC | Extended Maturity [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Mar. 22, 2023
Bank credit facility [Member] | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 125
Line of Credit Facility, Expiration Date		Mar. 22, 2022
Letters of Credit Outstanding, Amount		$ 30
Bank credit facility [Member] | NMGC | Extended Maturity [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Mar. 22, 2023
Bank credit facility [Member] | TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 400				$ 500
Line of Credit Facility, Expiration Date		Mar. 22, 2022				Mar. 5, 2020
Repayments of credit facility				$ 300	$ 200
Letters of Credit Outstanding, Amount		$ 50
Bank credit facility [Member] | TECO Finance | Extended Maturity [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Mar. 22, 2023				Jul. 3, 2020

Other Current Liabilities (Deta

Other Current Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
24. Other Current Liabilities
Accrued charges	$ 141	$ 147
Accrued interest on long-term debt	71	77
Pension and post-retirement liabilities (note 19)	23	22
Sales and other taxes payable	6	13
Income taxes payable	1	1
Other	98	73
Other current liabilities, Total	$ 340	$ 333

Long Term Debt (Details)

Long Term Debt (Details) - CAD ($) $ in Millions	Apr. 24, 2020	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Debt issuance costs		$ (110)	$ (119)
Long-term liabilities associated with assets held for sale		0	(899)
Amount due within one year		(1,382)	(501)
Long Term Debt, Adjustments		(1,487)	(1,128)
Long-Term Debt		12,339	13,679
Emera
Debt Instrument [Line Items]
Long-term debt		2,291	2,496
Emera Finance
Debt Instrument [Line Items]
Long-term debt		3,501	3,572
NSPI
Debt Instrument [Line Items]
Fixed interest rates	3.31%
Maturity	Apr. 25, 2050
Long-term debt		2,956	2,673
Emera Maine
Debt Instrument [Line Items]
Long-term debt		0	518
Long-term liabilities associated with assets held for sale		0	(516)
ECI
Debt Instrument [Line Items]
Long-term debt		476	470
TECO Energy
Debt Instrument [Line Items]
Fair market value adjustment		$ 5	$ 8
Bankers acceptances | LIBOR loans | Emera
Debt Instrument [Line Items]
Interest Rate Terms		Variable	Variable
Maturity		2024
Long-term debt		$ 263	$ 437
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		2021 - 2046
Fixed to floating subordinated notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate		6.75%	6.75%
Maturity		2076
Long-term debt		$ 1,528	$ 1,559
Unsecured senior notes | Emera Finance
Debt Instrument [Line Items]
Weighted average interest rate		3.86%	3.86%
Long-term debt		$ 3,501	$ 3,572
Fixed rate notes and bonds | TECO Finance
Debt Instrument [Line Items]
Weighted average interest rate			5.15%
Long-term debt		$ 0	$ 390
Fixed rate notes and bonds | TEC
Debt Instrument [Line Items]
Weighted average interest rate		4.53%	4.53%
Maturity		2021 - 2050
Long-term debt		$ 3,268	$ 3,334
Fixed rate notes and bonds | PGS
Debt Instrument [Line Items]
Weighted average interest rate		4.58%	4.58%
Maturity		2021 - 2050
Long-term debt		$ 429	$ 437
Fixed rate notes and bonds | NMGC
Debt Instrument [Line Items]
Weighted average interest rate		4.30%	4.30%
Maturity		2021 - 2049
Long-term debt		$ 465	$ 474
Fixed rate notes and bonds | NMGI
Debt Instrument [Line Items]
Weighted average interest rate		3.64%	3.64%
Maturity		2024
Long-term debt		$ 191	$ 195
Discount notes | NSPI
Debt Instrument [Line Items]
Interest Rate Terms		Variable	Variable
Maturity		2024
Long-term debt		$ 291	$ 308
Medium term fixed rate notes | NSPI
Debt Instrument [Line Items]
Weighted average interest rate		5.14%	5.37%
Maturity		2025 - 2097
Long-term debt		$ 2,665	$ 2,365
LIBOR loans and demand loans | Emera Maine
Debt Instrument [Line Items]
Interest Rate Terms			Variable
Long-term debt		0	$ 11
Secured fixed rate mortgage bonds | Emera Maine
Debt Instrument [Line Items]
Weighted average interest rate			9.74%
Long-term debt		0	$ 65
Unsecured senior fixed rate notes | Emera Maine
Debt Instrument [Line Items]
Weighted average interest rate			4.15%
Long-term debt		$ 0	$ 442
Senior secured credit facility | EBP
Debt Instrument [Line Items]
Interest Rate Terms		Variable	Variable
Long-term debt		$ 249	$ 248
Amortizing fixed rate notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate		3.92%	3.89%
Maturity		2021 - 2022
Long-term debt		$ 100	$ 122
Secured senior notes | ECI
Debt Instrument [Line Items]
Interest Rate Terms		Variable	Variable
Maturity		2021 - 2031
Long-term debt		$ 106	$ 130
Secured fixed rate senior notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate		4.39%	4.84%
Maturity		2022 - 2035
Long-term debt		$ 174	$ 218
Non-revolving term facility, floating rate | ECI
Debt Instrument [Line Items]
Interest Rate Terms		Variable
Maturity		2025
Long-term debt		$ 28	0
Non-revolving term facility, fixed rate | ECI
Debt Instrument [Line Items]
Weighted average interest rate		2.60%
Maturity		2025
Long-term debt		$ 68	$ 0

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, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 2,677	$ 2,463
Letters of credit issued inside credit facilities	4	3
Use of available facilities	1,628	1,528
Available capacity under existing agreements	1,049	935
Advances on the revolving credit facility	1,624	1,525
NSPI
Debt Instrument [Line Items]
Letters of credit issued inside credit facilities	63	52
Revolving credit facility
Debt Instrument [Line Items]
Available capacity under existing agreements	1,528	1,629
Borrowings under credit facilities	569	771
Letters of credit issued inside credit facilities	31	65
Use of available facilities	600	836
Available capacity under existing agreements	928	793
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, 2024
Revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 600	600
Maturity	Oct. 31, 2024
Revolving credit facility | Emera Maine
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 0	104
Revolving credit facility | ECI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 28	$ 25
Revolving credit facility | Minimum | ECI
Debt Instrument [Line Items]
Maturity	Dec. 31, 2021
Revolving credit facility | Maximum | ECI
Debt Instrument [Line Items]
Maturity	Dec. 31, 2023

Long Term Debt (Debt Covenants)

Long Term Debt (Debt Covenants) (Details)	Dec. 31, 2020
Maximum
Debt Instrument [Line Items]
Debt to capital ratio	0.7
Syndicated credit facilities
Debt Instrument [Line Items]
Debt to capital ratio	0.56

Long Term Debt (Long Term Matur

Long Term Debt (Long Term Maturities) (Details) $ in Millions	Dec. 31, 2020CAD ($)
Subsidiaries
Debt Instrument [Line Items]
2021	$ 1,382
2022	407
2023	809
2024	820
2025	226
Thereafter	10,182
Total, long-term debt maturities, including capital lease obligations	13,826
Emera
Debt Instrument [Line Items]
2021	0
2022	0
2023	500
2024	263
2025	0
Thereafter	1,528
Total, long-term debt maturities, including capital lease obligations	2,291
Emera US Finance LP
Debt Instrument [Line Items]
2021	955
2022	0
2023	0
2024	0
2025	0
Thereafter	2,546
Total, long-term debt maturities, including capital lease obligations	3,501
Tampa Electric
Debt Instrument [Line Items]
2021	295
2022	286
2023	0
2024	0
2025	0
Thereafter	2,687
Total, long-term debt maturities, including capital lease obligations	3,268
PGS
Debt Instrument [Line Items]
2021	59
2022	33
2023	0
2024	0
2025	0
Thereafter	337
Total, long-term debt maturities, including capital lease obligations	429
NMGC
Debt Instrument [Line Items]
2021	0
2022	0
2023	0
2024	0
2025	0
Thereafter	465
Total, long-term debt maturities, including capital lease obligations	465
NMGI
Debt Instrument [Line Items]
2021	0
2022	0
2023	0
2024	191
2025	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	191
NSPI
Debt Instrument [Line Items]
2021	0
2022	0
2023	0
2024	291
2025	125
Thereafter	2,540
Total, long-term debt maturities, including capital lease obligations	2,956
EBP
Debt Instrument [Line Items]
2021	0
2022	0
2023	249
2024	0
2025	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	249
ECI
Debt Instrument [Line Items]
2021	73
2022	88
2023	60
2024	75
2025	101
Thereafter	79
Total, long-term debt maturities, including capital lease obligations	$ 476

Long Term Debt (Narrative) (Det

Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions, $ in Millions, $ in Millions	Feb. 05, 2021USD ($)	May 20, 2020USD ($)	Apr. 24, 2020CAD ($)	Mar. 13, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020BBD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	May 20, 2020BSD ($)	May 20, 2020USD ($)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 2,463		$ 2,677
Proceeds from issuance of long-term debt					$ 428	1,066
Repayments of Long-term Debt					$ 513	1,103
Emera
Debt Instrument [Line Items]
Long-term Debt, Gross						2,496		2,291
NSPI
Debt Instrument [Line Items]
Debt instrument, available for issuance under this prospectus			$ 300
Debt Instrument, Maturity Date			Apr. 25, 2050
Stated interest rate			3.31%
Long-term Debt, Gross						$ 2,673		$ 2,956
NMGC | Subsequent Event [Member]
Debt Instrument [Line Items]
Senior notes	$ 220
Repayments of Long-term Debt	$ 200
TECO Finance
Debt Instrument [Line Items]
Repayments of Long-term Debt				$ 300
Non-revolving term loan | GBPC
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity											$ 22
Line of Credit Facility, Expiration Date		May 20, 2025
Variable rate		90-day LIBOR plus a margin
Debt Instrument, Term					5 years
Repayments of Long-term Debt		$ 22
Non-revolving term loan | BPLC
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 110		$ 55
Stated interest rate							2.05%	2.05%	2.05%
Long-term Debt, Gross							$ 77		$ 38
Non-revolving term loan at 4% interest rate | GBPC
Debt Instrument [Line Items]
Debt Instrument, Maturity Date		May 20, 2025
Line of Credit Facility, Maximum Borrowing Capacity										$ 15	$ 15
Stated interest rate										4.00%	4.00%
Senior note maturity date of February 5, 2031 | NMGC | Subsequent Event [Member]
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, 2036 | NMGC | Subsequent Event [Member]
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, 2051 | NMGC | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Feb. 5, 2051
Stated interest rate	3.34%
Senior notes	$ 85

Asset Retirement Obligation (Ch

Asset Retirement Obligation (Change in ARO) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in ARO
Balance, January 1	$ 185	$ 205
Additions	10	0
Liabilities settled	(25)	(25)
Accretion included in depreciation expense	9	7
Accretion deferred to regulatory asset (included in property, plant and equipment)	(3)	0
Other	1	3
Change in foreign exchange rate	1	(5)
Balance, December 31	$ 178	$ 185

Commitments and Contingencies_2

Commitments and Contingencies (Contractual Commitments) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 16, 2020CAD ($)	Dec. 16, 2020USD ($)	Dec. 31, 2019CAD ($)
Recorded Unconditional Purchase Obligation [Line Items]
2021	$ 1,736
2022	1,143
2023	689
2024	573
2025	548
Thereafter	5,156
Contractual Commitments	9,845
NSPI Contractual obligation for use of the Maritime Link
Revenue, Remaining Performance Obligation, Amount	$ 464			$ 347
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	$ 149
Maritime Link Project | NSPML
NSPI Contractual obligation for use of the Maritime Link
2021 costs to be collected			$ 23
Maritime Link Project | Scenario Plan | NSPML
NSPI Contractual obligation for use of the Maritime Link
Approved payment		$ 172
Maritime Link Project | NSPI
NSPI Contractual obligation for use of the Maritime Link
Long-term Purchase Commitment, Period	38 years
Approved payment difference from interim cost assessment included its proposed fuel stability plan		$ 10
Maritime Link Project | NSPI | NSPML
NSPI Contractual obligation for use of the Maritime Link
Interim cost assessment, holdback	On December 16, 2020, the UARB approved NSPML’s 2021 interim assessment for recovery from NSPI of Maritime Link costs of approximately $172 million subject to a holdback of $10 million
Purchased power
Recorded Unconditional Purchase Obligation [Line Items]
2021	$ 231
2022	218
2023	216
2024	218
2025	224
Thereafter	2,242
Contractual Commitments	3,349
Transportation
Recorded Unconditional Purchase Obligation [Line Items]
2021	518
2022	393
2023	339
2024	306
2025	282
Thereafter	2,704
Contractual Commitments	4,542
Capital projects
Recorded Unconditional Purchase Obligation [Line Items]
2021	394
2022	98
2023	76
2024	0
2025	0
Thereafter	0
Contractual Commitments	568
Fuel, gas supply and storage
Recorded Unconditional Purchase Obligation [Line Items]
2021	494
2022	91
2023	6
2024	1
2025	0
Thereafter	0
Contractual Commitments	592
Long-term service agreements
Recorded Unconditional Purchase Obligation [Line Items]
2021	43
2022	41
2023	36
2024	33
2025	34
Thereafter	92
Contractual Commitments	279
Equity investment commitments
Recorded Unconditional Purchase Obligation [Line Items]
2021	0
2022	240
2023	0
2024	0
2025	0
Thereafter	0
Contractual Commitments	240
Leases and other
Recorded Unconditional Purchase Obligation [Line Items]
2021	16
2022	17
2023	16
2024	15
2025	8
Thereafter	118
Contractual Commitments	190
Demand side management
Recorded Unconditional Purchase Obligation [Line Items]
2021	40
2022	45
2023	0
2024	0
2025	0
Thereafter	0
Contractual Commitments	$ 85

Commitments and Contingencies_3

Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions, $ in Millions	Oct. 16, 2020USD ($)	May 13, 2020USD ($)	Nov. 30, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)
Loss Contingencies [Line Items]
Litigation Settlement, Amount				$ 49		$ 0
Prime Rate [Member] | Tampa Electric
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss				$ 22			$ 17
Prime Rate [Member] | TGH
Loss Contingencies [Line Items]
Litigation Settlement, Amount					$ 21
Litigation Settlement Variable Rate				2.00%	2.00%
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			$ 59
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, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 4		$ 3
Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Guaranty Liabilities		$ 18
Letters of Credit Outstanding, Amount	$ 63		$ 52
Guarantor Obligations, Term	The expiry date of this letter of credit was extended to June 2021
Emera Inc.
Guarantor Obligations [Line Items]
Guaranty Liabilities		35
Guarantor Obligations, Origin and Purpose	relating to outstanding notes of GBPC
Guarantor Obligations, Term	The guarantee for the notes will expire in May 2023
Payment Guarantee | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount		27
Guarantor Obligations, Maximum Exposure, Undiscounted		45
Surety Bonds
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount		$ 55		$ 82

Commitments and Contingencies_5

Commitments and Contingencies (Collaborative Arrangements) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Regulated fuel for generation and purchased power	$ 19	$ 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, 2020	Dec. 31, 2019	Aug. 17, 2020
Class of Stock [Line Items]
Issued and Outstanding		41,000,000	41,000,000
Net Proceeds		$ 1,004	$ 1,004
Series A Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 0.5456	$ 0.6388
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		4,866,814	3,864,636	3,864,636
Net Proceeds		$ 95	$ 95
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		1,133,186	2,135,364	2,135,364
Net Proceeds		$ 52	$ 52
Preferred Stock Dividend Payment Rate Variable		Floating
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	1.1802	$ 1.1802	$ 1.0505
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		$ 1.125
Preferred Stock, Redemption Price Per Share		$ 25.75
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	$ 1.0625
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		$ 1.225
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		12,000,000	12,000,000
Net Proceeds		$ 295	$ 295

Cumulative Preferred Stock (Cha

Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - $ / shares	Aug. 15, 2020	Jul. 16, 2020	Dec. 31, 2020	Dec. 31, 2019
Series A Preferred Stock
Class of Stock [Line Items]
Initial Yield		2.182%	4.40%
Current Annual Dividend	$ 0.5456		$ 0.6388
Earliest Redemption and/or Conversion Option Date			Aug. 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 A Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value			$ 25
Series C Preferred Stock
Class of Stock [Line Items]
Initial Yield			4.10%
Current Annual Dividend	1.1802		$ 1.1802	$ 1.0505
Earliest Redemption and/or Conversion Option Date			Aug. 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 C Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value			$ 25
Series F Preferred Stock
Class of Stock [Line Items]
Initial Yield			4.202%
Current Annual Dividend	$ 1.0505		$ 1.0625
Earliest Redemption and/or Conversion Option Date			Feb. 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
Right to Convert on a one for one basis			The holders of the Series F Shares have the right, at their option, to convert all or any of their Series F Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series G of the Company on February 15, 2020, or to continue to hold their Series F Shares.
Series F Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield			2.63%
Series F Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value			$ 25
Series B Preferred Stock
Class of Stock [Line Items]
Initial Yield		2.021%	2.393%
Earliest Redemption and/or Conversion Option Date			Aug. 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			$ 1.225
Earliest Redemption and/or Conversion Option Date			Aug. 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 H Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value			$ 25
Series I Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield			2.54%
Perpetual fixed rate Series E Preferred Stock
Class of Stock [Line Items]
Initial Yield			4.50%
Current Annual Dividend			$ 1.125
Redemption Value			$ 25.75

Cumulative Preferred Stock (Nar

Cumulative Preferred Stock (Narrative) (Details)	Aug. 17, 2020shares	Aug. 15, 2020$ / shares	Jul. 16, 2020$ / shares	Jan. 07, 2020shares	Dec. 31, 2020CAD ($)$ / sharesshares	Dec. 31, 2019$ / sharesshares
Class of Stock [Line Items]
Issued and Outstanding | shares					41,000,000	41,000,000
First Preferred Shares
Class of Stock [Line Items]
Redemption Value					$ 25
Stock Redeemed or Called During Period, Shares | shares				0
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 earnings 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 A Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		$ 0.5456			$ 0.6388
Redemption Value					$ 25
Conversion of Stock, Shares Converted | shares	128,610
Convertible Preferred Stock, Shares Issued upon Conversion | shares	4,866,814
Preferred Stock, Conversion Basis					Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted					Series B
Issued and Outstanding | shares	3,864,636				4,866,814	3,864,636
Percentage rate used to determine dividend rate			2.182%		4.40%
Amount per share used to determine dividend per share			$ 0.1364
Series A Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					1.84%
Series A Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value					$ 25
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		1.1802			1.1802	$ 1.0505
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
Issued and Outstanding | shares					10,000,000	10,000,000
Percentage rate used to determine dividend rate					4.10%
Series C Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					2.65%
Series C Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value					$ 25
Series F Preferred Stock
Class of Stock [Line Items]
Convertible Preferred Stock, Terms of Conversion					The holders of the Series F Shares have the right, at their option, to convert all or any of their Series F Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series G of the Company on February 15, 2020, or to continue to hold their Series F Shares.
Annual Dividend Per Share		$ 1.0505			$ 1.0625
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
Issued and Outstanding | shares					8,000,000	8,000,000
Percentage rate used to determine dividend rate					4.202%
Series F Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					2.63%
Series F Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value					$ 25
Series B Preferred Stock
Class of Stock [Line Items]
Redemption Value					$ 25
Preferred Stock Dividend Payment Rate Variable					Floating
Conversion of Stock, Shares Converted | shares	1,130,788,000,000
Convertible Preferred Stock, Shares Issued upon Conversion | shares	1,133,186
Preferred Stock, Conversion Basis					Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted					Series A
Issued and Outstanding | shares	2,135,364				1,133,186	2,135,364
Percentage rate used to determine dividend rate			2.021%		2.393%
Amount per share used to determine dividend per share			$ 0.1274
Series B Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					1.84%
Series H Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share					$ 1.225
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
Issued and Outstanding | shares					12,000,000	12,000,000
Percentage rate used to determine dividend rate					4.90%
Series H Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					4.90%
Series H Preferred Stock | Maximum
Class of Stock [Line Items]
Redemption Value					$ 25
Series I Preferred Stock | Minimum
Class of Stock [Line Items]
Percentage rate used to determine dividend rate					2.54%
Perpetual fixed rate Series E Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share					$ 1.125
Redemption Value					$ 25.75
Preferred Stock, Redemption Price, Annual Decrease | $					0.25
Preferred Stock, Redemption Price, Annual Decrease, After Year Five | $					25
Issued and Outstanding | shares					5,000,000	5,000,000
Percentage rate used to determine dividend rate					4.50%

Non-controlling Interest In S_3

Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 34	$ 35
Domlec
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	20	21
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, 2020	Dec. 31, 2019
Noncontrolling Interest [Line Items]
Number of shares issued and outstanding	41,000,000	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) - GBPC	12 Months Ended
	Dec. 31, 2020$ / shares
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Payment Terms	6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually
Preferred Stock, Redemption Terms	The preferred shares are redeemable by GBPC after June 17, 2021
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares
Noncontrolling Interest [Line Items]
Preferred Stock, Redemption Price Per Share	$ 1,000
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD preferred shares
Noncontrolling Interest [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%

Supplementary Information To Co

Supplementary Information To Condensed Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Changes in non-cash working capital
Inventory	$ 6	$ (19)
Receivables and other current assets	187	154
Accounts payable	55	(137)
Other current liabilities	(31)	(71)
Total non-cash working capital	217	(73)
Supplemental disclosure of cash paid:
Interest	679	750
Income Taxes	(148)	(107)
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	199	187
Reclassification of long-term debt from current to non-current	256	0
Increase in accrued capital expenditures	$ 17	$ 33

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, 2020CAD ($)shares	Dec. 31, 2020USD ($)shares	Dec. 31, 2019CAD ($)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, 2020, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 Canadian dollars or $15,000 US dollars 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, 2020, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 Canadian dollars or $15,000 US dollars 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	$ 2,000,000		$ 1,000,000
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 2020. Effective with the dividend payment of August 15, 2019, the discount changed from 5 per cent to 2 per cent.	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 2020. Effective with the dividend payment of August 15, 2019, the discount changed from 5 per cent to 2 per cent.
Maximum aggregate number of common shares reserved for issuance | shares	7	7	4
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) - CAD ($) $ / shares in Units, $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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	7	4
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	7	4
DSU Plan
Share Unit Plans
Cash payments made during the year	$ 11,000	$ 22,000
Employee Stock Option Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	3.5	3.9
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	3.5	3.9
Share Unit Plans
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	3.5	0.9
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	3.5	0.9
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 11.7 million shares. As at December 31, 2020, 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 be exercised within the 24 months following the option holders date of retirement or termination for other than just cause, and within six months following the date of termination for just cause, resignation or death. If stock options are not exercised within such time, they expire.
Maximum term	10 years
Maximum aggregate number of common shares reserved for issuance	11.7
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	$ 19,000	$ 97,000
Total intrinsic value of options exercised	$ 6,000	$ 32,000
Exercise Price Range, Lower Range Limit	$ 32.06	$ 32.06
Exercise Price Range, Upper Range Limit	$ 60.03	$ 46.39
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	$ 1,000	$ 1,000
Maximum aggregate number of common shares reserved for issuance	11.7
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 Deferred Share Unit Plan (“DSU”), Performance Share Unit Plan (“PSU”) and Restricted Share Unit Plan (“RSU”) 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	$ 2,000	24,000
Tax Benefit related to compensation costs for share units realized	1,000	7,000
Deferred Share Unit Plans | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	36,000	40,000
Deferred Share Unit Plans | Director
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 32,000	30,000
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
Share Unit Plans
Tax Benefit related to compensation costs for share units realized	$ 7,000	9,000
Cash payments made during the year	29,000	7,000
Performance Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 68,000	88,000
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	$ 27,000	34,000
Restricted Share Unit Plan
Share Unit Plans
Tax Benefit related to compensation costs for share units realized	1,000
Share Unit Plans: Aggregate intrinsic value	$ 10,000
Restricted Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value		$ 0
Restricted Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, Description	In 2020, Emera introduced an RSU plan, where 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	$ 4,000

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, 2020	Dec. 31, 2019
31. Stock-Based Compensation
Weighted average fair value per option	$ 3.58	$ 2.41
Expected term	5 years	6 years
Risk-free interest rate	1.33%	1.82%
Expected dividend yield	4.09%	5.10%
Expected volatility	14.10%	14.32%

Stock-based Compensatin (Stock

Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Total Options, Number of Options
Total Options: Number of Options, Exercised	(420,000)	(2,570,000)
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Granted	$ 3.58	$ 2.41
Stock option plan, Additional information
Non-Vested options: Unrecognized compensation	$ 2	$ 2
Non-vested options: Weighted average recognition period	3 years	2 years
Vested Options: Weighted average remaining term	6 years	6 years
Vested Options: Aggregate intrinsic value	$ 12	$ 11
Vested Options: Fair value	$ 2	$ 2
Employee Stock Option Plan
Total Options, Number of Options
Total Options: Number of Options, Outstanding, Beginning Balance	2,286,550
Granted	501,900
Total Options: Number of Options, Exercised	(417,968)
Total Options: Number of Options, Forfeited	(102,700)
Total Options: Number of Options, Outstanding, Ending Balance	2,267,782	2,286,550
Total Options: Number of Options, Options exercisable	973,932
Total Options, Weighted average exercise price per share
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 43.31
Total Options: Weighted average exercise price per share, Granted	60.03
Total Options: Weighted average exercise price per share, Exercised	44.74
Total Options: Weighted average exercise price per share, Forfeited	45.94
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance	46.62	$ 43.31
Total Options: Weighted average exercise price per share, Options exercisable	$ 42.08
Non-Vested Options, Number of Options
Non-Vested Options: Number of Options, Outstanding, Beginning Balance	1,549,025
Granted	501,900
Non-Vested Options: Number of Options, Vested	654,375
Non-Vested Options: Number of options, Forfeited	(102,700)
Non-Vested Options: Number of Options, Ending Balance	1,293,850	1,549,025
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 2.22
Non-Vested Options: Weighted average exercise price per share, Granted	3.58
Non-Vested Options: Weighted average exercise price per share, Vested	2.32
Non-Vested Options: Weighted average exercise price per share, Forteited	2.33
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance	$ 2.69	$ 2.22

Stock-based Compensation (Defer

Stock-based Compensation (Deferred Share Unit Plans) (Details) - DSU Plan - Deferred Share Unit Plans	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	704,597
Share Unit Plans: Granted including DRIP | shares	84,790
Share Unit Plans: Exercised | shares	(127,389)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	661,998
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 34.69
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	47.74
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	30.5
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 37.17
Director
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	531,454
Share Unit Plans: Granted including DRIP | shares	93,008
Share Unit Plans: Exercised | shares	(33,338)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	591,124
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 39.96
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	51.65
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	41.89
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 41.69

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, 2020	Dec. 31, 2019
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	1,381,100
Share Unit Plans: Granted including DRIP	271,185
Share Unit Plans: Exercised	(445,066)
Share Unit Plans: Forfeited	(80,690)
Share Unit Plans: Outstanding and exercisable, Ending Balance	1,126,529
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 45.37
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	53.14
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	45.41
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	46.25
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 47.16
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 68	$ 88

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, 2020	Dec. 31, 2019
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 10
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	0
Share Unit Plans: Granted including DRIP	171,908
Share Unit Plans: Exercised	0
Share Unit Plans: Forfeited	(5,633)
Share Unit Plans: Outstanding and exercisable, Ending Balance	166,275
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 0
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	54.62
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	0
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	54.62
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 54.62
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value		$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) - NSPML - NSPML - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity [Line Items]
Equity Method Investment, Underlying Equity in Net Assets	$ 547	$ 554
Maximum exposure to losss	$ 16	$ 23

Supplemental Financial Inform_3

Supplemental Financial Information (Narrative) (Details) $ in Millions	Jun. 16, 2016USD ($)
U.S. Notes | Emera US Finance LP | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Proceeds from Issuance of Unsecured Debt	$ 3,250

Supplemental Financial Inform_4

Supplemental Financial Information (Condensed Consolidated Statements of Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Condensed Income Statements, Captions [Line Items]
Total operating revenues	$ 5,506	$ 6,111
Total operating expenses	4,359	4,768
Income (loss) from equity investments and subsidiaries	149	154
Other income (expenses), net	708	12
Interest expense, net	679	738
Income (loss) before provision for income taxes	1,325	771
Income tax expense (recovery)	341	61
Net income	984	710
Non-controlling interest in subsidiaries	1	2
Preferred stock dividends	45	45
Net income (loss) attributable to common shareholders	937.6	662.8
Comprehensive Income (loss) of Emera Incorporated	809	465
Eliminations
Condensed Income Statements, Captions [Line Items]
Total operating revenues	(19)	(43)
Total operating expenses	(20)	(42)
Income (loss) from equity investments and subsidiaries	(1,048)	(752)
Other income (expenses), net	0	(20)
Interest expense, net	0	0
Income (loss) before provision for income taxes	(1,047)	(773)
Income tax expense (recovery)	1	0
Net income	(1,048)	(773)
Non-controlling interest in subsidiaries	1	2
Preferred stock dividends	(1)	(22)
Net income (loss) attributable to common shareholders	(1,048)	(753)
Comprehensive Income (loss) of Emera Incorporated	(867)	(321)
Emera Inc. | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues	(1)	0
Total operating expenses	51	31
Income (loss) from equity investments and subsidiaries	1,049	753
Other income (expenses), net	20	21
Interest expense, net	48	75
Income (loss) before provision for income taxes	969	668
Income tax expense (recovery)	(14)	(40)
Net income	983	708
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	45	45
Net income (loss) attributable to common shareholders	938	663
Comprehensive Income (loss) of Emera Incorporated	809	465
Subsidiary Issuer | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues	0	0
Total operating expenses	0	0
Income (loss) from equity investments and subsidiaries	0	0
Other income (expenses), net	0	0
Interest expense, net	(37)	(40)
Income (loss) before provision for income taxes	37	40
Income tax expense (recovery)	(1)	11
Net income	38	29
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	38	29
Comprehensive Income (loss) of Emera Incorporated	35	14
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues	3,456	4,125
Total operating expenses	2,640	3,084
Income (loss) from equity investments and subsidiaries	1	2
Other income (expenses), net	687	22
Interest expense, net	448	481
Income (loss) before provision for income taxes	1,056	584
Income tax expense (recovery)	348	60
Net income	708	524
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	19
Net income (loss) attributable to common shareholders	708	505
Comprehensive Income (loss) of Emera Incorporated	575	102
Non-guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues	2,070	2,029
Total operating expenses	1,688	1,695
Income (loss) from equity investments and subsidiaries	147	151
Other income (expenses), net	1	(11)
Interest expense, net	220	222
Income (loss) before provision for income taxes	310	252
Income tax expense (recovery)	7	30
Net income	303	222
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	1	3
Net income (loss) attributable to common shareholders	302	219
Comprehensive Income (loss) of Emera Incorporated	$ 257	$ 205

Supplemental Financial Inform_5

Supplemental Financial Information (Condensed Consolidated Statement of Financial Position) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Assets
Total current assets	$ 2,178	$ 2,486
Property, plant and equipment	19,535	18,167
Other assets
Regulatory assets (note 7)	1,419	1,431
Goodwill	5,720	5,835	$ 6,313
Other long-term assets	2,382	3,923
Total other assets	9,521	11,189
Total assets	31,234	31,842
Liabilities and Equity
Total current liabilities	4,875	4,166
Long-term liabilities
Long-term debt	12,339	13,679
Deferred income taxes	1,629	1,285
Regulatory liabilities	1,832	1,886
Equity
Total Emera Incorporated equity	9,204	8,566
Non-controlling interest in subsidiaries	34	35
Total equity	9,238	8,601	$ 8,358
Total liabilities and equity	31,234	31,842
Eliminations
Assets
Total current assets	(179)	(294)
Property, plant and equipment	(6)	5
Other assets
Regulatory assets (note 7)	0	0
Goodwill	0	0
Other long-term assets	(18,115)	(16,955)
Total other assets	(18,115)	(16,955)
Total assets	(18,300)	(17,244)
Liabilities and Equity
Total current liabilities	(2,547)	(1,079)
Long-term liabilities
Long-term debt	0	(6,209)
Deferred income taxes	14	0
Regulatory liabilities	0	0
Equity
Total Emera Incorporated equity	(10,225)	(9,949)
Non-controlling interest in subsidiaries	13	14
Total equity	(10,212)	(9,935)
Total liabilities and equity	(18,300)	(17,244)
Emera Inc. | Reportable Legal Entities
Assets
Total current assets	121	96
Property, plant and equipment	21	23
Other assets
Regulatory assets (note 7)	0	0
Goodwill	3	3
Other long-term assets	12,522	11,994
Total other assets	12,525	11,997
Total assets	12,667	12,116
Liabilities and Equity
Total current liabilities	554	542
Long-term liabilities
Long-term debt	2,210	2,978
Deferred income taxes	0	0
Regulatory liabilities	0	0
Equity
Total Emera Incorporated equity	9,203	8,558
Non-controlling interest in subsidiaries	0	0
Total equity	9,203	8,558
Total liabilities and equity	12,667	12,116
Subsidiary Issuer | Reportable Legal Entities
Assets
Total current assets	10	27
Property, plant and equipment	0	0
Other assets
Regulatory assets (note 7)	0	0
Goodwill	0	0
Other long-term assets	4,591	3,856
Total other assets	4,591	3,856
Total assets	4,601	3,883
Liabilities and Equity
Total current liabilities	2,024	12
Long-term liabilities
Long-term debt	2,513	3,534
Deferred income taxes	2	3
Regulatory liabilities	0	0
Equity
Total Emera Incorporated equity	62	334
Non-controlling interest in subsidiaries	0	0
Total equity	62	334
Total liabilities and equity	4,601	3,883
Guarantor Subsidiaries | Reportable Legal Entities
Assets
Total current assets	1,216	1,486
Property, plant and equipment	14,356	13,099
Other assets
Regulatory assets (note 7)	520	519
Goodwill	5,648	5,762
Other long-term assets	130	1,739
Total other assets	6,298	8,020
Total assets	21,870	22,605
Liabilities and Equity
Total current liabilities	4,121	3,699
Long-term liabilities
Long-term debt	4,026	8,829
Deferred income taxes	852	515
Regulatory liabilities	1,747	1,793
Equity
Total Emera Incorporated equity	6,614	6,072
Non-controlling interest in subsidiaries	0	0
Total equity	6,614	6,072
Total liabilities and equity	21,870	22,605
Non-guarantor Subsidiaries | Reportable Legal Entities
Assets
Total current assets	1,010	1,171
Property, plant and equipment	5,164	5,040
Other assets
Regulatory assets (note 7)	899	912
Goodwill	69	70
Other long-term assets	3,254	3,289
Total other assets	4,222	4,271
Total assets	10,396	10,482
Liabilities and Equity
Total current liabilities	723	992
Long-term liabilities
Long-term debt	3,590	4,547
Deferred income taxes	761	767
Regulatory liabilities	85	93
Equity
Total Emera Incorporated equity	3,550	3,551
Non-controlling interest in subsidiaries	21	21
Total equity	3,571	3,572
Total liabilities and equity	$ 10,396	$ 10,482

Supplemental Financial Inform_6

Supplemental Financial Information (Condensed Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net cash provided by (used in) operating activities	$ 1,637	$ 1,525
Investing activities
Additions to property, plant and equipment	(2,623)	(2,495)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(3)
Proceeds on disposal of assets significant influence and held-for-trading common shares	1,401	875
Other investing activities	(2)	3
Other investing activities		6
Net cash provided by (used in) investing activities	(1,224)	(1,617)
Financing activities
Change in short-term debt, net	96	413
Proceeds from long-term debt, net of issuance costs	428	1,066
Retirement of long-term debt	(513)	(1,103)
Net repayments under committed credit facilities	(203)	(118)
Issuance of common and preferred stock	285	203
Dividends paid	(454)	(423)
Other financing activities	(11)	(24)
Net cash provided by (used in) financing activities	(372)	14
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	(61)	(20)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	(20)	(98)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	274	372
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	254	274
Cash, cash equivalents, and restricted cash, beginning of year	274	372
Cash, cash equivalents, and restricted cash, end of year		274
Eliminations
Operating activities
Net cash provided by (used in) operating activities	(527)	(20)
Investing activities
Additions to property, plant and equipment	0	0
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0
Proceeds on disposal of assets significant influence and held-for-trading common shares	0	0
Other investing activities	(795)
Other investing activities		(960)
Net cash provided by (used in) investing activities	(795)	(960)
Financing activities
Change in short-term debt, net	0	0
Proceeds from long-term debt, net of issuance costs	(174)	520
Retirement of long-term debt	279	17
Net repayments under committed credit facilities	28	(28)
Issuance of common and preferred stock	191	562
Dividends paid	525	157
Other financing activities	473	(248)
Net cash provided by (used in) financing activities	1,322	980
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	0	0
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	0	0
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	0
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	0	0
Cash, cash equivalents, and restricted cash, beginning of year	0	0
Cash, cash equivalents, and restricted cash, end of year		0
Emera Inc. | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities	365	133
Investing activities
Additions to property, plant and equipment	(1)	(2)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0
Proceeds on disposal of assets significant influence and held-for-trading common shares	0	0
Other investing activities	(118)
Other investing activities		(402)
Net cash provided by (used in) investing activities	(119)	(404)
Financing activities
Change in short-term debt, net	(6)	399
Proceeds from long-term debt, net of issuance costs	0	0
Retirement of long-term debt	0	(225)
Net repayments under committed credit facilities	(82)	146
Issuance of common and preferred stock	285	203
Dividends paid	(454)	(423)
Other financing activities	(18)	(1)
Net cash provided by (used in) financing activities	(275)	99
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	18	147
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	(11)	(25)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	1
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	(10)	1
Cash, cash equivalents, and restricted cash, beginning of year	(5)	20
Cash, cash equivalents, and restricted cash, end of year		(5)
Subsidiary Issuer | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities	36	33
Investing activities
Additions to property, plant and equipment	0	0
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0
Proceeds on disposal of assets significant influence and held-for-trading common shares	0	0
Other investing activities	265
Other investing activities		595
Net cash provided by (used in) investing activities	265	595
Financing activities
Change in short-term debt, net	0	0
Proceeds from long-term debt, net of issuance costs	0	0
Retirement of long-term debt	0	(664)
Net repayments under committed credit facilities	0	0
Issuance of common and preferred stock	(241)	0
Dividends paid	(66)	0
Other financing activities	(4)	0
Net cash provided by (used in) financing activities	(311)	(664)
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	(8)	(3)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	(18)	(39)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	19
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	1	19
Cash, cash equivalents, and restricted cash, beginning of year	19	58
Cash, cash equivalents, and restricted cash, end of year		19
Guarantor Subsidiaries | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities	1,277	1,100
Investing activities
Additions to property, plant and equipment	(2,150)	(1,973)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(3)
Proceeds on disposal of assets significant influence and held-for-trading common shares	1,401	818
Other investing activities	546
Other investing activities		774
Net cash provided by (used in) investing activities	(203)	(384)
Financing activities
Change in short-term debt, net	107	(9)
Proceeds from long-term debt, net of issuance costs	173	(6)
Retirement of long-term debt	(705)	(65)
Net repayments under committed credit facilities	8	(11)
Issuance of common and preferred stock	(3)	(620)
Dividends paid	(80)	(19)
Other financing activities	(494)	138
Net cash provided by (used in) financing activities	(994)	(592)
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	(70)	(141)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	10	(17)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	87
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	97	87
Cash, cash equivalents, and restricted cash, beginning of year	87	104
Cash, cash equivalents, and restricted cash, end of year		87
Non-guarantor Subsidiaries | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities	486	279
Investing activities
Additions to property, plant and equipment	(472)	(520)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0
Proceeds on disposal of assets significant influence and held-for-trading common shares	0	57
Other investing activities	100
Other investing activities		(1)
Net cash provided by (used in) investing activities	(372)	(464)
Financing activities
Change in short-term debt, net	(5)	23
Proceeds from long-term debt, net of issuance costs	429	552
Retirement of long-term debt	(87)	(166)
Net repayments under committed credit facilities	(157)	(225)
Issuance of common and preferred stock	53	58
Dividends paid	(379)	(138)
Other financing activities	32	87
Net cash provided by (used in) financing activities	(114)	191
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale	(1)	(23)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale	(1)	(17)
Cash, cash equivalents, restricted cash, and assets held for sale, beginning of year	167
Cash, cash equivalents, restricted cash and assets held for sale, end of the year	166	167
Cash, cash equivalents, and restricted cash, beginning of year	$ 173	190
Cash, cash equivalents, and restricted cash, end of year		$ 173