Emera (EMRAF) 40-F 30 Mar 20 2019 FY Annual report (Canada) Financial data

Cover

Cover	12 Months Ended
	Dec. 31, 2019shares
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, 2019
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Current Fiscal Year End Date	--12-31
Entity File Number	000-54516
Entity Registrant Name	EMERA INCORPORATED
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	428-6096
City Area Code	902
Local Phone Number	428-6096
Entity Listings [Line Items]
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Trading Symbol	EMA
Annual Information Form	true
Audited Annual Financial Statements	true
Common Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	242,478,188
Series A Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	3,864,636
Series B Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	2,135,364
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, 2019	Dec. 31, 2018
Operating revenues
Total operating revenues (note 6)	$ 6,111	$ 6,524
Operating expenses
Operating, maintenance and general	1,464	1,580
Provincial, state, and municipal taxes	342	340
Depreciation and amortization	903	916
GBPC impairment charge (note 21)	34	0
Total operating expenses	4,768	5,126
Income from operations	1,343	1,398
Income from equity investments (note 7)	154	154
Other income (expenses), net	12	(23)
Interest expense, net	738	713
Income before provision for income taxes	771	816
Income tax expense (note 8)	61	69
Net income	710	747
Non-controlling interest in subsidiaries	2	1
Preferred stock dividends	45	36
Net income attributable to common shareholders	$ 662.8	$ 709.6
Weighted average shares of common stock outstanding (in millions) (note 10)
Basic	239.9	233
Diluted	240.5	233.5
Earnings per common share (note 10)
Basic	$ 2.76	$ 3.05
Diluted	2.76	3.04
Dividends per common share declared	$ 2.375	$ 2.2825
Regulated | Electric
Operating revenues
Total operating revenues (note 6)	$ 4,769	$ 4,852
Operating expenses
Fuel for generation and purchased power (notes 16 and 18)	1,609	1,677
Regulated | Gas
Operating revenues
Total operating revenues (note 6)	1,081	1,044
Operating expenses
Fuel for generation and purchased power (notes 16 and 18)	350	388
Non-Regulated
Operating revenues
Total operating revenues (note 6)	261	628
Non-Regulated | Electric
Operating expenses
Fuel for generation and purchased power (notes 16 and 18)	$ 66	$ 225

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Consolidated Statements of Comprehensive Income
Net income		$ 710	$ 747
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment	[1],[2]	(402)	627
Unrealized gains (losses) on net investment hedges		78	(122)
Cash flow hedges
Net derivative gains (losses)		3	2
Less: reclassification adjustment for losses (gains) included in income		3	(6)
Net effects of cash flow hedges		6	(4)
Unrealized gains on available-for-sale investment
Unrealized gain (loss) arising during the period		0	0
Less: reclassification adjustment for (gains) recognized in income		0	(4)
Net unrealized holding gains (losses)		0	(4)
Net change in unrecognized pension and post-retirement benefit obligation	[3]	74	9
Other comprehensive income (loss)	[4]	(244)	506
Comprehensive income (loss)		466	1,253
Comprehensive income (loss) attributable to non-controlling interest		1	4
Comprehensive Income of Emera Incorporated		$ 465	$ 1,249
[1]	1) 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.
[2]	2) Net of tax expense of $1 million (2018 - $9 million tax recovery) for the year ended December 31, 2019.
[3]	3) Net of tax expense of $9 million (2018 - $2 million tax recovery) for the year ended December 31, 2019.
[4]	4) Net of tax expense of $10 million (2018 - $11 million tax recovery) for the year ended December 31, 2019.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Consolidated Statements of Comprehensive Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax		$ 1,200
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax		$ 1		$ (9)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	$ 9		$ (2)
Other Comprehensive Income (Loss), Tax, Total	$ 10		$ (11)

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 222	$ 316
Restricted cash (note 31)	51	56
Inventory (note 12)	467	474
Derivative instruments (notes 13 and 14)	54	148
Regulatory assets (note 15)	121	165
Receivables and other current assets (note 17)	1,486	1,620
Assets held for sale (note 4)	85	53
Total current assets	2,486	2,832
Property, plant and equipment, net of accumulated depreciation and amortization of $8,295 and $8,567 respectively (note 19)	18,167	18,712
Other assets
Deferred income taxes	186	175
Derivative instruments (notes 13 and 14)	33	19
Regulatory assets (note 15)	1,431	1,404
Net investment in direct financing lease (note 18)	473	475
Goodwill (note 21)	5,835	6,313
Other long term assets	300	291
Assets held for sale (note 4)	1,619	777
Total other assets	11,189	10,770
Total assets	31,842	32,314
Current liabilities
Short-term debt (note 22)	1,537	1,186
Current portion of long-term debt (note 24)	501	1,119
Accounts payable	1,118	1,289
Derivative instruments (notes 13 and 14)	268	260
Regulatory liabilities (note 15)	295	251
Other current liabilities (note 23)	333	428
Liabilities associated with assets held for sale (note 4)	114	20
Total current liabilities	4,166	4,553
Long-term liabilities
Long-term debt (note 24)	13,679	14,292
Deferred income taxes (note 8)	1,285	1,320
Derivative instruments (notes 13 and 14)	102	105
Regulatory liabilities (note 15)	1,886	2,359
Pension and post-retirement liabilities (note 20)	460	641
Other long-term liabilities (note 7 and 25)	764	684
Long-term liabilities associated with assets held for sale (note 4)	899	2
Total long-term liabilities	19,075	19,403
Equity
Common stock (note 9)	6,216	5,816
Cumulative preferred stock (note 27)	1,004	1,004
Contributed surplus	78	84
Accumulated other comprehensive income (note 11)	95	338
Retained earnings	1,173	1,075
Total Emera Incorporated equity	8,566	8,317
Non-controlling interest in subsidiaries (note 28)	35	41
Total equity	8,601	8,358
Total liabilities and equity	31,842	32,314
Commitments and contingencies (note 26)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Consolidated Balance Sheets
Accumulated depreciation and amortization on property, plant and equipment	$ 8,295	$ 8,567

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating activities
Net income	$ 710	$ 747
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	911	928
Income from equity investments, net of dividends	(83)	(75)
Allowance for equity funds used during construction	(21)	(19)
Deferred income taxes, net	125	185
Net change in pension and post-retirement obligations	(17)	11
Regulated fuel adjustment mechanism	(46)	(16)
Net changes in fair value of derivative instruments	(39)	55
Net change in regulatory assets and liabilities	44	51
Net change in capitalized transportation capacity	(55)	(105)
Impairment charge (note 21)	34	0
Other operating activities, net	35	44
Changes in non-cash working capital (note 29)	(73)	(116)
Net cash provided by operating activities	1,525	1,690
Investing activities
Additions to property, plant and equipment	(2,495)	(2,162)
Net purchase of investments subject to significant influence, inclusive of acquisition costs	(3)	(49)
Proceeds from dispositions (note 4)	875	0
Other investing activities	6	21
Net cash used in investing activities	(1,617)	(2,190)
Financing activities
Change in short-term debt, net	413	99
Proceeds from short-term debt with maturities greater than 90 days	0	129
Repayment of short-term debt with maturities greater than 90 days	0	(390)
Proceeds from long-term debt, net of issuance costs	1,066	1,055
Retirement of long-term debt	(1,103)	(757)
Net borrowings (repayments) under committed credit facilities	(118)	321
Issuance of common stock, net of issuance costs	203	10
Issuance of preferred stock, net of issuance costs (note 27)	0	291
Dividends on common stock	(378)	(346)
Dividends on preferred stock	(45)	(36)
Other financing activities	(24)	(32)
Net cash provided by financing activities	14	344
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(20)	25
Net increase (decrease) in cash, cash equivalents, and restricted cash	(98)	(131)
Cash, cash equivalents, and restricted cash, beginning of year	372	503
Cash, cash equivalents, and restricted cash, end of year	274	372
Cash, cash equivalents, restricted cash and assets held for sale consists of:
Cash, cash equivalents, and restricted cash	$ 372	$ 503

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total		Common Stock	Preferred Stock	Contributed Surplus	Accumulated Other Comprehensive Income (Loss)	[1]	Retained Earnings	Non-Controlling Interest
Beginning Balance at Dec. 31, 2017	$ 7,204		$ 5,601	$ 709	$ 76	$ (165)		$ 891	$ 92
Net income from operations of Emera Incorporated	747		0	0	0	0		746	1
Other comprehensive income (loss), net of tax	506	[2]	0	0	0	503		0	3
Dividends declared on preferred stock (note 27)	(36)		0	0	0	0		(36)	0
Dividends declared on common stock	(528)		0	0	0	0		(528)	0
Common stock issued under purchase plan	191		191	0	0	0		0	0
Senior management stock options exercised			1
Issuance of common stock, net of after-tax issuance costs	295		0	295	0	0		0	0
Acquisition of non-controlling of ICD Utilities Limited ("ICDU")	(25)		(22)	0	(6)	0		0	(53)
Other	4		2	0	2	0		2	(2)
Ending 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 income (loss), net of tax	(244)	[2]	0	0	0	(243)		0	(1)
Dividends declared on preferred stock (note 27)	(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
Senior management stock options exercised	97		104	0	(7)	0		0	0
Issuance of common stock, net of after-tax issuance costs	99		99	0	0	0		0	0
Issuance of preferred shares of GBPC, net of issuance costs (note 28)	14		0	0	0	0		0	14
Redemption of preferred shares of GBPC (note 28)	(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
[1]	(1) Accumulated Other Comprehensive Income (Loss) ("AOCI") ("AOCL")
[2]	4) Net of tax expense of $10 million (2018 - $11 million tax recovery) for the year ended December 31, 2019.

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Consolidated Statements of Changes in Equity
Other comprehensive loss, tax expense/recovery	$ 10	$ (11)
Dividends per common share declared	$ 2.375	$ 2.2825

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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. Effective January 1, 2019, Emera revised its reportable segment s to align with strategic priorities and internal governance. These new reporting segments align with how the Company assesses financial performance and makes decisions about resource allocations. At December 31, 2019, Emera’s reportable segments include the following:  Florida Electric Utility , which consists of Tampa Electric , a vertically integrated regulated electric utility, serving approximately 779,000 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 523,000 customers ; and  Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting 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 and forecasted to be generating full power in the second half of 2020. 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 i sland of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and  a 49.5 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 en ergy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, which is forecasted to be in 2020.  Other Electric Utilities , which includes:  Emera Maine , a regulated electric transmission and distribution utility, s erving approximately 159,000 customers in the state of Maine . On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in early 2020 , subject to approval of the Maine Public Utilities Commission (“MPUC”) . Refer to note 4 for further details; and  Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:  The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated elec tric 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 18,000 customers. On September 1, 2019, Grand Bahama Island was struck by Hurricane Dorian, causing significant damage. Refer to note 15 and 21 for further details ;  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 31,000 customers ; and  a 19.1 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.  Gas Utilities and Infrastructure which includes:  Peoples Gas System (“PGS”), a regulated gas distribution utility, serving approximately 406,000 customers across Florida;  New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 534,000 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 del ivering 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 ; and  a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400 -kilometre pipeline, which transports natural gas throughout markets in Atlantic Canada and the northeastern United States. At December 31, 2019, Emera’s investments in other energy-related non-r egulated companies ( included within the Other reportable segment) include the following:  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 deduc tible 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; an d  other investments . In 2019, the Company completed the sale of assets previously included in the Other segment, including the sale of Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services (“EUS”) equipment and inventory . Refer to note 4 for further details of these transactions. 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 31 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. 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. Intercompany balances and intercompany 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-regul ated 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 n ature 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. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates. 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 the costs of providing the regulated products or services and provide a reasonable rate of retu rn on the equity invested or assets, as applicable (refer to n ote 15 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 bala nce 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 Stat es 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 balance 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 applicable 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 r ecognized on an accrual basis 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 bas is, 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 th e reporting period is calculated 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, weat her, line losses and inter-period 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, which 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 deli vered 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 expected 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 margin is comprised of Emera Energy’s corresponding 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 bas is, 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, which is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an aucti on 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, with the exception of gr oss 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 the 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 ass ociated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated 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 the 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 impli cit 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 lease 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 cost 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 l ease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value o f 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 for all leases. Franchise Fees and Gross Receipts Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts include d in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are includ ed 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 gros s basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated 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 construction. The cost of additions, including betterments and r eplacements 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 included in income as the dispositions occur. The cost of property, plant an d equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and executive 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 the overall life of the related as sets are expensed. When a major mainten ance 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 o f depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and equipment” consist primarily of computer software, land rights and nami ng rights with definite lives. 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 met hod which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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 estimated fair values of 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 f or the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to an annual assessment for impairmen t at the reporting unit level. Refer to note 21 for further detail. Income Taxes and Investment Tax Credits Emera rec ognizes 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 betwee n 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. Emera recognizes the effect of income tax posi tions 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-looking information, and the likelihood that deferred tax assets will be recovered from fu ture 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 determines that it is likely that some or all of a deferred income tax asset will not be r ealized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded 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, NMGC and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by regulatory practices. Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income ta x liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 8 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 i nstruments are considered 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 the 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 physic al delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contra cts 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 o f 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 reporting 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 e xception 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. Mana gement believes any gains or losses resulting from settlement of these derivatives 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 v alue normally recorded in net income of the period, unless deferred as a re sult of regulatory accounting. The Company has 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, inventory and property, operating maintenance and general and plant and equipment, depending on the nature of the i tem being economi cally hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in t he 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 refl ected 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 coll ateral are recognized in “Accounts payable”. Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. T here were no short-term investments at December 31, 2019 ( 2018 - $ 43 million with a n effective interest rate of 2.0 per cent). Receivables and Allowance for Doubtful Accounts 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 customers. Credit assessments may be conducted on new customers. Deposits are requested accounts as r equired. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and t he charact eristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adeq uate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectib le. 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 rates. 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. As a result of the damage caused by Hurricane Dorian, the Company completed an asset impairment analysis in Q4 2019. P roperty, plant and equipment and inventory with a book value of a pproximately $ 18 million USD was determined to be impaired and was reclassified as a regulatory asset. GBPC recorded an offsetting insurance receivable of $ 15 million USD against this regulatory asset. It is anticipated that the regulatory asset balance of $ 3 million USD remaining at December 31, 2019 will be recovered through insurance. Refer to note 15 for further details. No impairment was recorded in 2018 . Goodwill Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. 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 . En tities assessing goodwill for impairment have 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, macroeconom ic conditions, industry and market considerations and overall financial performance. If an entity 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 an entity choos es 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 its 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 income approach is a pplied 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 entity’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 average cost of capital of comparable companies. When using the market approach, management estimates fair value based on compar

Change in Accounting Policy

Change in Accounting Policy	12 Months Ended
	Dec. 31, 2019
2. Change in Accounting Policy
Change in Accounting Policy	2 . C HANGE IN ACCOUNTING POLICY

Future Accounting Pronouncement

Future Accounting Pronouncements	12 Months Ended
	Dec. 31, 2019
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 have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or have an insignificant impact on the consolidated financial statements. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments . T he 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, including 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 experien ce, 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 Company adopted ASU 2016-13 effective January 1, 2020, with no significant changes to accounting and disclosure identified related to the adoption of the standard. Simplifying 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 related to the approach for intraperiod tax allocation, 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 will be effective for annual reporting periods, including interim reporting within those periods, beginnin g after December 15, 2020, with early adoption permitted. The standard will be applied on both a prospe ctive and retrospective basis. The Company is currently evaluatin g the impact of adoption of the standard on its consolidated financial statements .

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2019
4. Dispositions
Dispositions	4 . DISPOSITIONS Held for sale Emera Maine On March 25, 2019, Emera announced the sale of Emera Maine for a total enterprise value of approximately $ 1.3 billion USD including cash proceeds of $ 959 million USD, transferred debt and a working capital adjustment on close. The transaction is expected t o close in early 2020 , subject to the approval of the MPUC. All other required regulatory approvals have been received. A material gain on the sale is expected to be recognized in earnings at closing. Emera Maine’s assets and liabilities a re classified as held for sale and ar e measured at the lower of their carrying value or fair value less costs to sell. The measurement did not resu lt in a fair value adjustment. The Company will continue to record depreciation on these assets, through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $ 39 million ( $ 2 9 million USD) has been recorded on these assets from March 25, 2019, the date they were classified as held for sale to December 3 1 , 2019. Details of Emera Maine's assets and liabilities classified as held for sale are as follows: As at December 31 millions of Canadian dollars 2019 Regulatory assets $ 16 Receivables and other current assets 69 Current assets held for sale 85 Property, plant and equipment 1,293 Goodwill 148 Regulatory assets 122 Other long-term assets 56 Long-term assets held for sale 1,619 Total assets held for sale $ 1,704 Regulatory liabilities $ 11 Accounts payable and other current liabilities 103 Current liabilities associated with assets held for sale 114 Long-term debt 467 Deferred income taxes 204 Regulatory liabilities 145 Other long-term liabilities 83 Long-term liabilities associated with assets held for sale 899 Total liabilities associated with assets held for sale $ 1,013 Dispositions New England Gas Generation On March 29, 2019, Emera completed the sale of its three NEGG facilities for cash proceeds of $ 799 million ($ 598 million USD) including a working capital adjustment. The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceas ed depreciation of these assets on November 27, 2018. The NEGG facilities were included within the Company’s Other reportable segment . The earnings impact of this sale transaction was immaterial. Details of NEGG's assets and liabilities classified as held for sale at December 31, 2018 are as follows: As at December 31 millions of Canadian dollars 2018 Receivables and other current assets $ 40 Inventory 13 Current assets held for sale 53 Property, plant and equipment 777 Long-term assets held for sale 777 Total assets held for sale $ 830 Accounts payable and other current liabilities $ 20 Current liabilities associated with assets held for sale 20 Other long-term liabilities 2 Long-term liabilities associated with assets held for sale 2 Total liabilities associated with assets held for sale $ 22 Other On March 5, 2019, the Company completed the sale of its Bayside facility for cash proceeds of $ 46 million. The Bayside facilit y w as included within the Company’s Other reportable segment . The earnings impact of this sale transaction was immaterial. O n December 20, 2019, Emera completed the sale of EUS assets . EUS ceased operations on September 30, 2019 , and t here was no material impact on Emera’s balance sheet or earnings as a result of this transaction .

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2019
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. Effective January 1, 2019, Emera revised its reportable segments to align with strategic prio rities and internal governance. These new reporting segments align with how the Company assesses financial performance and makes decisions about resource allocations. All comparative segment financial information has been restated with no impact to reported consolidated results. The five new 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, 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 AFUDC - debt and equity 20 6 5 2 - - 33 Depreciation and amortization 445 231 107 109 11 - 903 Interest expense, net 154 142 52 59 331 - 738 Internally allocated interest (2) - - - 14 (14) - - Income from equity investments - 91 5 22 36 - 154 Income tax expense (recovery) 79 (10) 11 48 (67) - 61 Operating, maintenance and general ("OM&G") 554 313 195 319 130 (47) 1,464 GBPC impairment charge - - 34 - - - 34 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. 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, 2018 Operating revenues from external customers (1) $ 2,670 $ 1,437 $ 745 $ 1,062 $ 610 $ - $ 6,524 Inter-segment revenues (1) 9 3 - 36 51 (99) - Total operating revenues 2,679 1,440 745 1,098 661 (99) 6,524 AFUDC - debt and equity 20 6 3 1 - - 30 Depreciation and amortization 405 219 114 129 49 - 916 Interest expense, net 132 139 48 55 339 - 713 Internally allocated interest (2) - - - 14 (14) - - Income from equity investments - 87 6 22 39 - 154 Income tax expense (recovery) 85 8 9 47 (80) - 69 OM&G 667 286 188 295 206 (62) 1,580 Net income (loss) attributable to common shareholders 381 218 85 135 (109) - 710 Capital expenditures 1,217 345 187 330 72 - 2,151 As at December 31, 2018 Total assets 15,997 6,275 3,094 5,404 2,653 (1,109) (3) 32,314 Investments subject to significant influence - 1,079 77 155 5 - 1,316 Goodwill 4,774 - 260 1,279 - - 6,313 (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 2019 2018 Canada $ 1,497 $ 1,520 United States 4,140 4,537 Barbados 320 319 The Bahamas 112 121 Dominica 42 27 $ 6,111 $ 6,524 (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 2019 2018 Canada $ 4,248 $ 4,128 United States (1) 13,095 13,739 Barbados 462 446 The Bahamas 282 315 Dominica 80 84 $ 18,167 $ 18,712 (1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to note 4 for further details.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
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, 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. 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, 2018 Regulated Electric Revenue Residential $ 1,384 $ 731 $ 261 $ - $ - $ - $ 2,376 Commercial 755 405 350 - - - 1,510 Industrial 209 233 46 - - - 488 Other electric and regulatory deferrals 312 43 16 - - - 371 Other (1) 19 28 72 - - (12) 107 Regulated electric revenue 2,679 1,440 745 - - (12) 4,852 Gas Revenue Residential - - - 492 - - 492 Commercial - - - 291 - - 291 Industrial - - - 49 - - 49 Finance income (2)(3) - - - 57 - - 57 Other - - - 191 - (36) 155 Regulated gas revenue - - - 1,080 - (36) 1,044 Non-Regulated Marketing and trading margin (4) - - - - 115 - 115 Energy sales (4) - - - - 309 (16) 293 Capacity - - - - 136 - 136 Other - - - 18 47 (35) 30 Mark-to-market (3) - - - - 54 - 54 Non-regulated revenue - - - 18 661 (51) 628 Total operating revenues $ 2,679 $ 1,440 $ 745 $ 1,098 $ 661 $ (99) $ 6,524 (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, 2019 , the aggregate amount of the transaction price allocated to remai ning performance obligations was $ 347 million ( 2018 – $ 370 million) . As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes re venue 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 2033 .

Investments Subject to Signific

Investments Subject to Significant Influence and Equity Income	12 Months Ended
	Dec. 31, 2019
7. Investments Subject to Significant Influence and Equity Earnings
Investments Subject to Significant Influence and Equity Earnings	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 2019 2018 2019 2018 2019 LIL (1) $ 579 $ 534 $ 45 $ 42 49.5 NSPML 554 545 46 45 100.0 M&NP (2) 138 155 22 22 12.9 Lucelec (2) 41 42 3 3 19.1 Bear Swamp (3) - - 35 38 50.0 Other Investments - 40 3 4 $ 1,312 $ 1,316 $ 154 $ 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 a result of a $179 million distribution received in 2015. Bear Swamp's credit investment balance of $137 million (2018 - $172 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Equity investments include a $ 14 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 31 ). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2019 2018 Balance Sheets Current assets $ 69 $ 86 Property, plant and equipment 1,671 1,690 Regulatory assets 177 108 Non-current assets 32 32 Total assets $ 1,949 $ 1,916 Current liabilities $ 23 $ 21 Long-term debt (1) 1,288 1,288 Non-current liabilities 84 62 Equity 554 545 Total liabilities and equity $ 1,949 $ 1,916 (1) The project debt has been guaranteed by the Government of Canada.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
8. Income Taxes
Income Taxes	8 . INCOME TAXES The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and Nova Scotia and New Brunswick provincial statutory income tax rate for the following reasons: millions of Canadian dollars 2019 2018 Income before provision for income taxes $ 771 $ 816 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 239 253 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (66) (59) Foreign tax rate variance (49) (55) Amortization of deferred income tax regulatory liabilities (36) (37) Tax effect of equity earnings (15) (15) GBPC impairment charge 11 - Investment tax credits (9) (4) Change in treatment of NMGC net operating loss carryforwards (7) - Florida state tax apportionment adjustment - (23) Change in prior year unrecognized tax benefits at NSPI - 7 Other (7) 2 Income tax expense $ 61 $ 69 Effective income tax rate 8% 8% The following 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 2019 2018 Current income taxes Canada $ (19) $ 3 United States (46) (121) Other 1 2 Deferred income taxes Canada 45 11 United States 137 215 Other - (4) Investment tax credits United States (9) (4) Operating loss carryforwards Canada (48) (33) Income tax expense (recovery) $ 61 $ 69 The following 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 2019 2018 Canada $ 98 $ 127 United States 682 646 Other (9) 43 Income before provision for income taxes $ 771 $ 816 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 2019 2018 Deferred income tax assets: Tax loss carryforwards $ 908 $ 917 Tax credit carryforwards 311 269 Regulatory liabilities - cost of removal 195 206 Derivative instruments 145 90 Pension and post-retirement liabilities 84 126 Other 329 441 Total deferred income tax assets before valuation allowance 1,972 2,049 Valuation allowance (193) (163) Total deferred income tax assets after valuation allowance $ 1,779 $ 1,886 Deferred income tax (liabilities): Property, plant and equipment $ (2,382) $ (2,591) Derivative instruments (148) (124) Other (348) (316) Total deferred income tax liabilities $ (2,878) $ (3,031) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 186 $ 175 Long-term deferred income tax liabilities (1,285) (1,320) Net deferred income tax liabilities $ (1,099) $ (1,145) 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 unrealized capital losses on investments. A valuation allowance of $ 193 million has been recorded as at December 31, 2019 (2018 - $ 163 million) related to the loss carryforwards and investments. Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2019 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 1,131 $ (554) $ 577 2027-2039 Capital loss 80 (80) - Indefinite United States Federal NOL $ 2,394 $ - $ 2,394 2024-2037 State NOL 1,174 - 1,174 2024-2039 Tax credit 311 - 311 2020-Indefinite Other NOL $ 38 $ (38) $ - 2020-2026 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 2019 2018 Balance, January 1 $ 26 $ 19 Increases due to tax positions related to current year 2 - Increases due to tax positions related to a prior year 1 8 Decreases due to tax positions related to a prior year - (1) Balance, December 31 $ 29 $ 26 The total amount of unrecognized tax benefits as at December 31, 2019 was $ 29 million ( 2018 - $ 26 million), which would affect the eff ective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $ 5 million ( 2018 - $ 4 million) with $ 1 million of interest expense recognized in the Consolidated Statements of Income (2018 - $ 3 million). No penalties have been accrued . The balance of unrecognized tax benefits could change in the next twelve 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. The Company inte nds to indefinitely reinvest earnings fr om certain foreign operations. Accordingly, US and non-US income and withholding taxes , for which deferred taxes might otherwise be required , have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $ 1.9 b illion as at December 31, 2019 ( 2018 - $ 1.4 billion). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera 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, 2019 , the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years. NSPI and the CRA are currently in a dispute with respect to the 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. Sho uld NSPI be successful in defending its position, 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 prev iously 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 ultim ate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Appeal pr ocess is not determinable at this time.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2019
Common Stock
Common Stock	9 . COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2019 2018 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2018 234.12 $ 5,816 228.77 $ 5,601 Conversion of Convertible Debentures 0.03 1 0.01 - Issuance of common stock (1) 1.77 99 0.45 22 Issued under Purchase Plans at market rate 3.99 202 4.87 200 Discount on shares purchased under Dividend Reinvestment Plan - (7) - (9) Options exercised under senior management share option plan 2.57 104 0.02 1 Employee Share Purchase Plan - 1 - 1 Balance, December 31, 2019 242.48 $ 6,216 234.12 $ 5,816 (1) As at December 31, 2019 a total of 1.77 million common shares have been issued through Emera's at-the-market equity program ("ATM Program") at an average price of $56.56 per share for gross proceeds of $100 million ($98.7 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 December 3 1 , 2019, an aggregate gross sales limit of $ 500 million remains available for issuance under the ATM program. As at December 31, 2019 , the following common shares were reserved for issuance: 3.9 million ( 2018 – 6.5 million) under the senior management stock option plan, 0.9 million ( 2018 – 1 million) under the employee common share purchase plan and 8.8 millio n ( 2018 – 12.6 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 outstanding common shares . As at December 31, 2019 , Emera is in compliance with this requirement.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
10. Earnings Per Share
Earnings Per Share	10 . 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) 2019 2018 Numerator Net income attributable to common shareholders $ 662.8 $ 709.6 Diluted numerator 662.8 709.6 Denominator Weighted average shares of common stock outstanding 238.5 231.7 Weighted average deferred share units outstanding 1.4 1.3 Weighted average shares of common stock outstanding – basic 239.9 233.0 Stock-based compensation 0.6 0.4 Convertible Debentures - 0.1 Weighted average shares of common stock outstanding – diluted 240.5 233.5 Earnings per common share Basic $ 2.76 $ 3.05 Diluted $ 2.76 $ 3.04

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2019
11. Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	11 . 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, 2019 Balance, January 1, 2019 $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 Other comprehensive income (loss) before reclassifications (401) 78 3 - - (320) Amounts reclassified from accumulated other comprehensive income loss (gain) - - 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 For the year ended December 31, 2018 Balance, January 1, 2018 (1) $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) Other comprehensive income (loss) before reclassifications 624 (122) 2 - - 504 Amounts reclassified from accumulated other comprehensive income loss (gain) - - (6) (4) 9 (1) Net current period other comprehensive income (loss) 624 (122) (4) (4) 9 503 Balance, December 31, 2018 $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 (1) The January 1, 2018 balance of AOCI and Regulatory assets includes a prior period reclassification of $37 million in unrecognized pension and post-retirement benefit costs and $15 million in deferred taxes ($22 million, net of tax) to be consistent with current year presentation. The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2019 2018 Affected line item in the Consolidated Financial Statements Losses (gain) on derivatives recognized as cash flow hedges Foreign exchange forwards Operating revenue - regulated $ 3 $ (5) Power and gas swaps Non-regulated fuel for generation and purchased power - (1) Total before tax 3 (6) Total net of tax $ 3 $ (6) Net change in available-for-sale investments Retained earnings (1) - (4) Total net of tax $ - $ (4) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 17 $ 25 Past service costs (gains) OM&G (1) (1) Amounts reclassified into obligations Pension and post-retirement benefits 39 (17) Amounts reclassified into obligations Regulatory assets 28 - Total before tax 83 7 Income tax recovery (expense) (9) 2 Total net of tax $ 74 $ 9 Total reclassifications out of AOCI, net of tax, for the period $ 77 $ (1) (1) Related to the adoption of ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Refer to note 2 for additional detail.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2019
12. Inventory
Inventory	12 . INVENTORY As at December 31 December 31 millions of Canadian dollars 2019 2018 Fuel $ 232 $ 213 Materials 235 241 Emission credits - 20 $ 467 $ 474

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2019
13. Derivative Instruments
Derivative Instruments	13 . 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 2019 2018 2019 2018 Cash flow hedges Foreign exchange forwards $ - $ - $ 1 $ 5 - - 1 5 Regulatory deferral Commodity swaps and forwards Coal purchases 8 71 39 1 Power purchases 23 2 36 1 Natural gas purchases and sales 2 2 5 4 Heavy fuel oil purchases 1 1 - 1 Foreign exchange forwards 2 29 6 - 36 105 86 7 HFT derivatives Power swaps and physical contracts 19 62 22 76 Natural gas swaps, futures, forwards, physical contracts 151 125 381 403 170 187 403 479 Other derivatives Equity derivatives and interest rate swaps 1 1 - - 1 1 - - Total gross current derivatives 207 293 490 491 Impact of master netting agreements with intent to settle net or simultaneously (120) (126) (120) (126) 87 167 370 365 Current 54 148 268 260 Long-term 33 19 102 105 Total derivatives $ 87 $ 167 $ 370 $ 365 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 2019 2018 2019 2018 Regulatory deferral $ 8 $ 1 $ 8 $ 1 HFT derivatives 112 125 112 125 Total impact of master netting agreements with intent to settle net or simultaneously $ 120 $ 126 $ 120 $ 126 Cash Flow Hedges The Company has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. 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 2019 2018 Foreign Foreign exchange Power exchange forwards swaps forwards Realized gain (loss) in operating revenue – regulated (3) - 5 Realized gain (loss) in non-regulated fuel for generation and purchased power - 1 - Total gains (losses) in Net income $ (3) $ 1 $ 5 As at December 31 millions of Canadian dollars 2019 2018 Foreign Foreign exchange Power exchange forwards swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ (1) $ (1) $ (6) The Company expects $1 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle. As at December 31, 2019, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2020 Foreign exchange forwards (USD) sales $ 30 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 2019 2018 Commodity swaps and forwards Foreign exchange forwards Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (89) $ (6) $ (34) $ 4 Unrealized gain (loss) in regulatory liabilities 9 (8) 29 24 Realized (gain) loss in regulatory liabilities (2) - (8) - Realized (gain) loss in inventory (1) (36) (11) (55) (18) Realized (gain) loss in regulated fuel for generation and purchased power (2) 3 (8) (2) (9) Total change derivative instruments $ (115) $ (33) $ (70) $ 1 (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; hedging relationships that have been terminated or the hedged transaction is no longer probable. Commodity Swaps and Forwards As at December 31, 2019 , 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: 2020 2021-2022 millions Purchases Purchases Coal (metric tonnes) - 1 Natural Gas (Mmbtu) 12 21 Heavy fuel oil (bbls) - 1 Power (MWh) 1 3 Foreign Exchange Swaps and Forwards As at December 31, 2019 , 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: 2020 2021-2022 Foreign exchange contracts (millions of US dollars) $ 173 $ 148 Weighted average rate 1.3148 1.3264 % of USD requirements 85% 39% 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 2019 2018 Power swaps and physical contracts in non-regulated operating revenues $ 1 $ (12) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 281 205 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (6) 2 $ 276 $ 195 As at December 31, 2019 , the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: millions 2020 2021 2022 2023 2024 Natural gas purchases (Mmbtu) 424 84 56 41 26 Natural gas sales (Mmbtu) 345 33 9 2 2 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - For the Year ended December 31 millions of Canadian dollars 2019 2018 Equity Interest rate derivatives swaps Unrealized gain in operating, maintenance and general $ 1 $ - Unrealized gain (loss) in interest expense, net - (1) Realized gain in operating, maintenance and general 27 - Total gains (losses) in net income $ 28 $ (1) 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, 2019 , the maximum exposure the Company has to credit risk is $ 860 million ( 2018 - $ 1,035 million) , which includes accounts receivable net 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 thei r 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. Counter parties 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, 2019 was $ 259 mi llion ( 2018 - $ 346 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 Company. 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 (“I SDA”), 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, collatera l, non-performance and default. As at December 31, 2019 , the Company had $ 115 million ( 2018 - $ 118 million) in financial assets, considered to be past due, which have been outstanding for an average 71 days. The fair value of these financial assets is $ 106 million ( 2018 - $ 107 million), the difference of which is included in the allowance for doubtf ul accounts. 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, 2019 December 31, 2018 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 344 31% $ 384 28% Commercial 170 15% 182 13% Industrial 66 6% 57 4% Other 131 12% 84 6% 711 64% 707 51% Trading group Credit rating of A- or above 38 3% 49 4% Credit rating of BBB- to BBB+ 59 5% 70 5% Credit rating of CCC- to CCC+ - 0% 8 0% Not rated 95 9% 108 8% 192 17% 235 17% Other accounts receivable 184 16% 273 20% Classification as assets held for sale (1) (55) -5% - 0% 1,032 92% 1,215 88% Derivative Instruments (current and long-term) Credit rating of A- or above 47 4% 130 9% Credit rating of BBB- to BBB+ 8 1% 9 1% Not rated 32 3% 28 2% 87 8% 167 12% $ 1,119 100% $ 1,382 100% (1) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details. Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of Canadian dollars 2019 2018 Cash collateral provided to others $ 101 $ 103 Cash collateral received from others 2 77 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 counter parties to such derivatives could request ongoing full collateralization. As at December 31, 2019 , the total fair value of these derivatives, in a l iability position, wa s $ 370 million ( December 31, 2018 – $ 365 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, 2019
14. Fair Value Measurements
Fair Value Measurements	14 . 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, 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 purchases 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) As at December 31, 2018 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards Coal purchases - 70 - 70 Power purchases 2 - - 2 Natural gas purchases and sales - 2 - 2 Heavy fuel oil purchases - 1 - 1 Foreign exchange forwards - 29 - 29 2 102 - 104 HFT derivatives Power swaps and physical contracts 2 2 3 7 Natural gas swaps, futures, forwards, physical contracts and related transportation 1 36 18 55 3 38 21 62 Other derivatives Interest rate swap - 1 - 1 - 1 - 1 Total assets 5 141 21 167 Liabilities Cash flow hedges Foreign exchange forwards - 5 - 5 - 5 - 5 Regulatory deferral Commodity swaps and forwards Coal purchases - 1 - 1 Power purchases 1 - - 1 Heavy fuel oil purchases - 1 - 1 Natural gas purchases and sales 3 - - 3 4 2 - 6 HFT derivatives Power swaps and physical contracts 14 6 1 21 Natural gas swaps, futures, forwards and physical contracts - 28 305 333 14 34 306 354 Total liabilities 18 41 306 365 Net assets (liabilities) $ (13) $ 100 $ (285) $ (198) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2019 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2019 $ 3 $ 18 $ 21 Total realized and unrealized gains (losses) included in non-regulated operating revenues (2) (4) (6) Balance, December 31, 2019 $ 1 $ 14 $ 15 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2019 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2019 $ 1 $ 305 $ 306 Total realized and unrealized gains (losses) included in non-regulated operating revenues (1) (56) (57) Balance, December 31, 2019 $ - $ 249 $ 249 The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2019 , there were no transfers between levels. 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 based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources mul tiple broker prices in an effort to evaluate and substanti ate these unobservable inputs. 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 poin ts. 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, 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, 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) As at December 31, 2018 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 3 Modelled pricing Third-party pricing $24.31 - $50.29 $31.43 Power swaps and Probability of default 0.03% - 0.13% 0.13% physical contracts Discount rate 0.03% - 2.19% 1.45% Correlation factor 84.98% - 84.98% 84.98% HFT derivatives – 8 Modelled pricing Third-party pricing $1.80 - $12.21 $4.75 Natural gas swaps, Probability of default 0.01% - 2.94% 0.24% futures, forwards, Discount rate 0.01% - 30.62% 4.25% physical contracts 10 Modelled pricing Third-party pricing $1.95 - $12.90 $8.68 and related transportation Basis adjustment $0.07 - $3.43 $1.88 Probability of default 0.01% - 3.20% 0.57% Discount rate 0.01% - 7.61% 0.42% Total assets $ 21 Liabilities HFT derivatives – 1 Modelled pricing Third-party pricing $20.80 - $50.29 $26.38 Power swaps and Correlation factor 84.98% - 84.98% 84.98% physical contracts Probability of default 0.08% - 0.29% 0.15% Discount rate 0.03% - 2.99% 1.65% HFT derivatives – 286 Modelled pricing Third-party pricing $1.48 - $12.90 $5.75 Natural gas swaps, futures, Own credit risk 0.01% - 2.94% 0.09% forwards and physical contracts Discount rate 0.01% - 11.96% 2.35% 19 Modelled pricing Third-party pricing $2.15 - $13.18 $7.54 Basis adjustment $0.07 - $3.43 $2.67 Own credit risk 0.01% - 2.76% 0.10% Discount rate 0.01% - 7.61% 1.38% Total liabilities $ 306 Net assets (liabilities) $ (285) The financial liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2019 $ 14,180 $ 16,049 $ - $ 15,598 $ 451 $ 16,049 December 31, 2018 $ 15,411 $ 15,908 $ - $ 14,991 $ 917 $ 15,908 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 $ 78 million was recorded in Other Comprehensive Income for the year ended December 31, 2019 ( 2018 – $ 122 million loss after-tax ).

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
15. Regulatory Assets and Liabilities
Regulatory Assets and Liabilities	15 . REGULATORY ASSETS AND LIABILITIES Regulatory assets represent 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 t hat an asset will be recovered, the deferred costs are charged 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 recognized 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 2019 (1) 2018 Regulatory assets Deferred income tax regulatory assets $ 862 $ 775 Pension and post-retirement medical plan 380 453 Deferrals related to derivative instruments 81 10 Storm restoration regulatory asset 38 32 Stranded cost recovery 27 28 Environmental remediations 26 31 Demand side management ("DSM") deferral 19 24 Unamortized defeasance costs 19 26 Cost recovery clauses 13 75 Other 87 115 $ 1,552 $ 1,569 Current $ 121 $ 165 Long-term 1,431 1,404 Total regulatory assets $ 1,552 $ 1,569 Regulatory liabilities Deferred income tax regulatory liabilities 985 1,218 Accumulated reserve - cost of remova l 891 955 Regulated fuel adjustment mechanism 115 161 Storm reserve 62 76 Cost recovery clauses 53 30 Deferrals related to derivative instruments 42 116 Self-insurance fund (note 31) 29 30 Other 4 24 $ 2,181 $ 2,610 Current $ 295 $ 251 Long-term 1,886 2,359 Total regulatory liabilities $ 2,181 $ 2,610 (1) On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Refer to note 4 for further details. Deferred Income Tax Regulatory Asset s and Liabilities To the extent deferred income taxes are expected to be re covered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post - retir ement benefits at Tampa Electric, PGS and NMGC . It is included in rate base and earns a rate of return as permitted by the FPSC, New Mexico Public Regulation Commission (“NMPRC”) and Maine Public Utilities Commission (“MPUC”) , 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 defer ring 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 generation and purchased power, inventory, operating, maintenance or general or property, plant and equipment, depending on the nature of the item being economically hedged. 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, Dorian struc k 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. GBP C’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain. It is currently estimated that restoration costs for GB P C self-insured assets will be approximately $15 milli on USD. In January 2020 , the GBPA approved the recovery of these costs through rates over a five-year period. A pproximately $ 12 million USD ($ 1 5 million CAD ) of these estimated cost s were incurred in 2019 , and recorded as a regulatory asset. Restoration costs associated with Hurricane Matthew in 2016 are being amortized over five years and included in rate base as approved by t he Grand Bahama Port Authority (“GBPA”) for full recovery . The balance as at December 31, 2019 is $ 23 million. 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 for 2019 and 2018 and is expected to be included in future years. Environmental Remediation s This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant (“MGP”) sites . The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is ba sed on a settlement agreement approved by the FPSC. DSM Deferral The UARB approved implementation of the 2015 DSM deferral set at $ 35 million for 2015 and recoverable from customers over an eight year period beginning in 2016. The UARB directed Efficien cyOne 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 behalf of its customers in 2015. In December 2016, EfficiencyOne secured financing and $ 31 million was advanced to NSPI to finance the 2015 DSM deferral. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne. This has been set up as a liability in “Other long-term liab ilities” with the current portion of the liability included in “Other current liabilities” on the 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 interest streams to match the related defeased debt, which as at December 31, 2019 , totalled $ 740 million ( 2018 – $ 759 million). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as permitted by the Nova Scotia Utility and Review Board (“UARB”) . 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 the next year. 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 equipm ent, 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. Regulated Fuel Adjustment Mechanism This regulated liability is the difference between actual fuel 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. For the years 2017 to 2019, differences between actual fuel costs and fuel revenues recovered from customers will be recovered or returned to customers after 2019, as required unde r the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”) . 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 202 0 to 2022, will be recovered or returned to customers after 2022 . 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 stor m reserve exceed the storm liability, the excess is to be carried as a regulatory 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 t he reserve. In September 2019, Tampa Electric incurred approximately $ 8 million USD in storm restoration preparation costs for Hurricane Dorian. These costs were charged to the storm reserve regulatory liability. 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”). T he 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 regulated return on equity (“ROE”) range for 2019 and 2018 is 9.25 per cen t to 11.25 per cent b ased 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. 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 capi tal 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 custo mers in a subsequent year. As of December 31, 2019, Tampa Electric has invested approximately $ 820 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). Tam pa Electric expects to invest an additional $ 30 million USD in these projects through 2021 . AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 554 MW or $ 96 million USD annually in estimated re venue requirements for in-service projects. Tampa Electric expects to file its final SoBRA petition for the January 1, 2021 tranche in 2020. On December 10 , 2019, the FPSC approved Tampa Electric’ s petition to reduce base rates and charges reflect ing reduction of the state income tax from 5.5 per cent to 4.46 per cent re troactive from January 1, 2019. The base rate reduction of approximately $ 5 million USD due to customers is subject to true-up, and the actual rate reduction may vary from year to year. On October 3, 2019, the FPSC issued a rule to implement a storm protection 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. Subject to final approval of the FPSC rule, Tampa Electric expects to file a storm protection plan with the FPSC in Q2 2020. On Aug ust 20, 2018, the FPSC approved a reduction in base rates of $ 103 million USD annually beginning in 2019 as a result of lower tax expense due to 2018 US tax reform benefits . On April 9, 2019, Tampa Electric reached a settlement agreement with consumer part ies regarding eligible storm costs as a result of Hurricane Irma in 2017 , which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $ 12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income . Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “ 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 to 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 an appropriate return to investors. NSPI’s approved regulated ROE range for 2019 and 2018 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity compo nent of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of f uel c osts through regularly scheduled rate adjustments. Differences between actual f uel c osts 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. T he Electricity Plan Act , was enacted by the Province of No va Scotia in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In March 2016, in accordance with the Electricity Plan Act, NSPI announced that it would not file a General Rate Applicat ion (“GRA”) for non-fuel electricity rates for the 2017 through 2019 period. The UARB approved NSPI’s three-year fuel stability plan for 2017 through 2019, which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for each of these three years. On December 6, 2019, the UARB approved NSPI’s three -year fuel stability plan which result s in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. For the years 2020 to 2022, differences between actual f uel c osts and fuel revenues recovered from customers will be recovered from or returned to customers after 2022. The decision further directed that annual excess non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM. In September 2017, the UARB approved NSPI’s interim assessment payment to NSP Maritime Link Inc. (“NSPML”) of the costs associated with the Maritime Link when it is in service . The UARB approved annual payment for 2019 is $ 11 1 million and as of December 31, 2019, $ 101 million of that has been paid. The payments are subject to a hold back 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. As of December 31, 201 9 , NSPI has recorded a $ 6 million holdback payable to NSPML. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment s of $ 110 million and $111 million for 2018 and 2019 respectively, reflect a $ 53 million reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017 through 2019 fu el rates and were recovered from customers, NSPI is providing a credit to customers, including interest, as the payments from NSPI to NSPML are not required in those years. In 2018, $ 17 million was refunded and i n 2019, a further $ 35 million was refunded . The UARB decision to reduce the assessment payable to NSPML in 2018 and 2019 results in the Company recording amounts collected from customers as a FAM regulatory liability, with no material impact on earnings. The UARB’s decision to approve NSPI’s 2020 through 2022 Fuel Stability Plan outlined the treatment of the reduced 2019 NSPML assessment of $ 52 million plus interest. The reduced assessment will be refunded to most customers through a reduction incorporated into their 2020 through 2022 rates and the remaining customers will receive a one-time on bill credit in 2020 . The credit to customers will be approximately $ 40 million plus interest in 2020, with the remaining $ 12 million plus interest to be returned to c ustomers subsequent to 2022. On November 27, 2019 , the UARB approved the 2020 interim cost assessment recovery from NSPI for costs associated with the Maritime Link of $145 million, subject to a holdback of up to $10 million. Refer to the NSPML section below for further details. Pursuant to the FAM Plan of Administration, NSPI’s fuel costs are subject to independent audit. In July 2018, the FAM audit results relating to fiscal 2016 and 2017 were publicly released. A UARB regulatory process is in progress with a hearing held on January 13, 2020. 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 November 27, 2019, the UARB approved NSPML’s interim assessment for recovery of 2020 Maritime Link costs from NSPI of approximately $ 145 milli on (2019 - $ 111 million). The total recovery of $145 million includes approximately $ 115 million of operating and maintenance, debt financing and equity financing costs, and approximately $ 30 million for depreciation and amortization of financing costs. Th is payment is subject to a holdback of up to $ 10 million. Recovery of the $115 million of operating and maintenance, debt financing and equity financing costs began on January 1, 2020. Beginning June 1, 2020, recovery of the $30 million of depreciation and amortization of financing costs will be included in NSPI customer rates, with payment of this recovery to NSPML to begin on the earlier of the confirmation of delivery of the N ova S cotia b lock (“NS Block”) of electricity transmitted through the Maritime L ink from the Muskrat Falls hydroelectric facility, and November 1, 2020. NSPML expects to file a final cost assessment with the UARB in 2020. Other Electric Utilities Emera Maine Emera Maine’s distribution operations and stranded cost recoveries are regulated by the MPUC. The transmission operations are regulated by the FERC. Rates for these are established in distinct regulatory proceedings. US tax reform benefits, resulting from the lower tax rate, were reflected in distribution and transmission rates effective July 1, 2018, with other components being deferred to be addressed in future regulatory proceedings. Distribution Operations Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. In June 2018, the MPUC approved a 5.3 per cent distribution rate increase. This increase was effective July 1, 2018 and is based on a 9.35 per cent ROE a nd a common equity component of 49 per cent. Prior to July 1, 2018, the allowed ROE was 9.0 per cent, on a common equity component of 49 per cent. Transmission Operations Emera Maine’s transmission operations are split between two districts; Bangor Hydro District and Maine Public Service (“MPS”). Bangor Hydro District local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecas ted transmission investments. The allowed ROE for Bangor Hydro District local transmission operations for 2019 and 2018 is 10.57 per cent. Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide p ool of assets. The allowed ROE range for Bangor Hydro bulk transmission assets is 11.07 to 11.74 per cent for 2019 and 2018. MPS District local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retai l customers based on a formula utilizing prior year actual transmission investments and expenses. The current allowed ROE for transmission operations is 9.6 per cent (2018 – 9.6 per cent). Stranded Cost Recoveries Stranded cost recoveries in Maine are se t by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC . The Barbados Light & Power Company Limited BLPC is regulated by the Fair Trading Commission , an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The G overnment 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 amendi ng the number of licenses required for the supply of electricity from a single integrated l icense which currently exists to multiple l icenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is negotiating the terms of the new l icenses 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 ap propriate return to investors. BLPC’s approved regulated return on rate base was 10 per cent for 2019 and 2018 . All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides opportunity to recover all fuel costs 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 legisl ation which is 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 income 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. Grand Bahama Power Company Limited GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulat ed 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 8.5 per cent for 2019 ( 2018 - 8. 5 per cent) . In December 201 8, the GBPA approved GBPC’s regulated return on rate base of 8. 44 per cent for 2019 . In December 2016, the GBPA approved that the all-in r ate 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 years, GBPC will have th e 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 Trans mission, 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 15 per cent for 2019 and 2018 . Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides opportunity to recover substantially all 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. The approved ROE range for PGS is 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 is used for the calculation of return on investments for clauses. PGS recovers the costs it pays for gas supply 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 and 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 replacement of cast iron and bare steel distributio n 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. As part of the depreciation study settlement agreement ap proved by the FPSC in February 2017, the Cast Iron/Bare Steel clause was expanded to allow recovery of accelerated replacement of certain obsolete pipe. On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility t o amortize $ 11 million USD of its MGP environmental regulatory asset and net it against its estimated 2018 tax reform benefits. Beginning in January 2019, PGS reduced its base rates by $ 12 million USD to reflect the impact of tax reform and reduce deprecia tion rates by $ 10 million USD in accordance with the settlement agreement. PGS is permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time, provided the new rates do not become effective before January 1, 2021. On February 7 , 2020, PGS notified the FPSC that it is planning to file a new base rate proceeding in April 2020 for new rates effective January 2021 . 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. The approved ROE for NMGC is 9.1 per cent, on a n 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 othe r related items associated with the purchase, distribution, and sale of natural gas to its customers. On a monthly 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 NM PRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In Decembe r 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020. 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 are being phased in over two years and are expected to result 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. 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 . On Dece mber 23, 2019, NMGC filed a future year rate case on December 23, 2019 for new rates effective January 2021. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure. The estimated annual incremental revenue requirement is approximately $ 13 million USD. A decision from the NMPRC is expected in late 2020. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) imp ort terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25 -year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline reg ulated by the Canada Energy Board (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the C ER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
16. Related Party Transactions
Related Party Transactions	16 . 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 transactions between Emera and its associat ed companies are as follows:  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 $ 107 million for the year ended December 31, 2019 ( 2018 - $ 97 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 reven ues, Non-regulated, totalled $ 63 million for the year ended December 31, 2019 ( 2018 - $ 29 million). There we re no significant receivables or payables between Emera and its associated companies reported on Emera’s C onsolidated Balance Sheets as at December 31, 2019 and at December 31, 2018 .

Receivables and Other Current A

Receivables and Other Current Assets	12 Months Ended
	Dec. 31, 2019
17. Receivables and Other Current Assets
Receivables and Other Current Assets	17. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2019 2018 Customer accounts receivable – billed $ 704 $ 844 Customer accounts receivable – unbilled 265 296 Allowance for doubtful accounts (9) (11) Other receivables 72 86 Capitalized transportation capacity (1) 272 179 Income tax receivable 118 175 Prepaid expenses 48 42 Net investment in direct financing lease (note 18 ) 9 9 Other current assets 7 - $ 1,486 $ 1,620 (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, 2019
18. Leases
Leases, Lessee	18 . 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 66 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 . As at December 31 millions of Canadian dollars Classification 2019 Right-of-use asset Other long-term assets $ 64 Lease liabilities Current Other current liabilities 5 Long-term Other long-term liabilities 61 Total lease liabilities $ 66 The Company has recorded lease expense of $ 172 million for the year ended December 31, 2019 , of which $ 156 million relates to variable costs for power generation facility finance leases , recorded in “Regulated fuel for generation and purchased power” in the consolidated statements of income . 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 2020 2021 2022 2023 2024 Thereafter Total Minimum lease payments $ 8 $ 8 $ 7 $ 6 $ 5 $ 102 $ 136 Less imputed interest (70) Total $ 8 $ 8 $ 7 $ 6 $ 5 $ 102 $ 66 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions of Canadian dollars) $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases (millions of Canadian dollars) $ 16 Weighted average remaining lease term (years) 39 Weighted average discount rate- operating leases 4.07% L essor The Company’s ne t investment in direct finance and sales-type lease s relate 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 th e lease term for a nominal fee. Ne t investment in direct finance and sales-type lease s consist of the following ( 1) : As at December 31 millions of Canadian dollars 2019 Total minimum lease payment to be received $ 1,066 Less: amounts representing estimated executory costs (189) Minimum lease payments receivable $ 877 Estimated residual value of leased property (unguaranteed) 183 Less: unearned finance lease income (532) Net investment in direct finance and sales-type leases $ 528 Principal due within one year (included in "Receivables and other current assets") 17 Net investment in sales-type leases - long-term (included in "Other long-term assets") 38 Net Investment in direct finance leases - long-term $ 473 (1) The net investment in direct finance lease balance as of December 31, 2018, primarily related to New Brunswick Pipeline, consisted of net minimum lease payments receivable of $865 million less an unguaranteed residual value of $183 million and unearned finance income of $564 million. As at December 31, 2019, 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 2020 2021 2022 2023 2024 Thereafter Total Minimum lease payments to be received $ 76 $ 74 $ 73 $ 73 $ 74 $ 696 $ 1,066 Less: executory costs (189) Minimum lease payments receivable $ 76 $ 74 $ 73 $ 73 $ 74 $ 696 $ 877

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
19. Property, Plant and Equipment
Property, Plant and Equipment	19 . 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 2019 (1) 2018 Generation (2) 3 to 131 $ 11,181 $ 11,092 Transmission 11 to 80 2,318 3,047 Distribution 4 to 80 5,820 6,348 Gas transmission and distribution 7 to 85 3,546 3,398 General plant and other 2 to 60 2,006 2,158 Total cost 24,871 26,043 Less: Accumulated depreciation (2) (8,295) (8,567) 16,576 17,476 Construction work in progress 1,591 1,236 Net book value $ 18,167 $ 18,712 (1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to the note 4 for further details. (2) On March 29, 2019, the Company sold its NEGG facilities. As of December 31, 2018, the Company classified these assets as held for sale on the Consolidated Balance Sheets. Refer to note 4 for additional information.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
20. Employee Benefit Plans
Employee Benefit Plans	20 . 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 Sc otia, New Brunswick, Newfoundland and Labrador, Florida, Maine, New Mexico, Barbados, Dominica and Grand Bahama Island. On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities, including bal ances related to benefit plans, were classified as held for sale. Refer to note 4 for further details. 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 2019 2018 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 $ 2,650 $ 350 $ 2,683 $ 356 Service cost 47 4 51 6 Plan participant contributions 8 5 8 5 Interest cost 102 14 95 13 Benefits paid (130) (23) (143) (33) Actuarial (gains) losses 231 19 (133) (25) Settlements and curtailments (20) - (18) - Foreign currency translation adjustment (66) (16) 107 28 Balance, December 31 2,822 353 2,650 350 Change in plan assets Balance, January 1 2,300 49 2,408 45 Employer contributions 52 19 51 31 Plan participant contributions 8 5 8 5 Benefits paid (130) (23) (143) (33) Actual return on assets, net of expenses 424 7 (105) (3) Settlements and curtailments (7) - (18) - Foreign currency translation adjustment (54) (1) 99 4 Balance, December 31 2,593 56 2,300 49 Funded status, end of year $ (229) $ (297) $ (350) $ (301) 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, for post-retirement benefit plans, the APBO exceeds the plan assets for the years ended December 31 is as follows: millions of Canadian dollars 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,797 $ 323 $ 2,623 $ 318 Fair value of plan assets 2,557 7 2,264 6 Funded status $ (240) $ (316) $ (359) $ (312) Plans with Accumulated Benefit Obligation (“ABO”) in E xcess of P lan A ssets The ABO for the defined benefit pension plans was $ 2,687 million as at December 31, 2019 ( 2018 – $ 2,527 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 2019 2018 Defined benefit pension plans Defined benefit pension plans ABO $ 2,665 $ 2,504 Fair value of plan assets 2,557 2,264 Funded status $ (108) $ (240) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (4) $ (18) $ (12) $ (19) Long-term liabilities (206) (254) (347) (294) Long-term liabilities associated with assets held for sale (1) (30) (44) - - Other long-term assets 11 19 9 11 Amount included in deferred income tax (7) 1 5 (2) AOCI, net of tax and regulatory assets 524 72 628 60 Net amount recognized $ 288 $ (224) $ 283 $ (244) (1) On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Refer to note 4 for further details. 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 . As at December 31, 2019, regulatory asset balances related to Emera Maine have been reclassified as assets held for sale. The following table summarizes the change in AOCI and r egulatory assets: Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2019 $ 389 $ 246 $ (2) Amortized in current period (20) (17) 1 Current year addition to AOCI or regulatory assets 6 (69) - Change in foreign exchange rate (17) - - Balance, December 31, 2019 $ 358 $ 160 $ (1) Non-pension benefits plans Balance, January 1, 2019 $ 65 $ (7) $ - Amortized in current period 5 - - Current year addition to AOCI or regulatory assets 11 2 - Change in foreign exchange rate (3) - - Balance, December 31, 2019 $ 78 $ (5) $ - 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 160 $ (5) $ 246 $ (7) Past service (gains) costs (1) - (2) - Regulatory assets 358 78 389 65 Total AOCI and regulatory assets before deferred income taxes 517 73 633 58 Amount included in deferred income tax assets 7 (1) (5) 2 Net amount in AOCI and regulatory assets $ 524 $ 72 $ 628 $ 60 Benefit C ost C omponents Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 47 $ 4 $ 51 $ 6 Interest cost 102 14 95 13 Expected return on plan assets (147) (2) (138) (2) Current year amortization of: Actuarial losses 16 - 33 (1) Past service costs (gains) (1) - (1) - Regulatory assets (liability) 20 (5) 26 (2) Settlement, curtailments 1 - 4 - Total $ 38 $ 11 $ 70 $ 14 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,401 million as at January 1, 2019 ( 2018 – $ 2,223 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 over 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 assumpt ions. 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 broad bas ket 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 40% to 45% Equities 55% to 60% 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, 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 % December 31, 2018 Cash and cash equivalents $ - $ 30 $ - $ 30 1 % Net in-transits - (56) - (56) -2 % Equity securities: Canadian equity - 191 - 191 8 % US equity - 330 - 330 14 % Other equity - 157 - 157 7 % Fixed Income securities: Government - - 119 119 5 % Corporate - - 108 108 5 % Other - 4 3 7 - Mutual funds - 132 - 132 6 % Other - 8 4 12 1 % Open-ended investments measured at NAV (1) 820 - - 820 36 % Common collective trusts measured at NAV (2) 450 - - 450 19 % Total $ 1,270 $ 796 $ 234 $ 2,300 100 % (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 14 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 are the NMGC Retiree Medical Plan, which is fully funded, and the Emera M aine post-retirement benefits plans, which are partially-funded . Investments in Emera As at December 31, 2019 and 2018 , 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 (1) Non-pension benefit plans (2) Expected employer contributions 2020 $ 44 $ 21 Expected benefit payments 2020 143 23 2021 154 23 2022 158 23 2023 165 23 2024 173 23 2025 – 2029 959 115 (1) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $10 million in 2020; $10 million in 2021; $11 million in 2022; $11 million in 2023; $12 million in 2024 and $62 million in 2025-2029. (2) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $3 million in 2020; $3 million in 2021; $3 million in 2022; $3 million in 2023; $4 million in 2024 and $17 million in 2025-2029. Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2019 2018 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 3.17 % 3.27 % 4.05 % 4.30 % Discount rate - future service 3.21 % 3.28 % 4.05 % 4.30 % Rate of compensation increase 3.32 % 3.70 % 3.30 % 3.67 % Health care trend - initial (next year) - 6.15 % - 6.39 % - ultimate - 4.38 % - 4.45 % - year ultimate reached - 2038 - 2035 Benefit cost for year ended December 31: Discount rate - past and future service 4.05 % 4.30 % 3.55 % 3.65 % Expected long-term return on plan assets 6.50 % 2.81 % 6.38 % 3.73 % Rate of compensation increase 3.30 % 3.67 % 3.12 % 3.28 % Health care trend - initial (current year) - 6.39 % - 6.65 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2036 Figures shown are weighted averages. 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 allo cation, 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 . Sensitivity Analysis for Non-Pension Benefits Plans The health care cost trend significantly influences the amount s presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2019 : millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 16 (14) Sensitivity Analysis for Defined Benefit Pension Plans The impact on the 2019 benefit cost of a 25 basis point change in the discount rate and asset return assumptions i s as follows: millions of Canadian dollars Increase Decrease Discount rate assumption $ (9) $ 9 Asset rate assumption (6) 6 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 2020: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (14) $ - Past service gains (1) - Regulatory assets (29) (1) Total $ (44) $ (1) Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2019 was $ 34 million ( 2018 – $ 31 million) .

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2019
21. Goodwill
Goodwill	21. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2019 2018 Balance, January 1 $ 6,313 $ 5,805 Additions 3 - GBPC i mpairment charge (30) - Classified as assets held for sale (1) (148) - Change in foreign exchange rate (303) 508 Balance, December 31 $ 5,835 $ 6,313 (1) On March 25, 2019, Emera announced the sale of Emera Maine. Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details. Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Balance Sheets at December 31, 2019 , relates to TECO Energy, Emera Maine and GBPC. Emera’s reporting units with goodwill are Tampa Electric, PGS, Ne w Mexico Gas, Emera Maine and GBPC. In 2019 , Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment for Tampa Electric, PGS and New Mexico Gas, respectively, using a combination of the income and market app roach. The Company concluded that the fair value of the reporting units exceeded their respective carrying values and , as such, no impairment charges were recognized. Goodwill on Emera’s Consolidated Balance Sheets at December 31, 2018 , included $ 104 million r elate d to GBPC. In 2019 , Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC using an income approach. This assessment concluded that the fair value of the reporting unit was below its carrying va lue, including goodwill. Certain assumptions used in determining the fair value of the reporting unit in the 2019 impairment test changed from those used in prior years, including a decrease in expected future cash flows due to the impacts of Hurricane Dorian storm recovery and changes in the anticipated long term regulated capital structure of GBPC. As a result, Emera recognized an impairment charge of $ 3 0 million in 2019 based on the excess of GBPC’s carrying amount over its fair value . This non-ca sh charge is included in “ GBPC i mpairment charge” in the Consolidated Statements of Income . $ 70 million in goodwill continues to be relate d to GBPC as at December 31, 2019 .

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2019
22. Short-Term Debt
Short-Term Debt	22 . 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 2019 Weighted average interest rate 2018 Weighted average interest rate TECO Finance Advances on revolving credit and term facilities $ 656 2.39 % $ 805 3.43 % Tampa Electric Company ("TEC") Advances on accounts receivable and revolving credit facilities 452 2.56 % 302 3.10 % Emera Inc. Non-revolving term facility 399 2.69 % Bank indebtedness 6 - % - - % GBPC Advances on revolving credit facilities 10 5.25 % - - % NMGC Advances on revolving credit facilities 8 2.70 % 79 3.40 % NSPI Bank indebtedness 6 - % - - % Short-term debt $ 1,537 $ 1,186 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 2019 2018 TECO Energy/TECO Finance - term credit facility 2020 $ 649 $ 682 TECO Energy/TECO Finance - revolving credit facility 2022 520 546 Tampa Electric Company - revolving credit facility 2022 520 443 Emera Inc. - non-revolving term facility 2020 400 - Tampa Electric Company - accounts receivable revolving credit facility 2021 195 205 NMGC - revolving credit facility 2022 162 171 GBPC - revolving credit facility on demand 17 18 Total 2,463 2,065 Less: Advances under revolving credit and term facilities 1,525 1,186 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,528 1,189 Available capacity under existing agreements $ 935 $ 876 The weighted average interest rate on outstanding short-term debt at December 31, 2019 was 2.54 per cent ( 2018 – 3.34 per cent ). Recent Significant Financing Activities 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 , 202 1 . The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate , plus a margin. On December 19, 2019, TEC increased its $ 325 million USD revolving credit facility by $ 75 million USD to $ 400 million USD. There were no other changes in commercial terms. Other On December 16, 2019, Emera entered int o a $ 400 million non-revolving credit agreement with a maturity date of December 15, 2020 . The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at Bankers Acceptance rates or prime rate advances, plus a margin. On March 7, 2019, TECO Energy/Finance extended the maturity date of its $ 500 million USD credit facility from March 8, 2019 to March 5, 2020 . There were no other significant changes in commercial te rms from the prior agreement.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2019
23. Other Current Liabilities
Other Current Liabilities	23 . OTHER CURRENT LIABILITIES As at December 31 December 31 millions of Canadian dollars 2019 2018 Accrued charges $ 147 $ 154 Accrued interest on long-term debt 77 93 Pension and post-retirement liabilities (note 20 ) 22 31 Sales and other taxes payable 13 9 Income tax payable 1 6 Other 73 135 $ 333 $ 428

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
24. Long-term Debt
Long-term Debt	24 . 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 2019 2018 Maturity 2019 2018 Emera Bankers acceptances, LIBOR loans Variable Variable 2024 $ 437 $ 339 Unsecured fixed rate notes 2.90% 3.50% 2023 500 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,559 1,637 $ 2,496 $ 2,701 Emera Finance Unsecured senior notes (USD) 3.86% 3.60% 2021 - 2046 $ 3,572 $ 4,434 TECO Finance (2) Fixed rate notes and bonds (USD) 5.15% 5.15% 2020 390 409 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.53% 4.64% 2021 - 2050 $ 3,334 $ 3,126 PGS Fixed rate notes and bonds (USD) 4.58% 4.66% 2021 - 2050 $ 437 $ 425 NMGC Fixed rate notes and bonds (USD) 4.30% 4.53% 2021 - 2049 $ 474 $ 368 NMGI Fixed rate notes and bonds (USD) 3.64% 3.41% 2024 $ 195 $ 273 NSPI Discount notes Variable Variable 2024 $ 308 $ 516 Medium term fixed rate notes 5.37% 5.73% 2025 - 2097 2,365 1,965 Fixed rate debenture - 9.75% - - 95 $ 2,673 $ 2,576 Emera Maine LIBOR loans and demand loans Variable Variable 2023 $ 11 $ 28 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020 - 2022 65 68 Unsecured senior fixed rate notes (USD) 4.15% 4.23% 2022 - 2049 442 382 $ 518 $ 478 EBP Senior secured credit facility Variable 3.08% 2023 $ 248 $ 248 ECI Secured senior notes (USD) Variable Variable 2021 $ 130 $ 159 Amortizing fixed rate notes (USD) 3.89% 3.83% 2021 - 2022 $ 122 $ 114 Secured fixed rate senior notes (4) 4.84% 5.51% 2020 - 2035 $ 218 $ 191 $ 470 $ 464 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 8 $ 22 Debt issuance costs (119) (113) Classification as liabilities held for sale (6) (516) - Amount due within one year (7) (501) (1,119) $ (1,128) $ (1,210) Long-Term Debt $ 13,679 $ 14,292 (1) Weighted average interest rate of fixed rate long-term debt. (2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (3) 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. (4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (5) 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. (6) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details. (7) Excludes Emera Maine amounts which are classified as current liabilities associated with assets 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 2019 2018 Emera – revolving credit facility (1) June 2024 $ 900 $ 900 NSPI - revolving credit facility (1) October 2024 600 600 Emera Maine – revolving credit facility February 2023 104 109 BLPC – revolving credit facility 2020-2032 25 26 Total 1,629 1,635 Less: Borrowings under credit facilities 771 899 Letters of credit issued inside credit facilities 65 77 Use of available facilities 836 976 Available capacity under existing agreements $ 793 $ 659 (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 complianc e with covenant requirements. Emera’s significa nt covenants are listed below: As at Financial Covenant Requirement December 31, 2019 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.59 : 1 Recent Significant Financing Activity by Segment Florida Electric Utilities On July 24, 2019, TEC completed a $ 300 million USD 30-year senior notes issuance. The notes bear interest at a rate of 3.625 per cent and have a maturity date of June 15, 2050 . Canadian Electric Utilities On November 25, 2019, NSPI amended its operating credit facility to extend the maturity from October 2023 to October 2024. All other terms of the agreement are the same. On August 2, 2019, NSPI repaid a $ 95 million debenture upon maturity. The debenture was repaid using its operating credit facility. On April 4, 2019, NSPI completed a $ 400 million Series AB 30-year medium term notes issuance. The notes bear interest at a rate of 3.57 per cent and have a maturity date of April 5, 2049 . Gas Utilities and Infrastructure On December 19, 2019, NMGC completed a $ 80 million USD 30-year unsecured note issuance. The notes bear interest at a rate of 3.72 per cent and have a maturity date of December 15, 2049 . On December 19, 2019, NMGC completed a $ 15 million USD 15-year unsecured note issuance. The notes bear interest at a rate of 3.24 per cent an d have a maturity date of December 15, 2034 . On July 31, 2019, New Mexico Gas Intermediate (“NMGI”) repaid a $ 50 million USD note upon maturity. The note was repaid using cash on hand. On May 17, 2019, Emera Brunswick Pipeline amended the maturity date of its $ 250 million Credit Agreement from February 2022 to May 2023. There were no other material changes in commercial terms. Other Electric Utilities On December 10, 2019, Emera Maine completed a securities issuance for $ 60 million USD senior unsecured notes. The 30-year notes bear interest at a rate of 3.79 per cent and will mature on December 10, 2049 . Other On December 2, 2019, Emera’s Series G $ 225 million 4.83 per cent medium-term notes matured and were repaid. The no tes were repaid using existing credit facilities. On June 14, 2019, Emera Finance repaid a $ 500 million USD note upon maturity. The note was repaid using proceeds from the sale of the NEGG facilities. On June 13, 2019, Emera extended the maturity date of its $ 900 million revolving credit facility from June 2020 to June 2024. There were no other significant changes in commercial terms from the prior agreement. 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 2020 2021 2022 2023 2024 Thereafter Total Emera $ - $ - $ - $ 500 $ 437 $ 1,559 $ 2,496 Emera US Finance LP - 974 - - - 2,598 3,572 TECO Finance 390 - - - - - 390 Tampa Electric - 301 292 - - 2,741 3,334 PGS - 61 32 - - 344 437 NMGC - - - - 195 - 195 NMGI - 260 - - - 214 474 NSPI - - - - 308 2,365 2,673 Emera Maine (1) 49 - 107 11 - 351 518 EBP - - - 248 - - 248 ECI 111 69 81 72 47 90 470 Total $ 550 $ 1,665 $ 512 $ 831 $ 987 $ 10,262 $ 14,807 (1) Classified as held for sale.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligations
Asset Retirement Obligations	25 . 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 2019 2018 Balance, January 1 $ 205 $ 172 Additions (1) - 25 Liabilities settled (1) (25) (2) Accretion included in depreciation expense 7 6 Other 3 (1) Change in foreign exchange rate (5) 5 Balance, December 31 $ 185 $ 205 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The increase in ARO in 2018 was to achieve compliance with the US Environmental Protection Agency's CCR rule due to the closure of a CCR management facility that began in 2018. The closure was completed in 2019.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	26 . COMMITMENTS AND CONTINGENCIES A. Commitments As at December 31, 2019 , 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 2020 2021 2022 2023 2024 Thereafter Total Purchased power (1)(2) $ 210 $ 233 $ 237 $ 246 $ 249 $ 2,228 $ 3,403 Transportation (3) 514 398 340 281 264 2,720 4,517 Capital projects (4) 411 109 103 86 - - 709 Fuel, gas supply and storage 466 133 22 1 - - 622 Long-term service agreements (5)(6) 52 37 36 27 26 100 278 Equity investment commitments (7) 240 - - - - - 240 Leases and other (8) 19 19 18 17 8 118 199 Demand side management 38 41 43 - - - 122 $ 1,950 $ 970 $ 799 $ 658 $ 547 $ 5,166 $ 10,090 As noted below, contractual obligations at December 31, 2019 include amounts related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future contractual obligations will be transferred to the buyer. Refer to note 4 for additional information. (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Includes $520 million related to Emera Maine ($13 million in 2020; $23 million in 2021; $27 million in 2022; $31 million in 2023; $31 million in 2024 and $395 million thereafter). (3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (4) Includes $345 million of commitments related to Tampa Electric's solar and Big Bend Power Station modernization projects. (5) 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. (6) Includes $44 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($19 million in 2020; $9 million in 2021; $8 million in 2022; and $8 million in 2023). (7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (8) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments. NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2019 was $ 111 million subject to a $ 10 million holdback and as at December 31, 2019, $ 101 million has been paid . The UARB approved payment for 2020 is $ 145 million, subject to a holdback of up to $ 10 million . As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $ 145 million approved for 2020 and estimated amounts of $ 164 million and $ 162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 3 7-year commitment period are dependent on regulatory filings with the UARB. 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 Sco tia. This energy would be transmitted from Nova Scotia to New England energy markets beginning at first commercial 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, Emera includes the obligations within “Leases and other” in the above table. B. Legal Proceedings TECO Guatemala Holdings (“TGH”) In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $ 21 mill ion USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as wel l as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding. On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted , and th e matter was fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain 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 , 2019 , TEC has estimated its financial liability to be $ 2 7 million ($ 21 million USD), pr imarily 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. Th e 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 attributable to TEC. The estimates to perform the work are based on TEC’s experienc e with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs ar e 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 the mselves 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 Maine From 2011 to 2016, four separate complain ts were filed with the FERC to challenge the base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”).  Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, was remanded to the FERC by the US Court of Appeals in 2017 for further proceedings. No reserve has been made with respect to Complaint I due to uncertainty of the outcome.  Complaints II and III (the “ENE” and “MA AG II” cases), brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively, have been joined together and are presently pending before the FERC. Emera Maine has recorded a reserve of approximately $ 4 million USD for these cases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Stateme nts of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome.  Complaint IV was filed by the Eastern Massachusetts Consumer Owned Systems (“EMCOS”). On March 27, 2018, a FERC Administrative Law Judge issued an Ini tial Decision concluding that the currently filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. This decision was appealed to the FERC. No reserve has been made in relatio n to Complaint IV due to the uncertainty of the final outcome . On October 16, 2018, the FERC issued an order that addressed all four complaint proceedings. The FERC order proposed a new methodology to set ROEs. Based on the new methodology, the FERC’s pr eliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comment on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect t o any of the four pending complaints due to uncertainty. On Nov ember 21, 2019, the FERC approved an order affecting transmission ROEs in the Midcontinent ISO region (MISO) that alters the Commission’s methodology for analyzing the base return on equity component of a jurisdictional public utility’s rates. T he methodology applied in the M ISO case may be applied by the FERC in the pending ISO NE cases. No date for a decision has been made yet, but the FERC is expected to rule on these three outstanding ISO-NE cases in 2020 . Additionally, both the MISO case, and a decision in the ISO-NE case s, will be subject to further appeal rights and , if appealed, a final decision would be unlikely to occur before Q4 2020. Therefore, no change in Emera Maine’s accrual related to ROE complaints has been made as a result of the MISO decision. 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 wit h derivative instruments and fair value measurements are discussed in note 13 and note 14 . Sound risk management 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 . Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internati onally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affe ct 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 ea rnings exposure. The Company may enter 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 Company’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 speculativ e 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 will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, accept able pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs. Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions a nd 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 c apital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s abil ity to fund its growth plan. 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 framew ork, 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 sever weather events. A decrease in a cred it 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 operati ons. Emera manages this risk 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, preferred share units and deferred share units . Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financ ing 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 maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. 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 that 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 affect the economic viability of project development and acquisition initiatives. Commodity Price Risk A large portion of the Compa ny’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to br oader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidia ries permits the recovery of prudently incurred fuel costs . 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 o f existing tax laws to ensure 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, 2019 : TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The g uarantee is for a maximum potential amount of $ 45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which is expected to terminate on Janu ary 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. The Company has standby letters of credit and surety bonds in the amount of $ 82 million USD ( December 31, 2018 - $ 67 milli on USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds t ypically 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 letter of credit expires in June 2020 and is renewed annuall y. The amount committed as at December 31, 2019 was $ 52 million (December 31, 2018 - $ 49 million) . Collaborative Arrangement s For the years ended December 31, 2019 and 2018 , 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 2019 , NSPI recognized $ 19 million net expense ( 2018 - $ 1 9 million) in “Regulated fuel for generation and purchased power” and $ 3 million ( 2018 - $ 2 million) in OM&G .

Cumulative Preferred Stock

Cumulative Preferred Stock	12 Months Ended
	Dec. 31, 2019
Cumulative Preferred Stock
Cumulative Preferred Stock	27 . CUMULATIVE PREFERRED STOCK Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2019 December 31, 2018 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 3,864,636 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 2,135,364 $ 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 4.400 0.6388 1.84 August 15, 2020 25.00 Series B Series C (5) 4.100 1.1802 2.65 August 15, 2023 25.00 Series D Series F (6) 4.250 1.0625 2.63 February 15, 2020 25.00 Series G Minimum rate reset (3)(4) Series B 2.393 Floating 1.84 August 15, 2020 25.00 Series A Series H 4.900 1.2250 4.90 August 15, 2023 25.00 Series I Perpetual fixed rate Series E (7) 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 C was reset from $1.0250 to $1.1802 for the five-year period from and including August 15, 2018. (6) 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. (7) 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, 2019
Non-Controlling Interest in Subsidiaries
Non-Controlling Interest in Subsidiaries	28. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of Canadian dollars 2019 2018 Preferred shares of GBPC $ 14 $ 19 Domlec 21 22 $ 35 $ 41 Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual preferred shares. 2019 2018 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 20,000 $ 19 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: In June 2019, GBPC redeemed all outstanding preferred shares, replacing them with $ 10 million USD debt at 4 per cent and $ 10 million USD preferred shares at 6 per cent. The new 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, wit h the first payment scheduled for January 2020 . 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, 2019
29. Supplementary Information to Consolidated Statements of Cash Flows
Supplementary Information to Consolidated Statements of Cash Flows	29 . SUPPLEMENTARY INFORMATIO N TO CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year ended December 31 millions of Canadian dollars 2019 2018 Changes in non-cash working capital: Inventory $ (19) $ (44) Receivables and other current assets 154 (144) Accounts payable (137) 59 Other current liabilities (71) 13 Total non-cash working capital $ (73) $ (116) Supplemental disclosure of cash paid (received): Interest $ 750 $ 696 Income taxes $ (107) $ 33 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 187 $ 181 Increase in accrued capital expenditures $ 33 $ 50 Issuance of depository receipts $ - $ 22

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2019
Stock-Based Compensation
Stock-based Compensation	30 . 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, 2019, the plan allows employees to make cash contributions of a minimum of $ 25 to a maximum of $ 8,000 per year for the purpose of purc hasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any am ount up to $ 3,000 to the employee’s p lan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $3 ,000, up to the $ 8,000 maximum, the Company will contribute 10 per cent of that amount. The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common shares. A s at December 31 , 2019 , Emera is in compliance with this requirement. Compensation cost for shares issued by Emera for the year ended December 31, 2019 under the Employee Common Share Purchase Plan was $ 1 million ( 2018 – $ 1 million) and is included in “ OM&G” on the Consolidated Statements of Income. In November 2019, Emera’s Board of Directors approved changes to the ECSPP which are expected to be effective in 2020. These changes include increasing the maximum employee cas h contribution to $ 20,000 and changing the Company’s matching contribution to 20 per cent of the employees’ contributions. In addition, the Company match on dividends that exists within the current ECSPP plan will be discontinued. 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. In 2019, the discount was changed from 5 per cent to 2 per cent effective with the dividend payment of August 15 , 2019 . 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 ten 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, 2019 , 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 ten 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 sto cks 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 da te of termination for just cause, resignation or death. If stock options are not exercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and r ecognizes 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 : 2019 2018 Weighted average fair value per option $ 2.41 $ 1.70 Expected term (1) 6 years 6 years Risk-free interest rate (2) 1.82 % 2.13 % Expected dividend yield (3) 5.10 % 5.69 % Expected volatility (4) 14.32 % 13.71 % (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 2019 : 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, 2018 4,225,575 $ 39.56 1,679,325 $ 2.22 Granted 651,400 46.39 651,400 2.41 Exercised (2,568,625) 37.90 N/A N/A Vested N/A N/A (759,900) 2.37 Forfeited (21,800) 46.39 (21,800) 2.41 Expired N/A N/A N/A N/A Options outstanding December 31, 2019 2,286,550 $ 43.31 1,549,025 $ 2.22 Options exercisable December 31, 2019 (2)(3) 737,525 $ 41.43 (1) As at December 31, 2019, 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 2.4 years (2018 - $2 million, 2.2 years). (2) As at December 31, 2019, the weighted average remaining term of vested options was 5.5 years with an aggregate intrinsic value of $11 million (2018 - 5.1 years, $18 million). (3) As at December 31, 2019, the fair value of options that vested in the year was $2 million (2018 - $2 million). Compensation cost recognized for stock options for the year ended December 31, 2019 was $ 1 million ( 2018 – $ 1 million), which is included in “ OM&G ” on the Consolidated Statements of Income. As at December 31, 2019 , cash received from option exercises was $ 97 million ( 2018 – $ 1 million). The total intrinsic value of options exercised for the year ended December 31, 2019 was $ 32 million ( 2018 – $ 1 million). The range of exercise prices for the options outsta nding as at December 31, 2019 was $ 32.06 to $ 46.39 ( 2018 – $ 21. 99 to $ 46.19 ). Share Unit Plans The Company has DSU, PSU and RSU plans and the liabilities are marked-to-market at the end of each period based on the common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fe es 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 credit ed 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. Follo wing 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. Un der the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. When incentive awards are determined, the amount elected is conver ted 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 o f 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 i n 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 to achieve certain corporate objectives. A summary of the activity related to employee and director DSUs for the year ended December 31, 2019 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, 2018 837,109 $ 29.54 563,521 $ 37.07 Granted including DRIP 120,098 39.05 104,293 42.25 Exercised (252,610) 19.68 (136,360) 29.76 Outstanding and exercisable as at December 31, 2019 704,597 $ 34.69 531,454 $ 39.96 Compensation cost recognized for employee and director DSU for the year ended December 31, 2019 was $ 24 million ( 2018 – ( $ 2 million)). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2019 were $ 7 million ( 2018 – $ 1 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2019 for employees was $ 40 million ( 2018 - $ 37 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 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, 2019 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2018 1,127,114 $ 46.02 $ 56.9 Granted including DRIP 545,008 43.15 Exercised (140,754) 43.00 Forfeited (150,268) 44.41 Outstanding as at December 31, 2019 1,381,100 $ 45.37 $ 88.1 Compensation cost recognized for the PSU plan for the year ended December 31, 2019 was $ 34 million ( 2018 – $ 14 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2019 were $ 9 million ( 2018 – $ 4 million). Restricted Share Unit Plan In November 2019, a new RSU plan was approved by Emera’s Board of Directors, with grants to begin in 2020. Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annua lly for three-year overlapping 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 will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual serv ice over the performance cycle and may be pro-rated in certain departure scenarios.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
Variable Interest Entities
Variable Interest Entities	31 . VARIABLE INTEREST ENTITIES The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing VIEs . To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary b eneficiary 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 wh ere Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. 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 b uilding 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, accordingly, 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 from 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 existing 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. Amount s 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 purcha se all or a majority of the electricity generation at a fixed price. However, 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 generati ng facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2019 December 31, 2018 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) $ 554 $ 23 $ 545 $ 51

Comparative Information

Comparative Information	12 Months Ended
	Dec. 31, 2019
Comparative Information
Comparative Information	32 . 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.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
33. Subsequent Events
Subsequent Events	33 . SUBSEQUENT EVENTS These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 14, 2020 , the date the financial statements were issued.

Supplemental Financial Informat

Supplemental Financial Information	12 Months Ended
	Dec. 31, 2019
34. Supplemental Financial Information
Supplemental Financial Information	34 . 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, 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 For the year ended December 31, 2018 Operating revenues $ - $ - $ 4,432 $ 2,146 $ (54) $ 6,524 Operating expenses 45 - 3,468 1,665 (52) 5,126 Income (loss) from equity investments and subsidiaries 801 - 3 150 (800) 154 Other income (expenses), net 22 - 20 (27) (38) (23) Interest expense, net (1) 79 (40) 456 218 - 713 Income (loss) before provision for income taxes 699 40 531 386 (840) 816 Income tax expense (recovery) (47) 9 64 43 - 69 Net income (loss) 746 31 467 343 (840) 747 Non-controlling interest in subsidiaries - - - (1) 2 1 Preferred stock dividends 36 - 38 4 (42) 36 Net income (loss) attributable to common shareholders $ 710 $ 31 $ 429 $ 340 $ (800) $ 710 Comprehensive income (loss) of Emera Incorporated $ 1,249 $ 56 $ 973 $ 439 $ (1,468) $ 1,249 (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, 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 As at December 31, 2018 Assets Current assets $ 146 $ 67 1,767 $ 1,096 $ (244) $ 2,832 Property, plant and equipment 24 - 13,745 4,946 (3) 18,712 Other assets Regulatory assets - - 645 759 - 1,404 Goodwill - - 6,208 105 - 6,313 Other long-term assets 11,457 4,660 971 3,200 (17,235) 3,053 Total other assets 11,457 4,660 7,824 4,064 (17,235) 10,770 Total assets $ 11,627 $ 4,727 $ 23,336 $ 10,106 $ (17,482) $ 32,314 Liabilities and Equity Current liabilities $ 368 $ 695 $ 2,829 $ 926 $ (265) $ 4,553 Long-term liabilities Long-term debt 2,906 3,709 10,243 4,428 (6,994) 14,292 Deferred income taxes - 3 668 643 6 1,320 Regulatory liabilities - - 2,118 241 - 2,359 Other long-term liabilities 36 - 874 543 (21) 1,432 Total long-term liabilities 2,942 3,712 13,903 5,855 (7,009) 19,403 Total Emera Incorporated equity 8,317 320 6,604 3,303 (10,227) 8,317 Non-controlling interest in subsidiaries - - - 22 19 41 Total equity 8,317 320 6,604 3,325 (10,208) 8,358 Total liabilities and equity $ 11,627 $ 4,727 $ 23,336 $ 10,106 $ (17,482) $ 32,314 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, 2019 Net cash provided by (used in) by 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 - - 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, restricted cash and assets held for sale 147 (3) (141) (23) - (20) Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale (25) (39) (17) (17) - (98) Cash, cash equivalents, and restricted cash, beginning of year 20 58 104 190 - 372 Cash, cash equivalents, restricted cash and assets held for sale end of year $ (5) $ 19 $ 87 $ 173 $ - $ 274 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, 2018 Net cash provided by (used in) operating activities $ 191 $ 35 $ 1,266 $ 465 $ (267) $ 1,690 Investing activities Additions to property, plant and equipment (9) - (1,687) (466) - (2,162) Net purchase of investments subject to significant influence - - (16) (33) - (49) Other investing activities (489) - 3 (65) 572 21 Net cash provided by (used in) investing activities (498) - (1,700) (564) 572 (2,190) Financing activities Change in short-term debt, net - - (162) - - (162) Proceeds from long-term debt - - 1,174 75 (194) 1,055 Retirement of long-term debt - - (716) (41) - (757) Net borrowings (repayments) under committed credit facilities 136 - (103) 178 110 321 Issuance of common and preferred stock 301 - 319 127 (446) 301 Dividends paid (382) - (37) (311) 348 (382) Other financing activities - - - 91 (123) (32) Net cash provided by (used in) financing activities 55 - 475 119 (305) 344 Effect of exchange rate changes on cash, cash equivalents and restricted cash (4) 2 9 18 - 25 Net increase (decrease) in cash, cash equivalents, and restricted cash (256) 37 50 38 - (131) Cash, cash equivalents and restricted cash, beginning of year 276 21 54 152 - 503 Cash, cash equivalents and restricted cash, end of year $ 20 $ 58 $ 104 $ 190 $ - $ 372

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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 31 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. 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. Intercompany balances and intercompany 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-regul ated 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 n ature 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. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates.
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 the costs of providing the regulated products or services and provide a reasonable rate of retu rn on the equity invested or assets, as applicable (refer to n ote 15 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 bala nce 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 Stat es 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 balance 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 applicable 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 r ecognized on an accrual basis 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 bas is, 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 th e reporting period is calculated 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, weat her, line losses and inter-period 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, which 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 deli vered 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 expected 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 margin is comprised of Emera Energy’s corresponding 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 bas is, 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, which is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an aucti on 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, with the exception of gr oss 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 the 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 ass ociated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated 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 the 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 impli cit 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 lease 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 cost 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 l ease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value o f 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 for all leases.
Lease, Practical Expedient, Land Easement [true false]	true
Lease, Practical Expedient, Use of Hindsight [true false]	true
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 the 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 ass ociated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated 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 the 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 impli cit 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 lease 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 cost 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 l ease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value o f 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 for all leases.
Franchise Fees and Gross Receipts	Franchise Fees and Gross Receipts Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts include d in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are includ ed 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 gros s basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated 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 construction. The cost of additions, including betterments and r eplacements 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 included in income as the dispositions occur. The cost of property, plant an d equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and executive 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 the overall life of the related as sets are expensed. When a major mainten ance 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 o f depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and equipment” consist primarily of computer software, land rights and nami ng rights with definite lives. 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 met hod which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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 estimated fair values of 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 f or the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to an annual assessment for impairmen t at the reporting unit level. Refer to note 21 for further detail.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits Emera rec ognizes 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 betwee n 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. Emera recognizes the effect of income tax posi tions 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-looking information, and the likelihood that deferred tax assets will be recovered from fu ture 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 determines that it is likely that some or all of a deferred income tax asset will not be r ealized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded 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, NMGC and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by regulatory practices. Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income ta x liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 8 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 i nstruments are considered 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 the 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 physic al delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contra cts 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 o f 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 reporting 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 e xception 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. Mana gement believes any gains or losses resulting from settlement of these derivatives 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 v alue normally recorded in net income of the period, unless deferred as a re sult of regulatory accounting. The Company has 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, inventory and property, operating maintenance and general and plant and equipment, depending on the nature of the i tem being economi cally hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in t he 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 refl ected 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 coll ateral are recognized in “Accounts payable”.
Cash, Cash Equivalents and Restricted Cash	Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. T here were no short-term investments at December 31, 2019 ( 2018 - $ 43 million with a n effective interest rate of 2.0 per cent).
Receivables and Allowance for Doubtful Accounts	Receivables and Allowance for Doubtful Accounts 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 customers. Credit assessments may be conducted on new customers. Deposits are requested accounts as r equired. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and t he charact eristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adeq uate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectib le.
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 rates.
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. As a result of the damage caused by Hurricane Dorian, the Company completed an asset impairment analysis in Q4 2019. P roperty, plant and equipment and inventory with a book value of a pproximately $ 18 million USD was determined to be impaired and was reclassified as a regulatory asset. GBPC recorded an offsetting insurance receivable of $ 15 million USD against this regulatory asset. It is anticipated that the regulatory asset balance of $ 3 million USD remaining at December 31, 2019 will be recovered through insurance. Refer to note 15 for further details. No impairment was recorded in 2018 . Goodwill Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. 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 . En tities assessing goodwill for impairment have 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, macroeconom ic conditions, industry and market considerations and overall financial performance. If an entity 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 an entity choos es 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 its 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 income approach is a pplied 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 entity’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 average 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 discount and growth rates , rate case assumptions, valuation of Emera’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 assumptions described above could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill. In Q4 2019 , the Company performed quantitative impairment assessments at the reporting unit level. The quantitative assessments for Tampa Electric, PGS and NMGC concluded that the fair value of the reporting units exceeded their respective carrying amounts. However, it was determined that including the impacts of Hurricane Dorian, the fair value of GBPC did not exceed its carrying amount. As a result of this assessment, a goodwill impairment 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. No impairment was recorded in 2018 . Refer to note 21 for further details. Emera Maine’s assets and liabilities are classified as held for sale, including $148 million of goodwill, and are measured at the lower of their carrying value or fair value less costs to sell. The measurement did not result in a fair value adjustment and goodwi ll is not impaired. Refer to note s 4 and 21 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. 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 requi red for either 2018 or 2019. 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 inves tments 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 material impairment o f financial assets was required for either 2018 or 2019.
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 statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash f lows 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, pri or 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 depr eciated 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 and equipment” and included in the next depreciation study. As at December 31, 2019 and 2018 , 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 obligat ion to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be wit hin the control of the entity. Management monitors these obligations and a liability is recognized at fa ir value in the period in which an amount can be determined. Cost of Removal Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs 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 retirement. 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 experien ce 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 grant date, based on the calculated fair value of the award, and is recogn ized 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 measured at fair value and re-measured at fair value at each reporting dat e 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 the 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 recognizes 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 Income
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 have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or have an insignificant impact on the consolidated financial statements. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments . T he 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, including 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 experien ce, 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 Company adopted ASU 2016-13 effective January 1, 2020, with no significant changes to accounting and disclosure identified related to the adoption of the standard. Simplifying 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 related to the approach for intraperiod tax allocation, 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 will be effective for annual reporting periods, including interim reporting within those periods, beginnin g after December 15, 2020, with early adoption permitted. The standard will be applied on both a prospe ctive and retrospective basis. The Company is currently evaluatin g the impact of adoption of the standard on its consolidated financial statements .

Dispositions (Tables)

Dispositions (Tables) - Held for sale	12 Months Ended
	Dec. 31, 2019
Emera Maine
Details of the assets and liabilities classified as held for sale [Line items]
Details of the assets and liabilities classified as held for sale	Details of Emera Maine's assets and liabilities classified as held for sale are as follows: As at December 31 millions of Canadian dollars 2019 Regulatory assets $ 16 Receivables and other current assets 69 Current assets held for sale 85 Property, plant and equipment 1,293 Goodwill 148 Regulatory assets 122 Other long-term assets 56 Long-term assets held for sale 1,619 Total assets held for sale $ 1,704 Regulatory liabilities $ 11 Accounts payable and other current liabilities 103 Current liabilities associated with assets held for sale 114 Long-term debt 467 Deferred income taxes 204 Regulatory liabilities 145 Other long-term liabilities 83 Long-term liabilities associated with assets held for sale 899 Total liabilities associated with assets held for sale $ 1,013
New England Gas Generating Facilities
Details of the assets and liabilities classified as held for sale [Line items]
Details of the assets and liabilities classified as held for sale	Details of NEGG's assets and liabilities classified as held for sale at December 31, 2018 are as follows: As at December 31 millions of Canadian dollars 2018 Receivables and other current assets $ 40 Inventory 13 Current assets held for sale 53 Property, plant and equipment 777 Long-term assets held for sale 777 Total assets held for sale $ 830 Accounts payable and other current liabilities $ 20 Current liabilities associated with assets held for sale 20 Other long-term liabilities 2 Long-term liabilities associated with assets held for sale 2 Total liabilities associated with assets held for sale $ 22

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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 AFUDC - debt and equity 20 6 5 2 - - 33 Depreciation and amortization 445 231 107 109 11 - 903 Interest expense, net 154 142 52 59 331 - 738 Internally allocated interest (2) - - - 14 (14) - - Income from equity investments - 91 5 22 36 - 154 Income tax expense (recovery) 79 (10) 11 48 (67) - 61 Operating, maintenance and general ("OM&G") 554 313 195 319 130 (47) 1,464 GBPC impairment charge - - 34 - - - 34 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. 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, 2018 Operating revenues from external customers (1) $ 2,670 $ 1,437 $ 745 $ 1,062 $ 610 $ - $ 6,524 Inter-segment revenues (1) 9 3 - 36 51 (99) - Total operating revenues 2,679 1,440 745 1,098 661 (99) 6,524 AFUDC - debt and equity 20 6 3 1 - - 30 Depreciation and amortization 405 219 114 129 49 - 916 Interest expense, net 132 139 48 55 339 - 713 Internally allocated interest (2) - - - 14 (14) - - Income from equity investments - 87 6 22 39 - 154 Income tax expense (recovery) 85 8 9 47 (80) - 69 OM&G 667 286 188 295 206 (62) 1,580 Net income (loss) attributable to common shareholders 381 218 85 135 (109) - 710 Capital expenditures 1,217 345 187 330 72 - 2,151 As at December 31, 2018 Total assets 15,997 6,275 3,094 5,404 2,653 (1,109) (3) 32,314 Investments subject to significant influence - 1,079 77 155 5 - 1,316 Goodwill 4,774 - 260 1,279 - - 6,313 (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 2019 2018 Canada $ 1,497 $ 1,520 United States 4,140 4,537 Barbados 320 319 The Bahamas 112 121 Dominica 42 27 $ 6,111 $ 6,524 (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 2019 2018 Canada $ 4,248 $ 4,128 United States (1) 13,095 13,739 Barbados 462 446 The Bahamas 282 315 Dominica 80 84 $ 18,167 $ 18,712 (1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to note 4 for further details.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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. 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, 2018 Regulated Electric Revenue Residential $ 1,384 $ 731 $ 261 $ - $ - $ - $ 2,376 Commercial 755 405 350 - - - 1,510 Industrial 209 233 46 - - - 488 Other electric and regulatory deferrals 312 43 16 - - - 371 Other (1) 19 28 72 - - (12) 107 Regulated electric revenue 2,679 1,440 745 - - (12) 4,852 Gas Revenue Residential - - - 492 - - 492 Commercial - - - 291 - - 291 Industrial - - - 49 - - 49 Finance income (2)(3) - - - 57 - - 57 Other - - - 191 - (36) 155 Regulated gas revenue - - - 1,080 - (36) 1,044 Non-Regulated Marketing and trading margin (4) - - - - 115 - 115 Energy sales (4) - - - - 309 (16) 293 Capacity - - - - 136 - 136 Other - - - 18 47 (35) 30 Mark-to-market (3) - - - - 54 - 54 Non-regulated revenue - - - 18 661 (51) 628 Total operating revenues $ 2,679 $ 1,440 $ 745 $ 1,098 $ 661 $ (99) $ 6,524 (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.

Investments Subject to Signif_2

Investments Subject to Significant Influence and Equity Income (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2019 2018 2019 LIL (1) $ 579 $ 534 $ 45 $ 42 49.5 NSPML 554 545 46 45 100.0 M&NP (2) 138 155 22 22 12.9 Lucelec (2) 41 42 3 3 19.1 Bear Swamp (3) - - 35 38 50.0 Other Investments - 40 3 4 $ 1,312 $ 1,316 $ 154 $ 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 a result of a $179 million distribution received in 2015. Bear Swamp's credit investment balance of $137 million (2018 - $172 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 31 ). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2019 2018 Balance Sheets Current assets $ 69 $ 86 Property, plant and equipment 1,671 1,690 Regulatory assets 177 108 Non-current assets 32 32 Total assets $ 1,949 $ 1,916 Current liabilities $ 23 $ 21 Long-term debt (1) 1,288 1,288 Non-current liabilities 84 62 Equity 554 545 Total liabilities and equity $ 1,949 $ 1,916 (1) The project debt has been guaranteed by the Government of Canada.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
8. 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 Nova Scotia and New Brunswick provincial statutory income tax rate for the following reasons: millions of Canadian dollars 2019 2018 Income before provision for income taxes $ 771 $ 816 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 239 253 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (66) (59) Foreign tax rate variance (49) (55) Amortization of deferred income tax regulatory liabilities (36) (37) Tax effect of equity earnings (15) (15) GBPC impairment charge 11 - Investment tax credits (9) (4) Change in treatment of NMGC net operating loss carryforwards (7) - Florida state tax apportionment adjustment - (23) Change in prior year unrecognized tax benefits at NSPI - 7 Other (7) 2 Income tax expense $ 61 $ 69 Effective income tax rate 8% 8%
Composition of taxes on income from continuing operations	millions of Canadian dollars 2019 2018 Current income taxes Canada $ (19) $ 3 United States (46) (121) Other 1 2 Deferred income taxes Canada 45 11 United States 137 215 Other - (4) Investment tax credits United States (9) (4) Operating loss carryforwards Canada (48) (33) Income tax expense (recovery) $ 61 $ 69 The following 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 2019 2018 Canada $ 98 $ 127 United States 682 646 Other (9) 43 Income before provision for income taxes $ 771 $ 816
Composition of income before provision for income taxes	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 2019 2018 Deferred income tax assets: Tax loss carryforwards $ 908 $ 917 Tax credit carryforwards 311 269 Regulatory liabilities - cost of removal 195 206 Derivative instruments 145 90 Pension and post-retirement liabilities 84 126 Other 329 441 Total deferred income tax assets before valuation allowance 1,972 2,049 Valuation allowance (193) (163) Total deferred income tax assets after valuation allowance $ 1,779 $ 1,886 Deferred income tax (liabilities): Property, plant and equipment $ (2,382) $ (2,591) Derivative instruments (148) (124) Other (348) (316) Total deferred income tax liabilities $ (2,878) $ (3,031) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 186 $ 175 Long-term deferred income tax liabilities (1,285) (1,320) Net deferred income tax liabilities $ (1,099) $ (1,145)
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, 2019 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 1,131 $ (554) $ 577 2027-2039 Capital loss 80 (80) - Indefinite United States Federal NOL $ 2,394 $ - $ 2,394 2024-2037 State NOL 1,174 - 1,174 2024-2039 Tax credit 311 - 311 2020-Indefinite Other NOL $ 38 $ (38) $ - 2020-2026
Details of the change in unrecognized tax benefits	millions of Canadian dollars 2019 2018 Balance, January 1 $ 26 $ 19 Increases due to tax positions related to current year 2 - Increases due to tax positions related to a prior year 1 8 Decreases due to tax positions related to a prior year - (1) Balance, December 31 $ 29 $ 26

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2019
Common Stock
Common Stock	Authorized : Unlimited number of non-par value common shares. 2019 2018 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2018 234.12 $ 5,816 228.77 $ 5,601 Conversion of Convertible Debentures 0.03 1 0.01 - Issuance of common stock (1) 1.77 99 0.45 22 Issued under Purchase Plans at market rate 3.99 202 4.87 200 Discount on shares purchased under Dividend Reinvestment Plan - (7) - (9) Options exercised under senior management share option plan 2.57 104 0.02 1 Employee Share Purchase Plan - 1 - 1 Balance, December 31, 2019 242.48 $ 6,216 234.12 $ 5,816 (1) As at December 31, 2019 a total of 1.77 million common shares have been issued through Emera's at-the-market equity program ("ATM Program") at an average price of $56.56 per share for gross proceeds of $100 million ($98.7 million net of issuance costs).

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
10. 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) 2019 2018 Numerator Net income attributable to common shareholders $ 662.8 $ 709.6 Diluted numerator 662.8 709.6 Denominator Weighted average shares of common stock outstanding 238.5 231.7 Weighted average deferred share units outstanding 1.4 1.3 Weighted average shares of common stock outstanding – basic 239.9 233.0 Stock-based compensation 0.6 0.4 Convertible Debentures - 0.1 Weighted average shares of common stock outstanding – diluted 240.5 233.5 Earnings per common share Basic $ 2.76 $ 3.05 Diluted $ 2.76 $ 3.04

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2019
11. 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, 2019 Balance, January 1, 2019 $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 Other comprehensive income (loss) before reclassifications (401) 78 3 - - (320) Amounts reclassified from accumulated other comprehensive income loss (gain) - - 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 For the year ended December 31, 2018 Balance, January 1, 2018 (1) $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) Other comprehensive income (loss) before reclassifications 624 (122) 2 - - 504 Amounts reclassified from accumulated other comprehensive income loss (gain) - - (6) (4) 9 (1) Net current period other comprehensive income (loss) 624 (122) (4) (4) 9 503 Balance, December 31, 2018 $ 654 $ (74) $ (7) $ (1) $ (234) $ 338 (1) The January 1, 2018 balance of AOCI and Regulatory assets includes a prior period reclassification of $37 million in unrecognized pension and post-retirement benefit costs and $15 million in deferred taxes ($22 million, net of tax) to be consistent with current year presentation.
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 2019 2018 Affected line item in the Consolidated Financial Statements Losses (gain) on derivatives recognized as cash flow hedges Foreign exchange forwards Operating revenue - regulated $ 3 $ (5) Power and gas swaps Non-regulated fuel for generation and purchased power - (1) Total before tax 3 (6) Total net of tax $ 3 $ (6) Net change in available-for-sale investments Retained earnings (1) - (4) Total net of tax $ - $ (4) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 17 $ 25 Past service costs (gains) OM&G (1) (1) Amounts reclassified into obligations Pension and post-retirement benefits 39 (17) Amounts reclassified into obligations Regulatory assets 28 - Total before tax 83 7 Income tax recovery (expense) (9) 2 Total net of tax $ 74 $ 9 Total reclassifications out of AOCI, net of tax, for the period $ 77 $ (1) (1) Related to the adoption of ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Refer to note 2 for additional detail.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
12. Inventory
Inventory	As at December 31 December 31 millions of Canadian dollars 2019 2018 Fuel $ 232 $ 213 Materials 235 241 Emission credits - 20 $ 467 $ 474

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
13. 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 2019 2018 2019 2018 Cash flow hedges Foreign exchange forwards $ - $ - $ 1 $ 5 - - 1 5 Regulatory deferral Commodity swaps and forwards Coal purchases 8 71 39 1 Power purchases 23 2 36 1 Natural gas purchases and sales 2 2 5 4 Heavy fuel oil purchases 1 1 - 1 Foreign exchange forwards 2 29 6 - 36 105 86 7 HFT derivatives Power swaps and physical contracts 19 62 22 76 Natural gas swaps, futures, forwards, physical contracts 151 125 381 403 170 187 403 479 Other derivatives Equity derivatives and interest rate swaps 1 1 - - 1 1 - - Total gross current derivatives 207 293 490 491 Impact of master netting agreements with intent to settle net or simultaneously (120) (126) (120) (126) 87 167 370 365 Current 54 148 268 260 Long-term 33 19 102 105 Total derivatives $ 87 $ 167 $ 370 $ 365 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 2019 2018 2019 2018 Regulatory deferral $ 8 $ 1 $ 8 $ 1 HFT derivatives 112 125 112 125 Total impact of master netting agreements with intent to settle net or simultaneously $ 120 $ 126 $ 120 $ 126
Cash flow hedges recorded in income and AOCI	For the Year ended December 31 millions of Canadian dollars 2019 2018 Foreign Foreign exchange Power exchange forwards swaps forwards Realized gain (loss) in operating revenue – regulated (3) - 5 Realized gain (loss) in non-regulated fuel for generation and purchased power - 1 - Total gains (losses) in Net income $ (3) $ 1 $ 5 As at December 31 millions of Canadian dollars 2019 2018 Foreign Foreign exchange Power exchange forwards swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ (1) $ (1) $ (6) The Company expects $1 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle. As at December 31, 2019, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2020 Foreign exchange forwards (USD) sales $ 30
Realized and unrealized gains (losses) with respect to derivatives	For the Year ended December 31 millions of Canadian dollars 2019 2018 Commodity swaps and forwards Foreign exchange forwards Commodity swaps and forwards Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (89) $ (6) $ (34) $ 4 Unrealized gain (loss) in regulatory liabilities 9 (8) 29 24 Realized (gain) loss in regulatory liabilities (2) - (8) - Realized (gain) loss in inventory (1) (36) (11) (55) (18) Realized (gain) loss in regulated fuel for generation and purchased power (2) 3 (8) (2) (9) Total change derivative instruments $ (115) $ (33) $ (70) $ 1 (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; hedging relationships that have been terminated or the hedged transaction is no longer probable. For the Year ended December 31 millions of Canadian dollars 2019 2018 Power swaps and physical contracts in non-regulated operating revenues $ 1 $ (12) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 281 205 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (6) 2 $ 276 $ 195 For the Year ended December 31 millions of Canadian dollars 2019 2018 Equity Interest rate derivatives swaps Unrealized gain in operating, maintenance and general $ 1 $ - Unrealized gain (loss) in interest expense, net - (1) Realized gain in operating, maintenance and general 27 - Total gains (losses) in net income $ 28 $ (1)
Notional volumes of derivatives designated for regulatory deferral that are expected to settle as outlined	2020 2021-2022 millions Purchases Purchases Coal (metric tonnes) - 1 Natural Gas (Mmbtu) 12 21 Heavy fuel oil (bbls) - 1 Power (MWh) 1 3 2020 2021-2022 Foreign exchange contracts (millions of US dollars) $ 173 $ 148 Weighted average rate 1.3148 1.3264 % of USD requirements 85% 39% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required. millions 2020 2021 2022 2023 2024 Natural gas purchases (Mmbtu) 424 84 56 41 26 Natural gas sales (Mmbtu) 345 33 9 2 2 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - -
Concentration Risk	Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2019 December 31, 2018 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 344 31% $ 384 28% Commercial 170 15% 182 13% Industrial 66 6% 57 4% Other 131 12% 84 6% 711 64% 707 51% Trading group Credit rating of A- or above 38 3% 49 4% Credit rating of BBB- to BBB+ 59 5% 70 5% Credit rating of CCC- to CCC+ - 0% 8 0% Not rated 95 9% 108 8% 192 17% 235 17% Other accounts receivable 184 16% 273 20% Classification as assets held for sale (1) (55) -5% - 0% 1,032 92% 1,215 88% Derivative Instruments (current and long-term) Credit rating of A- or above 47 4% 130 9% Credit rating of BBB- to BBB+ 8 1% 9 1% Not rated 32 3% 28 2% 87 8% 167 12% $ 1,119 100% $ 1,382 100% (1) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details.
Cash Collateral	As at December 31 December 31 millions of Canadian dollars 2019 2018 Cash collateral provided to others $ 101 $ 103 Cash collateral received from others 2 77

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
14. Fair Value Measurements
Classification of the methodology used by the Company to fair value its derivatives	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 purchases 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) As at December 31, 2018 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral Commodity swaps and forwards Coal purchases - 70 - 70 Power purchases 2 - - 2 Natural gas purchases and sales - 2 - 2 Heavy fuel oil purchases - 1 - 1 Foreign exchange forwards - 29 - 29 2 102 - 104 HFT derivatives Power swaps and physical contracts 2 2 3 7 Natural gas swaps, futures, forwards, physical contracts and related transportation 1 36 18 55 3 38 21 62 Other derivatives Interest rate swap - 1 - 1 - 1 - 1 Total assets 5 141 21 167 Liabilities Cash flow hedges Foreign exchange forwards - 5 - 5 - 5 - 5 Regulatory deferral Commodity swaps and forwards Coal purchases - 1 - 1 Power purchases 1 - - 1 Heavy fuel oil purchases - 1 - 1 Natural gas purchases and sales 3 - - 3 4 2 - 6 HFT derivatives Power swaps and physical contracts 14 6 1 21 Natural gas swaps, futures, forwards and physical contracts - 28 305 333 14 34 306 354 Total liabilities 18 41 306 365 Net assets (liabilities) $ (13) $ 100 $ (285) $ (198)
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, 2019 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2019 $ 3 $ 18 $ 21 Total realized and unrealized gains (losses) included in non-regulated operating revenues (2) (4) (6) Balance, December 31, 2019 $ 1 $ 14 $ 15 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2019 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2019 $ 1 $ 305 $ 306 Total realized and unrealized gains (losses) included in non-regulated operating revenues (1) (56) (57) Balance, December 31, 2019 $ - $ 249 $ 249 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, 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) As at December 31, 2018 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 3 Modelled pricing Third-party pricing $24.31 - $50.29 $31.43 Power swaps and Probability of default 0.03% - 0.13% 0.13% physical contracts Discount rate 0.03% - 2.19% 1.45% Correlation factor 84.98% - 84.98% 84.98% HFT derivatives – 8 Modelled pricing Third-party pricing $1.80 - $12.21 $4.75 Natural gas swaps, Probability of default 0.01% - 2.94% 0.24% futures, forwards, Discount rate 0.01% - 30.62% 4.25% physical contracts 10 Modelled pricing Third-party pricing $1.95 - $12.90 $8.68 and related transportation Basis adjustment $0.07 - $3.43 $1.88 Probability of default 0.01% - 3.20% 0.57% Discount rate 0.01% - 7.61% 0.42% Total assets $ 21 Liabilities HFT derivatives – 1 Modelled pricing Third-party pricing $20.80 - $50.29 $26.38 Power swaps and Correlation factor 84.98% - 84.98% 84.98% physical contracts Probability of default 0.08% - 0.29% 0.15% Discount rate 0.03% - 2.99% 1.65% HFT derivatives – 286 Modelled pricing Third-party pricing $1.48 - $12.90 $5.75 Natural gas swaps, futures, Own credit risk 0.01% - 2.94% 0.09% forwards and physical contracts Discount rate 0.01% - 11.96% 2.35% 19 Modelled pricing Third-party pricing $2.15 - $13.18 $7.54 Basis adjustment $0.07 - $3.43 $2.67 Own credit risk 0.01% - 2.76% 0.10% Discount rate 0.01% - 7.61% 1.38% Total liabilities $ 306 Net assets (liabilities) $ (285)
Financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value	The financial liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2019 $ 14,180 $ 16,049 $ - $ 15,598 $ 451 $ 16,049 December 31, 2018 $ 15,411 $ 15,908 $ - $ 14,991 $ 917 $ 15,908

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
15. Regulatory Assets and Liabilities
Regulatory Assets	As at December 31 December 31 millions of Canadian dollars 2019 (1) 2018 Regulatory assets Deferred income tax regulatory assets $ 862 $ 775 Pension and post-retirement medical plan 380 453 Deferrals related to derivative instruments 81 10 Storm restoration regulatory asset 38 32 Stranded cost recovery 27 28 Environmental remediations 26 31 Demand side management ("DSM") deferral 19 24 Unamortized defeasance costs 19 26 Cost recovery clauses 13 75 Other 87 115 $ 1,552 $ 1,569 Current $ 121 $ 165 Long-term 1,431 1,404 Total regulatory assets $ 1,552 $ 1,569 Regulatory liabilities Deferred income tax regulatory liabilities 985 1,218 Accumulated reserve - cost of remova l 891 955 Regulated fuel adjustment mechanism 115 161 Storm reserve 62 76 Cost recovery clauses 53 30 Deferrals related to derivative instruments 42 116 Self-insurance fund (note 31) 29 30 Other 4 24 $ 2,181 $ 2,610 Current $ 295 $ 251 Long-term 1,886 2,359 Total regulatory liabilities $ 2,181 $ 2,610 (1) On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Refer to note 4 for further details.
Regulatory Liabilities	As at December 31 December 31 millions of Canadian dollars 2019 (1) 2018 Regulatory assets Deferred income tax regulatory assets $ 862 $ 775 Pension and post-retirement medical plan 380 453 Deferrals related to derivative instruments 81 10 Storm restoration regulatory asset 38 32 Stranded cost recovery 27 28 Environmental remediations 26 31 Demand side management ("DSM") deferral 19 24 Unamortized defeasance costs 19 26 Cost recovery clauses 13 75 Other 87 115 $ 1,552 $ 1,569 Current $ 121 $ 165 Long-term 1,431 1,404 Total regulatory assets $ 1,552 $ 1,569 Regulatory liabilities Deferred income tax regulatory liabilities 985 1,218 Accumulated reserve - cost of remova l 891 955 Regulated fuel adjustment mechanism 115 161 Storm reserve 62 76 Cost recovery clauses 53 30 Deferrals related to derivative instruments 42 116 Self-insurance fund (note 31) 29 30 Other 4 24 $ 2,181 $ 2,610 Current $ 295 $ 251 Long-term 1,886 2,359 Total regulatory liabilities $ 2,181 $ 2,610 (1) On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Refer to note 4 for further details.

Receivables and Other Current_2

Receivables and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2019
17. Receivables and Other Current Assets
Summary of Receivables And Other Current Assets	17. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2019 2018 Customer accounts receivable – billed $ 704 $ 844 Customer accounts receivable – unbilled 265 296 Allowance for doubtful accounts (9) (11) Other receivables 72 86 Capitalized transportation capacity (1) 272 179 Income tax receivable 118 175 Prepaid expenses 48 42 Net investment in direct financing lease (note 18 ) 9 9 Other current assets 7 - $ 1,486 $ 1,620 (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, 2019
19. 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 2019 (1) 2018 Generation (2) 3 to 131 $ 11,181 $ 11,092 Transmission 11 to 80 2,318 3,047 Distribution 4 to 80 5,820 6,348 Gas transmission and distribution 7 to 85 3,546 3,398 General plant and other 2 to 60 2,006 2,158 Total cost 24,871 26,043 Less: Accumulated depreciation (2) (8,295) (8,567) 16,576 17,476 Construction work in progress 1,591 1,236 Net book value $ 18,167 $ 18,712 (1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to the note 4 for further details. (2) On March 29, 2019, the Company sold its NEGG facilities. As of December 31, 2018, the Company classified these assets as held for sale on the Consolidated Balance Sheets. Refer to note 4 for additional information.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
20. 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 2019 2018 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 $ 2,650 $ 350 $ 2,683 $ 356 Service cost 47 4 51 6 Plan participant contributions 8 5 8 5 Interest cost 102 14 95 13 Benefits paid (130) (23) (143) (33) Actuarial (gains) losses 231 19 (133) (25) Settlements and curtailments (20) - (18) - Foreign currency translation adjustment (66) (16) 107 28 Balance, December 31 2,822 353 2,650 350 Change in plan assets Balance, January 1 2,300 49 2,408 45 Employer contributions 52 19 51 31 Plan participant contributions 8 5 8 5 Benefits paid (130) (23) (143) (33) Actual return on assets, net of expenses 424 7 (105) (3) Settlements and curtailments (7) - (18) - Foreign currency translation adjustment (54) (1) 99 4 Balance, December 31 2,593 56 2,300 49 Funded status, end of year $ (229) $ (297) $ (350) $ (301)
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 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,797 $ 323 $ 2,623 $ 318 Fair value of plan assets 2,557 7 2,264 6 Funded status $ (240) $ (316) $ (359) $ (312) millions of Canadian dollars 2019 2018 Defined benefit pension plans Defined benefit pension plans ABO $ 2,665 $ 2,504 Fair value of plan assets 2,557 2,264 Funded status $ (108) $ (240)
Amounts recognized in the Consolidated Balance Sheets	As at December 31 December 31 millions of Canadian dollars 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (4) $ (18) $ (12) $ (19) Long-term liabilities (206) (254) (347) (294) Long-term liabilities associated with assets held for sale (1) (30) (44) - - Other long-term assets 11 19 9 11 Amount included in deferred income tax (7) 1 5 (2) AOCI, net of tax and regulatory assets 524 72 628 60 Net amount recognized $ 288 $ (224) $ 283 $ (244) (1) On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine's assets and liabilities were classified as held for sale. Refer to note 4 for further details.
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, 2019 $ 389 $ 246 $ (2) Amortized in current period (20) (17) 1 Current year addition to AOCI or regulatory assets 6 (69) - Change in foreign exchange rate (17) - - Balance, December 31, 2019 $ 358 $ 160 $ (1) Non-pension benefits plans Balance, January 1, 2019 $ 65 $ (7) $ - Amortized in current period 5 - - Current year addition to AOCI or regulatory assets 11 2 - Change in foreign exchange rate (3) - - Balance, December 31, 2019 $ 78 $ (5) $ - 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 160 $ (5) $ 246 $ (7) Past service (gains) costs (1) - (2) - Regulatory assets 358 78 389 65 Total AOCI and regulatory assets before deferred income taxes 517 73 633 58 Amount included in deferred income tax assets 7 (1) (5) 2 Net amount in AOCI and regulatory assets $ 524 $ 72 $ 628 $ 60
Benefit Cost Components	As at Year ended December 31 millions of Canadian dollars 2019 2018 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 47 $ 4 $ 51 $ 6 Interest cost 102 14 95 13 Expected return on plan assets (147) (2) (138) (2) Current year amortization of: Actuarial losses 16 - 33 (1) Past service costs (gains) (1) - (1) - Regulatory assets (liability) 20 (5) 26 (2) Settlement, curtailments 1 - 4 - Total $ 38 $ 11 $ 70 $ 14
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 40% to 45% Equities 55% to 60%
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, 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 % December 31, 2018 Cash and cash equivalents $ - $ 30 $ - $ 30 1 % Net in-transits - (56) - (56) -2 % Equity securities: Canadian equity - 191 - 191 8 % US equity - 330 - 330 14 % Other equity - 157 - 157 7 % Fixed Income securities: Government - - 119 119 5 % Corporate - - 108 108 5 % Other - 4 3 7 - Mutual funds - 132 - 132 6 % Other - 8 4 12 1 % Open-ended investments measured at NAV (1) 820 - - 820 36 % Common collective trusts measured at NAV (2) 450 - - 450 19 % Total $ 1,270 $ 796 $ 234 $ 2,300 100 % (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 (1) Non-pension benefit plans (2) Expected employer contributions 2020 $ 44 $ 21 Expected benefit payments 2020 143 23 2021 154 23 2022 158 23 2023 165 23 2024 173 23 2025 – 2029 959 115 (1) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $10 million in 2020; $10 million in 2021; $11 million in 2022; $11 million in 2023; $12 million in 2024 and $62 million in 2025-2029. (2) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $3 million in 2020; $3 million in 2021; $3 million in 2022; $3 million in 2023; $4 million in 2024 and $17 million in 2025-2029.
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: 2019 2018 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 3.17 % 3.27 % 4.05 % 4.30 % Discount rate - future service 3.21 % 3.28 % 4.05 % 4.30 % Rate of compensation increase 3.32 % 3.70 % 3.30 % 3.67 % Health care trend - initial (next year) - 6.15 % - 6.39 % - ultimate - 4.38 % - 4.45 % - year ultimate reached - 2038 - 2035 Benefit cost for year ended December 31: Discount rate - past and future service 4.05 % 4.30 % 3.55 % 3.65 % Expected long-term return on plan assets 6.50 % 2.81 % 6.38 % 3.73 % Rate of compensation increase 3.30 % 3.67 % 3.12 % 3.28 % Health care trend - initial (current year) - 6.39 % - 6.65 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2036 Figures shown are weighted averages. Actual assumptions used differ by plan.
Sensitivity Analysis for Non-Pension Benefits Plans and Defined Benefit Pension Plans	millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 16 (14) millions of Canadian dollars Increase Decrease Discount rate assumption $ (9) $ 9 Asset rate assumption (6) 6
Amounts to be Amortized in the Next Fiscal Year	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 2020: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (14) $ - Past service gains (1) - Regulatory assets (29) (1) Total $ (44) $ (1)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
18. Leases
Lessee, Operating Lease and additional information	As at December 31 millions of Canadian dollars Classification 2019 Right-of-use asset Other long-term assets $ 64 Lease liabilities Current Other current liabilities 5 Long-term Other long-term liabilities 61 Total lease liabilities $ 66 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions of Canadian dollars) $ 7 Right-of-use assets obtained in exchange for lease obligations: Operating leases (millions of Canadian dollars) $ 16 Weighted average remaining lease term (years) 39 Weighted average discount rate- operating leases 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 2020 2021 2022 2023 2024 Thereafter Total Minimum lease payments $ 8 $ 8 $ 7 $ 6 $ 5 $ 102 $ 136 Less imputed interest (70) Total $ 8 $ 8 $ 7 $ 6 $ 5 $ 102 $ 66
Net Investment in direct finance leases	As at December 31 millions of Canadian dollars 2019 Total minimum lease payment to be received $ 1,066 Less: amounts representing estimated executory costs (189) Minimum lease payments receivable $ 877 Estimated residual value of leased property (unguaranteed) 183 Less: unearned finance lease income (532) Net investment in direct finance and sales-type leases $ 528 Principal due within one year (included in "Receivables and other current assets") 17 Net investment in sales-type leases - long-term (included in "Other long-term assets") 38 Net Investment in direct finance leases - long-term $ 473 (1) The net investment in direct finance lease balance as of December 31, 2018, primarily related to New Brunswick Pipeline, consisted of net minimum lease payments receivable of $865 million less an unguaranteed residual value of $183 million and unearned finance income of $564 million.
Future minimum lease payments to be received for the next five years	As at December 31, 2019, 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 2020 2021 2022 2023 2024 Thereafter Total Minimum lease payments to be received $ 76 $ 74 $ 73 $ 73 $ 74 $ 696 $ 1,066 Less: executory costs (189) Minimum lease payments receivable $ 76 $ 74 $ 73 $ 73 $ 74 $ 696 $ 877

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
21. Goodwill
Change in goodwill	21. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2019 2018 Balance, January 1 $ 6,313 $ 5,805 Additions 3 - GBPC i mpairment charge (30) - Classified as assets held for sale (1) (148) - Change in foreign exchange rate (303) 508 Balance, December 31 $ 5,835 $ 6,313 (1) On March 25, 2019, Emera announced the sale of Emera Maine. Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
22. Short-Term Debt
Short-term debt and the related weighted-average interest rates	millions of Canadian dollars 2019 Weighted average interest rate 2018 Weighted average interest rate TECO Finance Advances on revolving credit and term facilities $ 656 2.39 % $ 805 3.43 % Tampa Electric Company ("TEC") Advances on accounts receivable and revolving credit facilities 452 2.56 % 302 3.10 % Emera Inc. Non-revolving term facility 399 2.69 % Bank indebtedness 6 - % - - % GBPC Advances on revolving credit facilities 10 5.25 % - - % NMGC Advances on revolving credit facilities 8 2.70 % 79 3.40 % NSPI Bank indebtedness 6 - % - - % Short-term debt $ 1,537 $ 1,186 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 2019 2018 TECO Energy/TECO Finance - term credit facility 2020 $ 649 $ 682 TECO Energy/TECO Finance - revolving credit facility 2022 520 546 Tampa Electric Company - revolving credit facility 2022 520 443 Emera Inc. - non-revolving term facility 2020 400 - Tampa Electric Company - accounts receivable revolving credit facility 2021 195 205 NMGC - revolving credit facility 2022 162 171 GBPC - revolving credit facility on demand 17 18 Total 2,463 2,065 Less: Advances under revolving credit and term facilities 1,525 1,186 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,528 1,189 Available capacity under existing agreements $ 935 $ 876

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
23. Other Current Liabilities
Other Current Liabilities	As at December 31 December 31 millions of Canadian dollars 2019 2018 Accrued charges $ 147 $ 154 Accrued interest on long-term debt 77 93 Pension and post-retirement liabilities (note 20 ) 22 31 Sales and other taxes payable 13 9 Income tax payable 1 6 Other 73 135 $ 333 $ 428

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
24. 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 2019 2018 Maturity 2019 2018 Emera Bankers acceptances, LIBOR loans Variable Variable 2024 $ 437 $ 339 Unsecured fixed rate notes 2.90% 3.50% 2023 500 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,559 1,637 $ 2,496 $ 2,701 Emera Finance Unsecured senior notes (USD) 3.86% 3.60% 2021 - 2046 $ 3,572 $ 4,434 TECO Finance (2) Fixed rate notes and bonds (USD) 5.15% 5.15% 2020 390 409 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.53% 4.64% 2021 - 2050 $ 3,334 $ 3,126 PGS Fixed rate notes and bonds (USD) 4.58% 4.66% 2021 - 2050 $ 437 $ 425 NMGC Fixed rate notes and bonds (USD) 4.30% 4.53% 2021 - 2049 $ 474 $ 368 NMGI Fixed rate notes and bonds (USD) 3.64% 3.41% 2024 $ 195 $ 273 NSPI Discount notes Variable Variable 2024 $ 308 $ 516 Medium term fixed rate notes 5.37% 5.73% 2025 - 2097 2,365 1,965 Fixed rate debenture - 9.75% - - 95 $ 2,673 $ 2,576 Emera Maine LIBOR loans and demand loans Variable Variable 2023 $ 11 $ 28 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020 - 2022 65 68 Unsecured senior fixed rate notes (USD) 4.15% 4.23% 2022 - 2049 442 382 $ 518 $ 478 EBP Senior secured credit facility Variable 3.08% 2023 $ 248 $ 248 ECI Secured senior notes (USD) Variable Variable 2021 $ 130 $ 159 Amortizing fixed rate notes (USD) 3.89% 3.83% 2021 - 2022 $ 122 $ 114 Secured fixed rate senior notes (4) 4.84% 5.51% 2020 - 2035 $ 218 $ 191 $ 470 $ 464 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 8 $ 22 Debt issuance costs (119) (113) Classification as liabilities held for sale (6) (516) - Amount due within one year (7) (501) (1,119) $ (1,128) $ (1,210) Long-Term Debt $ 13,679 $ 14,292 (1) Weighted average interest rate of fixed rate long-term debt. (2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (3) 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. (4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (5) 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. (6) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details. (7) Excludes Emera Maine amounts which are classified as current liabilities associated with assets 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 2019 2018 Emera – revolving credit facility (1) June 2024 $ 900 $ 900 NSPI - revolving credit facility (1) October 2024 600 600 Emera Maine – revolving credit facility February 2023 104 109 BLPC – revolving credit facility 2020-2032 25 26 Total 1,629 1,635 Less: Borrowings under credit facilities 771 899 Letters of credit issued inside credit facilities 65 77 Use of available facilities 836 976 Available capacity under existing agreements $ 793 $ 659 (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, 2019 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.59 : 1
Long-Term Debt Maturities	millions of Canadian dollars 2020 2021 2022 2023 2024 Thereafter Total Emera $ - $ - $ - $ 500 $ 437 $ 1,559 $ 2,496 Emera US Finance LP - 974 - - - 2,598 3,572 TECO Finance 390 - - - - - 390 Tampa Electric - 301 292 - - 2,741 3,334 PGS - 61 32 - - 344 437 NMGC - - - - 195 - 195 NMGI - 260 - - - 214 474 NSPI - - - - 308 2,365 2,673 Emera Maine (1) 49 - 107 11 - 351 518 EBP - - - 248 - - 248 ECI 111 69 81 72 47 90 470 Total $ 550 $ 1,665 $ 512 $ 831 $ 987 $ 10,262 $ 14,807 (1) Classified as held for sale.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligations
Change in ARO	The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2019 2018 Balance, January 1 $ 205 $ 172 Additions (1) - 25 Liabilities settled (1) (25) (2) Accretion included in depreciation expense 7 6 Other 3 (1) Change in foreign exchange rate (5) 5 Balance, December 31 $ 185 $ 205 (1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The increase in ARO in 2018 was to achieve compliance with the US Environmental Protection Agency's CCR rule due to the closure of a CCR management facility that began in 2018. The closure was completed in 2019.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
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 2020 2021 2022 2023 2024 Thereafter Total Purchased power (1)(2) $ 210 $ 233 $ 237 $ 246 $ 249 $ 2,228 $ 3,403 Transportation (3) 514 398 340 281 264 2,720 4,517 Capital projects (4) 411 109 103 86 - - 709 Fuel, gas supply and storage 466 133 22 1 - - 622 Long-term service agreements (5)(6) 52 37 36 27 26 100 278 Equity investment commitments (7) 240 - - - - - 240 Leases and other (8) 19 19 18 17 8 118 199 Demand side management 38 41 43 - - - 122 $ 1,950 $ 970 $ 799 $ 658 $ 547 $ 5,166 $ 10,090 As noted below, contractual obligations at December 31, 2019 include amounts related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future contractual obligations will be transferred to the buyer. Refer to note 4 for additional information. (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Includes $520 million related to Emera Maine ($13 million in 2020; $23 million in 2021; $27 million in 2022; $31 million in 2023; $31 million in 2024 and $395 million thereafter). (3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (4) Includes $345 million of commitments related to Tampa Electric's solar and Big Bend Power Station modernization projects. (5) 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. (6) Includes $44 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($19 million in 2020; $9 million in 2021; $8 million in 2022; and $8 million in 2023). (7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (8) 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, 2019
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, 2019 December 31, 2018 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 3,864,636 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 2,135,364 $ 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 4.400 0.6388 1.84 August 15, 2020 25.00 Series B Series C (5) 4.100 1.1802 2.65 August 15, 2023 25.00 Series D Series F (6) 4.250 1.0625 2.63 February 15, 2020 25.00 Series G Minimum rate reset (3)(4) Series B 2.393 Floating 1.84 August 15, 2020 25.00 Series A Series H 4.900 1.2250 4.90 August 15, 2023 25.00 Series I Perpetual fixed rate Series E (7) 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 C was reset from $1.0250 to $1.1802 for the five-year period from and including August 15, 2018. (6) 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. (7) 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, 2019
Non-Controlling Interest in Subsidiaries
Non-controlling Interest	28. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of Canadian dollars 2019 2018 Preferred shares of GBPC $ 14 $ 19 Domlec 21 22 $ 35 $ 41
Preferred shares of GBPC	Preferred shares of GBPC: Authorized: 10,000 non-voting cumulative redeemable variable perpetual preferred shares. 2019 2018 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 20,000 $ 19

Supplemental Information to C_2

Supplemental Information to Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2019
29. 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 2019 2018 Changes in non-cash working capital: Inventory $ (19) $ (44) Receivables and other current assets 154 (144) Accounts payable (137) 59 Other current liabilities (71) 13 Total non-cash working capital $ (73) $ (116) Supplemental disclosure of cash paid (received): Interest $ 750 $ 696 Income taxes $ (107) $ 33 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 187 $ 181 Increase in accrued capital expenditures $ 33 $ 50 Issuance of depository receipts $ - $ 22

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Stock-Based Compensation
Weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted	2019 2018 Weighted average fair value per option $ 2.41 $ 1.70 Expected term (1) 6 years 6 years Risk-free interest rate (2) 1.82 % 2.13 % Expected dividend yield (3) 5.10 % 5.69 % Expected volatility (4) 14.32 % 13.71 % (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, 2018 4,225,575 $ 39.56 1,679,325 $ 2.22 Granted 651,400 46.39 651,400 2.41 Exercised (2,568,625) 37.90 N/A N/A Vested N/A N/A (759,900) 2.37 Forfeited (21,800) 46.39 (21,800) 2.41 Expired N/A N/A N/A N/A Options outstanding December 31, 2019 2,286,550 $ 43.31 1,549,025 $ 2.22 Options exercisable December 31, 2019 (2)(3) 737,525 $ 41.43 (1) As at December 31, 2019, 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 2.4 years (2018 - $2 million, 2.2 years). (2) As at December 31, 2019, the weighted average remaining term of vested options was 5.5 years with an aggregate intrinsic value of $11 million (2018 - 5.1 years, $18 million). (3) As at December 31, 2019, the fair value of options that vested in the year was $2 million (2018 - $2 million).
Activity related to the Performance Share Unit Plan	Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2018 837,109 $ 29.54 563,521 $ 37.07 Granted including DRIP 120,098 39.05 104,293 42.25 Exercised (252,610) 19.68 (136,360) 29.76 Outstanding and exercisable as at December 31, 2019 704,597 $ 34.69 531,454 $ 39.96 Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2018 1,127,114 $ 46.02 $ 56.9 Granted including DRIP 545,008 43.15 Exercised (140,754) 43.00 Forfeited (150,268) 44.41 Outstanding as at December 31, 2019 1,381,100 $ 45.37 $ 88.1

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2019
Variable Interest Entities
NSPML's consolidated summarized balance sheets	As at December 31, 2019 December 31, 2018 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) $ 554 $ 23 $ 545 $ 51

Supplemental Financial Inform_2

Supplemental Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
34. 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, 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 For the year ended December 31, 2018 Operating revenues $ - $ - $ 4,432 $ 2,146 $ (54) $ 6,524 Operating expenses 45 - 3,468 1,665 (52) 5,126 Income (loss) from equity investments and subsidiaries 801 - 3 150 (800) 154 Other income (expenses), net 22 - 20 (27) (38) (23) Interest expense, net (1) 79 (40) 456 218 - 713 Income (loss) before provision for income taxes 699 40 531 386 (840) 816 Income tax expense (recovery) (47) 9 64 43 - 69 Net income (loss) 746 31 467 343 (840) 747 Non-controlling interest in subsidiaries - - - (1) 2 1 Preferred stock dividends 36 - 38 4 (42) 36 Net income (loss) attributable to common shareholders $ 710 $ 31 $ 429 $ 340 $ (800) $ 710 Comprehensive income (loss) of Emera Incorporated $ 1,249 $ 56 $ 973 $ 439 $ (1,468) $ 1,249 (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, 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 As at December 31, 2018 Assets Current assets $ 146 $ 67 1,767 $ 1,096 $ (244) $ 2,832 Property, plant and equipment 24 - 13,745 4,946 (3) 18,712 Other assets Regulatory assets - - 645 759 - 1,404 Goodwill - - 6,208 105 - 6,313 Other long-term assets 11,457 4,660 971 3,200 (17,235) 3,053 Total other assets 11,457 4,660 7,824 4,064 (17,235) 10,770 Total assets $ 11,627 $ 4,727 $ 23,336 $ 10,106 $ (17,482) $ 32,314 Liabilities and Equity Current liabilities $ 368 $ 695 $ 2,829 $ 926 $ (265) $ 4,553 Long-term liabilities Long-term debt 2,906 3,709 10,243 4,428 (6,994) 14,292 Deferred income taxes - 3 668 643 6 1,320 Regulatory liabilities - - 2,118 241 - 2,359 Other long-term liabilities 36 - 874 543 (21) 1,432 Total long-term liabilities 2,942 3,712 13,903 5,855 (7,009) 19,403 Total Emera Incorporated equity 8,317 320 6,604 3,303 (10,227) 8,317 Non-controlling interest in subsidiaries - - - 22 19 41 Total equity 8,317 320 6,604 3,325 (10,208) 8,358 Total liabilities and equity $ 11,627 $ 4,727 $ 23,336 $ 10,106 $ (17,482) $ 32,314
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, 2019 Net cash provided by (used in) by 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 - - 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, restricted cash and assets held for sale 147 (3) (141) (23) - (20) Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale (25) (39) (17) (17) - (98) Cash, cash equivalents, and restricted cash, beginning of year 20 58 104 190 - 372 Cash, cash equivalents, restricted cash and assets held for sale end of year $ (5) $ 19 $ 87 $ 173 $ - $ 274 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, 2018 Net cash provided by (used in) operating activities $ 191 $ 35 $ 1,266 $ 465 $ (267) $ 1,690 Investing activities Additions to property, plant and equipment (9) - (1,687) (466) - (2,162) Net purchase of investments subject to significant influence - - (16) (33) - (49) Other investing activities (489) - 3 (65) 572 21 Net cash provided by (used in) investing activities (498) - (1,700) (564) 572 (2,190) Financing activities Change in short-term debt, net - - (162) - - (162) Proceeds from long-term debt - - 1,174 75 (194) 1,055 Retirement of long-term debt - - (716) (41) - (757) Net borrowings (repayments) under committed credit facilities 136 - (103) 178 110 321 Issuance of common and preferred stock 301 - 319 127 (446) 301 Dividends paid (382) - (37) (311) 348 (382) Other financing activities - - - 91 (123) (32) Net cash provided by (used in) financing activities 55 - 475 119 (305) 344 Effect of exchange rate changes on cash, cash equivalents and restricted cash (4) 2 9 18 - 25 Net increase (decrease) in cash, cash equivalents, and restricted cash (256) 37 50 38 - (131) Cash, cash equivalents and restricted cash, beginning of year 276 21 54 152 - 503 Cash, cash equivalents and restricted cash, end of year $ 20 $ 58 $ 104 $ 190 $ - $ 372

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions	2 Months Ended	3 Months Ended	12 Months Ended
	Mar. 05, 2019	Mar. 29, 2019	Dec. 31, 2019CAD ($)MWCustomerskm	Dec. 20, 2019
EUS | Disposition
Nature of operations [Line items]
Disposition, Name				EUS
Description and Timing and Disposition				EUS ceased operations on September 30, 2019
New England Gas Generating Facilities | Disposition
Nature of operations [Line items]
Disposition, Name		New England Gas Generation
Description and Timing and Disposition		The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceased depreciation of these assets on November 27, 2018.
Segment that Includes Disposition		Other reportable segment
Bayside Power Limited Partnership | Disposition
Nature of operations [Line items]
Disposition, Name	Bayside facility
Segment that Includes Disposition	Other reportable segment
Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following: 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.
Operating | Other Electric Utilities
Nature of operations [Line items]
Segment that Includes Disposition			Other Electric Utilities
Operating | Other Electric Utilities | Held for sale
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			, a regulated electric transmission and distribution utility, serving approximately 159,000 customers in the state of Maine. On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in early 2020, subject to approval of the Maine Public Utilities Commission (“MPUC”).
Number of Customers			159,000
Disposition, Name			Emera Maine
Description and Timing and Disposition			On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in early 2020, subject to approval of the Maine Public Utilities Commission (“MPUC”)
Operating | Other
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			At December 31, 2019, Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following: 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.
Maritimes and Northeast Pipline | Gas Utilities and Infrastructure
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage			12.90%
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage			19.10%
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage			51.90%
Number of Customers			31,000
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 779,000 customers in West Central Florida
Number of Customers			779,000
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 523,000 customers
Number of Customers			523,000
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”), consisting 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 and forecasted to be generating full power in the second half of 2020. 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 ##D<LIL_%Ownership> 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, which is forecasted to be in 2020.
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			49.50%
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 18,000 customers. On September 1, 2019, Grand Bahama Island was struck by Hurricane Dorian, causing significant damage. Refer to note ##NRM and ##NGW for further details; 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 31,000 customers; and a 19.1 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.
Barbados Light and Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados, serving approximately 131,000 customers;
Number of Customers			131,000
Grand Bahama Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island, serving approximately 18,000 customers. On September 1, 2019, Grand Bahama Island was struck by Hurricane Dorian, causing significant damage. Refer to note ##NRM and ##NGW for further details;
Number of Customers			18,000
Dominica Electricity Services Ltd. | Operating | Other Electric Utilities
Nature of operations [Line items]
Segment Reporting, Additional Information about Entity's Reportable Segments			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 31,000 customers
Peoples Gas System Division
Nature of operations [Line items]
Length Of Pipeline | km			800
Peoples Gas System Division | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers			406,000
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 406,000 customers across Florida;
New Mexico Gas Company | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers			534,000
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 534,000 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
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;
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	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Short-term Investments	$ 0		$ 43,000,000
Investment Interest Rate			2.00%
Asset Impairment Charges
Regulatory Assets	1,552,000,000		$ 1,569,000,000
Net book value	$ 16,576,000,000		$ 17,476,000,000
Asset Impairment for Regulatory Action [Member] | Hurricane Dorian [Member] | GBPC
Asset Impairment Charges
Regulatory Assets		$ 3
Offsetting insurance receivable		15
Net book value		$ 18

Change in Accounting Policy (Na

Change in Accounting Policy (Narrative) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	Leases On January 1, 2019, the Company adopted Accounting Standard Updates (“ASU”) 2016-02, Leases (Topic 842), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements. As permitted by the optional transition method, Emera did not restate comparative financial information in the Company’s consolidated financial statements, did not reassess whether any expired or existing contracts contained leases and carried forward existing lease classifications. Additionally, the Company elected to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under the leasing guidance within ASC Topic 840. The Company elected to use hindsight to determine the lease term for existing leases and elected to not separate lease components from non-lease components for all lessee and lessor arrangements. Emera has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There were no updates to information technology systems as a result of implementation. The Company’s adoption of this new standard resulted in right-of-use (“ROU”) assets and lease liabilities of approximately $58 million as of January 1, 2019. The ROU assets and lease liabilities were measured at the present value of remaining lease payments using the Company’s incremental borrowing rate. There was no impact to opening retained earnings as at January 1, 2019 or the Company’s net income or cash flows for the year ended December 31, 2019 as a result of the adoption of the standard. There were no significant impacts to Emera’s accounting for lessor arrangements. Refer to note ##NLEA of the consolidated financial statements for further detail.
Change in Accounting Principle, Accounting Standards Update, Transition Option Elected [Fixed List]	Modified Retrospective
Change in Accounting Principle, Accounting Standards Update, Adoption Date	Jan. 1, 2019
New Accounting Pronouncement or Change in Accounting Principle, Prior Period Not Restated [true false]	true
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		$ 58,000,000
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets		$ 0
Accounting Standards Update 2017-12 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	Targeted Improvements to Accounting for Hedging Activities On January 1, 2019, the Company adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. 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, Adoption Date	Jan. 1, 2019
Accounting Standards Update 2018-15 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Description	Cloud Computing In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. The Company early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.
Change in Accounting Principle, Accounting Standards Update, Transition Option Elected [Fixed List]	Prospective
Change in Accounting Principle, Accounting Standards Update, Adoption Date	Jan. 1, 2019

Dispositions (Narrative) (Detai

Dispositions (Narrative) (Details) $ in Millions	2 Months Ended	3 Months Ended				12 Months Ended
	Mar. 05, 2019CAD ($)	Mar. 29, 2019CAD ($)Facilities	Mar. 29, 2019USD ($)Facilities	Mar. 25, 2019CAD ($)	Mar. 25, 2019USD ($)	Dec. 20, 2019CAD ($)
Emera Maine | Held for sale
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Depreciation and Amortization				$ 39,000,000	$ 29
Emera Maine | Held for sale | Plan, subject to approval
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Name				Emera Maine	Emera Maine
Description and Timing and Disposition				The transaction is expected to close in early 2020	The transaction is expected to close in early 2020
Disposition, Value					$ 1,300
Proceeds on disposition of business					$ 959
EUS | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Name						EUS
Description and Timing and Disposition						EUS ceased operations on September 30, 2019
Disposition, Value						$ 0
New England Gas Generating Facilities [Member] | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Name		New England Gas Generation	New England Gas Generation
Description and Timing and Disposition		The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceased depreciation of these assets on November 27, 2018.	The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceased depreciation of these assets on November 27, 2018.
Proceeds on disposition of business		$ 799,000,000	$ 598
Number of facilities | Facilities		3	3
Segment that Includes Disposition		Other reportable segment	Other reportable segment
Bayside Power Limited Partnership [Member] | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Name	Bayside facility
Proceeds on disposition of business	$ 46,000,000
Segment that Includes Disposition	Other reportable segment

Dispositions (Held for sale) (D

Dispositions (Held for sale) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Details of the assets and liabilities classified as held for sale [Line items]
Current assets held for sale	$ 85	$ 53
Long-term assets held for sale	1,619	777
Current liabilities associated with assets held for sale	114	20
Long-term liabilities associated with assets held for sale	899	$ 2
Emera Maine | Held for sale
Details of the assets and liabilities classified as held for sale [Line items]
Regulatory assets	16
Receivables and other current assets	69
Current assets held for sale	85
Property, plant and equipment	1,293
Goodwill	148
Regulatory assets	122
Other long-term assets	56
Long-term assets held for sale	1,619
Total assets held for sale	1,704
Regulatory liabilities	11
Accounts payable and other current liabilities	103
Current liabilities associated with assets held for sale	114
Long-term debt	467
Deferred income taxes	204
Regulatory liabilities	145
Other long-term liabilities	83
Long-term liabilities associated with assets held for sale	899
Total liabilities associated with assets held for sale	$ 1,013

Dispositions (New England Gas G

Dispositions (New England Gas Generating Facilities and Bayside) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Details of the assets and liabilities classified as held for sale [Line items]
Current assets held for sale	$ 85	$ 53
Total assets held for sale	1,619	777
Current liabilities associated with assets held for sale	114	20
Long-term liabilities associated with assets held for sale	$ 899	2
New England Gas Generating Facilities | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Receivables and other current assets		40
Inventory		13
Current assets held for sale		53
Property, plant and equipment		777
Total assets held for sale		777
Total assets held for sale		830
Accounts payable and other current liabilities		20
Current liabilities associated with assets held for sale		20
Other long-term liabilities		2
Long-term liabilities associated with assets held for sale		2
Total liabilities associated with assets held for sale		$ 22

Segment Information (Reportable

Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	$ 6,111	$ 6,524
AFUDC - debt and equity	33	30
Depreciation and amortization	903	916
Interest expense, net	738	713
Internally allocated interest	0	0
Income from equity investments	154	154
Income tax expense (recovery)	61	69
Operating, maintenance and general	1,464	1,580
Impairment charge	34	0
Net income (loss) attributable to common shareholders	662.8	709.6
Capital expenditures	2,483	2,151
Segment Reporting Information, Additional Information [Abstract]
Total assets	31,842	32,314
Investments subject to significant influence	1,312	1,316
Goodwill	5,835	6,313	$ 5,805
Florida Electric Utility
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	2,607	2,679
AFUDC - debt and equity	20	20
Depreciation and amortization	445	405
Interest expense, net	154	132
Internally allocated interest	0	0
Income from equity investments	0	0
Income tax expense (recovery)	79	85
Operating, maintenance and general	554	667
Impairment charge	0
Net income (loss) attributable to common shareholders	419	381
Capital expenditures	1,393	1,217
Segment Reporting Information, Additional Information [Abstract]
Total assets	16,214	15,997
Investments subject to significant influence	0	0
Goodwill	4,544	4,774
Canadian Electric Utilities
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	1,430	1,440
AFUDC - debt and equity	6	6
Depreciation and amortization	231	219
Interest expense, net	142	139
Internally allocated interest	0	0
Income from equity investments	91	87
Income tax expense (recovery)	(10)	8
Operating, maintenance and general	313	286
Impairment charge	0
Net income (loss) attributable to common shareholders	229	218
Capital expenditures	384	345
Segment Reporting Information, Additional Information [Abstract]
Total assets	6,717	6,275
Investments subject to significant influence	1,133	1,079
Goodwill	0	0
Other Electric Utilities
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	744	745
AFUDC - debt and equity	5	3
Depreciation and amortization	107	114
Interest expense, net	52	48
Internally allocated interest	0	0
Income from equity investments	5	6
Income tax expense (recovery)	11	9
Operating, maintenance and general	195	188
Impairment charge	34
Net income (loss) attributable to common shareholders	45	85
Capital expenditures	195	187
Segment Reporting Information, Additional Information [Abstract]
Total assets	3,069	3,094
Investments subject to significant influence	41	77
Goodwill	70	260
Gas Utilities and Infrastructure
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	1,119	1,098
AFUDC - debt and equity	2	1
Depreciation and amortization	109	129
Interest expense, net	59	55
Internally allocated interest	14	14
Income from equity investments	22	22
Income tax expense (recovery)	48	47
Operating, maintenance and general	319	295
Impairment charge	0
Net income (loss) attributable to common shareholders	183	135
Capital expenditures	448	330
Segment Reporting Information, Additional Information [Abstract]
Total assets	5,489	5,404
Investments subject to significant influence	138	155
Goodwill	1,218	1,279
Other
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	282	661
AFUDC - debt and equity	0	0
Depreciation and amortization	11	49
Interest expense, net	331	339
Internally allocated interest	(14)	(14)
Income from equity investments	36	39
Income tax expense (recovery)	(67)	(80)
Operating, maintenance and general	130	206
Impairment charge	0
Net income (loss) attributable to common shareholders	(213)	(109)
Capital expenditures	63	72
Segment Reporting Information, Additional Information [Abstract]
Total assets	1,459	2,653
Investments subject to significant influence	0	5
Goodwill	3	0
Operating
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	6,111	6,524
Operating | Florida Electric Utility
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	2,596	2,670
Operating | Canadian Electric Utilities
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	1,429	1,437
Operating | Other Electric Utilities
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	744	745
Operating | Gas Utilities and Infrastructure
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	1,097	1,062
Operating | Other
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	245	610
Intersegment Eliminations
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues	(71)	(99)
AFUDC - debt and equity	0	0
Depreciation and amortization	0	0
Interest expense, net	0	0
Internally allocated interest	0	0
Income from equity investments	0	0
Income tax expense (recovery)	0	0
Operating, maintenance and general	(47)	(62)
Impairment charge	0
Net income (loss) attributable to common shareholders	0	0
Capital expenditures	0	0
Segment Reporting Information, Additional Information [Abstract]
Total assets	(1,106)	(1,109)
Investments subject to significant influence	0	0
Goodwill	$ 0	$ 0

Segment Information (Geographic

Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 6,111	$ 6,524
Property, Plant and Equipment, Net	18,167	18,712
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	1,497	1,520
Property, Plant and Equipment, Net	4,248	4,128
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	4,140	4,537
Property, Plant and Equipment, Net	13,095	13,739
Barbados
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	320	319
Property, Plant and Equipment, Net	462	446
The Bahamas
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	112	121
Property, Plant and Equipment, Net	282	315
Dominica
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	42	27
Property, Plant and Equipment, Net	$ 80	$ 84

Revenue (Disaggregation) (Detai

Revenue (Disaggregation) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 6,111	$ 6,524
Total operating revenues	6,111	6,524
Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	2,607	2,679
Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1,430	1,440
Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	744	745
Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1,119	1,098
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	282	661
Operating
Disaggregation of Revenue [Line Items]
Total operating revenues	6,111	6,524
Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,607	2,679
Total operating revenues	2,596	2,670
Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,430	1,440
Total operating revenues	1,429	1,437
Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	744	745
Total operating revenues	744	745
Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,119	1,098
Total operating revenues	1,097	1,062
Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	282	661
Total operating revenues	245	610
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(71)	(99)
Total operating revenues	(43)	(54)
Eliminations | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	11	9
Eliminations | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1	3
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	22	36
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	37	51
Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	261	628
Total operating revenues	261	628
Non-Regulated | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	38	136
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	18
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	282	661
Non-Regulated | Operating | Other | Capacity
Disaggregation of Revenue [Line Items]
Total operating revenues	38	136
Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(37)	(51)
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	4,769	4,852
Total operating revenues	4,769	4,852
Electric | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,607	2,679
Electric | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,430	1,440
Electric | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	744	745
Electric | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	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	(12)	(12)
Electric | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,409	2,376
Electric | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,387	1,384
Electric | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	746	731
Electric | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	276	261
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	1,484	1,510
Electric | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	745	755
Electric | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	400	405
Electric | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	339	350
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	461	488
Electric | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	207	209
Electric | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	210	233
Electric | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	44	46
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	304	371
Electric | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	246	312
Electric | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	45	43
Electric | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	13	16
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
Electric | Regulated | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	111	107
Electric | Regulated | Other | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	22	19
Electric | Regulated | Other | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	29	28
Electric | Regulated | Other | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	72	72
Electric | Regulated | Other | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Other | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric | Regulated | Other | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(12)	(12)
Gas | Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,081	1,044
Total operating revenues	1,081	1,044
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	1,103	1,080
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	(22)	(36)
Gas | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	502	492
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	502	492
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	298	291
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	298	291
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	50	49
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	50	49
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 | Finance Income
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	60	57
Gas | Regulated | Finance Income | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Finance Income | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Finance Income | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Finance Income | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	60	57
Gas | Regulated | Finance Income | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Finance Income | 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	171	155
Gas | Regulated | Other | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Other | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Other | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas | Regulated | Other | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	193	191
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	(22)	(36)
Marketing and trading margin | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	31	115
Marketing and trading margin | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Marketing and trading margin | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Marketing and trading margin | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Marketing and trading margin | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Marketing and trading margin | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	31	115
Marketing and trading margin | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Energy sales | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	68	293
Energy sales | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Energy sales | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Energy sales | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Energy sales | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	80	309
Energy sales | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(12)	(16)
Other | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	22	30
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	18
Other | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	31	47
Other | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(25)	(35)
Mark-To-Market | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	102	54
Mark-To-Market | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Mark-To-Market | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Mark-To-Market | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Mark-To-Market | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Mark-To-Market | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	102	54
Mark-To-Market | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 0	$ 0

Revenue (Remaining Performance

Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
6. Revenue
Revenue, Remaining Performance Obligation, Amount	$ 347	$ 370
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Explanation	2033	2033

Investments Subject to Signif_3

Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - Equity Method Investee - Emera Inc. - Entity [Domain] - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence		$ 1,312	$ 1,316
Income from equity investments		154	154
NSPML
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence		554	545
Income from equity investments		$ 46	45
Percentage of Ownership		100.00%
LIL
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	[1]	$ 579	534
Income from equity investments	[1]	$ 45	42
Percentage of Ownership	[1]	49.50%
M&NP
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	[2]	$ 138	155
Income from equity investments	[2]	$ 22	22
Percentage of Ownership	[2]	12.90%
Lucelec
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	[2]	$ 41	42
Income from equity investments	[2]	$ 3	3
Percentage of Ownership	[2]	19.10%
Bear Swamp
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	[3]	$ 0	0
Income from equity investments	[3]	$ 35	38
Percentage of Ownership	[3]	50.00%
Other Investments
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence		$ 0	40
Income from equity investments		$ 3	$ 4
[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 a result of a $179 million distribution received in 2015. Bear Swamp's credit investment balance of $137 million (2018 - $172 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets.

Investments Subject to Signif_4

Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Balance Sheets
Current assets		$ 2,486	$ 2,832
Property, plant and equipment		18,167	18,712
Non-current assets		11,189	10,770
Total assets		31,842	32,314
Current liabilities		4,166	4,553
Non-current liabilities		19,075	19,403
Equity		8,601	8,358	$ 7,204
Total liabilities and equity		31,842	32,314
Variable Interest Entity, Not Primary Beneficiary | NSPML
Balance Sheets
Current assets		69	86
Property, plant and equipment		1,671	1,690
Non-current assets		32	32
Total assets		1,949	1,916
Current liabilities		23	21
Long-term debt	[1]	1,288	1,288
Non-current liabilities		84	62
Equity		554	545
Total liabilities and equity		$ 1,949	$ 1,916
[1]	The project debt has been guaranteed by the Government of Canada.

Income Taxes (Reconiliation of

Income Taxes (Reconiliation of Income tax provision) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income before provision for income taxes	$ 771	$ 816
Statutory income tax rate	31.00%	31.00%
Income taxes, at statutory income tax rates	$ 239	$ 253
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(66)	(59)
Foreign tax rate variance	(49)	(55)
Amortization of deferred income tax regulatory liabilities	(36)	(37)
Florida state tax apportionment adjustment	0	(23)
Tax effect of equity earnings	(15)	(15)
GBPC impairment charge	11	0
Investment tax credits	(9)	(4)
Change in treatment of NMGC net operating loss carryforwards	(7)	0
Change in prior year unrecognized tax benefits at NSPI	0	7
Other	(7)	2
Income tax expense (recovery)	$ 61	$ 69
Effective income tax rate	8.00%	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ 125	$ 185
Income tax expense (recovery)	61	69
Supplemental Tax Information [Abstract]
Income before provision for income taxes	771	816
Canada
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	(19)	3
Deferred income taxes	45	11
Operating loss carry forwards	(48)	(33)
Supplemental Tax Information [Abstract]
Income before provision for income taxes	98	127	$ 127
United States
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	(46)	(121)
Deferred income taxes	137	215
Investment tax credits	(9)	(4)
Operating loss carry forwards	0	0
Revaluation of US non-regulated deferred income taxes due to tax reform	0	0
Supplemental Tax Information [Abstract]
Income before provision for income taxes	682	646	646
Other
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	1	2
Deferred income taxes	0	(4)
Operating loss carry forwards	0	0
Supplemental Tax Information [Abstract]
Income before provision for income taxes	$ (9)	$ 43	$ 43

Income Taxes (Deferred income t

Income Taxes (Deferred income tax assets and liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred income tax assets:
Tax loss carryforwards	$ 908	$ 917
Tax credit carry forwards	311	269
Regulatory liabilities - cost of removal	195	206
Derivative instruments	145	90
Pension and post-retirement liabilities	84	126
Other	329	441
Total deferred income tax assets before valuation allowance	1,972	2,049
Valuation allowance	(193)	(163)
Total deferred income tax assets after valuation allowance	1,779	1,886
Deferred income tax (liabilities):
Property, plant and equipment	(2,382)	(2,591)
Derivative instruments	(148)	(124)
Other	(348)	(316)
Total deferred income tax liabilities	(2,878)	(3,031)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets	186	175
Long-term deferred income tax liabilities	(1,285)	(1,320)
Net deferred income tax liabilities	$ (1,099)	$ (1,145)

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, 2019CAD ($)
Canada | Capital loss
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 80
Unrecognized Amounts	(80)
Net Tax Credit Carryforwards	$ 0
Expiration period	Indefinite
Canada | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,131
Unrecognized Amounts	(554)
Net Tax Credit Carryforwards	$ 577
Expiration period	2027-2039
United States | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2,394
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 2,394
Expiration period	2024-2037
United States | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 311
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 311
Expiration period	2020-Indefinite
State | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,174
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 1,174
Expiration period	2024-2039
Other | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 38
Unrecognized Amounts	(38)
Net Tax Credit Carryforwards	$ 0
Expiration period	2020-2026

Income Taxes (Change in unrecog

Income Taxes (Change in unrecognized tax benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 26	$ 19
Increases due to tax positions related to a prior year	1	8
Decreases due to tax positions related to a prior year	0	(1)
Increases due to tax positions related to current year	2	0
Balance, December 31	$ 29	$ 26

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Entity [Domain]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change	$ 1,900	$ 1,400
2005 and subsequent years | Entity [Domain]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Open Tax Year	2005
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
Prepaid amount in dispute	$ 23

Common Stock (Common Stock Roll

Common Stock (Common Stock Rollfoward) (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) In Common Stock Value [Roll Forward]
Balance, December 31, 2018	$ 5,816
Issuance of common stock		$ 25
Issuance of common stock	99	295
Options exercised under senior management share option plan	97
Balance, December 31, 2019	$ 6,216	$ 5,816
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2018	234,120	228,770
Conversion of Convertible Debentures	30	10
Issuance of common stock	1,770	450
Issued under Purchase Plans at market rate	3,990	4,870
Discount on shares purchased under Dividend Reinvestment Plan	0	0
Options exercised under senior management share option plan	2,570	20
Employee Share Purchase Plan	0	0
Balance, December 31, 2019	242,480	234,120
Common Stock
Increase (Decrease) In Common Stock Value [Roll Forward]
Balance, December 31, 2018	$ 5,816	$ 5,601
Conversion of Convertible Debentures	1	0
Issuance of common stock		22
Issuance of common stock	99	0
Issued under Purchase Plans at market rate	202	200
Discount on shares purchased under Dividend Reinvestment Plan Value	7	9
Options exercised under senior management share option plan	104	1
Employee Share Purchase Plan	1	1
Balance, December 31, 2019	$ 6,216	$ 5,816

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jul. 11, 2019
Debt Instrument [Line Items]
Issuance of common stock	1,770	450
Gross proceeds from Issuance of Common Stock	$ 203	$ 10
ATM Program
Debt Instrument [Line Items]
Stock Repurchase Program, Authorized Amount			$ 600
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$ 500
ATM Program | Common Stock
Debt Instrument [Line Items]
Shares, Issued	1,770
Gross proceeds from Issuance of Common Stock	$ 100
Net proceeds from issuance of common stock	$ 98.7
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	3,900	6,500
Share Unit Plans
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	900	1,000
Dividend Reinvestment
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	8,800	12,600

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, 2019	Dec. 31, 2018
Numerator
Net income attributable to common shareholders	$ 662.8	$ 709.6
Diluted numerator	$ 662.8	$ 709.6
Denominator
Weighted average shares of common stock outstanding	238.5	231.7
Weighted average deferred share units outstanding	1.4	1.3
Weighted average shares of common stock outstanding - basic	239.9	233
Stock-based compensation	0.6	0.4
Convertible Debentures	0	0.1
Weighted average shares of common stock outstanding- diluted	240.5	233.5
Earnings per common share
Basic	$ 2.76	$ 3.05
Diluted	$ 2.76	$ 3.04

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Narrative) (Details) - Net change in unrecognized pension and post-retirement benefit costs - Restatement Adjustment $ in Millions	Jan. 01, 2018CAD ($)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income	$ 37
AOCI, deferred taxes	15
AOCI, net of tax	$ 22

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		$ 8,358	$ 7,204
Net current period other comprehensive income (loss)	[1]	(244)	506
Ending Balance		8,601	8,358
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[2]	338	(165)
Other comprehensive income (loss) before reclassifications		(320)	504
Amounts reclassified from accumulated other comprehensive income loss		77	(1)
Net current period other comprehensive income (loss)	[2]	(243)	503
Ending Balance	[2]	95	338
Unrealized (loss) gain on translation of self-sustaining foreign operations
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		654	30
Other comprehensive income (loss) before reclassifications		(401)	624
Amounts reclassified from accumulated other comprehensive income loss		0	0
Net current period other comprehensive income (loss)		(401)	624
Ending Balance		253	654
Net change in net investment hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(74)	48
Other comprehensive income (loss) before reclassifications		78	(122)
Amounts reclassified from accumulated other comprehensive income loss		0	0
Net current period other comprehensive income (loss)		78	(122)
Ending Balance		4	(74)
(Losses) gains on derivatives recognized as cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(7)	(3)
Other comprehensive income (loss) before reclassifications		3	2
Amounts reclassified from accumulated other comprehensive income loss		3	(6)
Net current period other comprehensive income (loss)		6	(4)
Ending Balance		(1)	(7)
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(1)	3
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income loss		0	(4)
Net current period other comprehensive income (loss)		0	(4)
Ending Balance		(1)	(1)
Net change in unrecognized pension and post-retirement benefit costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(234)	(243)
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income loss		74	9
Net current period other comprehensive income (loss)		74	9
Ending Balance		$ (160)	$ (234)
[1]	4) Net of tax expense of $10 million (2018 - $11 million tax recovery) for the year ended December 31, 2019.
[2]	(1) Accumulated Other Comprehensive Income (Loss) ("AOCI") ("AOCL")

Accumulated Other Comprehensi_5

Accumulated Other Comprehensive Income (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total operating revenues	$ 6,111	$ 6,524
Other income (expenses), net	12	(23)
Retained earnings	1,173	1,075
Operating, maintenance and general	1,464	1,580
Regulatory Assets	1,552	1,569
Income tax expense (recovery)	61	69
Net income	710	747
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	77	(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Fuel for generation and purchased power (notes 16 and 18)	0	(1)
Total operating revenues	3	(5)
Total before tax	3	(6)
Net income	3	(6)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in available-for-sale investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Retained earnings	0	(4)
Total before tax	0	(4)
Net income	0	(4)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in unrecognized pension and post-retirement benefit costs
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	83	7
Income tax expense (recovery)	(9)	2
Net income	74	9
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial losses (gains)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating, maintenance and general	17	25
Reclassification out of Accumulated Other Comprehensive Income [Member] | Past service costs (gains)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating, maintenance and general	(1)	(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amounts reclassified into obligations
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Pension and post-retirement benefits	39	(17)
Regulatory Assets	$ 28	$ 0

Inventory (Details)

Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
12. Inventory
Fuel	$ 232	$ 213
Raw Materials	235	241
Emission Credits	0	20
Inventory, Net, Total	$ 467	$ 474

Derivatives Instruments (Deriva

Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Cash flow hedges
Cash flow hedges, Derivative Assets	$ 0	$ 0
Cash flow hedges, Derivative Liabilities	1	5
HFT derivatives
HFT, Derivative Assets	170	187
HFT, Derivative Liabilities	403	479
Other derivatives
Other, Derivative Assets	1	1
Other, Derivative Liabilities	0	0
Derivative Assets
Total gross current derivative assets	207	293
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(120)	(126)
Derivative Asset, Total	87	167
Derivative Liabilities
Total gross current derivative liabilities	490	491
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	(120)	(126)
Derivative Liabilities, Total	370	365
Foreign exchange forwards
Cash flow hedges
Cash flow hedges, Derivative Assets	0	0
Cash flow hedges, Derivative Liabilities	1	5
Other derivatives
Other, Derivative Assets	0	0
Other, Derivative Liabilities	0	0
Power swaps and physical contracts
HFT derivatives
HFT, Derivative Assets	19	62
HFT, Derivative Liabilities	22	76
Natural gas swaps, futures, forwards, physical contracts
HFT derivatives
HFT, Derivative Assets	151	125
HFT, Derivative Liabilities	381	403
Equity derivatives and interest rate swaps
Other derivatives
Other, Derivative Assets	1	1
Other, Derivative Liabilities	0	0
Regulatory deferral
HFT derivatives
HFT, Derivative Assets	36	105
HFT, Derivative Liabilities	86	7
Derivative Assets
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(8)	(1)
Derivative Liabilities
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	(8)	(1)
Regulatory deferral | Commodity swaps and forwards | Power
HFT derivatives
HFT, Derivative Assets	23	2
HFT, Derivative Liabilities	36	1
Regulatory deferral | Commodity swaps and forwards | Coal
HFT derivatives
HFT, Derivative Assets	8	71
HFT, Derivative Liabilities	39	1
Regulatory deferral | Commodity swaps and forwards | Heavy fuel oil purchases
HFT derivatives
HFT, Derivative Assets	1	1
HFT, Derivative Liabilities	0	1
Regulatory deferral | Commodity swaps and forwards | Natural gas
HFT derivatives
HFT, Derivative Assets	2	2
HFT, Derivative Liabilities	5	4
Regulatory deferral | Foreign exchange forwards
HFT derivatives
HFT, Derivative Assets	2	29
HFT, Derivative Liabilities	6	0
HFT derivatives
Derivative Assets
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	(112)	(125)
Derivative Liabilities
Impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	$ (112)	$ (125)

Derivatives Instruments (Curren

Derivatives Instruments (Current and Long-term classification) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
13. Derivative Instruments
Derivative Assets, Current	$ 54	$ 148
Derivative Assets, Long-term	33	19
Derivative Asset, Total	87	167
Derivative Liabilities, Current	268	260
Derivative Liabilities, Long-term	102	105
Derivative Liabilities, Total	$ 370	$ 365

Derivatives Instruments (Master

Derivatives Instruments (Master Netting Agreements) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	$ 120	$ 126
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	120	126
Regulatory deferral
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	8	1
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	8	1
HFT derivatives
Derivatives, Fair Value [Line Items]
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Assets	112	125
Total impact of master netting agreements with intent to settle net or simultaneously, Derivative Liabilities	$ 112	$ 125

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, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)
Cash Flow Hedges
Total gains (losses) in Net income	$ 28	$ (1)
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 | Energy Related derivative | Power
Cash Flow Hedges
Total gains (losses) in Net income		1
Total unrealized gain (loss) in AOCI - effective portion, net of tax		(1)
Cash flow hedges | Energy Related derivative | Power | Non-Regulated
Cash Flow Hedges
Total gains (losses) in Net income		1
Cash flow hedges | Energy Related derivative | Power | Regulated
Cash Flow Hedges
Total gains (losses) in Net income		0
Cash flow hedges | Foreign exchange forwards
Cash Flow Hedges
Total gains (losses) in Net income	(3)	5
Total unrealized gain (loss) in AOCI - effective portion, net of tax	(1)	(6)
Cash flow hedges | Foreign exchange forwards | 2020
Cash Flow Hedges
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle			$ 30
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	$ (3)	$ 5

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, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	$ 39	$ (55)
Realized (gain) loss on derivatives receiving regulatory deferral	28	(1)
Regulatory deferral | Commodity swaps and forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(115)	(70)
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(89)	(34)
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	9	29
Realized (gain) loss on derivatives receiving regulatory deferral	(2)	(8)
Regulatory deferral | Commodity swaps and forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(36)	(55)
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	3	(2)
Regulatory deferral | Foreign exchange forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(33)	1
Regulatory deferral | Foreign exchange forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(6)	4
Regulatory deferral | Foreign exchange forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(8)	24
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	(11)	(18)
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	$ (8)	$ (9)

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, 2019MMBTUMWhTbbl
Coal | 2020
Derivative [Line Items]
Coal (metric tonnes) | T	0
Coal | 2021-2022
Derivative [Line Items]
Coal (metric tonnes) | T	1
Natural gas | 2020
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MMBTU	12
Natural gas | 2021-2022
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MMBTU	21
Heavy fuel oil | 2020
Derivative [Line Items]
Heavy fuel oil (bbls) | bbl	0
Heavy fuel oil | 2021-2022
Derivative [Line Items]
Heavy fuel oil (bbls) | bbl	1
Power | 2020
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	1
Power | 2021-2022
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	3

Derivatives Instruments (Noti_2

Derivatives Instruments (Notional Volumes of Foreign Exchange Swaps and Forward Contracts Related to Commodity Contracts) (Details) - Foreign Exchange Swaps and Forward Contracts $ in Millions	Dec. 31, 2019USD ($)
2020
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 173
Weighted average rate	0.013148
% of USD requirements	85.00%
2021-2022
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 148
Weighted average rate	0.013264
% of USD requirements	39.00%

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, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 276	$ 195
Operating revenues | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	1	(12)
Operating revenues | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	281	205
Fuel for generation and purchased power | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	(6)	2
Fuel for generation and purchased power | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 0	$ 0

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, 2019MMBTUMWh
Natural gas | Purchases | 2020
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	424
Natural gas | Purchases | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	84
Natural gas | Purchases | 2022
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	56
Natural gas | Purchases | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	41
Natural gas | Purchases | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	26
Natural gas | Sales | 2020
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	345
Natural gas | Sales | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	33
Natural gas | Sales | 2022
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	9
Natural gas | Sales | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	2
Natural gas | Sales | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	2
Power | Purchases | 2020
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Purchases | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
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 | Sales | 2020
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Sales | 2021
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2022
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	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

Derivatives Instruments (Real_2

Derivatives Instruments (Realized and Unrealized Gains (Losses) with Respect to Cash Flow Hedges) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) in Net income	$ 28	$ (1)
Interest expense, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain on equity derivatives	0
Operating, maintenance and general expense
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain on equity derivatives	1
Total gains (losses) in Net income	$ 27
Interest rate swaps | Interest expense, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain on equity derivatives		(1)
Interest rate swaps | Operating, maintenance and general expense
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain on equity derivatives		0
Total gains (losses) in Net income		$ 0

Derivatives Instruments (Credit

Derivatives Instruments (Credit Risk) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)NumberOfDays	Dec. 31, 2018CAD ($)
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	$ 1,119	$ 1,382
Total cash deposits/collateral on hand	101	103
Receivables, net
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	1,032	1,215
Credit Concentration Risk
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	860	1,035
Total cash deposits/collateral on hand	259	346
Credit Concentration Risk | Receivables, net
Credit Derivatives [Line Items]
Financial assets, considered to be past due	115	118
Fair Value, Financial assets, considered to be past due	$ 106	$ 107
Average number of days financial asset outstanding | NumberOfDays	71

Derivatives Instruments (Concen

Derivatives Instruments (Concentration Risk) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,119	$ 1,382
% of total exposure	100.00%	100.00%
Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 87	$ 167
% of total exposure	8.00%	12.00%
Credit Concentration Risk
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 860	$ 1,035
Credit rating of A- or above | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 47	$ 130
% of total exposure	4.00%	9.00%
Credit rating of BBB- to BBB+ | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 8	$ 9
% of total exposure	1.00%	1.00%
Not rated | Derivative Instruments (current and long-term)
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 32	$ 28
% of total exposure	3.00%	2.00%
Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,032	$ 1,215
% of total exposure	92.00%	88.00%
Receivables, net | Other accounts receivable
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 184	$ 273
% of total exposure	16.00%	20.00%
Receivables, net | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 192	$ 235
% of total exposure	17.00%	17.00%
Receivables, net | Credit rating of A- or above | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 38	$ 49
% of total exposure	3.00%	4.00%
Receivables, net | Credit rating of BBB- to BBB+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 59	$ 70
% of total exposure	5.00%	5.00%
Receivables, net | Credit rating of CCC- to CCC+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 0	$ 8
% of total exposure	0.00%	0.00%
Receivables, net | Not rated | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 95	$ 108
% of total exposure	9.00%	8.00%
Regulated utilities | Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 711	$ 707
% of total exposure	64.00%	51.00%
Regulated utilities | Receivables, net | Residential
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 344	$ 384
% of total exposure	31.00%	28.00%
Regulated utilities | Receivables, net | Commercial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 170	$ 182
% of total exposure	15.00%	13.00%
Regulated utilities | Receivables, net | Industrial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 66	$ 57
% of total exposure	6.00%	4.00%
Regulated utilities | Receivables, net | Other
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 131	$ 84
% of total exposure	12.00%	6.00%

Derivatives Instruments (Cash C

Derivatives Instruments (Cash Collateral) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
13. Derivative Instruments
Cash collateral provided to others	$ 101	$ 103
Cash collateral received from others	2	77
Total fair value of these derivatives, in a liability position	$ 370	$ 365

Fair Values (Derivatives) (Deta

Fair Values (Derivatives) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016
Assets
Total assets	$ 87	$ 167
Liabilities
Total liabilities	370	365
Fair Value, Measurements, Recurring
Assets
Total assets	87	167
Liabilities
Total liabilities	370	365
Net assets (liabilities)	(283)	(198)
Fair Value, Measurements, Recurring | Regulatory deferral
Assets
Total assets	28	104
Liabilities
Total liabilities	78	6
Fair Value, Measurements, Recurring | Regulatory deferral | Power
Assets
Total assets	23	2
Liabilities
Total liabilities	36	1
Fair Value, Measurements, Recurring | Regulatory deferral | Coal
Assets
Total assets	0	70
Liabilities
Total liabilities	31	1
Fair Value, Measurements, Recurring | Regulatory deferral | Heavy fuel oil purchases
Assets
Total assets	1	1
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Regulatory deferral | Natural gas
Assets
Total assets	2	2
Liabilities
Total liabilities	5	3
Fair Value, Measurements, Recurring | Regulatory deferral | Foreign exchange forwards
Assets
Total assets	2	29
Liabilities
Total liabilities	6
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument
Assets
Total assets	1	1
Fair Value, Measurements, Recurring | Not Designated as Hedging Instrument | Interest rate swaps
Assets
Total assets	1	1
Fair Value, Measurements, Recurring | HFT derivatives
Assets
Total assets	58	62
Liabilities
Total liabilities	291	354
Fair Value, Measurements, Recurring | HFT derivatives | Power
Assets
Total assets	5	7
Liabilities
Total liabilities	7	21
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | Natural gas
Assets
Total assets	53	55
Liabilities
Total liabilities	284	333
Fair Value, Measurements, Recurring | HFT derivatives | Interest rate swaps | Power
Assets
Total assets	5
Fair Value, Measurements, Recurring | Level 1
Assets
Total assets	18	5
Liabilities
Total liabilities	46	18
Net assets (liabilities)	(28)	(13)
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral
Assets
Total assets	23	2
Liabilities
Total liabilities	39	4	$ 18
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Power
Assets
Total assets	23	2
Liabilities
Total liabilities	36	1
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Coal
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Heavy fuel oil purchases
Assets
Total assets	0	0
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Natural gas
Assets
Total assets	0	0
Liabilities
Total liabilities	3	3
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Foreign exchange forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument
Assets
Total assets	1	0
Fair Value, Measurements, Recurring | Level 1 | Not Designated as Hedging Instrument | Interest rate swaps
Assets
Total assets	1	0
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives
Assets
Total assets	(6)	3
Liabilities
Total liabilities	7	14
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power
Assets
Total assets	1	2
Liabilities
Total liabilities		14
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | Natural gas
Assets
Total assets	(7)	1
Liabilities
Total liabilities	2	0
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Interest rate swaps | Power
Assets
Total assets	1
Fair Value, Measurements, Recurring | Level 2
Assets
Total assets	54	141
Liabilities
Total liabilities	75	41
Net assets (liabilities)	(21)	100
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral
Assets
Total assets	5	102
Liabilities
Total liabilities	39	2
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 | Coal
Assets
Total assets	0	70
Liabilities
Total liabilities	31	1
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Heavy fuel oil purchases
Assets
Total assets	1	1
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Natural gas
Assets
Total assets	2	2
Liabilities
Total liabilities	2	0
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Foreign exchange forwards
Assets
Total assets	2	29
Liabilities
Total liabilities	6
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument
Assets
Total assets	0	1
Fair Value, Measurements, Recurring | Level 2 | Not Designated as Hedging Instrument | Interest rate swaps
Assets
Total assets	0	1
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives
Assets
Total assets	49	38
Liabilities
Total liabilities	35	34
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power
Assets
Total assets	3	2
Liabilities
Total liabilities		6
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | Natural gas
Assets
Total assets	46	36
Liabilities
Total liabilities	33	28
Fair Value, Measurements, Recurring | Level 3
Assets
Total assets	15	21
Liabilities
Total liabilities	249	306
Net assets (liabilities)	(234)	(285)
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 | Power
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Coal
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	0
Liabilities
Total liabilities	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 swaps
Assets
Total assets	0	0
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives
Assets
Total assets	15	21
Liabilities
Total liabilities	249	306
Net assets (liabilities)	(234)	(285)
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power
Assets
Total assets	1	3
Liabilities
Total liabilities		1
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas
Assets
Total assets	9	8
Liabilities
Total liabilities	228	286
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Energy Related derivative | Natural gas
Assets
Total assets	5	10
Liabilities
Total liabilities	21	19
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | Natural gas
Assets
Total assets	14	18
Liabilities
Total liabilities	$ 249	$ 305

Fair Values (fair value of the

Fair Values (fair value of the Level 3 financial assets) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues	12 Months Ended
	Dec. 31, 2019CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 21,000,000
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(6,000,000)
Ending Balance	15,000,000
Net transfers out of Level 3	0
Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	3,000,000
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(2,000,000)
Ending Balance	1,000,000
Natural gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	18,000,000
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(4,000,000)
Ending Balance	$ 14,000,000

Fair Values (fair value of th_2

Fair Values (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, 2019CAD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 306
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(57)
Ending Balance	249
Power
Fair Value, Liabilities 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	(1)
Ending Balance	0
Natural gas
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	305
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(56)
Ending Balance	$ 249

Fair Values (Quantitative Infor

Fair Values (Quantitative Information Significant Unobservable Inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy) (Details)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Assets
Total assets	$ 87,000,000	$ 167,000,000
Liabilities
Total liabilities	370,000,000	365,000,000
Fair Value, Measurements, Recurring
Assets
Total assets	87,000,000	167,000,000
Liabilities
Total liabilities	370,000,000	365,000,000
Net assets (liabilities)	(283,000,000)	(198,000,000)
Not Designated as Hedging Instrument | Fair Value, Measurements, Recurring
Assets
Total assets	1,000,000	1,000,000
HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	58,000,000	62,000,000
Liabilities
Total liabilities	291,000,000	354,000,000
HFT derivatives | Power | Fair Value, Measurements, Recurring
Assets
Total assets	5,000,000	7,000,000
Liabilities
Total liabilities	7,000,000	21,000,000
Level 3 | Fair Value, Measurements, Recurring
Assets
Total assets	15,000,000	21,000,000
Liabilities
Total liabilities	249,000,000	306,000,000
Net assets (liabilities)	(234,000,000)	(285,000,000)
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	15,000,000	21,000,000
Liabilities
Total liabilities	249,000,000	306,000,000
Net assets (liabilities)	(234,000,000)	(285,000,000)
Level 3 | HFT derivatives | Power | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1,000,000	$ 3,000,000
Valuation Technique, Assets	us-gaap:ValuationTechniqueConsensusPricingModelMember	us-gaap:ValuationTechniqueConsensusPricingModelMember
Liabilities
Total liabilities		$ 1,000,000
Valuation Technique, Liabilities		us-gaap:ValuationTechniqueConsensusPricingModelMember
Level 3 | HFT derivatives | Natural gas | Fair Value, Measurements, Recurring
Assets
Total assets	$ 9,000,000	$ 8,000,000
Valuation Technique, Assets	us-gaap:ValuationTechniqueConsensusPricingModelMember	us-gaap:ValuationTechniqueConsensusPricingModelMember
Liabilities
Total liabilities	$ 228,000,000	$ 286,000,000
Valuation Technique, Liabilities	us-gaap:ValuationTechniqueConsensusPricingModelMember	us-gaap:ValuationTechniqueConsensusPricingModelMember
Level 3 | HFT derivatives | Energy Related derivative | Natural gas | Fair Value, Measurements, Recurring
Assets
Total assets	$ 5,000,000	$ 10,000,000
Valuation Technique, Assets	us-gaap:ValuationTechniqueConsensusPricingModelMember	us-gaap:ValuationTechniqueConsensusPricingModelMember
Liabilities
Total liabilities	$ 21,000,000	$ 19,000,000
Valuation Technique, Liabilities	us-gaap:ValuationTechniqueConsensusPricingModelMember	us-gaap:ValuationTechniqueConsensusPricingModelMember
Level 3 | HFT derivatives | Range, Minimum | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 21.4	$ 24.31
Liabilities
Total liabilities		$ 20.8
Level 3 | HFT derivatives | Range, Minimum | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.01	0.0003
Liabilities
Unobservable Input, Liabilities		0.0008
Level 3 | HFT derivatives | Range, Minimum | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.15	0.0003
Liabilities
Unobservable Input, Liabilities		0.0003
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.63	$ 1.8
Liabilities
Total liabilities	$ 1.54	$ 1.48
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.01	0.0001
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.01	0.0001
Liabilities
Unobservable Input, Liabilities	0.0001	0.0001
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities		0.8498
Level 3 | HFT derivatives | Range, Minimum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0001	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.33	$ 1.95
Liabilities
Total liabilities	$ 1.36	$ 2.15
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0001	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0001	0.0001
Liabilities
Unobservable Input, Liabilities	0.0001	0.0001
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 0	$ 0.07
Liabilities
Total liabilities	$ 0	$ 0.07
Level 3 | HFT derivatives | Range, Minimum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0001	0.0001
Level 3 | HFT derivatives | Range, Maximum | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 74.05	$ 50.29
Liabilities
Total liabilities		$ 50.29
Level 3 | HFT derivatives | Range, Maximum | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	1.14	0.0013
Liabilities
Unobservable Input, Liabilities		0.0029
Level 3 | HFT derivatives | Range, Maximum | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	6.65	0.0219
Liabilities
Unobservable Input, Liabilities		0.0299
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 7.45	$ 12.21
Liabilities
Total liabilities	$ 7.45	$ 12.9
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	2.31	0.0294
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	20.93	0.3062
Liabilities
Unobservable Input, Liabilities	0.1863	0.1196
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities		0.8498
Level 3 | HFT derivatives | Range, Maximum | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0231	0.0294
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 8.76	$ 12.9
Liabilities
Total liabilities	$ 9.75	$ 13.18
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0333	0.032
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0471	0.0761
Liabilities
Unobservable Input, Liabilities	0.0376	0.0761
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 1.31	$ 3.43
Liabilities
Total liabilities	$ 1.31	$ 3.43
Level 3 | HFT derivatives | Range, Maximum | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0333	0.0276
Level 3 | HFT derivatives | Weighted average | Power | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 35.03	$ 31.43
Liabilities
Total liabilities		$ 26.38
Level 3 | HFT derivatives | Weighted average | Power | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.21	0.0013
Liabilities
Unobservable Input, Liabilities		0.0015
Level 3 | HFT derivatives | Weighted average | Power | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	2.78	0.0145
Liabilities
Unobservable Input, Liabilities		0.0165
Level 3 | HFT derivatives | Weighted average | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 2.37	$ 4.75
Liabilities
Total liabilities	$ 4.07	$ 5.75
Level 3 | HFT derivatives | Weighted average | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.09	0.0024
Level 3 | HFT derivatives | Weighted average | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	1.55	0.0425
Liabilities
Unobservable Input, Liabilities	0.0189	0.0235
Level 3 | HFT derivatives | Weighted average | Natural gas | Correlation factor | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities		0.8498
Level 3 | HFT derivatives | Weighted average | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0012	0.0009
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Third-party pricing | Fair Value, Measurements, Recurring
Assets
Total assets	$ 5.05	$ 8.68
Liabilities
Total liabilities	$ 5.45	$ 7.54
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Probability of default | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0028	0.0057
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Discount rate | Fair Value, Measurements, Recurring
Assets
Unobservable Input, Assets	0.0091	0.0042
Liabilities
Unobservable Input, Liabilities	0.0081	0.0138
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Basis adjustment | Fair Value, Measurements, Recurring
Assets
Total assets	$ 0.76	$ 1.88
Liabilities
Total liabilities	$ 0.91	$ 2.67
Level 3 | HFT derivatives | Weighted average | Energy Related derivative | Natural gas | Own credit risk | Fair Value, Measurements, Recurring
Liabilities
Unobservable Input, Liabilities	0.0006	0.001

Fair Values (Assets and Liabili

Fair Values (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	$ (16,049)	$ (15,908)
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	(15,598)	(14,991)
Fair Value Measurement [Domain] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	(451)	(917)
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	(14,180)	(15,411)
Financial assets and liabilities	$ (16,049)	$ (15,908)

Fair Values (Hybrid Notes) (Det

Fair Values (Hybrid Notes) (Details) - Net investment in United States dollar denominated operations - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200
After-tax foreign currency gain (loss)	$ 78	$ 122

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 121	$ 165
Regulatory Assets, Long-term	1,431	1,404
Total regulatory assets	1,552	1,569
Deferred income tax regulatory assets
Regulatory Assets [Line Items]
Total regulatory assets	862	775
Pension and post-retirement medical plan
Regulatory Assets [Line Items]
Total regulatory assets	380	453
Deferrals related to derivative instruments
Regulatory Assets [Line Items]
Total regulatory assets	81	10
Storm reserve
Regulatory Assets [Line Items]
Total regulatory assets	38	32
Stranded cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	27	28
Environmental remediations
Regulatory Assets [Line Items]
Total regulatory assets	26	31
Demand side management ("DSM") deferral
Regulatory Assets [Line Items]
Total regulatory assets	19	24
Unamortized defeasance costs
Regulatory Assets [Line Items]
Total regulatory assets	19	26
Cost recovery clauses
Regulatory Assets [Line Items]
Total regulatory assets	13	75
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 87	$ 115

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 295	$ 251
Regulatory Liability, Long-term	1,886	2,359
Total regulatory liabilities	2,181	2,610
Deferred income tax regulatory liabilities
Regulatory Liabilities [Line Items]
Total regulatory liabilities	985	1,218
Accumulated reserve - cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	891	955
Regulated fuel adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	115	161
Storm reserve
Regulatory Liabilities [Line Items]
Total regulatory liabilities	62	76
Cost recovery clauses
Regulatory Liabilities [Line Items]
Total regulatory liabilities	53	30
Deferrals related to derivative instruments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	42	116
Self-insurance fund
Regulatory Liabilities [Line Items]
Total regulatory liabilities	29	30
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 4	$ 24

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions	Jan. 01, 2019USD ($)	Sep. 12, 2018USD ($)	Aug. 20, 2018USD ($)	Jan. 31, 2020USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018CAD ($)	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)kmMW	Dec. 31, 2019USD ($)MW	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)km	Dec. 31, 2018USD ($)	Dec. 13, 2016CAD ($)	Dec. 31, 2015CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities						$ 2,610					$ 2,181		$ 2,610
Depreciation and amortization											903		916
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses											1,464		1,580
Contractual Obligation, to be Paid, Year One											1,950
Contractual Obligation, to be Paid, Year Two											970
Income tax expense (recovery)											(61)		(69)
Regulatory Assets						1,569					$ 1,552		$ 1,569
State income tax											8.00%	8.00%	8.00%
Regulated fuel adjustment mechanism
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities						161					$ 115		$ 161
Cost recovery clauses
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						75					13		75
Renewable Energy Program
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						24					19		24
Environmental remediations
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						31					26		31
Unamortized defeasance costs
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						$ 26					19		$ 26
Emera Maine
Public Utilities, General Disclosures [Line Items]
Contractual Obligation, to be Paid, Year One											49
Contractual Obligation, to be Paid, Year Two											$ 0
Barbados Light and Power Company Limited
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											10.00%	10.00%
Deferred Tax Liabilities, Regulatory Assets and Liabilities														$ 6.9
Income tax expense (recovery)												$ 9.6
GBPC
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						8.44%					8.50%	8.50%	8.50%
GBPC | Loss from Catastrophes | Hurricane
Public Utilities, General Disclosures [Line Items]
Storm cost											$ 15	$ 12
Storm Reserve											$ 23
Brunswick Pipeline
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km											145			145
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life											25 years	25 years
NSPI
Public Utilities, General Disclosures [Line Items]
Regulated common equity component											40.00%	40.00%
Contractual Obligation, to be Paid, Year One											$ 0
Contractual Obligation, to be Paid, Year Two											0
NSPI | NSPML
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes											10
Regulatory Liabilities						$ 110					111		$ 110
Approved payment in period											$ 101
Interim cost assessment, holdback											The payments are 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.	The payments are 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.
Holdback payable											$ 6
Depreciation and amortization											53		53
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses											115
Depreciation and amortization of financing costs											30
Contractual Obligation, to be Paid, Year One											145
Contractual Obligation, to be Paid, Year Two											111
Phase-in Plan, Amount of Capitalized Costs Recovered											$ 35		17
Regulatory Asset Recovery Assessments											On December 6, 2019, the UARB approved NSPI’s three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. For the years 2020 to 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from or returned to customers after 2022. The decision further directed that annual excess non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.	On December 6, 2019, the UARB approved NSPI’s three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. For the years 2020 to 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from or returned to customers after 2022. The decision further directed that annual excess non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.
Recovery Period											3 years	3 years
NSPI | NSPML | Regulated fuel adjustment mechanism
Public Utilities, General Disclosures [Line Items]
Holdback payable											$ 10
NSPI | NSPML | Regulated fuel adjustment mechanism | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes											$ 52
Phase-in Plan, Amount of Capitalized Costs Recovered									$ 12	$ 40
Regulatory Asset Recovery Assessments											The UARB’s decision to approve NSPI’s 2020 through 2022 Fuel Stability Plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The reduced assessment will be refunded to most customers through a reduction incorporated into their 2020 through 2022 rates and the remaining customers will receive a one-time on bill credit in 2020.The credit to customers will be approximately $40 million plus interest in 2020, with the remaining $12 million plus interest to be returned to customers subsequent to 2022.	The UARB’s decision to approve NSPI’s 2020 through 2022 Fuel Stability Plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The reduced assessment will be refunded to most customers through a reduction incorporated into their 2020 through 2022 rates and the remaining customers will receive a one-time on bill credit in 2020.The credit to customers will be approximately $40 million plus interest in 2020, with the remaining $12 million plus interest to be returned to customers subsequent to 2022.
NSPI | Renewable Energy Program
Public Utilities, General Disclosures [Line Items]
Replacement program																$ 31	$ 35
NSPI | Unamortized defeasance costs | Defeased debt
Public Utilities, General Disclosures [Line Items]
Long-term debt						759					$ 740		759
NMGC
Public Utilities, General Disclosures [Line Items]
Public Utilities, Disclosure of Rate Matters											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 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.
Approved regulated return on equity											9.10%	9.10%
Allowed equity capital structure											52.00%	52.00%
Contractual Obligation, to be Paid, Year One											$ 0
Contractual Obligation, to be Paid, Year Two											$ 0
Deferred Tax Liabilities, Regulatory Assets and Liabilities						$ 11							$ 11		$ 8
PGS
Public Utilities, General Disclosures [Line Items]
Public Utilities, Disclosure of Rate Matters											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 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.
Approved regulated return on equity											10.75%	10.75%
Allowed equity capital structure											54.70%	54.70%
Length Of Pipeline | km											800			800
Contractual Obligation, to be Paid, Year One											$ 0
Contractual Obligation, to be Paid, Year Two											$ 61
Length Of Pipeline, percentage											5.00%			5.00%
Replacement program														$ 80
Amortization of Regulatory Asset		$ 11
Public utilities base rate decrease	$ 12
Reduction in annual depreciation	$ 10
Regulatory Asset Amortization Period											10 years	10 years
Tampa Electric
Public Utilities, General Disclosures [Line Items]
Contractual Obligation, to be Paid, Year One											$ 0
Contractual Obligation, to be Paid, Year Two											$ 301
State income tax											4.46%	4.46%	5.50%
Tampa Electric | Hurricane
Public Utilities, General Disclosures [Line Items]
Storm cost					$ 8
Tampa Electric | SoBRA
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
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Generation or Processing														$ 30
Maritime Link Project | NSPI
Public Utilities, General Disclosures [Line Items]
Contractual Obligation, to be Paid, Year One											$ 145
Contractual Obligation, to be Paid, Year Two											$ 164
Steam turbine | GBPC
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment												$ 21
New Mexico Public Regulatory | NMGC
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Capitalized Costs Recovered												$ 3
Public Utilities, Disclosure of Regulatory Matters Pending											On December 23, 2019, NMGC filed a future year rate case on December 23, 2019 for new rates effective January 2021. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure. The estimated annual incremental revenue requirement is approximately $13 million USD. A decision from the NMPRC is expected in late 2020.	On December 23, 2019, NMGC filed a future year rate case on December 23, 2019 for new rates effective January 2021. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure. The estimated annual incremental revenue requirement is approximately $13 million USD. A decision from the NMPRC is expected in late 2020.
Public Utilities, Phase-in Plan Terms											The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD.	The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD.
Public Utilities, Requested Rate Increase (Decrease), Amount												$ 13
Income tax expense (recovery)											$ 7	$ 5
MPUC | Emera Maine
Public Utilities, General Disclosures [Line Items]
Approved average annual increase							5.30%
Approved regulated return on equity								9.00%			9.35%	9.35%
Allowed equity capital structure											49.00%	49.00%	49.00%
FERC | Emera Maine
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											10.57%	10.57%	10.57%
FERC | Electric Transmission | Emera Maine
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											9.60%	9.60%	9.60%
Electricity Plan Act | NSPI
Public Utilities, General Disclosures [Line Items]
Approved average annual increase											1.50%	1.50%
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage											1.50%	1.50%
Florida Public Service Commission | Tampa Electric
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			$ 103									$ 5
Florida Public Service Commission | Tampa Electric | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Storm cost				$ 12
Florida Public Service Commission | Tampa Electric | Cost recovery clauses
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											10.25%	10.25%
Florida Public Service Commission | Tampa Electric | SoBRA
Public Utilities, General Disclosures [Line Items]
Estimated revenue												$ 96
Estimated revenue in MW | MW											554	554
Range, Minimum | NSPI
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											8.75%	8.75%
Range, Minimum | NSPI | NSPML
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											8.75%	8.75%
Range, Minimum | PGS
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											9.25%	9.25%
Range, Minimum | FERC | ISO-New England ("ISO-NE") Open Access Transmission Tariff ("OATT") | Emera Maine
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											11.07%	11.07%	11.07%
Range, Minimum | Florida Public Service Commission | Tampa Electric
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											9.25%	9.25%	9.25%
Range, Maximum | NSPI
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											9.25%	9.25%
Range, Maximum | NSPI | NSPML
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											9.25%	9.25%
Regulated common equity component											30.00%	30.00%
Range, Maximum | PGS
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											11.75%	11.75%
Range, Maximum | FERC | ISO-New England ("ISO-NE") Open Access Transmission Tariff ("OATT") | Emera Maine
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											11.74%	11.74%	11.74%
Range, Maximum | Florida Public Service Commission | Tampa Electric
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity											11.25%	11.25%	11.25%

Related Paty Transactions (Narr

Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
NSPML | Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 107	$ 97
M&NP | Non-Regulated
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 63	$ 29

Receivables And Other Current_3

Receivables And Other Current Assets (Summary of Receivables And Other Current Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
17. Receivables and Other Current Assets
Customer accounts receivable - billed	$ 704	$ 844
Customer accounts receivable - unbilled	265	296
Allowance for Doubtful Accounts	(9)	(11)
Other receivables	72	86
Capitalized transportation capacity	272	179
Income taxes receivable	118	175
Prepaid expenses	48	42
Net investment in direct financing lease (note 18)	9	9
Other current assets	7	0
Receivables and other current assets	$ 1,486	$ 1,620

Property, plant and equipment_2

Property, plant and equipment (Regulated and Non-regulated Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment, Net
Total cost	$ 24,871	$ 26,043
Less: Accumulated depreciation	(8,295)	(8,567)
Total cost less: Accumulated depreciation	16,576	17,476
Construction work in progress	1,591	1,236
Property, Plant and Equipment, Net	18,167	18,712
Generation
Property, Plant and Equipment, Net
Total cost	$ 11,181	11,092
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	$ 2,318	3,047
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	$ 5,820	6,348
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	$ 3,546	3,398
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	$ 2,006	$ 2,158
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

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, 2019	Dec. 31, 2018
Defined benefit pension plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	$ 2,650	$ 2,683
Service cost	47	51
Plan participant contributions	8	8
Interest cost	102	95
Benefits Paid	(130)	(143)
Actuarial (gains) losses	231	(133)
Settlement, curtailments	(20)	(18)
Foreign currency translation adjustment	(66)	107
Benefit Obligation, Ending Balance	2,822	2,650
Change in plan assets
Plan Assets, Beginning Balance	2,300	2,408
Employer contributions	52	51
Plan participant contributions	8	8
Benefits paid	(130)	(143)
Actual return on assets, net of expenses	424	(105)
Settlements and curtailments	(7)	(18)
Foreign currency translation adjustment	(54)	99
Plan Assets, Ending Balance	2,593	2,300
Funded Status
Funded status, end of year	(229)	(350)
Non-pension Benefit Plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	350	356
Service cost	4	6
Plan participant contributions	5	5
Interest cost	14	13
Benefits Paid	(23)	(33)
Actuarial (gains) losses	19	(25)
Settlement, curtailments	0	0
Foreign currency translation adjustment	(16)	28
Benefit Obligation, Ending Balance	353	350
Change in plan assets
Plan Assets, Beginning Balance	49	45
Employer contributions	19	31
Plan participant contributions	5	5
Benefits paid	(23)	(33)
Actual return on assets, net of expenses	7	(3)
Settlements and curtailments	0	0
Foreign currency translation adjustment	(1)	4
Plan Assets, Ending Balance	56	49
Funded Status
Funded status, end of year	$ (297)	$ (301)

Employee Benefit Plans (Plans w

Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Defined benefit pension plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	$ 2,797	$ 2,623
Fair value of plan assets	2,557	2,264
Funded Status	(240)	(359)
Non-pension Benefit Plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	323	318
Fair value of plan assets	7	6
Funded Status	$ (316)	$ (312)

Employee Benefit Plans (Accumul

Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - Defined benefit pension plans - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO for the defined benefit pension plans	$ 2,687	$ 2,527
ABO	2,665	2,504
Fair value of plan assets	2,557	2,264
Funded Status	$ (108)	$ (240)

Employee Benefit Plans (Amounts

Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Balance Sheet
Other current liabilities	$ (22)	$ (31)
Long-term liabilities	(460)	(641)
Long-term liabilities associated with assets held for sale	(899)	(2)
Defined benefit pension plans
Balance Sheet
Other current liabilities	(4)	(12)
Long-term liabilities	(206)	(347)
Long-term liabilities associated with assets held for sale	(30)	0
Other long-term assets	11	9
Amount included in deferred income tax		5
Amount included in deferred income tax	(7)
AOCI, net of tax and regulatory assets	524	628
Net amount recognized	288	283
Non-pension Benefit Plans
Balance Sheet
Other current liabilities	(18)	(19)
Long-term liabilities	(254)	(294)
Long-term liabilities associated with assets held for sale	(44)	0
Other long-term assets	19	11
Amount included in deferred income tax	1
Amount included in deferred income tax		(2)
AOCI, net of tax and regulatory assets	72	60
Net amount recognized	$ (224)	$ (244)

Employee Benefit Plans (Change

Employee Benefit Plans (Change in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined benefit pension plans
Change in AOCI and Regulatory Assets
Beginning Balance	$ 633
Amortized in current period	16	$ 33
Ending Balance	517	633
Defined benefit pension plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	389
Amortized in current period	(20)
Current year addition to AOCI	6
Foreign currency translation adjustment	(17)
Ending Balance	358	389
Defined benefit pension plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	246
Amortized in current period	(17)
Current year addition to AOCI	(69)
Foreign currency translation adjustment	0
Ending Balance	160	246
Defined benefit pension plans | Past service costs (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	(2)
Amortized in current period	1
Current year addition to AOCI	0
Foreign currency translation adjustment	0
Ending Balance	(1)	(2)
Non-pension Benefit Plans
Change in AOCI and Regulatory Assets
Beginning Balance	58
Amortized in current period	0	(1)
Ending Balance	73	58
Non-pension Benefit Plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	65
Amortized in current period	5
Current year addition to AOCI	11
Foreign currency translation adjustment	(3)
Ending Balance	78	65
Non-pension Benefit Plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	(7)
Amortized in current period	0
Current year addition to AOCI	2
Foreign currency translation adjustment	0
Ending Balance	(5)	(7)
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	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, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 1,552	$ 1,569
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	160	246
Past service (gains)	(1)	(2)
Regulatory assets	358	389
Accumulated Other Comprehensive Income (Loss), before Tax, Total	517	633
Amount included in deferred income tax		7
Amount included in deferred income tax	(5)
Net amount in AOCI after tax adjustment	524	628
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	(5)	(7)
Past service (gains)	0	0
Regulatory assets	78	65
Accumulated Other Comprehensive Income (Loss), before Tax, Total	73	58
Amount included in deferred income tax	2
Amount included in deferred income tax		(1)
Net amount in AOCI after tax adjustment	$ 72	$ 60

Employee Benefit Plans (Net Per

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (2,401)	$ (2,223)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	47	51
Interest cost	102	95
Expected return on plan assets	(147)	(138)
Current year amortization of: Actuarial losses	16	33
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(1)	(1)
Regulatory assets (liability)	26	20
Settlement, curtailments	1	4
Net Periodic Benefit Cost, Total	38	70
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	4	6
Interest cost	14	13
Expected return on plan assets	(2)	(2)
Current year amortization of: Actuarial losses	0	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Regulatory assets (liability)	(2)	(5)
Settlement, curtailments	0	0
Net Periodic Benefit Cost, Total	$ 11	$ 14

Employee Benefit Plans (Asset C

Employee Benefit Plans (Asset Class) (Details) - Defined benefit pension plans	Dec. 31, 2019
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	40.00%
Fixed income | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	45.00%
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	55.00%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	60.00%

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value of Investments) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Classification of the methodology used by the Company to fair value its investments
Percentage	100.00%	100.00%
Defined benefit pension plans
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,593	$ 2,300	$ 2,408
Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Percentage		1.00%
Net in-transits
Classification of the methodology used by the Company to fair value its investments
Percentage	(2.00%)	(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		14.00%
Other equity
Classification of the methodology used by the Company to fair value its investments
Percentage	7.00%	7.00%
Government
Classification of the methodology used by the Company to fair value its investments
Percentage	3.00%	5.00%
Corporate
Classification of the methodology used by the Company to fair value its investments
Percentage		5.00%
Other
Classification of the methodology used by the Company to fair value its investments
Percentage		0.00%
Mutual funds
Classification of the methodology used by the Company to fair value its investments
Percentage		6.00%
Other
Classification of the methodology used by the Company to fair value its investments
Percentage		1.00%
Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Percentage	33.00%	36.00%
Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Percentage	21.00%	19.00%
Total
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,593	$ 2,300
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	$ 44	30
Percentage	2.00%
Total | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (48)	(56)
Percentage	(2.00%)
Total | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 210	191
Percentage	8.00%
Total | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 388	330
Percentage	15.00%
Total | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 176	157
Percentage	7.00%
Total | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 93	119
Percentage	3.00%
Total | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 126	108
Percentage	5.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 14	7
Percentage	0.00%
Total | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 199	132
Percentage	8.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (4)	12
Percentage	0.00%
Total | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 860	820
Percentage	33.00%
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	$ 535	450
Percentage	21.00%
NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,395	1,270
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	860	820
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	535	450
Level 1
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	969	796
Level 1 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	44	30
Level 1 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(48)	(56)
Level 1 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	210	191
Level 1 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	388	330
Level 1 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	176	157
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	5	4
Level 1 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	199	132
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(5)	8
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	229	234
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	93	119
Level 2 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	126	108
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	9	3
Level 2 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	1	4
Level 2 | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 0	$ 0

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2019CAD ($)
Defined benefit pension plans
Expected employer contributions
Expected employer contributions, 2020	$ 44
Expected benefit payments
Expected benefit payments, 2020	143
Expected benefit payments, 2021	154
Expected benefit payments, 2022	158
Expected benefit payments, 2023	165
Expected benefit payments, 2024	173
Expected benefit payments, 2025 - 2028	959
Non-pension Benefit Plans
Expected employer contributions
Expected employer contributions, 2020	21
Expected benefit payments
Expected benefit payments, 2020	23
Expected benefit payments, 2021	23
Expected benefit payments, 2022	23
Expected benefit payments, 2023	23
Expected benefit payments, 2024	23
Expected benefit payments, 2025 - 2028	$ 115

Employee Benefit Plans (Assumpt

Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
An increase or decrease of one percentage point of the assumed health care cost trend
Service cost and interest cost, Increase	$ 1
Service cost and interest cost, Decrease	(1)
Accumulated post-retirement benefit obligation, December 31, Increase	16
Accumulated post-retirement benefit obligation, December 31, Decrease	(14)
A 25 basis point change in the discount rate and asset return assumptions
Discount rate assumption, Increase	(9)
Discount rate assumption, Decrease	9
Asset rate assumption, Increase	(6)
Asset rate assumption, Decrease	$ 6
Defined benefit pension plans
Benefit obligation - December 31:
Discount rate - past service	3.17%	4.05%
Discount rate - future service	3.21%	4.05%
Rate of compensation increase	3.32%	3.30%
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 and future service	4.05%	3.55%
Expected long-term return on plan assets	6.50%	6.38%
Rate of compensation increase	3.30%	3.12%
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	3.27%	4.30%
Discount rate - future service	3.28%	4.30%
Rate of compensation increase	3.70%	3.67%
Health care trend - initial (next year)	6.15%	6.39%
Health care trend - ultimate	4.38%	4.45%
Health care trend - year ultimate reached	2038	2035
Benefit cost for year ended December 31:
Discount rate - past and future service	4.30%	3.65%
Expected long-term return on plan assets	2.81%	3.73%
Rate of compensation increase	3.67%	3.28%
Health care trend - initial (next year)	6.39%	6.65%
Health care trend - ultimate	4.45%	4.45%
Health care trend - year ultimate reached	2035	2036

Employee Benefit Plans (Amoun_2

Employee Benefit Plans (Amounts to be Amortized in the Next Fiscal Year) (Details) $ in Millions	Dec. 31, 2019CAD ($)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial gains (losses)	$ (14)
Past service gains	(1)
Regulated assets	(29)
Total	(44)
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial gains (losses)	0
Past service gains	0
Regulated assets	(1)
Total	$ (1)

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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, Maine, 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	$ 2,401	$ 2,223
Defined Benefit Plan, Assumptions Used in Calculation, Description	benefit cost of a 25 basis point change in the discount rate and asset return assumptions i
Contribution Amount	$ 34	31
Defined benefit pension plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	147	138
Defined Benefit Plan, Fair Value of Plan Assets	2,593	2,300	$ 2,408
Non-pension Benefit Plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	2	2
Defined Benefit Plan, Fair Value of Plan Assets	$ 56	$ 49	$ 45

Leases (Operating Leases) (Deta

Leases (Operating Leases) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Assets and Liabilities, Lessee
Right-of-use asset	$ 64
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Other Assets, Miscellaneous, Noncurrent
Lease liabilities, Current	$ 5
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other Liabilities, Current
Lease liabilities, Long-term	$ 61
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Liabilities, Noncurrent
Total lease liabilities	$ 66
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	7
Right-of-use assets obtained in exchange for lease obligations: Operating leases	$ 16
Weighted average remaining lease term (years)	39 years
Weighted average discount rate - operating leases	4.07%

Leases (Future minimum lease pa

Leases (Future minimum lease payments under non-cancellable operating leases) (Details) $ in Millions	Dec. 31, 2019CAD ($)
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter
2020	$ 8
2021	8
2022	7
2023	6
2024	5
Thereafter	102
Minimum lease payments, Total	136
Less imputed interest	(70)
Total	$ 66

Leases (Direct Finance and Sale

Leases (Direct Finance and Sales-type Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Net investment in direct finance and sales-type leases
Total minimum lease payments to be received	$ 1,066
Less: amounts representing estimated executory costs	(189)
Minimum lease payments receivable	877	$ 865
Estimated residual value of leased property (unguaranteed)	183	183
Less: unearned finance lease income	(532)	(564)
Net investment in direct finance and sales-type leases	528
Principal due within one year (included in "Receivables and other current assets")	17
Net investment in sales-type leases - long-term (included in "Other long-term assets")	38
Net Investment in direct finance leases - long-term	473	475
Future minimum lease payments to be received for each of the next five years and in aggregate thereafter
2020	76
2021	74
2022	73
2023	73
2024	74
Thereafter	696
Total minimum lease payments to be received	1,066
Less: executory costs	(189)
Minimum lease payments receivable	$ 877	$ 865

Leases (Narrative) (Details)

Leases (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
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 66 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	$ 172
Variable costs for power generation facility finance leases	$ 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 66 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 relate 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 relate 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	66 years

Goodwill (Details)

Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Roll Forward]
Balance, January 1	$ 6,313	$ 5,805
Additions	3	0
GBPC impairment charge	(30)	0
Classified as assets held for sale	(148)	0
Change in foreign exchange rate	(303)	508
Balance, December 31	5,835	6,313
GBPC
Goodwill [Roll Forward]
Balance, January 1	104
GBPC impairment charge	(30)
Balance, December 31	$ 70	$ 104

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, 2019	Dec. 31, 2018
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 1,537	$ 1,186
Weighted average interest rate	2.54%	3.34%

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. 19, 2019USD ($)	Dec. 16, 2019CAD ($)	Mar. 07, 2019USD ($)	Dec. 31, 2019CAD ($)	Feb. 06, 2020USD ($)	Dec. 20, 2019USD ($)	Jun. 13, 2019CAD ($)	Dec. 31, 2018CAD ($)
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity				$ 2,463				$ 2,065
Advances under revolving credit and term facilities				1,525				1,186
Letters of credit issued within the credit facilities				3				3
Total advances under available facilities				1,528				1,189
Available capacity under existing agreements				$ 935				876
Parent Company [Member]
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity							$ 900
Term credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity				Dec. 31, 2020
Total available capacity				$ 649				682
Revolving credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity				Mar. 22, 2022
Total available capacity				$ 520				546
Revolving credit facility | Tampa Electric Company
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	Feb. 4, 2021			Mar. 22, 2022
Total available capacity	$ 325			$ 520	$ 300	$ 400		443
Revolving credit facility | NMGC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity				Mar. 22, 2022
Total available capacity				$ 162				171
Revolving credit facility | GBPC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity				$ 17				18
Non-revolving term credit facility
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity		Dec. 15, 2020
Total available capacity		$ 400
Non-revolving term credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity			Mar. 5, 2020
Total available capacity			$ 500
Non-revolving term credit facility | Parent Company [Member]
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity				Dec. 31, 2020
Total available capacity				$ 400				0
Accounts receivable revolving credit facility | Tampa Electric Company
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity				Dec. 31, 2021
Total available capacity				$ 195				$ 205

Short Term Debt (Narrative) (De

Short Term Debt (Narrative) (Details) $ in Millions, $ in Millions	Dec. 19, 2019USD ($)	Dec. 16, 2019CAD ($)	Mar. 07, 2019USD ($)	Dec. 31, 2019CAD ($)	Feb. 06, 2020USD ($)	Dec. 20, 2019USD ($)	Dec. 31, 2018CAD ($)
Line of Credit Facility [Line Items]
Weighted average interest rate				2.54%			3.34%
Line of Credit Facility, Maximum Borrowing Capacity				$ 2,463			$ 2,065
Revolving credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date				Mar. 22, 2022
Line of Credit Facility, Maximum Borrowing Capacity				$ 520			546
Revolving credit facility | Tampa Electric Company
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Feb. 4, 2021			Mar. 22, 2022
Line of Credit Facility, Maximum Borrowing Capacity	$ 325			$ 520	$ 300	$ 400	443
Line of Credit Facility, Increase (Decrease), Net	$ 75
Revolving credit facility | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date				Mar. 22, 2022
Line of Credit Facility, Maximum Borrowing Capacity				$ 162			171
Revolving credit facility | GBPC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 17			18
Accounts receivable revolving credit facility | Tampa Electric Company
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date				Dec. 31, 2021
Line of Credit Facility, Maximum Borrowing Capacity				$ 195			205
Term bank credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date				Dec. 31, 2020
Line of Credit Facility, Maximum Borrowing Capacity				$ 649			$ 682
Non-revolving term credit facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date		Dec. 15, 2020
Line of Credit Facility, Maximum Borrowing Capacity		$ 400
Non-revolving term credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date			Mar. 5, 2020
Line of Credit Facility, Maximum Borrowing Capacity			$ 500

Other Current Liabilities (Deta

Other Current Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
23. Other Current Liabilities
Accrued charges	$ 147	$ 154
Accrued interest on long-term debt	77	93
Pension and post-retirement liabilities (note 19)	22	31
Sales and other taxes payable	13	9
Income taxes payable	1	6
Other	73	135
Other current liabilities, Total	$ 333	$ 428

Long Term Debt (Details)

Long Term Debt (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Debt issuance costs	$ (119)	$ (113)
Long-term liabilities associated with assets held for sale	899	2
Amount due within one year	(501)	(1,119)
Long Term Debt, Adjustments	(1,128)	(1,210)
Long-Term Debt	13,679	14,292
Emera
Debt Instrument [Line Items]
Long-term debt	2,496	2,701
Emera US Finance LP
Debt Instrument [Line Items]
Long-term debt	3,572	4,434
TECO Finance
Debt Instrument [Line Items]
Long-term debt	390	409
Tampa Electric Company
Debt Instrument [Line Items]
Long-term debt	3,334	3,126
PGS
Debt Instrument [Line Items]
Long-term debt	437	425
NMGC
Debt Instrument [Line Items]
Long-term debt	474	368
NMGI
Debt Instrument [Line Items]
Long-term debt	195	273
NSPI
Debt Instrument [Line Items]
Long-term debt	2,673	2,576
Emera Maine
Debt Instrument [Line Items]
Long-term debt	518	478
EBP
Debt Instrument [Line Items]
Long-term debt	248	248
ECI
Debt Instrument [Line Items]
Long-term debt	470	464
TECO Energy
Debt Instrument [Line Items]
Fair market value adjustment	$ 8	22
Bankers acceptances | LIBOR loans | Emera
Debt Instrument [Line Items]
Maturity	Jan. 1, 2024
Long-term debt	$ 437	$ 339
Bankers acceptances | LIBOR loans | Emera US Finance LP
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Unsecured fixed rate notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	2.90%	3.50%
Maturity	Jan. 1, 2023
Long-term debt	$ 500	$ 725
Unsecured fixed rate notes | Emera US Finance LP
Debt Instrument [Line Items]
Maturity, Start	Dec. 31, 2021
Maturity, End	Dec. 31, 2046
Fixed to floating subordinated notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	6.75%	6.75%
Maturity	Dec. 31, 2076
Long-term debt	$ 1,559	$ 1,637
Unsecured senior notes | Emera US Finance LP
Debt Instrument [Line Items]
Weighted average interest rate	3.86%	3.60%
Long-term debt	$ 3,572	$ 4,434
Variable rate notes | TECO Finance
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Fixed rate notes and bonds | TECO Finance
Debt Instrument [Line Items]
Weighted average interest rate	5.15%	5.15%
Maturity	Jan. 1, 2020
Long-term debt	$ 390	$ 409
Fixed rate notes and bonds | Tampa Electric Company
Debt Instrument [Line Items]
Weighted average interest rate	4.53%	4.64%
Maturity, Start	Dec. 31, 2021
Maturity, End	Dec. 31, 2050
Long-term debt	$ 3,334	$ 3,126
Fixed rate notes and bonds | PGS
Debt Instrument [Line Items]
Weighted average interest rate	4.58%	4.66%
Maturity, Start	Dec. 31, 2021
Maturity, End	Dec. 31, 2050
Long-term debt	$ 437	$ 425
Fixed rate notes and bonds | NMGC
Debt Instrument [Line Items]
Weighted average interest rate	4.30%	4.53%
Maturity, Start	Dec. 31, 2021
Maturity, End	Dec. 31, 2049
Long-term debt	$ 474	$ 368
Fixed rate notes and bonds | NMGI
Debt Instrument [Line Items]
Weighted average interest rate	3.64%	3.41%
Maturity	Jan. 1, 2024
Long-term debt	$ 195	$ 273
Discount notes | NSPI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	Jan. 1, 2024
Long-term debt	$ 308	$ 516
Medium term fixed rate notes | NSPI
Debt Instrument [Line Items]
Weighted average interest rate	5.37%	5.73%
Maturity, Start	Dec. 31, 2025
Maturity, End	Dec. 31, 2097
Long-term debt	$ 2,365	$ 1,965
Fixed rate debenture | NSPI
Debt Instrument [Line Items]
Weighted average interest rate	0.00%	9.75%
Long-term debt	$ 0	$ 95
LIBOR loans and demand loans | Emera Maine
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	Jan. 1, 2023
Long-term debt	$ 11	$ 28
Secured fixed rate mortgage bonds | Emera Maine
Debt Instrument [Line Items]
Weighted average interest rate	9.74%	9.74%
Maturity, Start	Dec. 31, 2020
Maturity, End	Dec. 31, 2022
Long-term debt	$ 65	$ 68
Unsecured senior fixed rate notes | Emera Maine
Debt Instrument [Line Items]
Weighted average interest rate	4.15%	4.23%
Maturity, Start	Dec. 31, 2022
Maturity, End	Dec. 31, 2049
Long-term debt	$ 442	$ 382
Senior secured credit facility | EBP
Debt Instrument [Line Items]
Weighted average interest rate		3.08%
Interest Rate Terms	Variable
Maturity	Jan. 1, 2023
Long-term debt	$ 248	$ 248
Amortizing fixed rate notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	3.89%	3.83%
Maturity, Start	Dec. 31, 2021
Maturity, End	Dec. 31, 2022
Long-term debt	$ 122	$ 114
Secured senior notes | ECI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	Dec. 31, 2021
Long-term debt	$ 130	$ 159
Secured fixed rate senior notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	4.84%	5.51%
Maturity, Start	Dec. 31, 2020
Maturity, End	Dec. 31, 2035
Long-term debt	$ 218	$ 191

Long Term Debt (Revolving credi

Long Term Debt (Revolving credit facilities, outstanding borrowings and available capacity) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Jun. 13, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 2,463			$ 2,065
Letters of credit issued inside credit facilities	3			3
Use of available facilities	1,528			1,189
Available capacity under existing agreements	935			876
Advances on the revolving credit facility	1,525			1,186
Emera
Debt Instrument [Line Items]
Available capacity under existing agreements			$ 900
NSPI
Debt Instrument [Line Items]
Letters of credit issued inside credit facilities		$ 52			$ 49
Revolving credit facility
Debt Instrument [Line Items]
Available capacity under existing agreements	1,629			1,635
Borrowings under credit facilities	771			899
Letters of credit issued inside credit facilities	65			77
Use of available facilities	836			976
Available capacity under existing agreements	793			659
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 | BPLC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 25			26
Revolving credit facility | Emera Maine
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 104			$ 109
Maturity	Feb. 28, 2023
Revolving credit facility | Minimum | BPLC
Debt Instrument [Line Items]
Maturity	Dec. 31, 2020
Revolving credit facility | Maximum | BPLC
Debt Instrument [Line Items]
Maturity	Dec. 31, 2032

Long Term Debt (Debt Covenants)

Long Term Debt (Debt Covenants) (Details)	Dec. 31, 2019
Syndicated credit facilities
Debt Instrument [Line Items]
Debt to capital ratio	0.6

Long Term Debt (Long Term Matur

Long Term Debt (Long Term Maturities) (Details) $ in Millions	Dec. 31, 2019CAD ($)
Debt Instrument [Line Items]
2020	$ 1,950
2021	970
2022	799
2023	658
2024	547
Thereafter	5,166
Contractual Commitments	10,090
Subsidiaries
Debt Instrument [Line Items]
2020	550
2021	1,665
2022	512
2023	831
2024	987
Thereafter	10,262
Contractual Commitments	14,807
Emera
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	500
2024	437
Thereafter	1,559
Contractual Commitments	2,496
Emera US Finance LP
Debt Instrument [Line Items]
2020	0
2021	974
2022	0
2023	0
2024	0
Thereafter	2,598
Contractual Commitments	3,572
TECO Finance
Debt Instrument [Line Items]
2020	390
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Contractual Commitments	390
Tampa Electric Company
Debt Instrument [Line Items]
2020	0
2021	301
2022	292
2023	0
2024	0
Thereafter	2,741
Contractual Commitments	3,334
PGS
Debt Instrument [Line Items]
2020	0
2021	61
2022	32
2023	0
2024	0
Thereafter	344
Contractual Commitments	437
NMGC
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	195
Thereafter	0
Contractual Commitments	195
NMGI
Debt Instrument [Line Items]
2020	0
2021	260
2022	0
2023	0
2024	0
Thereafter	214
Contractual Commitments	474
NSPI
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	308
Thereafter	2,365
Contractual Commitments	2,673
Emera Maine
Debt Instrument [Line Items]
2020	49
2021	0
2022	107
2023	11
2024	0
Thereafter	351
Contractual Commitments	518
EBP
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	248
2024	0
Thereafter	0
Contractual Commitments	$ 248

Long Term Debt (Narrative) (Det

Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions

Dec. 19, 2019CAD ($)

Dec. 02, 2019CAD ($)

Aug. 02, 2019CAD ($)

Jul. 31, 2019CAD ($)

Jul. 24, 2019CAD ($)

Jun. 14, 2019USD ($)

Dec. 31, 2019CAD ($)

Dec. 31, 2018CAD ($)

Dec. 10, 2019USD ($)

Jun. 13, 2019CAD ($)

May 17, 2019CAD ($)

Apr. 04, 2019CAD ($)

Debt Instrument [Line Items]

Proceeds from Issuance of Preferred Stock

$ 0

$ 291

Proceeds from issuance of long-term debt

1,066

1,055

Repayments of Long-term Debt

1,103

757

Line of Credit Facility, Maximum Borrowing Capacity

2,463

2,065

Proceeds from Issuance of Common Stock

203

10

Emera

Debt Instrument [Line Items]

Repayments of Long-term Debt

$ 500

Line of Credit Facility, Maximum Borrowing Capacity

$ 900

Long-term Debt, Gross

2,496

2,701

Tampa Electric Company

Debt Instrument [Line Items]

Long-term Debt, Gross

3,334

3,126

NSPI

Debt Instrument [Line Items]

Repayments of Long-term Debt

$ 95

Long-term Debt, Gross

2,673

2,576

NMGC

Debt Instrument [Line Items]

Long-term Debt, Gross

474

368

NMGI

Debt Instrument [Line Items]

Long-term Debt, Gross

195

273

Emera Maine

Debt Instrument [Line Items]

Long-term Debt, Gross

518

478

ECI

Debt Instrument [Line Items]

Long-term Debt, Gross

470

464

EBP

Debt Instrument [Line Items]

Long-term Debt, Gross

$ 248

$ 248

Series G Preferred Stock | Emera

Debt Instrument [Line Items]

Stated interest rate

4.83%

Repayments of Long-term Debt

$ 225

Revolving credit facility | EBP

Debt Instrument [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity

$ 250

USD 30-year senior notes, Due 2050 | Tampa Electric Company

Debt Instrument [Line Items]

Proceeds from issuance of long-term debt

$ 300

Stated interest rate

3.625%

Debt Instrument, Maturity Date

Jun. 15, 2050

USD Note | NMGI

Debt Instrument [Line Items]

Repayments of Long-term Debt

$ 50

USD 30-year senior notes, Due 2049 | NSPI

Debt Instrument [Line Items]

Debt instrument, available for issuance under this prospectus

$ 400

Stated interest rate

3.57%

Debt Instrument, Maturity Date

Apr. 5, 2049

USD 30-year senior notes, Due 2049 | NMGC

Debt Instrument [Line Items]

Proceeds from issuance of long-term debt

$ 80

Stated interest rate

3.72%

Debt Instrument, Maturity Date

Dec. 15, 2049

USD 30-year senior notes, Due 2048 | Emera Maine

Debt Instrument [Line Items]

Debt instrument, available for issuance under this prospectus

$ 60

Stated interest rate

3.79%

Debt Instrument, Maturity Date

Dec. 10, 2049

USD 15-year senior notes, Due 2034 | NMGC

Debt Instrument [Line Items]

Proceeds from issuance of long-term debt

$ 15

Stated interest rate

3.24%

Debt Instrument, Maturity Date

Dec. 15, 2034

Asset Retirement Obligation (Ch

Asset Retirement Obligation (Change in ARO) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in ARO
Balance, January 1	$ 205	$ 172
Additions	0	25
Liabilities settled	(25)	(2)
Accretion included in depreciation expense	7	6
Other	3	(1)
Change in foreign exchange rate	(5)	5
Balance, December 31	$ 185	$ 205

Commitments and Contingencies_2

Commitments and Contingencies (Contractual Commitments) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Recorded Unconditional Purchase Obligation [Line Items]
2020	$ 1,950
2021	970
2022	799
2023	658
2024	547
Thereafter	5,166
Contractual Commitments	10,090
Subsidiaries
Recorded Unconditional Purchase Obligation [Line Items]
2020	550
2021	1,665
2022	512
2023	831
2024	987
Thereafter	10,262
Contractual Commitments	14,807
Tampa Electric Company
Recorded Unconditional Purchase Obligation [Line Items]
2020	0
2021	301
2022	292
2023	0
2024	0
Thereafter	2,741
Contractual Commitments	3,334
NSPI
Recorded Unconditional Purchase Obligation [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	308
Thereafter	2,365
Contractual Commitments	2,673
NSPI | NSPML
Recorded Unconditional Purchase Obligation [Line Items]
2020	145
2021	$ 111
NSPI Contractual obligation for use of the Maritime Link
Interim cost assessment, holdback	The payments are 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.
Maritime Link Project | NSPML
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Commitments	$ 101
Maritime Link Project | NSPI
Recorded Unconditional Purchase Obligation [Line Items]
2020	145
2021	164
2022	$ 162
NSPI Contractual obligation for use of the Maritime Link
Long-term Purchase Commitment, Period	37 years
Approved payment	$ 111
Approved payment difference from interim cost assessment included its proposed fuel stability plan	10
Purchased power
Recorded Unconditional Purchase Obligation [Line Items]
2020	210
2021	233
2022	237
2023	246
2024	249
Thereafter	2,228
Contractual Commitments	3,403
Purchased power | NEGG
Recorded Unconditional Purchase Obligation [Line Items]
2020	13
2021	23
2022	27
2023	31
2024	31
Thereafter	395
Contractual Commitments	520
Transportation
Recorded Unconditional Purchase Obligation [Line Items]
2020	514
2021	398
2022	340
2023	281
2024	264
Thereafter	2,720
Contractual Commitments	4,517
Capital projects
Recorded Unconditional Purchase Obligation [Line Items]
2020	411
2021	109
2022	103
2023	86
2024	0
Thereafter	0
Contractual Commitments	709
Capital projects | Independent Transmission and Distribution System [Member] | Tampa Electric Company
Recorded Unconditional Purchase Obligation [Line Items]
2020	345
Fuel, gas supply and storage
Recorded Unconditional Purchase Obligation [Line Items]
2020	466
2021	133
2022	22
2023	1
2024	0
Thereafter	0
Contractual Commitments	622
Long-term service agreements
Recorded Unconditional Purchase Obligation [Line Items]
2020	52
2021	37
2022	36
2023	27
2024	26
Thereafter	100
Contractual Commitments	278
Long-term service agreements | Independent Transmission and Distribution System [Member] | NEGG
Recorded Unconditional Purchase Obligation [Line Items]
2020	19
2021	9
2022	8
2023	8
Contractual Commitments	44
Equity investment commitments
Recorded Unconditional Purchase Obligation [Line Items]
2020	240
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Contractual Commitments	240
Leases and other
Recorded Unconditional Purchase Obligation [Line Items]
2020	19
2021	19
2022	18
2023	17
2024	8
Thereafter	118
Contractual Commitments	199
Demand side management
Recorded Unconditional Purchase Obligation [Line Items]
2020	38
2021	41
2022	43
2023	0
2024	0
Thereafter	0
Contractual Commitments	$ 122

Commitments and Contingencies_3

Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Prime Rate [Member] | Tampa Electric
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 27	$ 21
Prime Rate [Member] | TGH
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 21
Litigation Settlement Variable Rate	2.00%
Prime Rate [Member] | Maximum | Emera Maine
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage		10.41%
ISO-New England Open Access Transmission Tariff-allowed | Emera Maine
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss				$ 4
ISO-New England Open Access Transmission Tariff-allowed | Prime Rate [Member] | Emera Maine
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage		10.57%
ISO-New England Open Access Transmission Tariff-allowed | Prime Rate [Member] | Maximum | Emera Maine
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage		11.74%

Commitments and Contingencies_4

Commitments and Contingencies (Guarantees and Letters of Credit) (Details) $ in Millions, $ in Millions	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 3		$ 3
Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount		$ 52		$ 49
Payment Guarantee | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Guaranty Liabilities		45
Letters of Credit Outstanding, Amount		27
Surety Bonds
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount		$ 82		$ 67

Commitments and Contingencies_5

Commitments and Contingencies (Collaborative Arrangements) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Utilities Operating Expense, Purchased Power	$ 19	$ 19
Utilities Operating Expense, Maintenance and Operations	$ 3	$ 2

Cumulative Preferred Stock (Aut

Cumulative Preferred Stock (Authorized) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2018CAD ($)shares	Dec. 31, 2018د.إ / sharesshares
Class of Stock [Line Items]
Issued and Outstanding | shares	41,000,000	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	$ 0.6388
Preferred Stock, Redemption Price Per Share	$ 25
Issued and Outstanding | shares	3,864,636	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 | shares	2,135,364	2,135,364	2,135,364
Net Proceeds | $	$ 52	$ 52
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share | (per share)	$ 1.1802		د.إ 1.025
Preferred Stock, Redemption Price Per Share	$ 25
Issued and Outstanding | shares	10,000,000	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 | shares	5,000,000	5,000,000	5,000,000
Net Proceeds | $	$ 122	$ 122
Series F Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.0625
Preferred Stock, Redemption Price Per Share	$ 25
Issued and Outstanding | shares	8,000,000	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 | shares	12,000,000	12,000,000	12,000,000
Net Proceeds | $	$ 295	$ 295

Cumulative Preferred Stock (Cha

Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details)	12 Months Ended
	Dec. 31, 2019$ / shares	Dec. 31, 2018د.إ / shares
Series A Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.40%
Current Annual Dividend	$ 0.6388
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2020
Redemption Value	$ 25
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	$ 25.5
Series C Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.10%
Current Annual Dividend | (per share)	$ 1.1802	د.إ 1.025
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2023
Redemption Value	$ 25
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	$ 25.5
Series F Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.25%
Current Annual Dividend	$ 1.0625
Earliest Redemption and/or Conversion Option Date	Feb. 15, 2020
Redemption Value	$ 25
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	$ 25.5
Series B Preferred Stock
Class of Stock [Line Items]
Initial Yield	2.393%
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2020
Redemption Value	$ 25
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
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	$ 25.5
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)	Jan. 07, 2020shares	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2018د.إ / shares	Dec. 31, 2019د.إ / shares
First Preferred Shares
Class of Stock [Line Items]
Redemption Value | د.إ / shares				د.إ 25
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		$ 0.6388
Redemption Value		$ 25
Percentage rate used to determine dividend rate		4.40%
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		$ 25.5
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share | (per share)		1.1802	د.إ 1.025
Redemption Value		$ 25
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		$ 25.5
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		$ 1.0625
Redemption Value		$ 25
Percentage rate used to determine dividend rate		4.25%
Series F Preferred Stock | Subsequent Event
Class of Stock [Line Items]
Stock Redeemed or Called During Period, Shares | shares	0
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		$ 25.5
Series B Preferred Stock
Class of Stock [Line Items]
Redemption Value		$ 25
Percentage rate used to determine dividend rate		2.393%
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
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		$ 25.5
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
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, 2019	Dec. 31, 2018
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 35	$ 41
Domlec
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	21	22
GBPC
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Amount Represented by Preferred Stock	$ 14	$ 19

Non-controlling Interest In S_4

Non-controlling Interest In Subsidiaries (Preferred shares of GBPC) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
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	20,000
Outstanding as at December 31	$ 14	$ 19

Non-controlling Interest In S_5

Non-controlling Interest In Subsidiaries (Narrative) (Details) - 1 months ended Jun. 30, 2019 - GBPC $ in Millions	USD ($)	$ / shares
Noncontrolling Interest [Line Items]
Preferred Stock, Redemption Price Per Share | $ / shares		$ 1,000
Preferred Stock, Dividend Payment Terms	6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually, with the first payment scheduled for January 2020
USD Debt
Noncontrolling Interest [Line Items]
Conversion of Stock, Amount Issued	$ 10
USD preferred shares
Noncontrolling Interest [Line Items]
Conversion of Stock, Amount Issued	$ 10
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD Debt
Noncontrolling Interest [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
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 Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in non-cash working capital
Inventory	$ (19)	$ (44)
Receivables and other current assets	154	(144)
Accounts payable	(137)	59
Other current liabilities	(71)	13
Total non-cash working capital	(73)	(116)
Supplemental disclosure of cash paid:
Interest Paid	750	696
Income Taxes Paid, Net	(107)	33
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	187	181
Increase in accrued capital expenditures	33	50
Issuance of depository receipts	$ 0	$ 22

Stock-based Compensation (Emplo

Stock-based Compensation (Employee Common Share Purchase Plan and Dividend Reinvestment Plan) (Details) - CAD ($)	Aug. 15, 2019	Dec. 31, 2019	Dec. 31, 2018
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, 2019, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $8,000 per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any amount up to $3,000 to the employee’s plan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $3,000, up to the $8,000 maximum, the Company will contribute 10 per cent of that amount. The plan allows the reinvestment of dividends.
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount		$ 25
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount		$ 8,000
Maximum aggregate number of common shares reserved for issuance		4,000,000
Compensation cost for shares issued		$ 1,000,000	$ 1,000,000
Employee Common Share Purchase Plan | Scenario Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount		20,000
Employee Common Share Purchase Plan | Minimum
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount		$ 3,000
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		10.00%
Employee Common Share Purchase Plan | Maximum
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount		$ 8,000
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		20.00%
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. In 2019, the discount was changed from 5 per cent to 2 per cent effective with the dividend payment of August 15, 2019.
Discount from Market Price, Purchase Date	2.00%
Dividend Reinvestment Plan | Maximum
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Discount from Market Price, Purchase Date		5.00%

Stock-based Compensation (Narra

Stock-based Compensation (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Stock option plan, Additional information
Percentage of Outstanding Stock Maximum		10.00%
Employee Common Share Purchase Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	4,000,000
Deferred Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	4,000,000
Employee Stock Option Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	3,900,000	6,500,000
Deferred Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	3,900,000	6,500,000
Share Unit Plans
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	900,000	1,000,000
Deferred Share Unit Plans
Maximum aggregate number of common shares reserved for issuance	900,000	1,000,000
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 ten 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, 2019, 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 ten 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	11,700,000
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	$ 97	$ 1
Total intrinsic value of options exercised	$ 32	$ 1
Exercise Price Range, Lower Range Limit	$ 32.06	$ 21.99
Exercise Price Range, Upper Range Limit	$ 46.39	$ 46.19
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.
Deferred Share Unit Plans
Compensation cost recognized for employee and director	$ 1	$ 1
Maximum aggregate number of common shares reserved for issuance	11,700,000
Stock Option Plan | First Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25.00%
Stock Option Plan | Second Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25.00%
Stock Option Plan | Third Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25.00%
Stock Option Plan | Fourth Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25.00%
Share Unit Plans | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, Description	The Company has DSU, PSU and RSU plans and the liabilities are marked-to-market at the end of each period based on the common share price at the end of the period.
Deferred Share Unit Plans
Deferred Share Unit Plans
Compensation cost recognized for employee and director	$ 24	2
Tax Benefit related to compensation costs for share units realized	7	1
Deferred Share Unit Plans | Employee
Deferred Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	40	37
Deferred Share Unit Plans | Director
Deferred Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 30	25
Deferred Share Unit Plans | Share Unit Plans | DSU Plan
Deferred 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 to achieve certain corporate objectives.
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management
Deferred 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
Deferred 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
Deferred Share Unit Plans
Tax Benefit related to compensation costs for share units realized	$ 9	4
Performance Share Unit Plan | Employee
Deferred Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 88.1	56.9
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 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	$ 34	$ 14
Restricted Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, Description	In November 2019, a new RSU plan was approved by Emera’s Board of Directors, with grants to begin in 2020. Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping 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 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.

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, 2019	Dec. 31, 2018
Stock-Based Compensation
Weighted average fair value per option	$ 2.41	$ 1.7
Expected term	6 years	6 years
Risk-free interest rate	1.82%	2.13%
Expected dividend yield	5.10%	5.69%
Expected volatility	14.32%	13.71%

Stock-based Compensatin (Stock

Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Total Options, Number of Options
Total Options: Number of Options, Exercised	(2,570,000)	(20,000)
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Granted	$ 2.41	$ 1.7
Stock option plan, Additional information
Non-Vested options: Unrecognized compensation	$ 2	$ 2
Non-vested options: Weighted average recognition period	2 years 4 months 24 days	2 years 2 months 12 days
Vested Options: Weighted average remaining term	5 years 6 months	5 years 1 month 6 days
Vested Options: Aggregate intrinsic value	$ 11	$ 18
Vested Options: Fair value	$ 2	$ 2
Employee Stock Option Plan
Total Options, Number of Options
Total Options: Number of Options, Outstanding, Beginning Balance	4,225,575
Granted	651,400
Total Options: Number of Options, Exercised	(2,568,625)
Total Options: Number of Options, Forfeited	(21,800)
Total Options: Number of Options, Outstanding, Ending Balance	2,286,550	4,225,575
Total Options: Number of Options, Options exercisable	737,525
Total Options, Weighted average exercise price per share
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 39.56
Total Options: Weighted average exercise price per share, Granted	46.39
Total Options: Weighted average exercise price per share, Exercised	37.9
Total Options: Weighted average exercise price per share, Forfeited	46.39
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance	43.31	$ 39.56
Total Options: Weighted average exercise price per share, Options exercisable	$ 41.43
Non-Vested Options, Number of Options
Non-Vested Options: Number of Options, Outstanding, Beginning Balance	1,679,325
Granted	651,400
Non-Vested Options: Number of Options, Vested	759,900
Non-Vested Options: Number of options, Forfeited	(21,800)
Non-Vested Options: Number of Options, Ending Balance	1,549,025	1,679,325
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	2.41
Non-Vested Options: Weighted average exercise price per share, Vested	2.37
Non-Vested Options: Weighted average exercise price per share, Forteited	2.41
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance	$ 2.22	$ 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, 2019$ / sharesshares
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	837,109
Share Unit Plans: Granted including DRIP | shares	120,098
Share Unit Plans: Exercised | shares	(252,610)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	704,597
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 29.54
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	39.05
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	19.68
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 34.69
Director
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	563,521
Share Unit Plans: Granted including DRIP | shares	104,293
Share Unit Plans: Exercised | shares	(136,360)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	531,454
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 37.07
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	42.25
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	29.76
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 39.96

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, 2019	Dec. 31, 2018
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	1,127,114
Share Unit Plans: Granted including DRIP	545,008
Share Unit Plans: Exercised	(140,754)
Share Unit Plans: Forfeited	150,268
Share Unit Plans: Outstanding and exercisable, Ending Balance	1,381,100
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 46.02
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	43.15
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	43
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	44.41
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 45.37
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 88.1	$ 56.9

Variable Interest Entities (Det

Variable Interest Entities (Details) - NSPML - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Total assets	$ 554	$ 545
Maximum exposure to losss	$ 23	$ 51

Supplemental Financial Inform_3

Supplemental Financial Information (Condensed Consolidated Statements of Income) (Details) - CAD ($) $ in Millions	Jun. 16, 2016	Dec. 31, 2019	Dec. 31, 2018
Condensed Income Statements, Captions [Line Items]
Total operating revenues		$ 6,111	$ 6,524
Total operating expenses		4,768	5,126
Income from equity investments (note 7)		154	154
Other expenses, net		12	(23)
Interest expense, net		738	713
Income before provision for income taxes		771	816
Income tax expense (note 8)		61	69
Net income		710	747
Non-controlling interest in subsidiaries		2	1
Preferred stock dividends		45	36
Net income (loss) attributable to common shareholders		662.8	709.6
Comprehensive Income of Emera Incorporated		465	1,249
Eliminations
Condensed Income Statements, Captions [Line Items]
Total operating revenues		(43)	(54)
Total operating expenses		(42)	(52)
Income from equity investments (note 7)		(752)	(800)
Other expenses, net		(20)	(38)
Interest expense, net		0	0
Income before provision for income taxes		(773)	(840)
Income tax expense (note 8)		0	0
Net income		(773)	(840)
Non-controlling interest in subsidiaries		2	2
Preferred stock dividends		(22)	(42)
Net income (loss) attributable to common shareholders		(753)	(800)
Comprehensive Income of Emera Incorporated		(321)	(1,468)
Emera Inc. | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues		0	0
Total operating expenses		31	45
Income from equity investments (note 7)		753	801
Other expenses, net		21	22
Interest expense, net		(75)	(79)
Income before provision for income taxes		668	699
Income tax expense (note 8)		(40)	(47)
Net income		708	746
Non-controlling interest in subsidiaries		0	0
Preferred stock dividends		45	36
Net income (loss) attributable to common shareholders		663	710
Comprehensive Income of Emera Incorporated		465	1,249
Subsidiary Issuer | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues		0	0
Total operating expenses		0	0
Income from equity investments (note 7)		0	0
Other expenses, net		0	0
Interest expense, net		40	40
Income before provision for income taxes		40	40
Income tax expense (note 8)		11	9
Net income		29	31
Non-controlling interest in subsidiaries		0	0
Preferred stock dividends		0	0
Net income (loss) attributable to common shareholders		29	31
Comprehensive Income of Emera Incorporated		14	56
Emera US Finance LP | Reportable Legal Entities | U.S. Notes
Condensed Income Statements, Captions [Line Items]
Proceeds from Issuance of Unsecured Debt	$ 3,250
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues		4,125	4,432
Total operating expenses		3,084	3,468
Income from equity investments (note 7)		2	3
Other expenses, net		22	20
Interest expense, net		(481)	(456)
Income before provision for income taxes		584	531
Income tax expense (note 8)		60	64
Net income		524	467
Non-controlling interest in subsidiaries		0	0
Preferred stock dividends		19	38
Net income (loss) attributable to common shareholders		505	429
Comprehensive Income of Emera Incorporated		102	973
Non-guarantor Subsidiaries | Reportable Legal Entities
Condensed Income Statements, Captions [Line Items]
Total operating revenues		2,029	2,146
Total operating expenses		1,695	1,665
Income from equity investments (note 7)		151	150
Other expenses, net		(11)	(27)
Interest expense, net		(222)	(218)
Income before provision for income taxes		252	386
Income tax expense (note 8)		30	43
Net income		222	343
Non-controlling interest in subsidiaries		0	(1)
Preferred stock dividends		3	4
Net income (loss) attributable to common shareholders		219	340
Comprehensive Income of Emera Incorporated		$ 205	$ 439

Supplemental Financial Inform_4

Supplemental Financial Information (Condensed Consolidated Statement of Financial Position) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assets
Total current assets	$ 2,486	$ 2,832
Property, plant and equipment	18,167	18,712
Other assets
Regulatory assets (note 15)	1,431	1,404
Goodwill	5,835	6,313	$ 5,805
Other long-term assets	3,923	3,053
Total other assets	11,189	10,770
Total assets	31,842	32,314
Liabilities and Equity
Total current liabilities	4,166	4,553
Long-term liabilities
Long-term debt	13,679	14,292
Deferred income taxes	1,285	1,320
Regulatory liabilities	1,886	2,359
Other long-term liabilities	764	684
Total long-term liabilities	19,075	19,403
Equity
Total Emera Incorporated equity	8,566	8,317
Non-controlling interest in subsidiaries	35	41
Total equity	8,601	8,358	$ 7,204
Total liabilities and equity	31,842	32,314
Eliminations
Assets
Total current assets	(294)	(244)
Property, plant and equipment	5	(3)
Other assets
Regulatory assets (note 15)	0	0
Goodwill	0	0
Other long-term assets	(16,955)	(17,235)
Total other assets	(16,955)	(17,235)
Total assets	(17,244)	(17,482)
Liabilities and Equity
Total current liabilities	(1,079)	(265)
Long-term liabilities
Long-term debt	(6,209)	(6,994)
Deferred income taxes	0	6
Regulatory liabilities	0	0
Total long-term liabilities	(6,230)	(7,009)
Equity
Total Emera Incorporated equity	(9,949)	(10,227)
Non-controlling interest in subsidiaries	14	19
Total equity	(9,935)	(10,208)
Total liabilities and equity	(17,244)	(17,482)
Emera Inc. | Reportable Legal Entities
Assets
Total current assets	96	146
Property, plant and equipment	23	24
Other assets
Regulatory assets (note 15)	0	0
Goodwill	3	0
Other long-term assets	11,994	11,457
Total other assets	11,997	11,457
Total assets	12,116	11,627
Liabilities and Equity
Total current liabilities	542	368
Long-term liabilities
Long-term debt	2,978	2,906
Deferred income taxes	0	0
Regulatory liabilities	0	0
Total long-term liabilities	3,016	2,942
Equity
Total Emera Incorporated equity	8,558	8,317
Non-controlling interest in subsidiaries	0	0
Total equity	8,558	8,317
Total liabilities and equity	12,116	11,627
Subsidiary Issuer | Reportable Legal Entities
Assets
Total current assets	27	67
Property, plant and equipment	0	0
Other assets
Regulatory assets (note 15)	0	0
Goodwill	0	0
Other long-term assets	3,856	4,660
Total other assets	3,856	4,660
Total assets	3,883	4,727
Liabilities and Equity
Total current liabilities	12	695
Long-term liabilities
Long-term debt	3,534	3,709
Deferred income taxes	3	3
Regulatory liabilities	0	0
Total long-term liabilities	3,537	3,712
Equity
Total Emera Incorporated equity	334	320
Non-controlling interest in subsidiaries	0	0
Total equity	334	320
Total liabilities and equity	3,883	4,727
Guarantor Subsidiaries | Reportable Legal Entities
Assets
Total current assets	1,486	1,767
Property, plant and equipment	13,099	13,745
Other assets
Regulatory assets (note 15)	519	645
Goodwill	5,762	6,208
Other long-term assets	1,739	971
Total other assets	8,020	7,824
Total assets	22,605	23,336
Liabilities and Equity
Total current liabilities	3,699	2,829
Long-term liabilities
Long-term debt	8,829	10,243
Deferred income taxes	515	668
Regulatory liabilities	1,793	2,118
Total long-term liabilities	12,834	13,903
Equity
Total Emera Incorporated equity	6,072	6,604
Non-controlling interest in subsidiaries	0	0
Total equity	6,072	6,604
Total liabilities and equity	22,605	23,336
Non-guarantor Subsidiaries | Reportable Legal Entities
Assets
Total current assets	1,171	1,096
Property, plant and equipment	5,040	4,946
Other assets
Regulatory assets (note 15)	912	759
Goodwill	70	105
Other long-term assets	3,289	3,200
Total other assets	4,271	4,064
Total assets	10,482	10,106
Liabilities and Equity
Total current liabilities	992	926
Long-term liabilities
Long-term debt	4,547	4,428
Deferred income taxes	767	643
Regulatory liabilities	93	241
Total long-term liabilities	5,918	5,855
Equity
Total Emera Incorporated equity	3,551	3,303
Non-controlling interest in subsidiaries	21	22
Total equity	3,572	3,325
Total liabilities and equity	$ 10,482	$ 10,106

Supplemental Financial Inform_5

Supplemental Financial Information (Condensed Consolidated Statement of Cash Flows) (Details) $ in Millions, $ in Millions	Jun. 14, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Operating activities
Net cash provided by (used in) operating activities		$ 1,525	$ 1,690
Investing activities
Additions to property, plant and equipment		(2,495)	(2,162)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(3)	(49)
Proceeds on disposal of assets		875	0
Other investing activities		6	21
Net cash provided by (used in) investing activities		(1,617)	(2,190)
Financing activities
Change in short-term debt, net		413	(162)
Proceeds from long-term debt, net of issuance costs		1,066	1,055
Retirement of long-term debt		(1,103)	(757)
Net borrowings (repayments) under committed credit facilities		(118)	321
Issuance of common and preferred stock		203	301
Dividends paid		(423)	(382)
Other financing activities		(24)	(32)
Net cash provided by financing activities		14	344
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(20)	25
Net increase (decrease) in cash, cash equivalents, and restricted cash		(98)	(131)
Cash, cash equivalents, and restricted cash, beginning of year		372	503
Cash, cash equivalents, and restricted cash, end of year		274	372
Eliminations
Operating activities
Net cash provided by (used in) operating activities		(20)	(267)
Investing activities
Additions to property, plant and equipment		0	0
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0	0
Proceeds on disposal of assets		0
Other investing activities		(960)	572
Net cash provided by (used in) investing activities		(960)	572
Financing activities
Change in short-term debt, net		0	0
Proceeds from long-term debt, net of issuance costs		520	(194)
Retirement of long-term debt		17	0
Net borrowings (repayments) under committed credit facilities		(28)	110
Issuance of common and preferred stock		562	(446)
Dividends paid		157	348
Other financing activities		(248)	(123)
Net cash provided by financing activities		980	(305)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		0	0
Net increase (decrease) in cash, cash equivalents, and restricted cash		0	0
Cash, cash equivalents, and restricted cash, beginning of year		0	0
Cash, cash equivalents, and restricted cash, end of year		0	0
Emera Inc.
Financing activities
Retirement of long-term debt	$ (500)
Emera Inc. | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities		133	191
Investing activities
Additions to property, plant and equipment		(2)	(9)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0	0
Proceeds on disposal of assets		0
Other investing activities		(402)	(489)
Net cash provided by (used in) investing activities		(404)	(498)
Financing activities
Change in short-term debt, net		399	0
Proceeds from long-term debt, net of issuance costs		0	0
Retirement of long-term debt		(225)	0
Net borrowings (repayments) under committed credit facilities		146	136
Issuance of common and preferred stock		203	301
Dividends paid		(423)	(382)
Other financing activities		(1)	0
Net cash provided by financing activities		99	55
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		147	(4)
Net increase (decrease) in cash, cash equivalents, and restricted cash		(25)	(256)
Cash, cash equivalents, and restricted cash, beginning of year		20	276
Cash, cash equivalents, and restricted cash, end of year		(5)	20
Subsidiary Issuer | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities		33	35
Investing activities
Additions to property, plant and equipment		0	0
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0	0
Proceeds on disposal of assets		0
Other investing activities		595	0
Net cash provided by (used in) investing activities		595	0
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		(664)	0
Net borrowings (repayments) under committed credit facilities		0	0
Issuance of common and preferred stock		0	0
Dividends paid		0	0
Other financing activities		0	0
Net cash provided by financing activities		(664)	0
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(3)	2
Net increase (decrease) in cash, cash equivalents, and restricted cash		(39)	37
Cash, cash equivalents, and restricted cash, beginning of year		58	21
Cash, cash equivalents, and restricted cash, end of year		19	58
Guarantor Subsidiaries | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities		1,100	1,266
Investing activities
Additions to property, plant and equipment		(1,973)	(1,687)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(3)	(16)
Proceeds on disposal of assets		818
Other investing activities		774	3
Net cash provided by (used in) investing activities		(384)	(1,700)
Financing activities
Change in short-term debt, net		(9)	(162)
Proceeds from long-term debt, net of issuance costs		(6)	1,174
Retirement of long-term debt		(65)	(716)
Net borrowings (repayments) under committed credit facilities		(11)	(103)
Issuance of common and preferred stock		(620)	319
Dividends paid		(19)	(37)
Other financing activities		138	0
Net cash provided by financing activities		(592)	475
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(141)	9
Net increase (decrease) in cash, cash equivalents, and restricted cash		(17)	50
Cash, cash equivalents, and restricted cash, beginning of year		104	54
Cash, cash equivalents, and restricted cash, end of year		87	104
Non-guarantor Subsidiaries | Reportable Legal Entities
Operating activities
Net cash provided by (used in) operating activities		279	465
Investing activities
Additions to property, plant and equipment		(520)	(466)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		0	(33)
Proceeds on disposal of assets		57
Other investing activities		(1)	(65)
Net cash provided by (used in) investing activities		(464)	(564)
Financing activities
Change in short-term debt, net		23	0
Proceeds from long-term debt, net of issuance costs		552	75
Retirement of long-term debt		(166)	(41)
Net borrowings (repayments) under committed credit facilities		(225)	178
Issuance of common and preferred stock		58	127
Dividends paid		(138)	(311)
Other financing activities		87	91
Net cash provided by financing activities		191	119
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(23)	18
Net increase (decrease) in cash, cash equivalents, and restricted cash		(17)	38
Cash, cash equivalents, and restricted cash, beginning of year		190	152
Cash, cash equivalents, and restricted cash, end of year		$ 173	$ 190

Uncategorized Items - ema-20191

Label	Element	Value
Restricted Cash and Cash Equivalents	us-gaap_RestrictedCashAndCashEquivalents	$ 51,000,000
Restricted Cash and Cash Equivalents	us-gaap_RestrictedCashAndCashEquivalents	56,000,000
Assets Held-for-sale, Not Part of Disposal Group	us-gaap_AssetsHeldForSaleNotPartOfDisposalGroup	1,000,000
Assets Held-for-sale, Not Part of Disposal Group	us-gaap_AssetsHeldForSaleNotPartOfDisposalGroup	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	us-gaap_UnrecognizedTaxBenefitsIncomeTaxPenaltiesAccrued	0
Cash Equivalents, at Carrying Value	us-gaap_CashEquivalentsAtCarryingValue	0
Cash Equivalents, at Carrying Value	us-gaap_CashEquivalentsAtCarryingValue	43,000,000
Income Tax Examination, Interest Expense	us-gaap_IncomeTaxExaminationInterestExpense	1,000,000
Income Tax Examination, Interest Expense	us-gaap_IncomeTaxExaminationInterestExpense	3,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	us-gaap_UnrecognizedTaxBenefitsInterestOnIncomeTaxesAccrued	5,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	us-gaap_UnrecognizedTaxBenefitsInterestOnIncomeTaxesAccrued	4,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	us-gaap_UnrecognizedTaxBenefitsThatWouldImpactEffectiveTaxRate	29,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	us-gaap_UnrecognizedTaxBenefitsThatWouldImpactEffectiveTaxRate	26,000,000
Cash	us-gaap_Cash	222,000,000
Cash	us-gaap_Cash	$ 273,000,000