Emera (EMRAF) 40-F 29 Mar 19 2018 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2018shares
Document Information [Line Items]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Registrant Name	EMERA INC
Entity Central Index Key	0001127248
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Trading Symbol	EMA
Common Stock
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	234,116,829
Series A Preferred Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	3,864,636
Series B Preferred Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	2,135,364
Series C Preferred Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	10,000,000
Series E Preferred Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	5,000,000
Series F Preferred Stock [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding	8,000,000
Series H Preferred Stock [Member}
Document Information [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, 2018	Dec. 31, 2017
Operating revenues
Regulated electric	$ 4,852	$ 4,721
Regulated Gas	1,044	1,002
Non-regulated	628	503
Total operating revenues	6,524	6,226
Operating expenses
Regulated fuel for generation and purchased power	1,677	1,638
Regulated cost of natural gas	388	379
Non-regulated fuel for generation and purchased power	225	209
Non-regulated direct costs	16	28
Operating, maintenance and general	1,564	1,372
Provincial, state, and municipal taxes	340	326
Depreciation and amortization	916	856
Total operating expenses	5,126	4,808
Income from operations	1,398	1,418
Income from equity investments	154	124
Other income (expenses), net	23	25
Interest expense, net	713	698
Income before provision for income taxes	816	819
Income tax expense (recovery)	69	520
Net income	747	299
Non-controlling interest in subsidiaries	1	5
Preferred stock dividends	36	28
Net income attributable to common shareholders	$ 709.6	$ 266.1
Weighted average shares of common stock outstanding (in millions)
Basic	233	213.4
Diluted	233.5	214.1
Earnings per common share (note 9)
Basic	$ 3.05	$ 1.25
Diluted	3.04	1.24
Dividends per common share declared	$ 2.2825	$ 2.1325

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Consolidated Statements of Comprehensive Income [Abstract]
Net income	$ 747	$ 299
Foreign currency translation adjustment	627	(464)
Unrealized gains (losses) on net investment hedges	(122)	97
Cash flow hedges
Net derivative gains (losses)	2	10
Less: reclassification adjustment for losses (gains) included in income	(6)	8
Net effects of cash flow hedges	(4)	18
Unrealized gains on available-for-sale investment
Unrealized gain (loss) arising during the period	0	5
Less: reclassification adjustment for (gains) recognized in income	(4)	(1)
Net unrealized holding gains (losses)	(4)	4
Net change in unrecognized pension and post-retirement benefit obligation	9	40
Other comprehensive income (loss)	506	(305)
Comprehensive income (loss)	1,253	(6)
Comprehensive income (loss) attributable to non-controlling interest	4	0
Comprehensive Income of Emera Incorporated	$ 1,249	$ (6)

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017CAD ($)
Consolidated Statements of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax		$ 1.2
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	$ 9		$ (9)
Other Comprehensive Income (Loss), Available-for-sale Securities, before Reclassification Adjustments, Tax	0		1
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	2		4
Other comprehensive loss, Tax	$ 11		$ (4)

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 316	$ 438
Restricted cash	56	65
Inventory	474	418
Derivative instruments	148	141
Regulatory assets	165	138
Assets Held For Sale	53	0
Other current assets	1,620	1,326
Total current assets	2,832	2,526
Property, plant and equipment, net of accumulated depreciation and amortization of $8,567 and $7,824, respectively	18,712	16,995
Other assets
Deferred income taxes	175	138
Derivative instruments	19	112
Regulatory assets	1,404	1,273
Net investment in direct financing lease	475	481
Investments subject to significant influence	1,316	1,215
Goodwill	6,313	5,805
Other long term assets	291	261
Assets Held For Sale	777	0
Total other assets	10,770	9,285
Total assets	32,314	28,806
Current liabilities
Short-term debt	1,186	1,241
Current portion of long-term debt	1,119	741
Accounts payable	1,289	1,161
Derivative instruments	260	227
Regulatory liabilities	251	226
Other current liabilities	428	350
Liabilities associated with assets held for sale	20	0
Total current liabilities	4,553	3,946
Long-term liabilities
Long-term debt	14,292	13,140
Deferred income taxes	1,320	1,023
Derivative instruments	105	83
Regulatory liabilities	2,359	2,242
Pension and post-retirement liabilities	641	559
Other long-term liabilities	686	609
Total long-term liabilities	19,403	17,656
Commitments and contingencies
Equity
Common stock	5,816	5,601
Cumulative preferred stock	1,004	709
Contributed surplus	84	76
Accumulated other comprehensive Income	338	(165)
Retained earnings	1,075	891
Total Emera Incorporated equity	8,317	7,112
Non-controlling interest in subsidiaries	41	92
Total equity	8,358	7,204
Total liabilities and equity	$ 32,314	$ 28,806

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Consolidated Balance Sheets [Abstract]
Accumulated depreciation on property, plant and equipment	$ 8,567	$ 7,824

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net income	$ 747	$ 299
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	928	851
Income from equity investments, net of dividends	(75)	(90)
Allowance for equity funds used during construction	(19)	(9)
Deferred income taxes, net	185	469
Net change in pension and post-retirement obligations	11	(12)
Regulated Fuel Adjustments Mechanism	(16)	68
Net changes in fair value of derivative instruments	55	(157)
Net change in regulatory assets and liabilities	51	(237)
Net change in capitalized transportation capacity	(105)	84
Other operating activities, net	44	31
Changes in non-cash working capital	116	104
Net cash provided by operating activities	1,690	1,193
Investing activities
Additions to property, plant and equipment	(2,162)	(1,529)
Purchase of investments subject to significant influence, inclusive of acquisition costs	(49)	(213)
Other investing activities	21	(19)
Net cash used in investing activities	(2,190)	(1,761)
Financing activities
Change in short-term debt, net	99	(31)
Proceeds from short term debt	129	383
Repayment of short term debt	(390)	0
Proceeds from long-term debt	1,055	129
Retirement of long-term debt	(757)	(453)
Net borrowings under committed credit facilities	321	230
Issuance of preferred stock, net of issuance costs	291	0
Dividends on common stock	(346)	(287)
Dividends on preferred stock	(36)	(28)
Other financing activities	(32)	(32)
Issuance of common stock, net of issuance costs	10	682
Net cash provided by financing activities	344	593
Effect of exchange rate changes on cash and cash equivalents	25	(13)
Net increase (decrease) in cash and cash equivalents	(131)	12
Cash and cash equivalents, beginning of period	503	491
Cash and cash equivalents, end of period	372	503
Cash and cash equivalents consists of:
Cash	273	216
Short-term investments	43	222
Restricted cash	$ 56	$ 65

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common Stock	Preferred Stock	Contributed Surplus	Accumulated Other Comprehensive Loss ("AOCL")	Retained Earnings	Non- Controlling Interest
Balance at Dec. 31, 2016	$ 6,845	$ 4,738	$ 709	$ 75	$ 135	$ 1,076	$ 112
Net income	299	0	0	0	0	294	5
Other Comprehensive Income (Loss), Net of Tax	(305)	0	0	0	(300)	0	(5)
Issuance of stock, net of issuance costs	686	686	0	0	0	0	0
Cash dividends declared on preferred stock	(28)	0	0	0	0	(28)	0
Cash dividends declared on common stock	(451)	0	0	0	0	(451)	0
Common stock issued under purchase plan	173	173	0	0	0	0	0
Non-controlling interest investment	(14)	0	0	0	0	0	(14)
Other	(5)	1	0	0	0	0	(6)
Stock-based compensation	4	3	0	1	0	0	0
Balance at Dec. 31, 2017	7,204	5,601	709	76	(165)	891	92
Net income	747	0	0	0	0	746	1
Other Comprehensive Income (Loss), Net of Tax	506	0	0	0	503	0	3
Issuance of preferred stock, net of after-tax issuance costs	295	0	295	0	0	0	0
Cash dividends declared on preferred stock	(36)	0	0	0	0	(36)	0
Cash 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
Non-controlling interest investment	(25)	22	0	6	0	0	(53)
Other	4	2	0	2	0	2	(2)
Balance at Dec. 31, 2018	$ 8,358	$ 5,816	$ 1,004	$ 84	$ 338	$ 1,075	$ 41

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Other comprehensive loss, net of tax	$ 11	$ (4)
Cash dividends declared on common stock	$ 2.2825	$ 2.1325

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	1 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution and gas transmission and distribution. At December 31, 2018 , Emera’s primary rate-regulated subsidiaries a nd investments included the following: Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico that include: Tampa Electric Company (“TEC”), which hol ds the Tampa Electric Division (“Tampa Electric”), a vertically integrated regulated electric utility, serving approximately 764,000 customers in West Central Florida, and Peoples Gas System Division (“PGS”), a regulated gas distribution utility, serving approximately 392,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, ser ving approximately 530,000 customers across New Mexico; TECO Finance, Inc. (“TECO Finance”), a financing subsidiary of TECO Energy; and SeaCoast Gas Transmission LLC (“SeaCoast”), a regulated intrastate natural gas transmission company off ering services in Florida. Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 519,000 customers ; Emera Maine, a regulated electric transmission and distribution utility, serving approximately 159,000 customers in the state of Maine; Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: The Ba rbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 130,000 customers; Grand Bahama Power Company Limited (“GBPC”), a vertically int egrated utility operating on Grand Bahama Island, serving approximately 19,000 customers. On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD, increasing Emera’s interest in GBPC from 80.4 per cent to 100 per cent; a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated utility on the island of Dominica, serving approximately 26,000 customers; and a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. Emera Brunswick Pipeline Company Limited (“Bru nswick 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 Newf oundland & 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 forecas ted to be generating first power in 2019 and full power in 2020. ENL’s two investments are: a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two 170-ki lometre subsea cables, connecting the island 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 the energization phase of the proj ect began in June 2018. a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States . At December 31, 2018 , Emera’s investments in other energy-related non-regulated companies included the following: Emera Energy, which consists of: Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricit y and provides related energy asset management services; Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), 1,115 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States. On November 26, 2018, Emera announced an agreemen t to sell its NEGG facilities. The transaction is expected to close in the first quarter of 2019. Refer to n ote 17 for additional information; Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; 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 L P, a wholly owned financing subsidiary of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic C anada; and other investments. 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 otherwise indicated. Principles of Consolidation The consolidated financial stat ements 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. Emera uses the equity method of accounting to record investments in which the Co mpany 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. To identify potential VIEs, management re views contractual and ownership arrangements such as leases, 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 o f 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 consol idation, 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 abse nce of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, mainte nance and general (“OM&G”), depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. 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 return on the equity invested or assets as applicable (refer to n ote 14 for additional details). Foreign Currency Translation Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevail ing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en ominat ed debt held in Canadian dollar functional currency companies as hedges of net investments in United States dollar d enominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balan ce sheet date, and the effective portion of the hedge , is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings. 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 r eceives and consumes the benefits of the electricity . Electric revenues are recognized 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 an d recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenu e is recognized. The Company’s estimate of unbilled revenue at the end of the 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, weather, line losses and inter-period changes to customer classes. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applica ble 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 recogn ized 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 occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate 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. Direct Finance Lease The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which 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 for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease u sing a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income. 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 basis, refle cting 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 payment s 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 auction process held annually, three years in advance, through the forward capacity market. Other non-regulated revenues are recorded when obligations under terms of a contract are satisfied. Other Sales, value add, and other taxes, with the exception of gross receipts tax es discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Franchise Fees and Gross Receipts Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, thr ough prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fe es and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the 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 replacements of units of property, plant and equipment are included in “P roperty, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gai n or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Ex penditures 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 maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of de preciable property. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less s alvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and 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 method 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 for 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 Credi ts Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial sta tements or income tax returns. Deferred income tax assets and liabilities are determined based on the diff erence between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differ ences are expected to reverse. Emera recognizes the effect of in come tax positions only when it is more likely than not that they will be rea lized. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be reco vered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax as sets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded at the amount 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 the regulatory practi ces. 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 in come 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 tax 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 7 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 count erparties 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 Comp any has contracts for the physical pur chase and sale of natural gas. These physical and financial contracts are classifie d as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are 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 transactio n is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the count erparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if th ey meet string ent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value o f derivatives is deferred to AOCI and recognized in income in the same period the re lated hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period. Where th e 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 Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item wh en the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in f uture rates. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period, unless deferred as a re sult of regulatory accounting. The Company has not elected to desig nate 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 economically 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 the same category as the item being hedged within operating or investing activities on the Consolid ated Statements of Cash Flows. Non-hedged derivat ives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collater al with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”. Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term inve stments with original maturities of three months or less at acquisition. To tal short-term investments of $43 million have an effective interest rate of 2.0 per cent at December 31, 2018 ( 2017 - $ 222 million with a n effective interest rate of 1.4 per cent). Included in restricted cash are funds required to be set aside for the BLPC Self-Insurance Fund (“SIF”) (note 31 ). 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 amou nts receiv able from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. Management e stimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the 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 uncollectible. 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. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency. 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 r eceives and consumes the benefits of the electricity . Electric revenues are recognized 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 an d recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenu e is recognized. The Company’s estimate of unbilled revenue at the end of the 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, weather, line losses and inter-period changes to customer classes. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applica ble 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 recogn ized 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 occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate 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. Direct Finance Lease The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which 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 for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease u sing a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income. 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 basis, refle cting 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 payment s 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 auction process held annually, three years in advance, through the forward capacity market. Other non-regulated revenues are recorded when obligations under terms of a contract are satisfied. Other Sales, value add, and other taxes, with the exception of gross receipts tax es discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Franchise Fees and Gross Receipts Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, thr ough prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fe es and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. Asset Impairment Long-Lived Assets Emera assesses whether there has been an impairment of long-lived assets and intangibles when such indicators exist. The Company reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impa

Change in Accounting Policy

Change in Accounting Policy	12 Months Ended
	Dec. 31, 2018
Change in Accounting Policy [Abstract]
Accounting Changes and Error Corrections [Text Block]	2 . C HANGE IN ACCOUNTING POLICY The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2018, are described as follows: Leases On January 1, 2019, the Company adopted ASU No. 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 which resulted in the shortening of lease terms for certain existing leases. The Company also 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 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 $x million and $x million, respectively, as of January 1, 2019. The lease liabilities were measured at the present value of remaining lease payments using the Company’s incremental borrowing rate. The associated ROU assets were measured at the amount equal to the lease liability as of January 1, 2019 adjusted by the amount of any prepaid or accrued lease payments related to the lease recognized in the Consolidated Balance Sheet immediately before the date of transition. There was no impact to opening retained earnings as at January 1, 2019 or the Company’s net income or cash flows for the three months ended March 31, 2019 as a result of the adoption of the standard. There were no significant impacts to Emera’s accounting for lessor arrangements. The notes to the consolidated financial statements include new required disclosures regarding key information on leases. Refer to note XX for further detail. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Updates (“ASU”) No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Compre hensive Income . The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the US Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive in come. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. The Company early adopted the standard in Q2 2018 and elected to not reclassi fy tax effects resulting from the US Tax Cuts and Jobs Act stranded in accumulated other comprehensive income to retained earnings as amounts were not material. Emera utiliz es a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released. Revenue from Contracts with Customers On January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers and all the re lated amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as Accounting Standards Codification (“ASC”) Topic 606. The core principle is that a company should recognize revenue when it transfers pro mised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company adopted ASC 606 using the modified retrospective method . Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to the Company’s opening retained earnings as of the adoption date. The impact of the adoption of the new standard was immaterial to the Company’s net income and is expected to be immaterial on an ongoing basis. Recognition and Measurement of Financial Assets and Financial Liabilities On January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all of the related amendments. The standard provides gui dance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company has elected to measure equity securities that do not have a readily determinable fair value at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or similar investments of the same issuer. The standard eliminates the available-for-sale classificati on for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The impact as a result of the remeasurement of equity investments is ex pected to be immaterial to the Company’s net income on an ongoing basis. A cumulative-effect adjustment of $4 million was made which increased retained earnings in the Consolidated Balance Sheet as of January 1, 2018. Clarifying the Definition of a Busin ess In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business . The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance is effective for annu al reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. The Company adopted ASU 2017-01 effective January 1, 2018. There was no impact on the consolidated financ ial statements as a result of the adoption of this standard. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component is eligible for capitalization as property, plant a nd equipment under this guidance. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the C onsolidated Statements of Income and prospectively for the guidance around capitalization. The Company adopted ASU 2017-07 effective January 1, 2018 and December 31, 2017 balances have been retrospectively restated in the Consolidated Statements of Incom e. The standard allows the Company to use the amounts disclosed in its pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements. This change result ed in $27 million of costs, previously presented within “Operating, maintenance and general”, being reclassified to “Other income (expense), net” in the Consolidated Statements of Income for the year ended December 31 , 2017 .

Future Accounting Pronouncement

Future Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements [Abstract]
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. Leases In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organ izations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the previous guidance, operating leases are not recorded as assets and liabilities on the balance sheet. The effect of leases on t he Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted and is required to be applied using a modified retrospective approach. The Company will not early adopt the standard. In January 2018 , the FASB issued an amendment to ASC Topic 842 that permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The Company will make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The Company will make this election. Additionally, the Company will elect the options that allow the Company to not reassess whether any expired or existing contracts contain leases, carry forward existing lease classification, use hindsight to determine the lease term for existing leases and not separate lease components from non-lease components for all lessee and lessor arrangements. Over the past several years, the Company developed and executed a project plan which included holding training sessions with key stakeholders throughout the organization, gathering detailed information on existing lease arrangements, evaluating implementation alternatives and calculating the lease asset and liability balances associated with individual contractual arrangements. The Company has implemented additional process es and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. Updates to systems are not required as a result of implementation of this standard. The adoption of this standard will a ffect the Company’s financial position by increasing assets and liabilities related to operating leases by approximately $70 million , with no impact to the Company’s Consolidated Statements of Income. There will be no significant changes to the Company’s a ccounting for lessor arrangements as a result of the adoption of the standard. The Company is in the process of assessing the disclosure requirements and continues to monitor FASB amendments to ASC Topic 842. Measurement of Credit Losses on Financial Inst ruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments . The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted f or 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 w ith a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, includin g the credit loss methodology and credit quality indicators. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for annual reporti ng periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements. Targeted Impro vements to Accounting for Hedging Activities In August 2017, the FASB issued 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 appl ication 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 effective ness. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach. T he adoption of this standard will have no impact on the Company’s consolidated financial statements. Cloud Computing In August 2018, the 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 will be effective fo r 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 is currently evaluating the transition meth ods and the impact of the adoption of this standard on the consolidated financial statements.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Information [Abstract]
SEGMENT INFORMATION	4 . SEGMENT INFORMATION Emera manages its reportable segments separately due in part to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Emera’s six reportable segments are Emera Florida and New Mexico, NSPI , Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other (i ncludes Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and certain holding companies). The Company is re view ing its internal reporting to the chief operating decision maker and considering changes to its repor table segments for 2019. Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2018 Operating revenues from external customers (1) $ 3,675 $ 1,437 $ 278 $ 467 $ 600 $ 68 $ - $ 6,525 Inter-segment revenues (1) - 3 - - 14 36 (54) (1) Total operating revenues 3,675 1,440 278 467 614 104 (54) 6,524 AFUDC - debt and equity 21 6 3 - - - - 30 Regulated fuel and fixed cost deferral adjustments - (46) - - - - - (46) Depreciation and amortization 534 219 64 50 46 3 - 916 Interest expense (2) 238 142 22 27 5 290 - 724 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 3 3 38 110 - 154 Income tax expense (recovery) 101 8 11 (2) 66 (115) - 69 Net income attributable to common shareholders 428 131 44 41 165 (99) - 710 Capital expenditures 1,548 345 100 87 33 38 - 2,151 As at December 31, 2018 Total assets 20,051 5,143 1,721 1,373 1,785 2,275 (34) 32,314 Investments subject to significant influence (4) - - 35 42 - 1,239 - 1,316 Goodwill 6,053 - 156 104 - - - 6,313 (1) All significant intercompany balances and intercompany 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. Intercompany transactions which 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) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $12 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. (4) Emera Energy's segment includes an investment in Bear Swamp. At December 31, 2018 this investment is in a credit position of $172 million and is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2017 Operating revenues from external customers (1) $ 3,623 $ 1,335 $ 297 $ 434 $ 451 $ 86 $ - $ 6,226 Inter-segment revenues (1) - 3 - - 14 41 (58) - Total operating revenues 3,623 1,338 297 434 465 127 (58) 6,226 AFUDC - debt and equity 5 8 3 - - - - 16 Regulated fuel and fixed cost deferral adjustments - 59 - - - - - 59 Depreciation and amortization 500 207 47 51 48 3 - 856 Interest expense (2) 248 134 20 25 2 276 - 705 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 1 3 24 96 - 124 Income tax expense (recovery) 529 - 27 - 18 (54) - 520 Net income attributable to common shareholders 99 129 46 31 93 (132) - 266 Capital expenditures 910 385 82 72 47 26 - 1,522 As at December 31, 2017 Total assets 17,216 4,979 1,540 1,251 1,575 2,331 (86) 28,806 Investments subject to significant influence (4) - - 13 39 - 1,163 - 1,215 Goodwill 5,566 - 143 96 - - - 5,805 (1) All significant intercompany balances and intercompany 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. Intercompany transactions which 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) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $24 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. (4) Emera Energy's segment includes an investment in Bear Swamp. At December 31, 2017 this investment is in a credit position of $188 million and is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Geographical Information Revenues (1) : For the Year ended December 31 millions of Canadian dollars 2018 2017 Canada $ 1,520 $ 1,464 United States 4,537 4,328 Barbados 319 280 The Bahamas 121 119 Dominica 27 35 $ 6,524 $ 6,226 (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 2018 2017 Canada $ 4,128 $ 3,995 United States 13,739 12,257 Barbados 446 408 The Bahamas 315 276 Dominica 84 59 $ 18,712 $ 16,995

Revenue

Revenue	12 Months Ended
	Dec. 31, 2018
Revenue From Contracts With Customers [Abstract]
Revenue From Contracts With Customers [Text Block]	5 . REVENUE The following disaggregates the Company’s revenue by major source: Emera Florida Corporate Inter- and New Emera Emera Emera and Segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2018 Regulated Electric Revenue Residential $ 1,384 $ 731 $ 107 $ 154 $ - $ - $ - $ 2,376 Commercial 755 405 80 270 - - - 1,510 Industrial 209 233 16 30 - - - 488 Other electric and regulatory deferrals 312 43 9 7 - - - 371 Other (1) 10 28 66 6 - - (3) 107 Regulated electric revenue 2,670 1,440 278 467 - - (3) 4,852 Gas Revenue Residential 492 - - - - - - 492 Commercial 291 - - - - - - 291 Industrial 49 - - - - - - 49 Finance income (2)(3) - - - - - 57 - 57 Other 155 - - - - - - 155 Regulated gas revenue 987 - - - - 57 - 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 - - - 614 47 (51) 628 Total operating revenues $ 3,675 $ 1,440 $ 278 $ 467 $ 614 $ 104 $ (54) $ 6,524 (1) Other includes an immaterial amount of 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 arrangeme nts with fixed contract terms. As of December 31, 2018 , the aggregate amount of the transaction price allocated to remaining performance obligations was $ 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 re cognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining perf ormance obligations through 2033 .

Investments Subject to Signific

Investments Subject to Significant Influence and Equity Income	12 Months Ended
	Dec. 31, 2018
Investments Subject to Significant Influence and Equity Earnings [Abstract]
INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME	6 . INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME Investments subject to significant influence consisted of the following: Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2018 2017 2018 2017 2018 NSPML $ 545 $ 510 $ 45 $ 36 100.0 LIL (1) 534 492 42 37 49.5 M&NP (2) 155 156 22 23 12.9 Lucelec (2) 42 39 3 3 19.1 Bear Swamp (3) - - 38 23 50.0 Other Investments 40 18 4 2 $ 1,316 $ 1,215 $ 154 $ 124 (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 Q4 2015. Bear Swamp's credit investment balance of $172 million (2017 - $188 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Equity investments include a $ 12 million difference between the cost and the underlying fair value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 31 ). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2018 2017 Balance Sheets Current assets $ 86 $ 225 Property, plant and equipment 1,690 1,720 Non-current assets 140 74 Total assets $ 1,916 $ 2,019 Current liabilities $ 21 $ 180 Long-term debt 1,288 1,287 Non-current liabilities 62 42 Equity 545 510 Total liabilities and equity $ 1,916 $ 2,019

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
INCOME TAXES	7 . 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 2018 2017 Income before provision for income taxes $ 816 $ 819 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 253 254 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (59) (54) Foreign tax rate variance (55) 36 Amortization of deferred income tax regulatory liabilities (37) - Florida state tax apportionment adjustment (23) - Tax effect of equity earnings (15) (12) Financing deductions (4) (17) Revaluation of US non-regulated deferred income taxes due to tax reform - 317 Other 9 (4) Income tax expense (recovery) $ 69 $ 520 Effective income tax rate 8% 63% On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 (“the Act”) was signed into law enacting a broad range of legislative changes including reduction of the US federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018, limitations on the deductibility of interest and 100 per cent expensing of qualified property. The Act provides an exemption to regulated electric and g as utilities from the limitations on the deductibility of interest and the 100 per cent expensing of qualified property. At December 31, 2017, the Company was required to revalue its US deferred income tax assets and liabilities based on the new tax rate a t the date of enactment. The Company recognized a $ 317 million income tax expense as a result of the revaluation of its US non-regulated net deferred income tax assets. The Company also reduced its US regulated net deferred income tax liabilities by $ 1.1 b illion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator. The December 31, 2017 balances of deferred income t ax assets and liabilities that were revalued were $ 1.3 billion and $ 1.8 billion, respectively. No further adjustments were recognized in 2018 and the Company has completed its accounting for the revaluation of its US deferred income tax assets and liabilit ies resulting from the effects of the Act . T he measurement period allowed by SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act is now closed . In Q4 2018, the Company reclassified $ 149 million of AMT credit c arryforwards from deferred income tax assets to receivables and other current assets as it expects to receive the refund in 2019. On November 26, 2018, the Internal Revenue Service (“IRS”) issued proposed regulations on the interest deductibility limitatio n rules legislated under th e Act. The Company believes its US based financing interest will be deductible under the Act. 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 2018 2017 Current income taxes Canada $ 3 $ 24 United States (121) 24 Other 2 3 Deferred income taxes Canada 11 3 United States 211 384 Other (3) (1) Operating loss carryforwards Canada (33) (40) United States - (194) Other (1) - Revaluation of US non-regulated deferred income taxes United States - 317 Income tax expense (recovery) $ 69 $ 520 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 2018 2017 Canada $ 127 $ 88 United States 646 693 Other 43 38 Income before provision for income taxes $ 816 $ 819 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 2018 2017 Deferred income tax assets: Tax loss carryforwards $ 917 $ 853 Tax credit carryforwards 269 314 Regulatory liabilities - cost of removal 206 208 Pension and post-retirement liabilities 126 112 Derivative instruments 90 107 Other 441 394 Total deferred income tax assets before valuation allowance 2,049 1,988 Valuation allowance (163) (105) Total deferred income tax assets after valuation allowance $ 1,886 $ 1,883 Deferred income tax (liabilities): Property, plant and equipment $ (2,591) $ (2,321) Derivative instruments (124) (155) Other (316) (292) Total deferred income tax liabilities $ (3,031) $ (2,768) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 175 $ 138 Long-term deferred income tax liabilities (1,320) (1,023) Net deferred income tax liabilities $ (1,145) $ (885) 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 $163 million has been recorded as at December 31, 2018 (2017 - $105 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, 2018 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 817 $ (405) $ 412 2027-2038 Capital loss 86 (77) 9 Indefinite United States Federal NOL $ 2,848 $ - $ 2,848 2024-2037 State NOL 1,314 (47) 1,267 2024-2038 Capital loss 6 (6) - 2019 Tax credit 268 - 268 2019-Indefinite Other NOL $ 34 $ (34) $ - 2019-2025 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 2018 2017 Balance, January 1 $ 19 $ 18 Increases due to tax positions related to a prior year 8 - Decreases due to tax positions related to a prior year (1) - Increases due to tax positions related to current year - 1 Balance, December 31 $ 26 $ 19 The total amount of unrecognized tax benefits as at December 31, 2018 was $ 26 million ( 2017 - $ 19 million), which would affect the eff ective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $ 4 million ( 2017 - $ 1 million) with $3 million of interest expense recognized in the Consolidated Statement of Income (2017 - nil). No penalties have been accrued. The balance of unrecognized tax benefits could change in t he next twelve months as a result of resolving Canada Revenue Agency (“CRA”) and I RS audits. A reasonable estimate of any change cannot be made at this time. The Company intends to indefinitely reinvest earnings fr om certain foreign operations. Accordingl y, 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 $ 1.4 b illion as at December 31, 2018 ( 2017 - $ 822 million). 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 Nov a 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, 2018 , 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. Should 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 previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years. Should NSPI receive similar notices of reassessment for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Appeal process is n ot determinable at this time.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2018
Common Stock [Abstract]
COMMON STOCK	8 . COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2018 2017 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2017 228.77 $ 5,601 210.02 $ 4,738 Conversion of Convertible Debentures 0.01 - 0.15 6 Issuance of common stock (1) 0.45 22 14.61 680 Issued under Purchase Plans at market rate 4.87 200 3.89 182 Discount on shares purchased under Dividend Reinvestment Plan - (9) - (9) Options exercised under senior management share option plan 0.02 1 0.10 3 Employee Share Purchase Plan - 1 - 1 Balance, December 31, 2018 234.12 $ 5,816 228.77 $ 5,601 (1) In Q1 2018, Emera issued 0.45 million common shares to facilitate the creation and issuance of 1.8 million depository receipts in connection with the ICDU share acquisition. The depository receipts are listed on the Bahamas International Securities Exchange. As at December 31, 2018 , the following common shares were reserved for issuance: 6.5 million ( 2017 – 6.5 million) under the senior management stock option plan, 1.0 million ( 2017 – 1.3 million) under the employee common share purchase plan and 12.6 million ( 2017 – 4.2 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, 2018 , Emera is in compliance with this requirement.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
EARNINGS PER SHARE	9 . 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) 2018 2017 Numerator Net income attributable to common shareholders $ 709.6 $ 266.1 Diluted numerator 709.6 266.1 Denominator Weighted average shares of common stock outstanding 231.7 212.3 Weighted average deferred share units outstanding 1.3 1.1 Weighted average shares of common stock outstanding – basic 233.0 213.4 Stock-based compensation 0.4 0.6 Convertible Debentures 0.1 0.1 Weighted average shares of common stock outstanding – diluted 233.5 214.1 Earnings per common share Basic $ 3.05 $ 1.25 Diluted $ 3.04 $ 1.24

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	10 . 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 Balance, January 1, 2018 $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) Other comprehensive income (loss) before reclassifications 624 (122) 2 - - 504 Amounts reclassified from accumulated other comprehensive income loss - - (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 For the year ended December 31, 2017 Balance, January 1, 2017 (1) $ 489 $ (49) $ (21) $ (1) $ (283) $ 135 Other comprehensive income (loss) before reclassifications (459) 97 10 5 - (347) Amounts reclassified from accumulated other comprehensive income loss (gain) (2) - - 8 (1) 40 47 Net current period other comprehensive income (loss) (459) 97 18 4 40 (300) Balance, December 31, 2017 $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) (1) The January 1, 2017 balance of AOCI and Regulatory Assets includes a prior period reclassification of $44 million in unrecognized pension and post-retirement benefit costs and $18 million in deferred taxes ($26 million, net of tax) to be consistent with current year presentation. (2) Certain net changes in unrecognized pension and post-retirement benefit costs for Emera Maine of $4 million were previously presented as a change in AOCI and are now presented as a change in Regulatory Assets for the year ended December 31, 2017 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 2018 2017 Affected line item in the Consolidated Financial Statements Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (1) $ (3) Foreign exchange forwards Operating revenue - regulated (5) 10 Total before tax (6) 7 Income tax recovery (expense) - 1 Total net of tax $ (6) $ 8 Net change in available-for-sale investments Other income (expenses), net $ - $ (1) Retained earnings (1) (4) - Total net of tax $ (4) $ (1) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 25 $ 33 Past service costs (gains) OM&G (1) (8) Amounts reclassified into obligations Pension and post-retirement benefits (17) 11 Total before tax 7 36 Income tax recovery (expense) 2 4 Total net of tax $ 9 $ 40 Total reclassifications out of AOCI, net of tax, for the period $ (1) $ 47 (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, 2018
Inventory [Abstract]
INVENTORY	Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Fuel $ 213 $ 180 Materials 241 216 Emission credits (1) 20 22 $ 474 $ 418 (1) The NEGG facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative for carbon dioxide emissions. The emission credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments [Abstract]
DERIVATIVE INSTRUMENTS	12 . 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 2018 2017 2018 2017 Cash flow hedges Power swaps $ - $ 5 $ - $ 2 Foreign exchange forwards - 2 5 5 - 7 5 7 Regulatory deferral Commodity swaps and forwards Coal purchases 71 137 1 10 Power purchases 2 5 1 3 Natural gas purchases and sales 2 6 4 7 Heavy fuel oil purchases 1 15 1 4 Foreign exchange forwards 29 32 - 4 105 195 7 28 HFT derivatives Power swaps and physical contracts 62 125 76 162 Natural gas swaps, futures, forwards, physical contracts 125 105 403 294 187 230 479 456 Other derivatives Interest rate swap 1 2 - - 1 2 - - Total gross current derivatives 293 434 491 491 Impact of master netting agreements with intent to settle net or simultaneously (126) (181) (126) (181) 167 253 365 310 Current 148 141 260 227 Long-term 19 112 105 83 Total derivatives $ 167 $ 253 $ 365 $ 310 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 2018 2017 2018 2017 Regulatory deferral $ 1 $ 14 $ 1 $ 14 HFT derivatives 125 167 125 167 Total impact of master netting agreements with intent to settle net or simultaneously $ 126 $ 181 $ 126 $ 181 Cash Flow Hedges The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. The Company also enters into 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 2018 2017 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Realized gain (loss) in non-regulated fuel for generation and purchased power 1 - - 3 - - Realized gain (loss) in operating revenue – regulated - - 5 - - (10) Total gains (losses) in Net income $ 1 $ - $ 5 $ 3 $ - $ (10) As at December 31 millions of Canadian dollars 2018 2017 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ (1) $ - $ (6) $ - $ - $ (3) The Company expects $4 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, 2018, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2019 2020 2021 Foreign exchange forwards (USD) sales $ 30 $ 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 2018 2017 Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (34) $ - $ 4 $ (33) $ (1) $ (4) Unrealized gain (loss) in regulatory liabilities 29 - 24 83 1 (30) Realized (gain) loss in regulatory liabilities (8) - - (2) - - Realized (gain) loss in inventory (1) (55) - (18) (17) - (30) Realized (gain) loss in regulated fuel for generation and purchased power (2) (2) - (9) (3) - (14) Total change derivative instruments $ (70) $ - $ 1 $ 28 $ - $ (78) (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, 2018 , 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: 2019 2020-2023 millions Purchases Purchases Coal (metric tonnes) 1 1 Natural Gas (Mmbtu) 16 - Heavy fuel oil (bbls) - 1 Foreign Exchange Swaps and Forwards As at December 31, 2018 , the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below: 2019 2020 Foreign exchange contracts (millions of US dollars) $ 121 $ 111 Weighted average rate 1.1621 1.3027 % of USD requirements 66% 48% 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 2018 2017 Power swaps and physical contracts in non-regulated operating revenues $ (12) $ 7 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 205 401 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power - 10 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 2 2 $ 195 $ 420 As at December 31, 2018 , the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: millions 2019 2020 2021 2022 2023 Natural gas purchases (Mmbtu) 308 108 71 50 41 Natural gas sales (Mmbtu) 247 42 9 2 - Power purchases (MWh) 6 - - - - Power sales (MWh) 5 - - - - Other Derivatives For the Year ended December 31 millions of Canadian dollars 2018 2017 Interest rate Interest rate swaps swaps Unrealized gain (loss) in interest expense, net (1) 2 Total gains (losses) in net income $ (1) $ 2 As at December 31, 2018, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments through Q1 2019. 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 manages 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 r equested 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 creditworthin ess 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 probability 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 counterp arty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated. As at December 31, 2018 , the maximum exposure the Company has to credit risk is $ 1,035 million ( 2017 - $ 1,148 million) , which includes ac counts 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 fai l to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest r ate risk. Counterparties 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, 2018 was $ 346 million ( 2017 - $ 247 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 Associati on agreements (“ISDA”), 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 creditwort hiness, collateral, non-performance and default. As at December 31, 2018 , the Company had $ 118 million ( 2017 - $ 90 million) in financial assets, considered to be past due, which have been outstanding for an average 68 days. The fair value of these financial assets is $ 107 million ( 2017 - $ 78 million), the difference of which is included in the allowance for doubtful 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, 2018 December 31, 2017 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 384 28% $ 326 23% Commercial 182 13% 161 11% Industrial 57 4% 46 3% Other 84 6% 96 7% 707 51% 629 44% Trading group Credit rating of A- or above 49 4% 55 4% Credit rating of BBB- to BBB+ 70 5% 61 4% Credit rating of CCC- to CCC+ 8 0% - 0% Not rated 108 8% 96 7% 235 17% 212 15% Other accounts receivable 273 20% 300 22% 1,215 88% 1,141 81% Derivative Instruments (current and long-term) Credit rating of A- or above 130 9% 207 15% Credit rating of BBB- to BBB+ 9 1% 10 1% Not rated 28 2% 36 3% 167 12% 253 19% $ 1,382 100% $ 1,394 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Cash collateral provided to others $ 103 $ 119 Cash collateral received from others 77 99 Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material advers e credit-related event occurs. If a material adverse event resulted in t he senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full col lateralization. As at December 31, 2018 , the total fair value of these derivatives, in a l iability position, wa s $ 365 million ( December 31, 2017 – $ 310 million). If the credit ratings of the Company were reduced below investme nt 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, 2018
Fair Value Measurements [Abstract]
FAIR VALUE MEASUREMENTS	13 . FAIR VALUE MEASUREMENTS The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (refer to 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 liabilities. Level 2 - Where quoted pr ices 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, certain derivatives are valued usin g 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 transactions 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 models, although quoted prices wer e 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 classification of the methodology used by the Company to fair value its derivatives: 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) As at December 31, 2017 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 2 - 2 5 2 - 7 Regulatory deferral Commodity swaps and forwards Coal purchases - 127 - 127 Power purchases 5 - - 5 Natural gas purchases and sales - 5 - 5 Heavy fuel oil purchases 4 8 - 12 Foreign exchange forwards - 32 - 32 9 172 - 181 HFT derivatives Power swaps and physical contracts - 3 9 12 Natural gas swaps, futures, forwards, physical contracts and related transportation - 26 25 51 - 29 34 63 Other derivatives Interest rate swap - 2 - 2 - 2 - 2 Total assets 14 205 34 253 Liabilities Cash flow hedges Power swaps 2 - - 2 Foreign exchange forwards - 5 - 5 2 5 - 7 Regulatory deferral Power purchases 3 - - 3 Natural gas purchased and sales 5 1 - 6 Foreign exchange forwards - 4 - 4 8 5 - 13 HFT derivatives Power swaps and physical contracts 49 5 (4) 50 Natural gas swaps, futures, forwards and physical contracts 6 47 187 240 55 52 183 290 Total liabilities 65 62 183 310 Net assets (liabilities) $ (51) $ 143 $ (149) $ (57) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2018 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2018 $ 9 $ 25 $ 34 Total realized and unrealized gains (losses) included in non-regulated operating revenues (6) (7) (13) Balance, December 31, 2018 $ 3 $ 18 $ 21 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2018 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2018 $ (4) $ 187 $ 183 Total realized and unrealized gains (losses) included in non-regulated operating revenues 5 118 123 Balance, December 31, 2018 $ 1 $ 305 $ 306 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, 2018 , 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 a lso sources multiple 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 points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantl y 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, 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, futures, Probability of default 0.01% - 2.94% 0.24% forwards, physical contracts Discount rate 0.01% - 30.62% 4.25% and related transportation 10 Modelled pricing Third-party pricing $1.95 - $12.90 $8.68 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 Probability of default 0.08% - 0.29% 0.15% physical contracts Discount rate 0.03% - 2.99% 1.65% Correlation factor 84.98% - 84.98% 84.98% 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) As at December 31, 2017 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 1 Modelled pricing Third-party pricing $24.88 - $117.90 $92.93 Power swaps and Probability of default 0.00% - 0.01% 0.00% physical contracts Discount rate 0.00% - 0.13% 0.00% 8 Modelled pricing Third-party pricing $63.48 - $117.00 $102.68 Correlation factor 0.94% - 0.99% 0.96% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.00% 0.00% HFT derivatives – 18 Modelled pricing Third-party pricing $2.06 - $8.24 $3.61 Natural gas swaps, Probability of default 0.00% - 0.05% 0.00% futures, forwards, Discount rate 0.00% - 0.29% 0.06% physical contracts 7 Modelled pricing Third-party pricing $2.04 - $12.52 $6.42 and related transportation Basis adjustment 0.08% - 0.71% 0.52% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.09% 0.01% Total assets $ 34 Liabilities HFT derivatives – $ (6) Modelled pricing Third-party pricing $24.88 - $117.90 $95.46 Power swaps and Own credit risk 0.00% - 0.01% 0.00% physical contracts Discount rate 0.00% - 0.13% 0.00% 2 Modelled pricing Third-party pricing $94.5 - $117.00 $105.52 Correlation factor 0.94% - 0.99% 0.96% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.00% 0.00% HFT derivatives – 172 Modelled pricing Third-party pricing $1.89 - $11.81 $4.64 Natural gas swaps, futures, Own credit risk 0.00% - 0.00% 0.00% forwards and physical contracts Discount rate 0.00% - 0.12% 0.02% 15 Modelled pricing Third-party pricing $2.15 - $12.52 $8.94 Basis adjustment 0.08% - 0.71% 0.53% Own credit risk 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.08% 0.01% Total liabilities $ 183 Net assets (liabilities) $ (149) The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2018 $ 15,411 $ 15,908 $ - $ 14,991 $ 917 $ 15,908 December 31, 2017 $ 13,881 $ 15,217 $ 69 $ 14,346 $ 802 $ 15,217 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 loss of $122 million was recorded in Other Comprehensive Income for the year ended December 31, 2018 ( 2017 – $ 97 million gain after-tax ). There was no ineffectiveness for the year ended December 31, 2018 ( 2017 – nil ).

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	14 . REGULATORY 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 appropriate regulator, or due to regulatory precedent establis hed for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs ar e 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 r ecognized 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 2018 2017 Regulatory assets Deferred income tax regulatory assets $ 775 $ 667 Pension and post-retirement medical plan (1) 453 380 Cost recovery clauses 75 17 Environmental remediations 31 41 Hurricane Matthew restoration 28 28 Stranded cost recovery 28 25 Unamortized defeasance costs 26 32 Demand side management ("DSM") deferral 24 28 Deferrals related to derivative instruments 10 15 Storm reserve 4 59 Other 115 119 $ 1,569 $ 1,411 Current $ 165 $ 138 Long-term 1,404 1,273 Total regulatory assets $ 1,569 $ 1,411 Regulatory liabilities Deferred income tax regulatory liabilities 1,218 1,116 Accumulated reserve - cost of remova l 955 894 Regulated fuel adjustment mechanism 161 177 Deferrals related to derivative instruments 116 182 Storm reserve 76 - Cost recovery clauses 30 51 Self-insurance fund (note 31) 30 28 Other 24 20 $ 2,610 $ 2,468 Current $ 251 $ 226 Long-term 2,359 2,242 Total regulatory liabilities $ 2,610 $ 2,468 (1) The December 31, 2017 pension and post-retirement medical plan regulatory asset includes a prior period reclassification of $35 million from AOCI, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to note 10 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. In 2017, a s a result of enactment of the US Tax Cuts and Jobs Act of 2017 , the Company revalued i ts United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company reduced its US regulated net deferre d income tax liabilities by $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post - retir ement benefits at Emera Florida and New Mexico , and Emera Maine . 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 applicabl e. It is amortized over the remaining service life of plan participants. 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 a pproved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. Environmental Remediation s This asset is primarily related to PGS costs associated with the 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 based on a settlement agreement approved by the FPSC. Hurricane Matthew Restoration This asset represents restoration costs incurred by GBPC in 2016 associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The Grand Bahama Port Authority (“GBPA”) has approved full recovery of these storm res toration costs. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine during 2012, the GBPA approved the recovery of a $ 21 million USD stranded cost through electricity rates; it is included in rate base for 2018 and 2017 and is expected to be included in future years. 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 relate d defeased debt, which as at December 31, 2018 , totalled $ 759 million ( 2017 – $ 726 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 defease d debt as permitted by the Nova Scotia Utility and Review Board (“UARB”) . DSM Deferral The UARB approved the 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 EfficiencyOne to review the 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, E fficiencyOne 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 liab ility in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on the Consolidated Balance Sheets. Deferrals Related to Derivative Instruments Tampa Electric, PGS, NMGC, NSPI and GBPC defer 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 the respective regulators. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Tampa Electric deferrals related to der ivative instruments are recovered through cost-recovery mechanisms on a dollar-for-dollar basis in the year following the settlement of the derivative position. Accumulated Reserve – Cost of Removal This regulatory liability represents the non-ARO COR r eserve in Tampa Electric 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 o f property, plant and equipment, 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 in to 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 are deferred to a fuel adjustment mechanism (“F AM”) 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 aft er 2019, as required under the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”) . Storm Reserve The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a 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 the reserve. On September 10, 2017, Tampa Electric was impacted by Hurricane Irma and incurred total restoration costs of approximately $ 102 million USD. The amount charged to the storm reserve exceeded the balance in th e reserve by $47 million USD, which was recorded as a regulatory asset on the balance sheet. This regulated asset was included in rate base. On December 28, 2017, Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of t he storm reserve for several named storms and to replenish the reserve to the $56 million USD level that existed at October 31, 2013. On March 1, 2018 , the FPSC approved a settlement agreement authorizing the utility to net the amount of storm cost recover y against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. At December 31, 2018, Tampa Electric’s storm reserve liability was $ 56 million USD. Regulatory Environments Emera Florida and New Mexico Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their 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 c ollect total revenues equal to their cost of providing service, plus an appropriate return on invested capital. Tampa Electric Tampa Electric’s approved regulated return on equity (“ROE”) range is 9.25 per cent 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 it the opportunity to recover fluctua ting fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prude ntly incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in a subsequent year. In September 2 017, Tampa Electric announced its intention to invest approximately $ 850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. On November 6, 2017, the FPSC approved a settlement agreement allowing a sol ar base rate adjustment ("SoBRA") that provides for the recovery, upon in-service, of up to 600 MW of investments in utility-scale solar projects phased in from late 2018 through early 2021. On May 8, 2018, the FPSC approved Tampa Electric’s first SoBRA. T his SoBRA represents 145 MW and $ 24 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in September 2018. On October 29, 2018, the FPSC approved Tampa Electric’s second SoBRA. This SoBRA represents 260 MW and $ 46 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in January 2019. As discussed in the Storm Reserve section above, in September 2017, Tampa Electric was impacted by Hurricane Irma and i ncurred restoration costs in excess of the balance in its storm reserve. Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve. The FPSC approved a settlement agreement filed by Tampa Electric authorizing the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. In Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $ 19 million USD to offset tax reform benefits. This deferral was amortized over the balance of the year as a credit against recognition of storm expense. In total, OM&G expense due to the allowed netting of the s torm cost recovery with tax reform benefits, net of amortization of first quarter tax reform benefits, was approximately $ 103 million USD for the year ended December 31, 2018. Tampa Electric’s final storm costs subject to netting will be determined in a se parate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 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. PGS 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. Absent any rate case filing, the bottom of the range will increase to 9.75 per cent in 2021. 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 annual ly by the FPSC. The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. In 2012, the FPSC approved a new Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The FPSC approved a replacement program of approximately 5 per cent, or 800 kilometres, of the PGS system at a cost of approximately $ 80 million USD over a 10-year period. As part of the depreciation study settlement agreement approved 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 February 7, 2017 , the FPSC approved a settlement agreement which resulted in new depreciation rates that reduce annual depreciation by $ 16 million USD and accelerate the amortization of the regulated asset related to the MGP en vironmental remedi ation costs. As part of the settlement, PGS and the O ffice of P ublic C ounsel agreed that at least $ 32 million USD of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites wil l be amortized over the period 2016 through 2020 , with a t least $ 21 million USD amortized over a two year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $ 5 million USD and $ 16 million USD , respectively, of this amortization expense. Th e 2017 PGS settlement agreement does not contain a provision for tax reform. On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility to 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 will lower base rates by $ 12 million USD to reflect the impact of tax reform and reduce depreciation rates by $ 10 million USD in accordance with the settlement agreement. P GS is permitted to initiate a general base rate proceeding if it forecasts that ROE will fall below its allowed range. NMGC The approved ROE for NMGC is 10 per cent, on an allowed equity capital structure of 52 per cent. NMGC’s rates were established in a 2012 rate case settlement and were frozen until December 31, 2017 per the June 2016 NMPRC order (the “Order”) approving Emera’s acquisition of TECO Energy. NMGC filed a rate case, including the prospective impact of tax reform, on February 26, 2018. A hearing in the rate case was held on September 24, 2018, where an uncontested stipulation on the rate request was presented. A second hearing on the rate case related to 2018 tax reform benefits was held on December 17, 2018. As of December 31, 2018, NMGC recorded a regulatory liability of $ 8 million USD to reflect 2018 tax reform benefits. A decision by the NMPRC on the rate case and on 2018 tax reform benefits is expected in 2019. NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. O n 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 NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC mus t 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 December 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020. 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 cust omers, and provide an appropriate return to investors. NSPI’s approved regulated ROE range for 2018 and 2017 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, 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 lia bility and recovered from or returned to customers in a subsequent year. T he Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”) , was enacted by the Province of Nova Scotia in December 2015, which required NSPI to file a three-year stability plan for fuel c osts and a General Rate Application (“GRA”) for non-fuel costs if required . I n July 2016, the UARB approved a Consensus Agreement between NSPI and customer representatives related to the Rate Stability Plan for fuel cos ts for 2017 through 2019 which resulted in an average annual increase of 1.1 per cent for each of these three years. Subsequently, certain customer representatives requested changes resulting in amended rates t hat were approved by the UARB in November 2016 and result in an average annual rate increase of 1.5 per cent for each of these three years. In September 2017, the UARB approved NSPI’s interim assessment pay ment to NSPML of the costs associated with the Mariti me Link when it is in service. The Maritim e Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments. As of December 31, 2018, $ 96 million has been paid to NSPML. The UARB approved annual payment for 2019 is $ 111 million. The payments are subje ct to a hold back of $10 million in each of 2018 and 2019 pending UARB agreement that a minimum of $ 10 million per year 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, 2018, NSPI has recorded a $ 2 million holdback payable to NSPML. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects a $ 53 million reduction in NSPML’s assessment in each of 2018 and 2019, related t o depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being 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. The credit to customers will be approximately $ 36 million in 2019 and $ 53 million in 2020 . After 2019 and the Rate Stability Plan, the timing and amounts payable to NSPML and NSPI’s future rate recoveries of the Maritime Link costs will be subject to regulatory filings with the UARB, with expected filings in 2019 and 2020. Emera Maine Emera Maine’s distribution operations and stranded cost recoveries are regulated by the MPUC . The transmission operations are regulated by the FERC. R ates 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 and 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 a ctual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE for Bangor Hydro District local transmission operations for 2018 and 2017 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 pool of assets. The allowed ROE range for Bangor Hydro bulk transmission assets is 11.07 to 11.74 per cent for 2018 and 2017 . MPS District local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail 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 (2017 – 9.6 per cent). S tranded Cost Recoveries Stranded cost recoveries in Maine are set 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 account ing 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 government of Barbados has granted BLPC a franchise to generate , transmit and distribute electricity on the island until 2028. 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 2018 and 2017 . All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The approved c alculation of the fuel charge is adjusted monthly. In December 2018, the Government of Barbados signed the Income Tax Amendment Act into law. This legislation 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 mill ion 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, regulated and exclusive franchise to produce, transmit and distrib ute electricity on the island until 2054. There is a fuel pass - through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered and a reasonable return earned. GBPC’s approved regulated return on rate base was 8.5 per cent for 2018 ( 2017 - 8.8 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 over a five-year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. 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 ex cess 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 the opportunity to request recovery from customers in future rates. Dominica Electricity Services Ltd Domlec is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 20 14, for a period of 25 years. Domlec’s approved allowable regulated return on rate base was 15 per cent for 2018 and 2017 . Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover subs tantially all fuel costs in a timely manner . Dominica experienced unprecedented damage as a result of Hurricane Maria in September 2017, reducing the customer base from approximately 36,000 to 26, 000 at December 31, 2018. Many homes were destroyed and have not been rebuilt at this time. Domlec has fully restored power to all customers who request power and are able to receive it. Domlec maintains insurance for its generation fleet and, subsequent to Hurricane Maria, has obt ained specialized insurance for its transmission and distribution networks. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in t he northeastern United States. Brunswick Pipeline entered into a 25 - year firm service agreement commencing in July 2 009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB 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, 2018
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	15 . 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 certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material a mounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies are as follows : Transactions between NSPI and NSPML related to the Maritime Link assessme nt are reported in the Consolidated Statemen ts of Income. NSPI’s expense is reported in Regulated fuel for generation an d purchased power, totalling $ 97 million for the year ended December 31, 2018 ( 2017 - nil). 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 Consolidate d Statements of Income. Purchases from M&NP reported net in Operating revenues, N on-regulated, total led $ 29 million for the year ended December 31, 2018 ( 2017 - $ 28 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, 2018 and at December 31, 2017 .

Receivables and Other Current A

Receivables and Other Current Assets	12 Months Ended
	Dec. 31, 2018
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract]
Prepayment and other current assets [Text Block]	16. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Customer accounts receivable – billed $ 844 $ 805 Customer accounts receivable – unbilled 296 278 Allowance for doubtful accounts (11) (12) Other receivables 86 70 Capitalized transportation capacity (1) 179 89 Income tax receivable 175 24 Prepaid expenses 42 59 Net investment in direct financing lease (note 20 ) 9 8 Due from related parties (note 15 ) - 5 $ 1,620 $ 1,326 (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.

Held for Sale

Held for Sale	12 Months Ended
	Dec. 31, 2018
Assets held for sale [Abstract]
Assets held for sale [Text block]	17 . HELD FOR SALE On November 26, 2018, Emera announced an agreement to sell its three NEGG facilities for $ 590 million USD plus a final working capital adjustment made on close. Proceeds from the sale of the NEGG facilities will be used to reduce corporate level debt and support capital investment opportunities within the regulated utility business. The transaction is expected to close in the first quarter of 2019 and is subject to certain regulatory approvals including approval of the FERC. The applicable provisions of the Hart-Scott-Rodino Antitrust Act have been satisfied. As at December 31, 2018 , the assets of the NEGG facilities were classified as held for sale and were 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 the assets are no longer being depreciated. Included in assets held for sale on the Consolidated Balance Sheets was $ 777 million ($ 570 million USD) related to Property, plant and equipment. The NEGG operations are included within the Company’s Emera Energy segment.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	18 . 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 2018 2017 Generation (1) 3 to 131 $ 11,092 $ 11,010 Transmission 11 to 80 3,047 2,786 Distribution 4 to 80 6,348 5,660 Gas transmission and distribution 7 to 85 3,398 2,867 General plant and other 2 to 60 2,158 1,874 Total cost 26,043 24,197 Less: Accumulated depreciation (1) (8,567) (7,824) 17,476 16,373 Construction work in progress 1,236 622 Net book value $ 18,712 $ 16,995 (1) On November 26, 2018, the Company announced an agreement to sell the NEGG facilities and as of December 31, 2018, the Company has classified these assets as held for sale. As of December 31, 2017, these assets were recorded within Property, Plant and Equipment on the Consolidated Balance Sheets. Refer to note 17 for additional information.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
Employee Benefit Plans [Abstract]
EMPLOYEE BENEFIT PLANS	19 . EMPLOYEE BENEFIT PLANS Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island. Benefit Obligation and Plan Assets The changes in b enefit o bligation and p lan a ssets, and the f unded s tatus for all plans were as follows: For the Year ended December 31 millions of Canadian dollars 2018 2017 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 $ 2,683 $ 356 $ 2,607 $ 358 Service cost 51 6 49 5 Plan participant contributions 8 5 8 4 Interest cost 95 13 99 14 Benefits paid (143) (33) (129) (27) Actuarial (gains) losses (133) (25) 171 25 Settlements and curtailments (18) - (35) - Foreign currency translation adjustment 107 28 (87) (23) Balance, December 31 2,650 350 2,683 356 Change in plan assets Balance, January 1 2,408 45 2,208 39 Employer contributions 51 31 109 27 Plan participant contributions 8 5 8 4 Benefits paid (143) (33) (129) (27) Actual return on assets, net of expenses (105) (3) 313 5 Settlements and curtailments (18) - (34) - Foreign currency translation adjustment 99 4 (67) (3) Balance, December 31 2,300 49 2,408 45 Funded status, end of year $ (350) $ (301) $ (275) $ (311) 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 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,623 $ 318 $ 2,655 $ 325 Fair value of plan assets 2,264 6 2,370 6 Funded status $ (359) $ (312) $ (285) $ (319) Plans with Accumulated Benefit Obligation (“ABO”) in E xcess of P lan A ssets The ABO for the defined benefit pension plans was $ 2,527 million as at December 31, 2018 ( 2017 – $ 2,561 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 2018 2017 Defined benefit pension plans Defined benefit pension plans ABO $ 2,504 $ 1,608 Fair value of plan assets 2,264 1,409 Funded status $ (240) $ (199) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (12) $ (19) $ (23) $ (18) Long-term liabilities (347) (294) (264) (295) Other long-term assets 9 11 10 - Amount included in deferred income tax 5 (2) 2 - AOCI, net of tax and regulatory assets 628 60 561 74 Net amount recognized $ 283 $ (244) $ 286 $ (239) Amounts R ecognized in AOCI and Regulatory A ssets Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets . The following table summarizes the change in AOCI and r egulatory assets: Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans (1) Balance, January 1, 2018 $ 315 $ 251 $ (3) Amortized in current period (26) (37) 1 Current year addition to AOCI or regulatory assets 73 32 - Change in foreign exchange rate 27 - - Balance, December 31, 2018 $ 389 $ 246 $ (2) Non-pension benefits plans (1) Balance, January 1, 2018 $ 78 $ (4) $ - Amortized in current period 2 1 - Current year addition to AOCI or regulatory assets (17) (4) - Change in foreign exchange rate 2 - - Balance, December 31, 2018 $ 65 $ (7) $ - (1) The January 1, 2018 balances include a prior period reclassification from AOCI to Regulatory assets, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to notes 10 and 14 for further details. 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 246 $ (7) $ 251 $ (4) Past service (gains) costs (2) - (3) - Regulatory assets 389 65 315 78 Total AOCI and regulatory assets before deferred income taxes 633 58 563 74 Amount included in deferred income tax assets (5) 2 (2) - Net amount in AOCI and regulatory assets $ 628 $ 60 $ 561 $ 74 Benefit C ost C omponents Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 51 $ 6 $ 49 $ 5 Interest cost 95 13 99 14 Expected return on plan assets (138) (2) (129) (3) Current year amortization of: Actuarial losses 33 (1) 38 2 Past service costs (gains) (1) - - (8) Regulatory assets (liability) 26 (2) 17 (1) Settlement, curtailments 4 - (1) - Total $ 70 $ 14 $ 73 $ 9 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,223 million as at January 1, 2018 ( 2017 – $ 2,153 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 48% to 53% Equities 47% to 52% 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, 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 % December 31, 2017 Cash and cash equivalents $ - $ 32 $ - $ 32 1 % Net in-transits - (36) - (36) -1 % Equity securities: Canadian equity - 214 - 214 9 % US equity - 390 - 390 16 % Other equity - 197 - 197 8 % Fixed Income securities: Government - - 72 72 3 % Corporate - - 56 56 2 % Other - 5 - 5 - Mutual funds - 246 - 246 10 % Other - - 4 4 - Open-ended investments measured at NAV (1) 819 - - 819 34 % Common collective trusts measured at NAV (2) 409 - - 409 18 % Total $ 1,228 $ 1,048 $ 132 $ 2,408 100 % (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 13 for more information on the fair value hierarchy and inp uts used to measure fair value. Post - Retirement Benefit Plans There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required . Investments in Emera As at December 31, 2018 and 2017 , the assets related to the pension funds and post-retirement benefit plans do not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities. Cash Flows The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2019 $ 53 $ 22 Expected benefit payments 2019 149 24 2020 152 25 2021 162 25 2022 169 25 2023 175 26 2024 – 2028 988 127 Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2018 2017 (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 4.05 % 4.30 % 3.55 % 3.65 % Rate of compensation increase 3.30 % 3.67 % 3.12 % 3.28 % Health care trend - initial (next year) - 6.39 % - 6.65 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2036 Benefit cost for year ended December 31: Discount rate 3.55 % 3.65 % 3.96 % 4.18 % Expected long-term return on plan assets 6.38 % 3.73 % 6.29 % 6.08 % Rate of compensation increase 3.12 % 3.28 % 2.82 % 2.54 % Health care trend - initial (current year) - 6.65 % - 6.78 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2036 - 2035 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 allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan . Sensitivity Analysis for Non-Pension Benefits Plans The health care cost trend significantly influences the a mounts 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 2018 : millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 17 (15) Sensitivity Analysis for Defined Benefit Pension Plans The impact on the 2018 benefit cost of a 25 basis point change in the discount rate and asset return assumptions is 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 2019: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (15) $ (1) Past service gains 1 6 Regulatory assets (16) 2 Total $ (30) $ 7 Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2018 was $ 31 million ( 2017 – $ 23 million) .

Net Investment in Direct Financ

Net Investment in Direct Financing Lease	12 Months Ended
	Dec. 31, 2018
Net Investment in Direct Financing Lease [Abstract]
NET INVESTMENT IN DIRECT FINANCING LEASE	20 . NET INVESTMENT IN DIRECT FINANCING LEASE Emera’s net investment in direct financing lease primarily relates to Brunswick Pipeline. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The 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. Net investment in direct financing lease consists of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Total minimum lease payments to be received $ 1,066 $ 1,126 Less: amounts representing estimated executory costs (201) (211) Minimum lease payments receivable $ 865 $ 915 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (564) (609) Net investment in direct financing lease $ 484 $ 489 Principal due within one year (included in Receivables and other current assets) 9 8 Net investment in direct financing lease – long-term $ 475 $ 481 Future minimum lease payments to be received for the next five years: For the Year ended December 31 millions of Canadian dollars 2019 2020 2021 2022 2023 Minimum lease payments to be received $ 65 $ 65 $ 65 $ 65 $ 64 Less: amounts representing estimated executory costs (12) (12) (12) (12) (12) Minimum lease payments receivable $ 53 $ 53 $ 53 $ 53 $ 52

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2018
Goodwill [Abstract]
GOODWILL	21. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2018 2017 Balance, January 1 $ 5,805 $ 6,213 Change in foreign exchange rate 508 (408) Balance, December 31 $ 6,313 $ 5,805 G oodwill on Emera’s Consolidated B alance S heet s relates to the ac quisitions of TECO Energy , Emera Maine and GBPC. Goodwill is subject to an annual assessment for impairment at the reporting unit level. Emera’s reporting units with goodwill are Tampa Electric, PGS , New Mexico Gas, Emera Maine and GBPC. A qualitative impairment assessment was performed for Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC, concluding that the fair value of the re porting units exceeded their respective carrying values, and as such, no quantitative assessments were performed and no impairment charges were recognized.

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2018
Short-term Debt [Abstract]
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 rate s as at December 31 consisted of the following: millions of Canadian dollars 2018 Weighted average interest rate 2017 Weighted average interest rate TECO Finance Advances on revolving credit and term facilities $ 805 3.43 % $ 820 2.58 % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 302 3.10 % 382 2.07 % NMGC Advances on revolving credit facilities 79 3.40 % 38 2.47 % NSPI Bank indebtedness - - % 1 - % Short-Term debt $ 1,186 $ 1,241 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 2018 2017 TECO Energy/TECO Finance - term credit facility 2019 $ 682 $ 502 TECO Energy/TECO Finance - revolving credit facility 2022 546 376 Tampa Electric Company - revolving credit facility 2022 443 408 Tampa Electric Company - accounts receivable revolving credit facility 2021 205 188 Tampa Electric Company - term loan 2018 - 377 NMGC - revolving credit facility 2022 171 157 GBPC - revolving credit facility 2019 18 16 Total 2,065 2,024 Less: Advances under revolving credit and term facilities 1,186 1,241 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,189 1,244 Available capacity under existing agreements $ 876 $ 780 The weighted average interest rate on outstanding short-term debt at December 31, 2018 was 3.34 per cent ( 2017 – 2.42 per cent ). Recent F inancing Activity Emera Florida and New Mexico On October 11, 2018, TEC repaid a $300 million USD 1-year term credit facility using proceeds from a senior note issuance. Refer to note 24 . On March 23, 2018, TEC extended the maturity date of its $150 million USD accounts receivable collateralized borrowing facility from March 23, 2018 to March 22, 2021. There were no other changes in commercial terms. On March 7, 2018, TECO Energy/Finance increased its $300 million USD revolving credit facility by $100 million USD to $400 million USD. There were no other changes in commercial terms. On March 7, 2018, TECO Energy/Finance increased its $400 million USD term bank credit facility by $100 million USD to $500 million USD, and extended the maturity date to March 8, 2019. There were no other changes in commercial terms.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2018
Other Current Liabilities [Abstract]
OTHER CURRENT LIABILITIES	23 . OTHER CURRENT LIABILITIES Other current liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Accrued charges $ 154 $ 134 Accrued interest on long-term debt 93 78 Pension and post-retirement liabilities (note 19 ) 31 41 Sales and other taxes payable 9 11 Emission credits obligations (1) 8 21 Income tax payable 6 1 Other 127 64 $ 428 $ 350 (1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory ( note 11 ) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Long-term Debt [Abstract]
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 , 2018 , consisted of the following: Weighted average interest rate (1) millions of Canadian dollars 2018 2017 Maturity 2018 2017 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 339 $ 133 Unsecured fixed rate notes 3.50% 3.50% 2019-2023 725 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,637 1,505 $ 2,701 $ 2,363 Emera US Finance LP Unsecured senior notes (USD) 3.60% 3.60% 2019 - 2046 $ 4,434 $ 4,077 TECO Finance (2) Variable rate notes (USD) Variable 2018 $ - $ 314 Fixed rate notes and bonds (USD) 5.15% 5.15% 2020 409 376 $ 409 $ 690 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.64% 4.75% 2021 - 2049 $ 3,126 $ 2,410 PGS Fixed rate notes and bonds (USD) 4.66% 5.06% 2021 - 2049 $ 425 $ 328 NMGC Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2026 $ 368 $ 339 NMGI Fixed rate notes and bonds (USD) 3.41% 3.41% 2019 - 2024 $ 273 $ 251 NSPI Discount notes Variable Variable 2023 $ 516 $ 364 Medium term fixed rate notes 5.73% 5.73% 2025 - 2097 1,965 1,965 Fixed rate debenture 9.75% 9.75% 2019 95 95 $ 2,576 $ 2,424 Emera Maine LIBOR loans and demand loans Variable Variable 2023 $ 28 $ 51 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 68 63 Unsecured senior fixed rate notes (USD) 4.23% 4.15% 2022 -2048 382 294 $ 478 $ 408 EBP Senior secured credit facility 3.08% 3.08% 2022 $ 248 $ 248 GBPC Amortizing fixed rate notes (USD) 3.83% 3.77% 2021-2022 $ 114 $ 78 Senior notes (USD) 7.07% 7.07% 2020-2023 68 88 $ 182 $ 166 ICDU Fixed rate note (USD) 4.00% - 2023 $ 24 $ - BLPC & ECI Secured senior notes (USD) Variable Variable 2021 159 168 Secured fixed rate senior notes (4) 4.74% 5.06% 2020 - 2035 $ 99 $ 76 $ 258 $ 244 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 22 $ 31 Debt issuance costs (113) (98) Amount due within one year (1,119) (741) $ (1,210) $ (808) Long-Term Debt $ 14,292 $ 13,140 (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. 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 2018 2017 Emera – revolving credit facility (1) June 2020 $ 900 $ 900 NSPI - revolving credit facility (1) October 2023 600 600 Emera Maine – revolving credit facility February 2023 109 100 BLPC – revolving credit facility 2021 - 2022 26 24 Total 1,635 1,624 Less: Borrowings under credit facilities 899 598 Letters of credit issued inside credit facilities 77 44 Use of available facilities 976 642 Available capacity under existing agreements $ 659 $ 982 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. Debt Covenants Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significa nt covenants are listed below: As at Financial Covenant Requirement December 31, 2018 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.60 : 1 Recent Financing Activity Emera On May 16, 2018, Emera filed a $750 million debt and preferred equity shelf prospectus, providing the Company with access to raise long-term debt and preferred equity. On May 31, 2018, preferred shares were issued under this base shelf prospectus for gross proceeds of $300 million ( refer to note 27 ). As at December 31 , 2018 the Company has $450 million available for issuance under this prospectus, which expires on June 16, 2020. Emera Florida and New Mexico On Octob er 4, 2018, TEC completed a $375 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.45 per cent and have a maturity date of June 15, 2049. Proceeds from this issuance were used to repay a $300 million USD 1-year term credit f acility. Refer to note 22 . On June 7, 2018, TEC completed a $350 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.30 per cent and maturity date of June 15, 2048. On April 10, 2018, TECO Energy/Finance repaid a $250 m illion USD note upon maturity. The note was repaid using funds from existing credit facilities and cash on hand . NSPI On October 31, 2018, NSPI amended its operating credit facility to extend the maturity fro m October 2021 to October 2023. There were no other changes in commercial terms. Emera Maine On November 15, 2018, Emera Maine completed a $50 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.71 per cent and will mature on November 15, 2048. Proceeds from this iss uance were used for general corporate purposes. On February 28, 2018, Emera Maine extended the maturity date of its $80 million USD operating credit facility from September 25, 2019 to February 28, 2023. There were no other changes in commercial terms. E CI On January 12, 2018, a wholly owned indirect subsidiary of ECI entered into a five year $18 million Bahamian dollar loan agreement with an interest rate of 4.00 per cent and maturity date of January 12, 2023. EBP On October 31, 2018, Emera Brunswick Pipeline amended its Credit Agreement to extend the maturity from February 2021 to February 2022. There were no other changes in commercial terms . 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 follows: millions of Canadian dollars 2019 2020 2021 2022 2023 Thereafter Total Emera $ 225 $ 339 $ - $ - $ 500 $ 1,637 $ 2,701 Emera US Finance LP 682 - 1,023 - - 2,729 4,434 TECO Finance - 409 - - - - 409 Tampa Electric - - 315 307 - 2,504 3,126 PGS - - 64 34 - 327 425 NMGC - - 273 - - 95 368 NMGI 69 - - - - 204 273 NSPI 95 - - - 516 1,965 2,576 Emera Maine - 41 - 123 28 286 478 EBP - - - 248 - - 248 GBPC 17 50 37 33 45 - 182 ICDU - - - - 24 - 24 BLPC & ECI 31 59 30 13 25 100 258 Total $ 1,119 $ 898 $ 1,742 $ 758 $ 1,138 $ 9,847 $ 15,502

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATION	25 . ASSET RETIREMENT OBLIGATIONS AROs mostly relate to the 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 assets 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 2018 2017 Balance, January 1 $ 172 $ 170 Additions (1) 25 2 Liabilities settled (2) (3) Accretion included in depreciation expense 6 6 Other (1) 1 Change in foreign exchange rate 5 (4) Balance, December 31 $ 205 $ 172 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2018 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. Tampa Electric submitted a petition to the FPSC in December 2018 for recovery of costs associated with the ongoing project and the petition is currently under review.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies [Abstract]
COMMITMENTS AND CONTINGENCIES	26 . COMMITMENTS AND CONTINGENCIES Commitments As at December 31, 2018 , 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 consisted of the following: millions of Canadian dollars 2019 2020 2021 2022 2023 Thereafter Total Purchased power (1) $ 204 $ 203 $ 209 $ 208 $ 209 $ 2,194 $ 3,227 Transportation (2) (3) 569 347 255 215 170 1,492 3,048 Fuel and gas supply 642 237 49 7 3 - 938 Capital projects (4) 524 147 45 11 3 8 738 Long-term service agreements (5) (6) 110 67 42 30 33 246 528 Equity investment commitments (7) - 190 - - - - 190 Leases and other (8) 18 15 10 9 7 75 134 Demand side management 44 1 - - - - 45 $ 2,111 $ 1,207 $ 610 $ 480 $ 425 $ 4,015 $ 8,848 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (3) Includes $82 million related to NEGG transportation capacity ($5 million in 2019; $5 million in 2020; $5 million in 2021; $4 million in 2022; $4 million in 2023 and $59 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information. (4) Includes $439 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 $248 million related to various long-term service agreements NEGG has entered into for maintenance of certain generating equipment ($46 million in 2019; $9 million in 2020; $24 million in 2021; $16 million in 2022; $16 million in 2023 and $137 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information. (7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (8) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years. In January 2018, NSPI started paying the UARB approved interim assessment payments and as of December 31, 2018, $96 million has been paid to NSPML. The UARB approved payment for 2019 is $ 111 million and is subject to a $10 million holdback. Refer to note 14 for additional information. After 2019, the timing of and amount s payable to NSPML will be subject to regulatory filings with the UARB , with expected filings in 2019 and 2020. Legal Proceedings Emera Florida and New Mexico 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 a ward in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million 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 t he award was granted, and Guatemala was ordered to pay certain costs relatin g 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 well 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 tribuna l was constituted and the matter has been fully briefed. A hearing is scheduled for March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH has sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing . Guatema la’s motion to dismiss the enforcement action was denied. The parties are in the process of filing motions on the matter. 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 , 2018 , TEC has estimated its financial liability to be $ 38 million ($ 28 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amount s represent only the portion of the clea nup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the res pective governmental agencies. The es timates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy fo r the dur ation 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 cos ts. Other f actors that could impact these estimates include additional testing and invest igation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could r equire 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 complaints were filed with the FERC to challenge the base 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 reser ve 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 respe ctively, have been joined together and are pres ently pending before the FERC. Emera Maine has recorded a reserve of approximately $ 4 million USD for the se c ases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Balance Shee ts and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements 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 Initial 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 relation to Complaint IV due to the uncertainty of the final outcome. On October 16, 2018, the FERC issued an ord er that addresse d all four complaint proceedings. The FERC order propose d a new methodology to set ROEs. Based on the new methodology, the FERC’s preliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comme nt on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect to all four pending complaints due to uncertainty. Other Legal Proceedings Emera and its subsidiaries may, f rom 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 Co mpany. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are dis cussed in note 12 and note 13 . Sound risk management is an essential discipline for running the business efficiently and pursuing the Co mpany’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 internationally, 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 affect results. Consistent with the Company’s risk management poli cies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses foreign currency derivative instruments to hedge specific transactions. 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. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including fo reign exchange . The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign su bsidiaries 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 acc ess to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable 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 and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or c ause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an ad verse effect on the cost of financing. Inability to a ccess to cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. Emera is subject to financial risk associated with changes in its credit ratings. There are a nu mber of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A decrease in a credit rating cou ld result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Emera ma nages 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 compens ation, 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 R ate Risk Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes th e 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 regu lated 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 red ucing 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 a cquisition initiatives. Commodity Price Risk A large portion of the Company’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, mo nitor, report and mitigate these risks. Fuel contracts may be exposed to broader 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 he dging 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 subsidiaries 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 existin g tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results . Guarant ees and Letters of Credit Emera has several significant guarantees and letters of credit on behalf of third parties outstanding. The following guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2018 : TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transpor tation precedent agreement. The guarantee is for a maximum potential amount of $ 45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee e xpires five years after the gas transportation precedent agreement termination date, which is expected to terminate on January 1, 2022. In the e vent that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded b elow investment gr ade 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 $ 67 million USD to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one year term and are renewed annually as required . Emera Reinsurance Limited has issued a standby letter of credit to secure its obligations under re insurance agreements. The letter of credit expires in February 2019 and is renewed annually. The amount committed as of December 31, 2018 was $ 6 million USD. 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 2019 and is renewed annually. The amount committed as at December 31, 2018 was $ 49 million. Collaborative Arrangement s For the years ended December 31, 2018 and 2017 , 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 2018, NSPI recognized $ 19 million net expense (2017 - $ 18 million) in “Regulated fuel for gene ration and purchased power” and $ 2 million (2017 - $ 3 million) in OM&G .

Cumulative Preferred Stock

Cumulative Preferred Stock	12 Months Ended
	Dec. 31, 2018
Cumulative Preferred Stock [Abstract]
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, 2018 December 31, 2017 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 $ 26.00 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 - $ - Total 41,000,000 $ 1,004 29,000,000 $ 709 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 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 (6) 4.500 1.1250 26.00 (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, 2018, 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) First Preferred Shares, Series E are redeemable at $26.00 to August 15, 2019, 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 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 holder s of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

Non-Controlling Interest in Sub

Non-Controlling Interest in Subsidiaries	12 Months Ended
	Dec. 31, 2018
Non-Controlling Interest in Subsidiaries [Abstract]
Noncontrolling Interest Disclosure [Text Block]	28. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Domlec $ 22 $ 21 Preferred shares of GBPC 19 19 ICDU (1) - 52 $ 41 $ 92 (1) On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD. This acquisition increases Emera’s indirect ownership interest to 100 per cent. Preferred shares of GBPC: Authorized: 20,000 non-voting cumulative redeemable variable perpetual preferred shares. 2018 2017 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 20,000 $ 19 20,000 $ 19 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: The Preferred Stock is redeemable by GBPC , in whole at any time or in part from time to time , at $ 1,000 Bahamian per share plus accrued and unpaid dividends. The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016 , 8.50 per cent per annum fixed cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue. The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock 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, 2018
Supplemental Cash Flow Information [Abstract]
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 2018 2017 Changes in non-cash working capital: Inventory $ (44) $ 31 Receivables and other current assets (144) (154) Accounts payable 59 3 Other current liabilities 13 16 Total non-cash working capital $ (116) $ (104) Supplemental disclosure of cash paid: Interest $ 653 $ 689 Income taxes $ 33 $ 63 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 181 $ 166 Change in accrued capital expenditures $ (50) $ 13 Issuance of depository receipts $ 22 $ -

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2018
Stock-Based Compensation [Abstract]
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 to which employees 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 employee s’ contributions. If an employee contributes any am ount up to $ 3,000 to that 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. As at December 31 , 2018 , Emera is in compliance with this requirement. Compensation cost for shares issued by Emera for the year ended December 31, 2018 under the Employee Common Share Purchase Plan was $1 million ( 2017 – $ 1 million) and is included in “ OM&G” on the Consolidated Statements of Income. The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan” ) or (“DRIP” ), which provides an opportunity for shareholders to reinvest dividends for the purpose o f purchasing common shares. This plan pr ovides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares . 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, 2018 , 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 optio n 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 o ptions 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 ex ercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The 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 : 2018 2017 Weighted average fair value per option $ 1.70 $ 2.37 Expected term (1) 6 years 5 years Risk-free interest rate (2) 2.13 % 1.22 % Expected dividend yield (3) 5.69 % 4.60 % Expected volatility (4) 13.71 % 14.41 % (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 2018 : 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, 2017 3,643,575 $ 39.42 1,739,650 $ 2.52 Granted 627,600 39.93 627,600 1.70 Exercised (23,800) 24.98 N/A N/A Vested N/A N/A (666,125) 2.51 Forfeited (11,700) 45.10 (11,700) 2.54 Expired (10,100) 39.93 (10,100) 1.70 Options outstanding December 31, 2018 4,225,575 $ 39.56 1,679,325 $ 2.22 Options exercisable December 31, 2018 (2)(3) 2,546,250 $ 37.15 (1) As at December 31, 2018, there was $5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.2 years (2017 - $3 million, 2.5 years). (2) As at December 31, 2018, the weighted average remaining term of vested options was 5.1 years with an aggregate intrinsic value of $18 million (2017 - 5.4 years, $22 million). (3) As at December 31, 2018, the fair value of options that vested in the year was $2 million (2017 - $2 million). Compensation cost recognized for stock options for the year ended December 31, 2018 was $ 1 million ( 2017 – $ 2 million), which is included in “Operating, maintenance and general” on the Consolidated Statements of Income. As at December 31, 2018 , cash received from option exercises was $ 1 million ( 2017 – $ 3 million). The total intrinsic value of options exercised for the year ended December 31, 2018 was $ 1 million ( 2017 – $ 2 million). The range of exercise prices for the options outstand ing as at December 31, 2018 was $ 21.99 to $ 46.19 ( 2017 – $ 21.58 to $ 46.19 ). Share Unit Plans The Company has DSU and PSU 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’ fees are paid on a quarterly basis and, at the ti me 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 , also referred to as DRIP. 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 the average of Emera’s stock closing price during the ten trading days ending on the te nth trading day prior to the payment date. 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 sub ject 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 award s 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 t o 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 Managemen t 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, 2018 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, 2017 751,600 $ 28.44 472,485 $ 35.33 Granted including DRIP 90,549 38.72 101,676 43.93 Exercised (5,040) 30.15 (10,640) 25.31 Outstanding and exercisable as at December 31, 2018 837,109 $ 29.54 563,521 $ 37.07 Compensation cost recognized for employee and director DSU for the year ended December 31, 2018 was $ 2 million ( 2017 – $ 7 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2018 were $ 1 million ( 2017 – $ 2 million) . The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2018 was $ 37 million (2017 - $ 35 million). Performance Share Unit Plan Under the PSU plan, executive and senio r 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 a given calculation date. Dividend equivalents are awarded and paid in the form of additional P SUs, also referred to as DRIP. The PSU value varies acco rding 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 the per formance cycle and will be pro-rated in the case of termination , disability or death. A summary of the activity related to employee PSUs for the year ended December 31, 2018 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2017 829,998 $ 43.41 $ 41.1 Granted including DRIP 486,181 47.84 Exercised (176,805) 38.85 Forfeited (12,260) 44.88 Outstanding as at December 31, 2018 1,127,114 $ 46.02 $ 56.9 Compensation cost recognized for the PSU plan for the year ended December 31, 2018 was $ 14 million ( 2017 – $ 14 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2018 were $ 4 millio n ( 2017 – $ 4 million).

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2018
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	31 . VARIABLE INTEREST ENTITIES Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controllin g financial interest of NSPML. In Q2 2014, when the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic per formance of the Maritime Link. Thus, Em era began recording the Maritime Link as an equity investment. BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SI F must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the acti vities 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 re lated 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. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF. The Company has identified certain long-term purchase power agreements that meet the definition of variable i nterests as the Company has to purchase 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, includi ng the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2018 December 31, 2017 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) $ 545 $ 51 $ 510 $ 67

Comparative Information

Comparative Information	12 Months Ended
	Dec. 31, 2018
Comparative Information [Abstract]
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, 2018
Subsequent Events [Abstract]
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 15, 2019 , the date the financial statements were issued.

Supplemental Financial Informat

Supplemental Financial Information	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	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 ca sh 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 determined using geographic, service line or other similar criteria, and as a result, the “Parent ”, “Subsidiary Issuer”, “Gu arantor Subsidiaries ” and “Non-guarantor Subsidiaries” columns each include portions of our domestic and international operations. Accordingly, 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 requ irements 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, 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 For the year ended December 31, 2017 Operating revenues $ - $ - $ 4,274 $ 2,009 $ (57) $ 6,226 Operating expenses 41 - 3,241 1,583 (57) 4,808 Income (loss) from equity investments and subsidiaries 337 - 1 122 (336) 124 Other income (expenses), net 38 - 15 (46) (32) (25) Interest expense, net (1) 84 (40) 451 203 - 698 Income (loss) before provision for income taxes 250 40 598 299 (368) 819 Income tax expense (recovery) (44) 17 511 36 - 520 Net income (loss) 294 23 87 263 (368) 299 Non-controlling interest in subsidiaries - - - 1 4 5 Preferred stock dividends 28 - 29 13 (42) 28 Net income (loss) attributable to common shareholders $ 266 $ 23 $ 58 $ 249 $ (330) $ 266 Comprehensive income (loss) of Emera Incorporated $ (6) $ 3 $ (291) $ 265 $ 23 $ (6) (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, 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 As at December 31, 2017 Assets Current assets $ 358 $ 30 1,420 $ 891 $ (173) $ 2,526 Property, plant and equipment 17 - 12,258 4,720 - 16,995 Other assets Regulatory assets - - 587 686 - 1,273 Goodwill - - 5,709 96 - 5,805 Other long-term assets 9,761 4,285 156 3,094 (15,089) 2,207 Total other assets 9,761 4,285 6,452 3,876 (15,089) 9,285 Total assets $ 10,136 $ 4,315 $ 20,130 $ 9,487 $ (15,262) $ 28,806 Liabilities and Equity Current liabilities $ 129 $ 12 $ 3,293 $ 714 $ (202) $ 3,946 Long-term liabilities Long-term debt 2,861 4,034 8,468 4,262 (6,485) 13,140 Deferred income taxes - 4 447 565 7 1,023 Regulatory liabilities - - 1,888 354 - 2,242 Other long-term liabilities 34 - 691 550 (24) 1,251 Total long-term liabilities 2,895 4,038 11,494 5,731 (6,502) 17,656 Total Emera Incorporated equity 7,112 265 5,343 2,970 (8,578) 7,112 Non-controlling interest in subsidiaries - - - 72 20 92 Total equity 7,112 265 5,343 3,042 (8,558) 7,204 Total liabilities and equity $ 10,136 $ 4,315 $ 20,130 $ 9,487 $ (15,262) $ 28,806 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, 2018 Net cash provided by (used in) by 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 As at December 31, 2017 Net cash provided by (used in) operating activities $ 195 $ 22 $ 658 $ 1,080 $ (762) $ 1,193 Investing activities Additions to property, plant and equipment (5) - (1,031) (480) (13) (1,529) Net purchase of investments subject to significant influence - - - (213) - (213) Other investing activities (742) (26) (5) 1,852 (1,098) (19) Net cash provided by (used in) investing activities (747) (26) (1,036) 1,159 (1,111) (1,761) Financing activities Change in short-term debt, net - - 365 (13) - 352 Proceeds from long-term debt - - 147 (31) 13 129 Retirement of long-term debt - - (413) (55) 15 (453) Net borrowings (repayments) under committed credit facilities (30) - 59 192 9 230 Issuance of common and preferred stock 682 - 134 (2,032) 1,898 682 Dividends paid (315) - (29) (285) 314 (315) Other financing activities 290 - 96 (42) (376) (32) Net cash provided by (used in) financing activities 627 - 359 (2,266) 1,873 593 Effect of exchange rate changes on cash, cash equivalents and restricted cash 1 (3) 1 (12) - (13) Net increase (decrease) in cash, cash equivalents and restricted cash 76 (7) (18) (39) - 12 Cash, cash equivalents and restricted cash, beginning of year 200 28 72 191 - 491 Cash, cash equivalents and restricted cash, end of year $ 276 $ 21 $ 54 $ 152 $ - $ 503

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies [Abstract]
Nature of Operations [Text Block]	Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution and gas transmission and distribution. At December 31, 2018 , Emera’s primary rate-regulated subsidiaries a nd investments included the following: Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico that include: Tampa Electric Company (“TEC”), which hol ds the Tampa Electric Division (“Tampa Electric”), a vertically integrated regulated electric utility, serving approximately 764,000 customers in West Central Florida, and Peoples Gas System Division (“PGS”), a regulated gas distribution utility, serving approximately 392,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, ser ving approximately 530,000 customers across New Mexico; TECO Finance, Inc. (“TECO Finance”), a financing subsidiary of TECO Energy; and SeaCoast Gas Transmission LLC (“SeaCoast”), a regulated intrastate natural gas transmission company off ering services in Florida. Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 519,000 customers ; Emera Maine, a regulated electric transmission and distribution utility, serving approximately 159,000 customers in the state of Maine; Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: The Ba rbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 130,000 customers; Grand Bahama Power Company Limited (“GBPC”), a vertically int egrated utility operating on Grand Bahama Island, serving approximately 19,000 customers. On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD, increasing Emera’s interest in GBPC from 80.4 per cent to 100 per cent; a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated utility on the island of Dominica, serving approximately 26,000 customers; and a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. Emera Brunswick Pipeline Company Limited (“Bru nswick 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 Newf oundland & 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 forecas ted to be generating first power in 2019 and full power in 2020. ENL’s two investments are: a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two 170-ki lometre subsea cables, connecting the island 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 the energization phase of the proj ect began in June 2018. a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States . At December 31, 2018 , Emera’s investments in other energy-related non-regulated companies included the following: Emera Energy, which consists of: Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricit y and provides related energy asset management services; Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), 1,115 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States. On November 26, 2018, Emera announced an agreemen t to sell its NEGG facilities. The transaction is expected to close in the first quarter of 2019. Refer to n ote 17 for additional information; Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; 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 L P, a wholly owned financing subsidiary of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic C anada; and other investments.
Basis of Accounting, Policy [Policy Text Block]	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 otherwise indicated.
Consolidation, Policy [Policy Text Block]	Principles of Consolidation The consolidated financial stat ements 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. Emera uses the equity method of accounting to record investments in which the Co mpany 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. To identify potential VIEs, management re views contractual and ownership arrangements such as leases, 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 o f 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 consol idation, 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 abse nce of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, mainte nance and general (“OM&G”), depending on the nature of the transaction.
Use of Estimates, Policy [Policy Text Block]	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 Policy [Policy Text Block]	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 return on the equity invested or assets as applicable (refer to n ote 14 for additional details).
Foreign Currency Transactions and Translations Policy [Policy Text Block]	Foreign Currency Translation Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevail ing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en ominat ed debt held in Canadian dollar functional currency companies as hedges of net investments in United States dollar d enominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balan ce sheet date, and the effective portion of the hedge , is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings.
Revenue Recognition, Policy [Policy Text Block]	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 r eceives and consumes the benefits of the electricity . Electric revenues are recognized 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 an d recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenu e is recognized. The Company’s estimate of unbilled revenue at the end of the 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, weather, line losses and inter-period changes to customer classes. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applica ble 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 recogn ized 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 occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate 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. Direct Finance Lease The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which 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 for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease u sing a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income. 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 basis, refle cting 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 payment s 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 auction process held annually, three years in advance, through the forward capacity market. Other non-regulated revenues are recorded when obligations under terms of a contract are satisfied. Other Sales, value add, and other taxes, with the exception of gross receipts tax es discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Franchise Fees and Gross Receipts Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, thr ough prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fe es and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.
Property, Plant and Equipment, Policy [Policy Text Block]	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 replacements of units of property, plant and equipment are included in “P roperty, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gai n or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attrib utable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Ex penditures 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 maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of de preciable property. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less s alvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets , which are included in “Property, plant and 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 method 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 Policy [Policy Text Block]	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 for 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 Tax, Policy [Policy Text Block]	Income Taxes and Investment Tax Credi ts Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial sta tements or income tax returns. Deferred income tax assets and liabilities are determined based on the diff erence between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differ ences are expected to reverse. Emera recognizes the effect of in come tax positions only when it is more likely than not that they will be rea lized. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be reco vered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax as sets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded at the amount 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 the regulatory practi ces. 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 in come 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 tax 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 7 for further details.
Derivatives, Hedge Discontinuances [Policy Text Block]	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 count erparties 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 Comp any has contracts for the physical pur chase and sale of natural gas. These physical and financial contracts are classifie d as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are 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 transactio n is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the count erparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if th ey meet string ent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value o f derivatives is deferred to AOCI and recognized in income in the same period the re lated hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period. Where th e 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 Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item wh en the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in f uture rates. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period, unless deferred as a re sult of regulatory accounting. The Company has not elected to desig nate 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 economically 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 the same category as the item being hedged within operating or investing activities on the Consolid ated Statements of Cash Flows. Non-hedged derivat ives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collater al with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term inve stments with original maturities of three months or less at acquisition. To tal short-term investments of $43 million have an effective interest rate of 2.0 per cent at December 31, 2018 ( 2017 - $ 222 million with a n effective interest rate of 1.4 per cent). Included in restricted cash are funds required to be set aside for the BLPC Self-Insurance Fund (“SIF”) (note 31 ).
Receivables, Policy [Policy Text Block]	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 amou nts receiv able from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. Management e stimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the 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 uncollectible.
Inventory, Policy [Policy Text Block]	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. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency.
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block]	Asset Impairment Long-Lived Assets Emera assesses whether there has been an impairment of long-lived assets and intangibles when such indicators exist. The Company reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. In the case of a triggering event, such as a significant market disruption or sale of a business, the values of related lo ng-lived assets are reviewed outside of this annual analysis. 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 indic ates 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 operat ions 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 bas ed 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 f or valuation and pricing activities. 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 . Entities 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, macroeconomic conditions, industry and m arket considerations and overall financial performance. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity chooses to bypass the qualitative assessment , a q uantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carryi ng amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is record ed 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 applied using a discounted ca sh 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. Whe n 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, val uation 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 impair ment of the goodwill assigned to Emera’s reporting units with goodwill. Emera reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit to which goodwill has been allocated, with interim impairment tests performed whe n impairment indicators are present. No impairment provisions were required for either 2018 or 2017 . Refer to note 21 for further detail. 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 pres ence of impairment 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. Financial Assets Equity investments, other than those accounted for under the equity method of accounting, are measured a t fair value with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments.
Asset Retirement Obligations, Policy [Policy Text Block]	Asset Retirement Obligation s An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or stat ute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s c redit adjusted risk-free rate . The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governm ental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and a ccretion expense is included as part of “D epreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant a nd equipment” and included in the next depreciation study. As at December 31, 2018 and 2017 , some of the Company’s transmission and distribution assets may have conditional ARO’s which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are cond itional 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 fair 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.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	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; and a performance share unit (“PSU”) 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 recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measur ed at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	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

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Information [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2018 Operating revenues from external customers (1) $ 3,675 $ 1,437 $ 278 $ 467 $ 600 $ 68 $ - $ 6,525 Inter-segment revenues (1) - 3 - - 14 36 (54) (1) Total operating revenues 3,675 1,440 278 467 614 104 (54) 6,524 AFUDC - debt and equity 21 6 3 - - - - 30 Regulated fuel and fixed cost deferral adjustments - (46) - - - - - (46) Depreciation and amortization 534 219 64 50 46 3 - 916 Interest expense (2) 238 142 22 27 5 290 - 724 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 3 3 38 110 - 154 Income tax expense (recovery) 101 8 11 (2) 66 (115) - 69 Net income attributable to common shareholders 428 131 44 41 165 (99) - 710 Capital expenditures 1,548 345 100 87 33 38 - 2,151 As at December 31, 2018 Total assets 20,051 5,143 1,721 1,373 1,785 2,275 (34) 32,314 Investments subject to significant influence (4) - - 35 42 - 1,239 - 1,316 Goodwill 6,053 - 156 104 - - - 6,313 (1) All significant intercompany balances and intercompany 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. Intercompany transactions which 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) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $12 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. (4) Emera Energy's segment includes an investment in Bear Swamp. At December 31, 2018 this investment is in a credit position of $172 million and is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2017 Operating revenues from external customers (1) $ 3,623 $ 1,335 $ 297 $ 434 $ 451 $ 86 $ - $ 6,226 Inter-segment revenues (1) - 3 - - 14 41 (58) - Total operating revenues 3,623 1,338 297 434 465 127 (58) 6,226 AFUDC - debt and equity 5 8 3 - - - - 16 Regulated fuel and fixed cost deferral adjustments - 59 - - - - - 59 Depreciation and amortization 500 207 47 51 48 3 - 856 Interest expense (2) 248 134 20 25 2 276 - 705 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 1 3 24 96 - 124 Income tax expense (recovery) 529 - 27 - 18 (54) - 520 Net income attributable to common shareholders 99 129 46 31 93 (132) - 266 Capital expenditures 910 385 82 72 47 26 - 1,522 As at December 31, 2017 Total assets 17,216 4,979 1,540 1,251 1,575 2,331 (86) 28,806 Investments subject to significant influence (4) - - 13 39 - 1,163 - 1,215 Goodwill 5,566 - 143 96 - - - 5,805 (1) All significant intercompany balances and intercompany 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. Intercompany transactions which 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) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $24 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. (4) Emera Energy's segment includes an investment in Bear Swamp. At December 31, 2017 this investment is in a credit position of $188 million and is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Geographical Information Revenues (1) : For the Year ended December 31 millions of Canadian dollars 2018 2017 Canada $ 1,520 $ 1,464 United States 4,537 4,328 Barbados 319 280 The Bahamas 121 119 Dominica 27 35 $ 6,524 $ 6,226 (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 2018 2017 Canada $ 4,128 $ 3,995 United States 13,739 12,257 Barbados 446 408 The Bahamas 315 276 Dominica 84 59 $ 18,712 $ 16,995

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue From Contracts With Customers [Abstract]
Disaggregation Of Revenue [Table Text Block]	Emera Florida Corporate Inter- and New Emera Emera Emera and Segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2018 Regulated Electric Revenue Residential $ 1,384 $ 731 $ 107 $ 154 $ - $ - $ - $ 2,376 Commercial 755 405 80 270 - - - 1,510 Industrial 209 233 16 30 - - - 488 Other electric and regulatory deferrals 312 43 9 7 - - - 371 Other (1) 10 28 66 6 - - (3) 107 Regulated electric revenue 2,670 1,440 278 467 - - (3) 4,852 Gas Revenue Residential 492 - - - - - - 492 Commercial 291 - - - - - - 291 Industrial 49 - - - - - - 49 Finance income (2)(3) - - - - - 57 - 57 Other 155 - - - - - - 155 Regulated gas revenue 987 - - - - 57 - 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 - - - 614 47 (51) 628 Total operating revenues $ 3,675 $ 1,440 $ 278 $ 467 $ 614 $ 104 $ (54) $ 6,524 (1) Other includes an immaterial amount of 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, 2018
Investments Subject to Significant Influence and Equity Earnings [Abstract]
Equity Method Investments [Table Text Block]	Investments subject to significant influence consisted of the following: Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2018 2017 2018 2017 2018 NSPML $ 545 $ 510 $ 45 $ 36 100.0 LIL (1) 534 492 42 37 49.5 M&NP (2) 155 156 22 23 12.9 Lucelec (2) 42 39 3 3 19.1 Bear Swamp (3) - - 38 23 50.0 Other Investments 40 18 4 2 $ 1,316 $ 1,215 $ 154 $ 124 (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 Q4 2015. Bear Swamp's credit investment balance of $172 million (2017 - $188 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets.
Variable Interest Investment As An Equity Investment Consolidated Summarized Balance Sheet [Table Text Block]	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 2018 2017 Balance Sheets Current assets $ 86 $ 225 Property, plant and equipment 1,690 1,720 Non-current assets 140 74 Total assets $ 1,916 $ 2,019 Current liabilities $ 21 $ 180 Long-term debt 1,288 1,287 Non-current liabilities 62 42 Equity 545 510 Total liabilities and equity $ 1,916 $ 2,019

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	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 2018 2017 Income before provision for income taxes $ 816 $ 819 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 253 254 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (59) (54) Foreign tax rate variance (55) 36 Amortization of deferred income tax regulatory liabilities (37) - Florida state tax apportionment adjustment (23) - Tax effect of equity earnings (15) (12) Financing deductions (4) (17) Revaluation of US non-regulated deferred income taxes due to tax reform - 317 Other 9 (4) Income tax expense (recovery) $ 69 $ 520 Effective income tax rate 8% 63%
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	millions of Canadian dollars 2018 2017 Current income taxes Canada $ 3 $ 24 United States (121) 24 Other 2 3 Deferred income taxes Canada 11 3 United States 211 384 Other (3) (1) Operating loss carryforwards Canada (33) (40) United States - (194) Other (1) - Revaluation of US non-regulated deferred income taxes United States - 317 Income tax expense (recovery) $ 69 $ 520 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 2018 2017 Canada $ 127 $ 88 United States 646 693 Other 43 38 Income before provision for income taxes $ 816 $ 819
Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block]	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 2018 2017 Deferred income tax assets: Tax loss carryforwards $ 917 $ 853 Tax credit carryforwards 269 314 Regulatory liabilities - cost of removal 206 208 Pension and post-retirement liabilities 126 112 Derivative instruments 90 107 Other 441 394 Total deferred income tax assets before valuation allowance 2,049 1,988 Valuation allowance (163) (105) Total deferred income tax assets after valuation allowance $ 1,886 $ 1,883 Deferred income tax (liabilities): Property, plant and equipment $ (2,591) $ (2,321) Derivative instruments (124) (155) Other (316) (292) Total deferred income tax liabilities $ (3,031) $ (2,768) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 175 $ 138 Long-term deferred income tax liabilities (1,320) (1,023) Net deferred income tax liabilities $ (1,145) $ (885)
Summary of Tax Credit Carryforwards [Table Text Block]	Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2018 consisted of the following: Gross Tax Unrecognized Net Tax Expiration millions of Canadian dollars Carryforwards Amounts Carryforwards Period Canada NOL $ 817 $ (405) $ 412 2027-2038 Capital loss 86 (77) 9 Indefinite United States Federal NOL $ 2,848 $ - $ 2,848 2024-2037 State NOL 1,314 (47) 1,267 2024-2038 Capital loss 6 (6) - 2019 Tax credit 268 - 268 2019-Indefinite Other NOL $ 34 $ (34) $ - 2019-2025
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	millions of Canadian dollars 2018 2017 Balance, January 1 $ 19 $ 18 Increases due to tax positions related to a prior year 8 - Decreases due to tax positions related to a prior year (1) - Increases due to tax positions related to current year - 1 Balance, December 31 $ 26 $ 19

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2018
Common Stock [Abstract]
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Authorized : Unlimited number of non-par value common shares. 2018 2017 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2017 228.77 $ 5,601 210.02 $ 4,738 Conversion of Convertible Debentures 0.01 - 0.15 6 Issuance of common stock (1) 0.45 22 14.61 680 Issued under Purchase Plans at market rate 4.87 200 3.89 182 Discount on shares purchased under Dividend Reinvestment Plan - (9) - (9) Options exercised under senior management share option plan 0.02 1 0.10 3 Employee Share Purchase Plan - 1 - 1 Balance, December 31, 2018 234.12 $ 5,816 228.77 $ 5,601 (1) In Q1 2018, Emera issued 0.45 million common shares to facilitate the creation and issuance of 1.8 million depository receipts in connection with the ICDU share acquisition. The depository receipts are listed on the Bahamas International Securities Exchange.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	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) 2018 2017 Numerator Net income attributable to common shareholders $ 709.6 $ 266.1 Diluted numerator 709.6 266.1 Denominator Weighted average shares of common stock outstanding 231.7 212.3 Weighted average deferred share units outstanding 1.3 1.1 Weighted average shares of common stock outstanding – basic 233.0 213.4 Stock-based compensation 0.4 0.6 Convertible Debentures 0.1 0.1 Weighted average shares of common stock outstanding – diluted 233.5 214.1 Earnings per common share Basic $ 3.05 $ 1.25 Diluted $ 3.04 $ 1.24

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	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 Balance, January 1, 2018 $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) Other comprehensive income (loss) before reclassifications 624 (122) 2 - - 504 Amounts reclassified from accumulated other comprehensive income loss - - (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 For the year ended December 31, 2017 Balance, January 1, 2017 (1) $ 489 $ (49) $ (21) $ (1) $ (283) $ 135 Other comprehensive income (loss) before reclassifications (459) 97 10 5 - (347) Amounts reclassified from accumulated other comprehensive income loss (gain) (2) - - 8 (1) 40 47 Net current period other comprehensive income (loss) (459) 97 18 4 40 (300) Balance, December 31, 2017 $ 30 $ 48 $ (3) $ 3 $ (243) $ (165) (1) The January 1, 2017 balance of AOCI and Regulatory Assets includes a prior period reclassification of $44 million in unrecognized pension and post-retirement benefit costs and $18 million in deferred taxes ($26 million, net of tax) to be consistent with current year presentation. (2) Certain net changes in unrecognized pension and post-retirement benefit costs for Emera Maine of $4 million were previously presented as a change in AOCI and are now presented as a change in Regulatory Assets for the year ended December 31, 2017 to be consistent with current year presentation.
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2018 2017 Affected line item in the Consolidated Financial Statements Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (1) $ (3) Foreign exchange forwards Operating revenue - regulated (5) 10 Total before tax (6) 7 Income tax recovery (expense) - 1 Total net of tax $ (6) $ 8 Net change in available-for-sale investments Other income (expenses), net $ - $ (1) Retained earnings (1) (4) - Total net of tax $ (4) $ (1) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 25 $ 33 Past service costs (gains) OM&G (1) (8) Amounts reclassified into obligations Pension and post-retirement benefits (17) 11 Total before tax 7 36 Income tax recovery (expense) 2 4 Total net of tax $ 9 $ 40 Total reclassifications out of AOCI, net of tax, for the period $ (1) $ 47 (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, 2018
Inventory [Abstract]
Schedule of Inventory, Current [Table Text Block]	Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Fuel $ 213 $ 180 Materials 241 216 Emission credits (1) 20 22 $ 474 $ 418 (1) The NEGG facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative for carbon dioxide emissions. The emission credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments [Abstract]
Schedule of Derivative Instruments [Table Text Block]	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 2018 2017 2018 2017 Cash flow hedges Power swaps $ - $ 5 $ - $ 2 Foreign exchange forwards - 2 5 5 - 7 5 7 Regulatory deferral Commodity swaps and forwards Coal purchases 71 137 1 10 Power purchases 2 5 1 3 Natural gas purchases and sales 2 6 4 7 Heavy fuel oil purchases 1 15 1 4 Foreign exchange forwards 29 32 - 4 105 195 7 28 HFT derivatives Power swaps and physical contracts 62 125 76 162 Natural gas swaps, futures, forwards, physical contracts 125 105 403 294 187 230 479 456 Other derivatives Interest rate swap 1 2 - - 1 2 - - Total gross current derivatives 293 434 491 491 Impact of master netting agreements with intent to settle net or simultaneously (126) (181) (126) (181) 167 253 365 310 Current 148 141 260 227 Long-term 19 112 105 83 Total derivatives $ 167 $ 253 $ 365 $ 310 Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Offsetting Liabilities [Table Text Block]	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 2018 2017 2018 2017 Regulatory deferral $ 1 $ 14 $ 1 $ 14 HFT derivatives 125 167 125 167 Total impact of master netting agreements with intent to settle net or simultaneously $ 126 $ 181 $ 126 $ 181
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	For the Year ended December 31 millions of Canadian dollars 2018 2017 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Realized gain (loss) in non-regulated fuel for generation and purchased power 1 - - 3 - - Realized gain (loss) in operating revenue – regulated - - 5 - - (10) Total gains (losses) in Net income $ 1 $ - $ 5 $ 3 $ - $ (10) As at December 31 millions of Canadian dollars 2018 2017 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ (1) $ - $ (6) $ - $ - $ (3) The Company expects $4 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, 2018, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2019 2020 2021 Foreign exchange forwards (USD) sales $ 30 $ 30 $ -
Schedule Of Regulatory Deferred Gain Losses Derivatives [Table Text Block]	For the Year ended December 31 millions of Canadian dollars 2018 2017 Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (34) $ - $ 4 $ (33) $ (1) $ (4) Unrealized gain (loss) in regulatory liabilities 29 - 24 83 1 (30) Realized (gain) loss in regulatory liabilities (8) - - (2) - - Realized (gain) loss in inventory (1) (55) - (18) (17) - (30) Realized (gain) loss in regulated fuel for generation and purchased power (2) (2) - (9) (3) - (14) Total change derivative instruments $ (70) $ - $ 1 $ 28 $ - $ (78) (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.
Schedule Of Regulatory Commody Swaps Forwards [Table Text Block]	2019 2020-2023 millions Purchases Purchases Coal (metric tonnes) 1 1 Natural Gas (Mmbtu) 16 - Heavy fuel oil (bbls) - 1 2019 2020 Foreign exchange contracts (millions of US dollars) $ 121 $ 111 Weighted average rate 1.1621 1.3027 % of USD requirements 66% 48% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.
Unrealized Gain (Loss) on Investments [Table Text Block]	For the Year ended December 31 millions of Canadian dollars 2018 2017 Power swaps and physical contracts in non-regulated operating revenues $ (12) $ 7 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 205 401 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power - 10 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 2 2 $ 195 $ 420
Offsetting Liabilities Expected To Settle [Table Text Block]	millions 2019 2020 2021 2022 2023 Natural gas purchases (Mmbtu) 308 108 71 50 41 Natural gas sales (Mmbtu) 247 42 9 2 - Power purchases (MWh) 6 - - - - Power sales (MWh) 5 - - - -
Derivative Documentation Unmet [Table Text Block]	Other Derivatives For the Year ended December 31 millions of Canadian dollars 2018 2017 Interest rate Interest rate swaps swaps Unrealized gain (loss) in interest expense, net (1) 2 Total gains (losses) in net income $ (1) $ 2 As at December 31, 2018, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments through Q1 2019.
Schedules of Concentration of Risk, by Risk Factor [Table Text Block]	Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2018 December 31, 2017 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 384 28% $ 326 23% Commercial 182 13% 161 11% Industrial 57 4% 46 3% Other 84 6% 96 7% 707 51% 629 44% Trading group Credit rating of A- or above 49 4% 55 4% Credit rating of BBB- to BBB+ 70 5% 61 4% Credit rating of CCC- to CCC+ 8 0% - 0% Not rated 108 8% 96 7% 235 17% 212 15% Other accounts receivable 273 20% 300 22% 1,215 88% 1,141 81% Derivative Instruments (current and long-term) Credit rating of A- or above 130 9% 207 15% Credit rating of BBB- to BBB+ 9 1% 10 1% Not rated 28 2% 36 3% 167 12% 253 19% $ 1,382 100% $ 1,394 100%
Schedule of Financial Instruments Owned and Pledged as Collateral [Table Text Block]	As at December 31 December 31 millions of Canadian dollars 2018 2017 Cash collateral provided to others $ 103 $ 119 Cash collateral received from others 77 99

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	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) As at December 31, 2017 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 2 - 2 5 2 - 7 Regulatory deferral Commodity swaps and forwards Coal purchases - 127 - 127 Power purchases 5 - - 5 Natural gas purchases and sales - 5 - 5 Heavy fuel oil purchases 4 8 - 12 Foreign exchange forwards - 32 - 32 9 172 - 181 HFT derivatives Power swaps and physical contracts - 3 9 12 Natural gas swaps, futures, forwards, physical contracts and related transportation - 26 25 51 - 29 34 63 Other derivatives Interest rate swap - 2 - 2 - 2 - 2 Total assets 14 205 34 253 Liabilities Cash flow hedges Power swaps 2 - - 2 Foreign exchange forwards - 5 - 5 2 5 - 7 Regulatory deferral Power purchases 3 - - 3 Natural gas purchased and sales 5 1 - 6 Foreign exchange forwards - 4 - 4 8 5 - 13 HFT derivatives Power swaps and physical contracts 49 5 (4) 50 Natural gas swaps, futures, forwards and physical contracts 6 47 187 240 55 52 183 290 Total liabilities 65 62 183 310 Net assets (liabilities) $ (51) $ 143 $ (149) $ (57)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	The change in the fair value of the Level 3 financial assets for the year ended December 31, 2018 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2018 $ 9 $ 25 $ 34 Total realized and unrealized gains (losses) included in non-regulated operating revenues (6) (7) (13) Balance, December 31, 2018 $ 3 $ 18 $ 21 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2018 was as follows: HFT Derivatives millions of Canadian dollars Power Natural gas Total Balance, January 1, 2018 $ (4) $ 187 $ 183 Total realized and unrealized gains (losses) included in non-regulated operating revenues 5 118 123 Balance, December 31, 2018 $ 1 $ 305 $ 306
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	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, futures, Probability of default 0.01% - 2.94% 0.24% forwards, physical contracts Discount rate 0.01% - 30.62% 4.25% and related transportation 10 Modelled pricing Third-party pricing $1.95 - $12.90 $8.68 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 Probability of default 0.08% - 0.29% 0.15% physical contracts Discount rate 0.03% - 2.99% 1.65% Correlation factor 84.98% - 84.98% 84.98% 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) As at December 31, 2017 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – $ 1 Modelled pricing Third-party pricing $24.88 - $117.90 $92.93 Power swaps and Probability of default 0.00% - 0.01% 0.00% physical contracts Discount rate 0.00% - 0.13% 0.00% 8 Modelled pricing Third-party pricing $63.48 - $117.00 $102.68 Correlation factor 0.94% - 0.99% 0.96% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.00% 0.00% HFT derivatives – 18 Modelled pricing Third-party pricing $2.06 - $8.24 $3.61 Natural gas swaps, Probability of default 0.00% - 0.05% 0.00% futures, forwards, Discount rate 0.00% - 0.29% 0.06% physical contracts 7 Modelled pricing Third-party pricing $2.04 - $12.52 $6.42 and related transportation Basis adjustment 0.08% - 0.71% 0.52% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.09% 0.01% Total assets $ 34 Liabilities HFT derivatives – $ (6) Modelled pricing Third-party pricing $24.88 - $117.90 $95.46 Power swaps and Own credit risk 0.00% - 0.01% 0.00% physical contracts Discount rate 0.00% - 0.13% 0.00% 2 Modelled pricing Third-party pricing $94.5 - $117.00 $105.52 Correlation factor 0.94% - 0.99% 0.96% Probability of default 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.00% 0.00% HFT derivatives – 172 Modelled pricing Third-party pricing $1.89 - $11.81 $4.64 Natural gas swaps, futures, Own credit risk 0.00% - 0.00% 0.00% forwards and physical contracts Discount rate 0.00% - 0.12% 0.02% 15 Modelled pricing Third-party pricing $2.15 - $12.52 $8.94 Basis adjustment 0.08% - 0.71% 0.53% Own credit risk 0.00% - 0.00% 0.00% Discount rate 0.00% - 0.08% 0.01% Total liabilities $ 183 Net assets (liabilities) $ (149)
Fair Value, Estimate Not Practicable [Table Text Block]	The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2018 $ 15,411 $ 15,908 $ - $ 14,991 $ 917 $ 15,908 December 31, 2017 $ 13,881 $ 15,217 $ 69 $ 14,346 $ 802 $ 15,217

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule Of Regulatory Assets and Liabilities [Table Text Block]	As at December 31 December 31 millions of Canadian dollars 2018 2017 Regulatory assets Deferred income tax regulatory assets $ 775 $ 667 Pension and post-retirement medical plan (1) 453 380 Cost recovery clauses 75 17 Environmental remediations 31 41 Hurricane Matthew restoration 28 28 Stranded cost recovery 28 25 Unamortized defeasance costs 26 32 Demand side management ("DSM") deferral 24 28 Deferrals related to derivative instruments 10 15 Storm reserve 4 59 Other 115 119 $ 1,569 $ 1,411 Current $ 165 $ 138 Long-term 1,404 1,273 Total regulatory assets $ 1,569 $ 1,411 Regulatory liabilities Deferred income tax regulatory liabilities 1,218 1,116 Accumulated reserve - cost of remova l 955 894 Regulated fuel adjustment mechanism 161 177 Deferrals related to derivative instruments 116 182 Storm reserve 76 - Cost recovery clauses 30 51 Self-insurance fund (note 31) 30 28 Other 24 20 $ 2,610 $ 2,468 Current $ 251 $ 226 Long-term 2,359 2,242 Total regulatory liabilities $ 2,610 $ 2,468 (1) The December 31, 2017 pension and post-retirement medical plan regulatory asset includes a prior period reclassification of $35 million from AOCI, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to note 10 for further details.

Receivables and Other Current_2

Receivables and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract]
Receivables and other current assets [ Table Text Block]	16. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Customer accounts receivable – billed $ 844 $ 805 Customer accounts receivable – unbilled 296 278 Allowance for doubtful accounts (11) (12) Other receivables 86 70 Capitalized transportation capacity (1) 179 89 Income tax receivable 175 24 Prepaid expenses 42 59 Net investment in direct financing lease (note 20 ) 9 8 Due from related parties (note 15 ) - 5 $ 1,620 $ 1,326 (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, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	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 2018 2017 Generation (1) 3 to 131 $ 11,092 $ 11,010 Transmission 11 to 80 3,047 2,786 Distribution 4 to 80 6,348 5,660 Gas transmission and distribution 7 to 85 3,398 2,867 General plant and other 2 to 60 2,158 1,874 Total cost 26,043 24,197 Less: Accumulated depreciation (1) (8,567) (7,824) 17,476 16,373 Construction work in progress 1,236 622 Net book value $ 18,712 $ 16,995 (1) On November 26, 2018, the Company announced an agreement to sell the NEGG facilities and as of December 31, 2018, the Company has classified these assets as held for sale. As of December 31, 2017, these assets were recorded within Property, Plant and Equipment on the Consolidated Balance Sheets. Refer to note 17 for additional information.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Employee Benefit Plans [Abstract]
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]	For the Year ended December 31 millions of Canadian dollars 2018 2017 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 $ 2,683 $ 356 $ 2,607 $ 358 Service cost 51 6 49 5 Plan participant contributions 8 5 8 4 Interest cost 95 13 99 14 Benefits paid (143) (33) (129) (27) Actuarial (gains) losses (133) (25) 171 25 Settlements and curtailments (18) - (35) - Foreign currency translation adjustment 107 28 (87) (23) Balance, December 31 2,650 350 2,683 356 Change in plan assets Balance, January 1 2,408 45 2,208 39 Employer contributions 51 31 109 27 Plan participant contributions 8 5 8 4 Benefits paid (143) (33) (129) (27) Actual return on assets, net of expenses (105) (3) 313 5 Settlements and curtailments (18) - (34) - Foreign currency translation adjustment 99 4 (67) (3) Balance, December 31 2,300 49 2,408 45 Funded status, end of year $ (350) $ (301) $ (275) $ (311)
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]	millions of Canadian dollars 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,623 $ 318 $ 2,655 $ 325 Fair value of plan assets 2,264 6 2,370 6 Funded status $ (359) $ (312) $ (285) $ (319) millions of Canadian dollars 2018 2017 Defined benefit pension plans Defined benefit pension plans ABO $ 2,504 $ 1,608 Fair value of plan assets 2,264 1,409 Funded status $ (240) $ (199)
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	As at December 31 December 31 millions of Canadian dollars 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (12) $ (19) $ (23) $ (18) Long-term liabilities (347) (294) (264) (295) Other long-term assets 9 11 10 - Amount included in deferred income tax 5 (2) 2 - AOCI, net of tax and regulatory assets 628 60 561 74 Net amount recognized $ 283 $ (244) $ 286 $ (239)
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans (1) Balance, January 1, 2018 $ 315 $ 251 $ (3) Amortized in current period (26) (37) 1 Current year addition to AOCI or regulatory assets 73 32 - Change in foreign exchange rate 27 - - Balance, December 31, 2018 $ 389 $ 246 $ (2) Non-pension benefits plans (1) Balance, January 1, 2018 $ 78 $ (4) $ - Amortized in current period 2 1 - Current year addition to AOCI or regulatory assets (17) (4) - Change in foreign exchange rate 2 - - Balance, December 31, 2018 $ 65 $ (7) $ - (1) The January 1, 2018 balances include a prior period reclassification from AOCI to Regulatory assets, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to notes 10 and 14 for further details. 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 246 $ (7) $ 251 $ (4) Past service (gains) costs (2) - (3) - Regulatory assets 389 65 315 78 Total AOCI and regulatory assets before deferred income taxes 633 58 563 74 Amount included in deferred income tax assets (5) 2 (2) - Net amount in AOCI and regulatory assets $ 628 $ 60 $ 561 $ 74
Schedule of Net Benefit Costs [Table Text Block]	As at Year ended December 31 millions of Canadian dollars 2018 2017 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 51 $ 6 $ 49 $ 5 Interest cost 95 13 99 14 Expected return on plan assets (138) (2) (129) (3) Current year amortization of: Actuarial losses 33 (1) 38 2 Past service costs (gains) (1) - - (8) Regulatory assets (liability) 26 (2) 17 (1) Settlement, curtailments 4 - (1) - Total $ 70 $ 14 $ 73 $ 9
Schedule of Allocation of Plan Assets [Table Text Block]	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 48% to 53% Equities 47% to 52%
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	millions of Canadian dollars NAV Level 1 Level 2 Total Percentage 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 % December 31, 2017 Cash and cash equivalents $ - $ 32 $ - $ 32 1 % Net in-transits - (36) - (36) -1 % Equity securities: Canadian equity - 214 - 214 9 % US equity - 390 - 390 16 % Other equity - 197 - 197 8 % Fixed Income securities: Government - - 72 72 3 % Corporate - - 56 56 2 % Other - 5 - 5 - Mutual funds - 246 - 246 10 % Other - - 4 4 - Open-ended investments measured at NAV (1) 819 - - 819 34 % Common collective trusts measured at NAV (2) 409 - - 409 18 % Total $ 1,228 $ 1,048 $ 132 $ 2,408 100 % (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.
Schedule of Expected Benefit Payments [Table Text Block]	millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2019 $ 53 $ 22 Expected benefit payments 2019 149 24 2020 152 25 2021 162 25 2022 169 25 2023 175 26 2024 – 2028 988 127
Schedule of Assumptions Used [Table Text Block]	Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2018 2017 (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 4.05 % 4.30 % 3.55 % 3.65 % Rate of compensation increase 3.30 % 3.67 % 3.12 % 3.28 % Health care trend - initial (next year) - 6.39 % - 6.65 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2036 Benefit cost for year ended December 31: Discount rate 3.55 % 3.65 % 3.96 % 4.18 % Expected long-term return on plan assets 6.38 % 3.73 % 6.29 % 6.08 % Rate of compensation increase 3.12 % 3.28 % 2.82 % 2.54 % Health care trend - initial (current year) - 6.65 % - 6.78 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2036 - 2035 Figures shown are weighted averages. Actual assumptions used differ by plan.
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 17 (15) millions of Canadian dollars Increase Decrease Discount rate assumption $ (9) $ 9 Asset rate assumption (6) 6
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	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 2019: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (15) $ (1) Past service gains 1 6 Regulatory assets (16) 2 Total $ (30) $ 7

Net Investment in Direct Fina_2

Net Investment in Direct Financing Lease (Tables)	12 Months Ended
	Dec. 31, 2018
Net Investment in Direct Financing Lease [Abstract]
Schedule of Components of Leveraged Lease Investments [Table Text Block]	As at December 31 December 31 millions of Canadian dollars 2018 2017 Total minimum lease payments to be received $ 1,066 $ 1,126 Less: amounts representing estimated executory costs (201) (211) Minimum lease payments receivable $ 865 $ 915 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (564) (609) Net investment in direct financing lease $ 484 $ 489 Principal due within one year (included in Receivables and other current assets) 9 8 Net investment in direct financing lease – long-term $ 475 $ 481
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future minimum lease payments to be received for the next five years: For the Year ended December 31 millions of Canadian dollars 2019 2020 2021 2022 2023 Minimum lease payments to be received $ 65 $ 65 $ 65 $ 65 $ 64 Less: amounts representing estimated executory costs (12) (12) (12) (12) (12) Minimum lease payments receivable $ 53 $ 53 $ 53 $ 53 $ 52

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill [Abstract]
Schedule of Goodwill [Table Text Block]	21. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2018 2017 Balance, January 1 $ 5,805 $ 6,213 Change in foreign exchange rate 508 (408) Balance, December 31 $ 6,313 $ 5,805

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Short-term Debt [Abstract]
Schedule of Short-term Debt [Table Text Block]	millions of Canadian dollars 2018 Weighted average interest rate 2017 Weighted average interest rate TECO Finance Advances on revolving credit and term facilities $ 805 3.43 % $ 820 2.58 % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 302 3.10 % 382 2.07 % NMGC Advances on revolving credit facilities 79 3.40 % 38 2.47 % NSPI Bank indebtedness - - % 1 - % Short-Term debt $ 1,186 $ 1,241 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 2018 2017 TECO Energy/TECO Finance - term credit facility 2019 $ 682 $ 502 TECO Energy/TECO Finance - revolving credit facility 2022 546 376 Tampa Electric Company - revolving credit facility 2022 443 408 Tampa Electric Company - accounts receivable revolving credit facility 2021 205 188 Tampa Electric Company - term loan 2018 - 377 NMGC - revolving credit facility 2022 171 157 GBPC - revolving credit facility 2019 18 16 Total 2,065 2,024 Less: Advances under revolving credit and term facilities 1,186 1,241 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,189 1,244 Available capacity under existing agreements $ 876 $ 780

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Other Current Liabilities [Abstract]
Other Current Liabilities [Table Text Block]	Other current liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Accrued charges $ 154 $ 134 Accrued interest on long-term debt 93 78 Pension and post-retirement liabilities (note 19 ) 31 41 Sales and other taxes payable 9 11 Emission credits obligations (1) 8 21 Income tax payable 6 1 Other 127 64 $ 428 $ 350 (1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory ( note 11 ) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Long-term Debt [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Weighted average interest rate (1) millions of Canadian dollars 2018 2017 Maturity 2018 2017 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 339 $ 133 Unsecured fixed rate notes 3.50% 3.50% 2019-2023 725 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,637 1,505 $ 2,701 $ 2,363 Emera US Finance LP Unsecured senior notes (USD) 3.60% 3.60% 2019 - 2046 $ 4,434 $ 4,077 TECO Finance (2) Variable rate notes (USD) Variable 2018 $ - $ 314 Fixed rate notes and bonds (USD) 5.15% 5.15% 2020 409 376 $ 409 $ 690 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.64% 4.75% 2021 - 2049 $ 3,126 $ 2,410 PGS Fixed rate notes and bonds (USD) 4.66% 5.06% 2021 - 2049 $ 425 $ 328 NMGC Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2026 $ 368 $ 339 NMGI Fixed rate notes and bonds (USD) 3.41% 3.41% 2019 - 2024 $ 273 $ 251 NSPI Discount notes Variable Variable 2023 $ 516 $ 364 Medium term fixed rate notes 5.73% 5.73% 2025 - 2097 1,965 1,965 Fixed rate debenture 9.75% 9.75% 2019 95 95 $ 2,576 $ 2,424 Emera Maine LIBOR loans and demand loans Variable Variable 2023 $ 28 $ 51 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 68 63 Unsecured senior fixed rate notes (USD) 4.23% 4.15% 2022 -2048 382 294 $ 478 $ 408 EBP Senior secured credit facility 3.08% 3.08% 2022 $ 248 $ 248 GBPC Amortizing fixed rate notes (USD) 3.83% 3.77% 2021-2022 $ 114 $ 78 Senior notes (USD) 7.07% 7.07% 2020-2023 68 88 $ 182 $ 166 ICDU Fixed rate note (USD) 4.00% - 2023 $ 24 $ - BLPC & ECI Secured senior notes (USD) Variable Variable 2021 159 168 Secured fixed rate senior notes (4) 4.74% 5.06% 2020 - 2035 $ 99 $ 76 $ 258 $ 244 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 22 $ 31 Debt issuance costs (113) (98) Amount due within one year (1,119) (741) $ (1,210) $ (808) Long-Term Debt $ 14,292 $ 13,140 (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. 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 2018 2017 Emera – revolving credit facility (1) June 2020 $ 900 $ 900 NSPI - revolving credit facility (1) October 2023 600 600 Emera Maine – revolving credit facility February 2023 109 100 BLPC – revolving credit facility 2021 - 2022 26 24 Total 1,635 1,624 Less: Borrowings under credit facilities 899 598 Letters of credit issued inside credit facilities 77 44 Use of available facilities 976 642 Available capacity under existing agreements $ 659 $ 982 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million.
Schedule of Debt Conversions [Table Text Block]	As at Financial Covenant Requirement December 31, 2018 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.60 : 1
Schedule of Maturities of Long-term Debt [Table Text Block]	millions of Canadian dollars 2019 2020 2021 2022 2023 Thereafter Total Emera $ 225 $ 339 $ - $ - $ 500 $ 1,637 $ 2,701 Emera US Finance LP 682 - 1,023 - - 2,729 4,434 TECO Finance - 409 - - - - 409 Tampa Electric - - 315 307 - 2,504 3,126 PGS - - 64 34 - 327 425 NMGC - - 273 - - 95 368 NMGI 69 - - - - 204 273 NSPI 95 - - - 516 1,965 2,576 Emera Maine - 41 - 123 28 286 478 EBP - - - 248 - - 248 GBPC 17 50 37 33 45 - 182 ICDU - - - - 24 - 24 BLPC & ECI 31 59 30 13 25 100 258 Total $ 1,119 $ 898 $ 1,742 $ 758 $ 1,138 $ 9,847 $ 15,502

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2018 2017 Balance, January 1 $ 172 $ 170 Additions (1) 25 2 Liabilities settled (2) (3) Accretion included in depreciation expense 6 6 Other (1) 1 Change in foreign exchange rate 5 (4) Balance, December 31 $ 205 $ 172 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2018 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. Tampa Electric submitted a petition to the FPSC in December 2018 for recovery of costs associated with the ongoing project and the petition is currently under review.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies [Abstract]
Other Commitments [Table Text Block]	millions of Canadian dollars 2019 2020 2021 2022 2023 Thereafter Total Purchased power (1) $ 204 $ 203 $ 209 $ 208 $ 209 $ 2,194 $ 3,227 Transportation (2) (3) 569 347 255 215 170 1,492 3,048 Fuel and gas supply 642 237 49 7 3 - 938 Capital projects (4) 524 147 45 11 3 8 738 Long-term service agreements (5) (6) 110 67 42 30 33 246 528 Equity investment commitments (7) - 190 - - - - 190 Leases and other (8) 18 15 10 9 7 75 134 Demand side management 44 1 - - - - 45 $ 2,111 $ 1,207 $ 610 $ 480 $ 425 $ 4,015 $ 8,848 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (3) Includes $82 million related to NEGG transportation capacity ($5 million in 2019; $5 million in 2020; $5 million in 2021; $4 million in 2022; $4 million in 2023 and $59 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information. (4) Includes $439 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 $248 million related to various long-term service agreements NEGG has entered into for maintenance of certain generating equipment ($46 million in 2019; $9 million in 2020; $24 million in 2021; $16 million in 2022; $16 million in 2023 and $137 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information. (7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. (8) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

Cumulative Preferred Stock (Tab

Cumulative Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2018
Cumulative Preferred Stock [Abstract]
Schedule of Stock by Class [Table Text Block]	Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2018 December 31, 2017 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 $ 26.00 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 - $ - Total 41,000,000 $ 1,004 29,000,000 $ 709 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 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 (6) 4.500 1.1250 26.00 (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, 2018, 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) First Preferred Shares, Series E are redeemable at $26.00 to August 15, 2019, 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, 2018
Non-Controlling Interest in Subsidiaries [Abstract]
Noncontrolling Interest [Table Text Block]	28. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2018 2017 Domlec $ 22 $ 21 Preferred shares of GBPC 19 19 ICDU (1) - 52 $ 41 $ 92 (1) On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD. This acquisition increases Emera’s indirect ownership interest to 100 per cent.
Schedule of Sale of Stock by Subsidiary or Equity Method Investee Disclosure [Table Text Block]	Preferred shares of GBPC: Authorized: 20,000 non-voting cumulative redeemable variable perpetual preferred shares. 2018 2017 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 20,000 $ 19 20,000 $ 19

Supplemental Information to C_2

Supplemental Information to Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	For the Year ended December 31 millions of Canadian dollars 2018 2017 Changes in non-cash working capital: Inventory $ (44) $ 31 Receivables and other current assets (144) (154) Accounts payable 59 3 Other current liabilities 13 16 Total non-cash working capital $ (116) $ (104) Supplemental disclosure of cash paid: Interest $ 653 $ 689 Income taxes $ 33 $ 63 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 181 $ 166 Change in accrued capital expenditures $ (50) $ 13 Issuance of depository receipts $ 22 $ -

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Stock-Based Compensation [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value [Table Text Block]	2018 2017 Weighted average fair value per option $ 1.70 $ 2.37 Expected term (1) 6 years 5 years Risk-free interest rate (2) 2.13 % 1.22 % Expected dividend yield (3) 5.69 % 4.60 % Expected volatility (4) 13.71 % 14.41 % (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.
Schedule of Stock Options Roll Forward [Table Text Block]	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, 2017 3,643,575 $ 39.42 1,739,650 $ 2.52 Granted 627,600 39.93 627,600 1.70 Exercised (23,800) 24.98 N/A N/A Vested N/A N/A (666,125) 2.51 Forfeited (11,700) 45.10 (11,700) 2.54 Expired (10,100) 39.93 (10,100) 1.70 Options outstanding December 31, 2018 4,225,575 $ 39.56 1,679,325 $ 2.22 Options exercisable December 31, 2018 (2)(3) 2,546,250 $ 37.15 (1) As at December 31, 2018, there was $5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.2 years (2017 - $3 million, 2.5 years). (2) As at December 31, 2018, the weighted average remaining term of vested options was 5.1 years with an aggregate intrinsic value of $18 million (2017 - 5.4 years, $22 million). (3) As at December 31, 2018, the fair value of options that vested in the year was $2 million (2017 - $2 million).
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block]	Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2017 751,600 $ 28.44 472,485 $ 35.33 Granted including DRIP 90,549 38.72 101,676 43.93 Exercised (5,040) 30.15 (10,640) 25.31 Outstanding and exercisable as at December 31, 2018 837,109 $ 29.54 563,521 $ 37.07 Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2017 829,998 $ 43.41 $ 41.1 Granted including DRIP 486,181 47.84 Exercised (176,805) 38.85 Forfeited (12,260) 44.88 Outstanding as at December 31, 2018 1,127,114 $ 46.02 $ 56.9

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2018
Variable Interest Entities [Abstract]
Schedule of Variable Interest Entities [Table Text Block]	As at December 31, 2018 December 31, 2017 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) $ 545 $ 51 $ 510 $ 67

Supplemental Financial Inform_2

Supplemental Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Income Statement [Table Text Block]	Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars 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 For the year ended December 31, 2017 Operating revenues $ - $ - $ 4,274 $ 2,009 $ (57) $ 6,226 Operating expenses 41 - 3,241 1,583 (57) 4,808 Income (loss) from equity investments and subsidiaries 337 - 1 122 (336) 124 Other income (expenses), net 38 - 15 (46) (32) (25) Interest expense, net (1) 84 (40) 451 203 - 698 Income (loss) before provision for income taxes 250 40 598 299 (368) 819 Income tax expense (recovery) (44) 17 511 36 - 520 Net income (loss) 294 23 87 263 (368) 299 Non-controlling interest in subsidiaries - - - 1 4 5 Preferred stock dividends 28 - 29 13 (42) 28 Net income (loss) attributable to common shareholders $ 266 $ 23 $ 58 $ 249 $ (330) $ 266 Comprehensive income (loss) of Emera Incorporated $ (6) $ 3 $ (291) $ 265 $ 23 $ (6) (1) Interest expense is net of interest revenue.
Condensed Balance Sheet [Table Text Block]	Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars 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 As at December 31, 2017 Assets Current assets $ 358 $ 30 1,420 $ 891 $ (173) $ 2,526 Property, plant and equipment 17 - 12,258 4,720 - 16,995 Other assets Regulatory assets - - 587 686 - 1,273 Goodwill - - 5,709 96 - 5,805 Other long-term assets 9,761 4,285 156 3,094 (15,089) 2,207 Total other assets 9,761 4,285 6,452 3,876 (15,089) 9,285 Total assets $ 10,136 $ 4,315 $ 20,130 $ 9,487 $ (15,262) $ 28,806 Liabilities and Equity Current liabilities $ 129 $ 12 $ 3,293 $ 714 $ (202) $ 3,946 Long-term liabilities Long-term debt 2,861 4,034 8,468 4,262 (6,485) 13,140 Deferred income taxes - 4 447 565 7 1,023 Regulatory liabilities - - 1,888 354 - 2,242 Other long-term liabilities 34 - 691 550 (24) 1,251 Total long-term liabilities 2,895 4,038 11,494 5,731 (6,502) 17,656 Total Emera Incorporated equity 7,112 265 5,343 2,970 (8,578) 7,112 Non-controlling interest in subsidiaries - - - 72 20 92 Total equity 7,112 265 5,343 3,042 (8,558) 7,204 Total liabilities and equity $ 10,136 $ 4,315 $ 20,130 $ 9,487 $ (15,262) $ 28,806
Condensed Cash Flow Statement [Table Text Block]	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, 2018 Net cash provided by (used in) by 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 As at December 31, 2017 Net cash provided by (used in) operating activities $ 195 $ 22 $ 658 $ 1,080 $ (762) $ 1,193 Investing activities Additions to property, plant and equipment (5) - (1,031) (480) (13) (1,529) Net purchase of investments subject to significant influence - - - (213) - (213) Other investing activities (742) (26) (5) 1,852 (1,098) (19) Net cash provided by (used in) investing activities (747) (26) (1,036) 1,159 (1,111) (1,761) Financing activities Change in short-term debt, net - - 365 (13) - 352 Proceeds from long-term debt - - 147 (31) 13 129 Retirement of long-term debt - - (413) (55) 15 (453) Net borrowings (repayments) under committed credit facilities (30) - 59 192 9 230 Issuance of common and preferred stock 682 - 134 (2,032) 1,898 682 Dividends paid (315) - (29) (285) 314 (315) Other financing activities 290 - 96 (42) (376) (32) Net cash provided by (used in) financing activities 627 - 359 (2,266) 1,873 593 Effect of exchange rate changes on cash, cash equivalents and restricted cash 1 (3) 1 (12) - (13) Net increase (decrease) in cash, cash equivalents and restricted cash 76 (7) (18) (39) - 12 Cash, cash equivalents and restricted cash, beginning of year 200 28 72 191 - 491 Cash, cash equivalents and restricted cash, end of year $ 276 $ 21 $ 54 $ 152 $ - $ 503

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Nature of Operations Narrative) (Details) $ in Millions	Dec. 31, 2018CAD ($)MWCustomerskm
Emera Maine [Member] | Maine
Public Utilities, General Disclosures [Line Items]
Number Of Customers	159,000
Nova Scotia Power Inc. [Member] | Nova Scotia [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers	519,000
Emera (Caribbean) Incorporated Parent [Member] | Dominica Electricity Services Ltd. [Member] | BAHAMAS
Public Utilities, General Disclosures [Line Items]
Controlling Interest Ownership Percentage By Parent	51.90%
Number Of Customers	26,000
Emera (Caribbean) Incorporated Parent [Member] | Grand Bahama Power Company Limited [Member]
Public Utilities, General Disclosures [Line Items]
Controlling Interest Ownership Percentage By Parent	100.00%
Number Of Customers	19,000
Emera (Caribbean) Incorporated Parent [Member] | St. Lucia Electricity Services Limited [Member] | SAINT LUCIA
Public Utilities, General Disclosures [Line Items]
Indirect Ownership Percentage By Parent	19.10%
Emera (Caribbean) Incorporated Parent [Member] | The Barbados Light and Power Company Limited [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers	130,000
Emera Inc | Bayside Power Limited Partnership [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	290
Emera Inc | Brooklyn Power Corporation [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	30
Emera Inc | Emera Brunswick Pipeline Company Limited [Member]
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km	145
Emera Inc | Emera Energy Services [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	1,115
Emera Inc | Bear Swamp Power Company LLC [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	600
Emera Inc | Bear Swamp Power Company LLC [Member] | Massachusetts
Public Utilities, General Disclosures [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Emera Newfoundland and Labrador Holdings Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	824
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Maritimes and Northeast Pipline [Member]
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km	1,400
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Maritimes and Northeast Pipline [Member] | Newfoundland and Labrador [Member]
Public Utilities, General Disclosures [Line Items]
Controlling Interest Ownership Percentage By Parent	12.90%
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | NSP Maritime Link Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km	170
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | NSP Maritime Link Inc. [Member] | Newfoundland and Labrador [Member]
Public Utilities, General Disclosures [Line Items]
Equity Method Investment, Ownership Percentage	100.00%
Public Utilities, Property, Plant and Equipment, Transmission and Distribution | $	$ 1,560
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Labrador-Island Link Limited Partnership [Member] | Newfoundland and Labrador [Member]
Public Utilities, General Disclosures [Line Items]
Equity Method Investment, Ownership Percentage	49.50%
Public Utilities, Property, Plant and Equipment, Transmission and Distribution | $	$ 3,700
TECO Energy Inc Parent [Member] | New Mexico Gas Company [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers	530,000
TECO Energy Inc Parent [Member] | Peoples Gas System Division [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers	392,000
TECO Energy Inc Parent [Member] | Tampa Electric Division [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers	764,000

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Cash, Short-term Investments and Receivables) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash and Cash Equivalents [Abstract]
Short-term Investments	$ 43	$ 222
Investment Interest Rate	2.00%	1.40%

Segment Information (Reportable

Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	$ 6,524	$ 6,226
Allowance for Funds Used During Construction, Investing Activities	30	16
Regulated Fuel Adjustment	(46)	59
Depreciation, Depletion and Amortization	916	856
Interest Expense	724	705
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	154	124
Income tax expense (recovery)	69	520
Net income attributable to common shareholders	709.6	266.1
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	2,151	1,522
Assets, Total	32,314	28,806
Goodwill	6,313	5,805	$ 6,213
Investments subject to significant influence	1,316	1,215
All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	6,525	6,226
Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	(1)	0
Intersegment Eliminations [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	(54)	(58)
Allowance for Funds Used During Construction, Investing Activities	0	0
Regulated Fuel Adjustment	0	0
Depreciation, Depletion and Amortization	0	0
Interest Expense	0	0
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	0	0
Income tax expense (recovery)	0	0
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	0	0
Assets, Total	(34)	(86)
Goodwill	0	0
Investments subject to significant influence	0	0
Intersegment Eliminations [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	0	0
Intersegment Eliminations [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	(54)	(58)
Emera Florida And New Mexico Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	3,675	3,623
Allowance for Funds Used During Construction, Investing Activities	21	5
Regulated Fuel Adjustment	0	0
Depreciation, Depletion and Amortization	534	500
Interest Expense	238	248
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	0	0
Income tax expense (recovery)	101	529
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	1,548	910
Assets, Total	20,051	17,216
Goodwill	6,053	5,566
Investments subject to significant influence	0	0
Emera Florida And New Mexico Segment [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	3,675	3,623
Emera Florida And New Mexico Segment [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	0	0
Nova Scotia Power Inc Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	1,440	1,338
Allowance for Funds Used During Construction, Investing Activities	6	8
Regulated Fuel Adjustment	(46)	59
Depreciation, Depletion and Amortization	219	207
Interest Expense	142	134
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	0	0
Income tax expense (recovery)	8	0
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	345	385
Assets, Total	5,143	4,979
Goodwill	0	0
Investments subject to significant influence	0	0
Nova Scotia Power Inc Segment [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	1,437	1,335
Nova Scotia Power Inc Segment [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	3	3
Emera Maine Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	278	297
Allowance for Funds Used During Construction, Investing Activities	3	3
Regulated Fuel Adjustment	0	0
Depreciation, Depletion and Amortization	64	47
Interest Expense	22	20
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	3	1
Income tax expense (recovery)	11	27
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	100	82
Assets, Total	1,721	1,540
Goodwill	156	143
Investments subject to significant influence	35	13
Emera Maine Segment [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	278	297
Emera Maine Segment [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	0	0
Emera Caribbean Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	467	434
Allowance for Funds Used During Construction, Investing Activities	0	0
Regulated Fuel Adjustment	0	0
Depreciation, Depletion and Amortization	50	51
Interest Expense	27	25
Internally Allocated Interest	0	0
Income (Loss) from Equity Method Investments	3	3
Income tax expense (recovery)	(2)	0
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	87	72
Assets, Total	1,373	1,251
Goodwill	104	96
Investments subject to significant influence	42	39
Emera Caribbean Segment [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	467	434
Emera Caribbean Segment [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	0	0
NEGG [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total		465
Allowance for Funds Used During Construction, Investing Activities		0
Regulated Fuel Adjustment		0
Depreciation, Depletion and Amortization		48
Interest Expense		2
Internally Allocated Interest		(24)
Income (Loss) from Equity Method Investments		24
Income tax expense (recovery)		18
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures		47
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	104	127
Allowance for Funds Used During Construction, Investing Activities	0	0
Regulated Fuel Adjustment	0	0
Depreciation, Depletion and Amortization	3	3
Interest Expense	290	276
Internally Allocated Interest	24	24
Income (Loss) from Equity Method Investments	110	96
Income tax expense (recovery)	(115)	(54)
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	38	26
Assets, Total	2,275	2,331
Goodwill	0	0
Investments subject to significant influence	1,239	1,163
Amortization Related to Unregulated Long Term Debt	12	24
Corporate and Other [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	68	86
Corporate and Other [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	36	41
Emera Energy Services [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	614
Allowance for Funds Used During Construction, Investing Activities	0
Regulated Fuel Adjustment	0
Depreciation, Depletion and Amortization	46
Interest Expense	5
Internally Allocated Interest	(24)
Income (Loss) from Equity Method Investments	38
Income tax expense (recovery)	66
Segment Reporting Information, Additional Information [Abstract]
Capital expenditures	33
Assets, Total	1,785	1,575
Goodwill	0	0
Investments subject to significant influence	0	0
Emera Energy Services [Member] | All External Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	600	451
Emera Energy Services [Member] | Internal Customers [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Revenues, Total	$ 14	$ 14

Segment Information (Geographic

Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	$ 6,524	$ 6,226
Noncurrent Assets	18,712	16,995
CA
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	1,520	1,464
Noncurrent Assets	4,128	3,995
UNITED STATES
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	4,537	4,328
Noncurrent Assets	13,739	12,257
BARBADOS
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	319	280
Noncurrent Assets	446	408
BAHAMAS
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	121	119
Noncurrent Assets	315	276
DOMINICA
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues, Total	27	35
Noncurrent Assets	$ 84	$ 59

Revenue (Details)

Revenue (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		$ 1,044	$ 1,002
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		628	$ 503
Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		2,376
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		2,376
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		2,376
Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,510
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,510
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,510
Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		488
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		488
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		488
Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Regulated Operation [Member] | Electricity [Member] | Other [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		371
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		371
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		371
Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		492
Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		291
Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		49
Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		155
Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		57
Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		136
Unregulated Operation Member | Product And Service Other [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		30
Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		115
Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		293
Unregulated Operation Member | Mark-to-market [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		54
Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		18
Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Emera Maine Segment [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Emera Caribbean Segment [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Emera Energy Services [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		614
Corporate and Other [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		47
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		1,384
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		755
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		755
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		755
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		209
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		209
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		209
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax	[1]	10
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax	[1]	10
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax	[1]	10
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		492
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		291
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		49
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		155
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas	[2],[3]	0
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		18
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue	[4]	0
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Florida And New Mexico Segment [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		731
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		405
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		405
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		405
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		233
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		233
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		233
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		28
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		28
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		28
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Nova Scotia Power Inc Segment [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		107
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		80
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		80
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		80
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		16
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		16
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		16
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		66
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		66
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		66
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Maine Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Maine Segment [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Maine Segment [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Maine Segment [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Maine Segment [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Maine Segment [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		154
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		270
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		270
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		270
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		30
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		30
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		30
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		6
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		6
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		6
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Caribbean Segment [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Caribbean Segment [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Caribbean Segment [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Caribbean Segment [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Caribbean Segment [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Caribbean Segment [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Electricity [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Energy Services [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Emera Energy Services [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Emera Energy Services [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		136
Operating Segments Member | Emera Energy Services [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		115
Operating Segments Member | Emera Energy Services [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		309
Operating Segments Member | Emera Energy Services [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		54
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Operating Segments Member | Corporate and Other [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		57
Operating Segments Member | Corporate and Other [Member] | Unregulated Operation Member | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		47
Operating Segments Member | Corporate and Other [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Corporate and Other [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Corporate and Other [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Operating Segments Member | Corporate and Other [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Electricity [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Electricity [Member] | Commercial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Electricity [Member] | Industrial [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		(3)
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		(3)
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		(3)
Intersegment Eliminations [Member] | Regulated Operation [Member] | Electricity [Member] | Other [Member] | Other Electric and Regulatory Deferrals [Member]
Regulated Operating Revenue Electric Non Nuclear Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Unregulated Operating Revenue Abstract
Revenue From Contract With Customer Excluding Assessed Tax		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Oil And Gas Service [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Commercial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Industrial [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Intersegment Eliminations [Member] | Regulated Operation [Member] | Oil And Gas Service [Member] | Other [Member] | Finance Income [Member]
Results Of Operations Revenue From Oil And Gas Producing Activities Abstract
Regulated Operating Revenue, Gas		0
Intersegment Eliminations [Member] | Unregulated Operation Member | Other [Member] | Capacity [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Intersegment Eliminations [Member] | Unregulated Operation Member | Product And Service Other [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		(35)
Intersegment Eliminations [Member] | Unregulated Operation Member | Energy Marketing And Trading Margin [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		0
Intersegment Eliminations [Member] | Unregulated Operation Member | Energy Commodities And Service [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		(16)
Intersegment Eliminations [Member] | Unregulated Operation Member | Mark-to-market [Member] | Other [Member] | Finance Income [Member]
Unregulated Operating Revenue Abstract
Unregulated Operating Revenue		$ 0
[1]	Other includes an immaterial amount of 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.

Revenue Narrative (Details)

Revenue Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Revenue From Contracts With Customers [Abstract]
Revenue Remaining Performance Obligation	$ 370
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Year	2033

Investments Subject to Signif_3

Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		$ 1,316	$ 1,215
Income (Loss) from Equity Method Investments		154	124
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investments		1,316	1,215
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity			13
Other Liabilities, Noncurrent		686	609
Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		40	18
Income (Loss) from Equity Method Investments		4	2
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investments		40	18
Labrador-Island Link Limited Partnership [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		534	492
Income (Loss) from Equity Method Investments		$ 42	37
Equity Method Investment, Ownership Percentage		49.50%
Equity Method Investment, Summarized Financial Information [Abstract]
Indirect Ownership Percentage By Parent		24.90%
Equity Method Investments		$ 534	492
NSP Maritime Link Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		545	510
Income (Loss) from Equity Method Investments		$ 45	36
Equity Method Investment, Ownership Percentage		100.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investments		$ 545	510
Maritimes and Northeast Pipline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		155	156
Income (Loss) from Equity Method Investments		$ 22	23
Equity Method Investment, Ownership Percentage		12.90%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investments		$ 155	156
Saint Lucia Electricity Services Limited [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		42	39
Income (Loss) from Equity Method Investments		$ 3	3
Equity Method Investment, Ownership Percentage		19.10%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investments		$ 42	39
Bear Swamp Power Company Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		0	0
Income (Loss) from Equity Method Investments		$ 38	23
Equity Method Investment, Ownership Percentage		50.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	$ 179
Equity Method Investments		$ 0	0
Other Liabilities, Noncurrent		$ 172	$ 188

Investments Subject to Signif_4

Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets [Abstract]
Assets, Current, Total	$ 2,832	$ 2,526
Property, Plant and Equipment, Net	18,712	16,995
Other Assets, Noncurrent, Total	10,770	9,285
Assets, Total	32,314	28,806
Liabilities, Current, Total	4,553	3,946
Liabilities, Noncurrent, Total	19,403	17,656
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total	8,358	7,204	$ 6,845
Liabilities and Equity, Total	32,314	28,806
NSPML [Member]
Consolidated Balance Sheets [Abstract]
Assets, Current, Total	86	225
Property, Plant and Equipment, Net	1,690	1,720
Other Assets, Noncurrent, Total	140	74
Assets, Total	1,916	2,019
Liabilities, Current, Total	21	180
Long-term Debt	1,288	1,287
Liabilities, Noncurrent, Total	62	42
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total	545	510
Liabilities and Equity, Total	$ 1,916	$ 2,019

Interest Expense, Net (Details)

Interest Expense, Net (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Interest Expense (Income), Net	$ (713)	$ (698)

Income Taxes (Effective Tax Rat

Income Taxes (Effective Tax Rate) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income before provision for income taxes	$ 816	$ 819
Statutory income tax rate	31.00%	31.00%
Income taxes, at statutory income tax rates	$ 253	$ 254
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(59)	(54)
Foreign tax rate variance	(55)	36
Amortization of deferred income tax regulatory liabilities	(37)	0
Florida state tax apportionment adjustment	(23)	0
Tax effect of equity earnings	15	12
Financing deductions	(4)	(17)
Other	9	(4)
Income Tax Expense (Benefit), Total	$ 69	$ 520
Effective Income Tax Rate Reconciliation, Percent	8.00%	63.00%
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 149
Change in US Tax Reform [Abstract]
Tax Cuts and Jobs Act, Change in Tax Rate, Deferred Tax Asset, Income Tax Expense		$ 1,300
Tax Cuts and Jobs Act, Change in Tax Rate, Deferred Tax Liability, Income Tax Benefit		1,800
Tax Cuts and Jobs Act, Accounting Complete [true false]	true
Receivables and other current assets	$ 1,620	1,326
Income Tax Reconciliation Revaluation Of US Non Regulated Deferred Income Taxes	$ 0	$ 317
Statutory income tax rate	31.00%	31.00%
Deferred tax assets	$ 1,886	$ 1,883
Regulated Operation [Member]
Change in US Tax Reform [Abstract]
Tax Cuts and Jobs Act, Decrease in Deferred Tax Liability due to Transition Tax		1,100
Unregulated Operation Member
Change in US Tax Reform [Abstract]
Income Tax Reconciliation Revaluation Of US Non Regulated Deferred Income Taxes		$ 317

Income Taxes (Components) (Deta

Income Taxes (Components) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ 185	$ 469
Income tax expense (recovery)	69	520
Income Tax Reconciliation Revaluation Of US Non Regulated Deferred Income Taxes	0	317
Supplemental Tax Information [Abstract]
Income before provision for income taxes	816	819
Income taxes, at statutory income tax rates	253	254
Canada [Member]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	3	24
Deferred income taxes	11	3
Operating loss carry forwards	(33)	(40)
Supplemental Tax Information [Abstract]
Income before provision for income taxes	127	88
United States [Member]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	(121)	24
Deferred income taxes	211	384
Operating loss carry forwards	0	(194)
Supplemental Tax Information [Abstract]
Income before provision for income taxes	646	693
Other [Member]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	2	3
Deferred income taxes	(3)	(1)
Operating loss carry forwards	(1)	0
Supplemental Tax Information [Abstract]
Income before provision for income taxes	$ 43	$ 38

Income Taxes (Deferred) (Detail

Income Taxes (Deferred) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Components of Deferred Tax Assets [Abstract]
Deferred Tax Assets, Tax Loss Carry Forwards	$ 917	$ 853
Tax credit carry forwards	269	314
Regulatory liabilities - cost of removal	206	208
Deferred Tax Assets, Derivative Instruments	90	107
Pension and post-retirement liabilities	126	112
Deferred Tax Assets, Other	441	394
Deferred Tax Assets, Gross, Total	2,049	1,988
Deferred Tax Assets, Valuation Allowance	(163)	(105)
Deferred Tax Assets, Net of Valuation Allowance, Total	1,886	1,883
Components of Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	(2,591)	(2,321)
Deferred Tax Liabilities, Derivatives	(124)	(155)
Deferred Tax Liabilities, Other	(316)	(292)
Deferred Tax Liabilities, Gross, Total	(3,031)	(2,768)
Noncurrent Deferred Tax Liabilities And Assets [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent	175	138
Deferred Tax Liabilities, Net, Noncurrent	(1,320)	(1,023)
Deferred Tax Assets (Liabilities), Net, Noncurrent, Total	$ (1,145)	$ (885)

Income Taxes (Carry Overs) (Det

Income Taxes (Carry Overs) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Tax Loss Carry Forwards [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards	$ 269	$ 314
Tax Loss Carry Forwards Valuation Allowance [Abstract]
Deferred Tax Assets, Valuation Allowance	163	105
Capital Loss Carryforward [Member] | Canada Revenue Agency [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	86
Unrecognized amounts, Tax credit / capital loss	(77)
Tax credit carryforwards, NOL / capital loss	9
Capital Loss Carryforward [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	6
Unrecognized amounts, Tax credit / capital loss	(6)
Tax credit carryforwards, NOL / capital loss	$ 0
Capital Loss Carryforward [Member] | Minimum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2019
Operating Loss Carryforward [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	$ 34
Unrecognized amounts, Tax credit / capital loss	(34)
Tax credit carryforwards, NOL / capital loss	0
Operating Loss Carryforward [Member] | Canada Revenue Agency [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	817
Unrecognized amounts, Tax credit / capital loss	(405)
Tax credit carryforwards, NOL / capital loss	412
Operating Loss Carryforward [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	2,848
Unrecognized amounts, Tax credit / capital loss	0
Tax credit carryforwards, NOL / capital loss	$ 2,848
Operating Loss Carryforward [Member] | Maximum [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2025
Operating Loss Carryforward [Member] | Maximum [Member] | Canada Revenue Agency [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2038
Operating Loss Carryforward [Member] | Maximum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2037
Operating Loss Carryforward [Member] | Minimum [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2019
Operating Loss Carryforward [Member] | Minimum [Member] | Canada Revenue Agency [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2027
Operating Loss Carryforward [Member] | Minimum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2024
State Operating Loss Carryforward [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	$ 1,314
Unrecognized amounts, Tax credit / capital loss	(47)
Tax credit carryforwards, NOL / capital loss	$ 1,267
State Operating Loss Carryforward [Member] | Maximum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2038
State Operating Loss Carryforward [Member] | Minimum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2024
Tax credit carry forwards [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Gross Tax Carryforwards, Tax credit / capital loss	$ 268
Unrecognized amounts, Tax credit / capital loss	0
Tax credit carryforwards, NOL / capital loss	$ 268
Tax credit carry forwards [Member] | Minimum [Member] | US Tax authority [Member]
Tax Credit Carryforward [Line Items]
Expiration period, Tax credit / capital loss	2019
Domestic Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Gross tax carry forwards, NOL	$ 33	40
Foreign Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Gross tax carry forwards, NOL	0	194
Other Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Gross tax carry forwards, NOL	$ 1	$ 0

Income Taxes (Unrecognized Bene

Income Taxes (Unrecognized Benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 19	$ 18
Increases due to tax positions related to current year	0	1
Increases due to tax positions related to a prior year	8	0
Decreases due to tax positions related to a prior year	(1)	0
Balance, December 31	$ 26	$ 19

Income Taxes (Reasonable Probab

Income Taxes (Reasonable Probablity of Tax Benefit) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Accrued interest	$ 1	$ 4
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change	822	$ 1,400
Settlement with Taxing Authority [Member] | 2006 through 2010 years [Member] | Nova Scotia Power Inc. [Member] | Canada Revenue Agency [Member]
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) In Common Stock Shares [Roll Forward]
Balance, January 1	228,770,000	210,020,000
Conversion of Convertible Debentures	10,000	150,000
Issuance of common stock	450,000	14,610,000
Issued for cash under Purchase Plans at market rate	4,870,000	3,890,000
Discount on shares purchased under Dividend Reinvestment Plan	0	0
Exercised	(20,000)	(100,000)
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	0	0
Balance, December 31	234,120,000	228,770,000
Increase (Decrease) In Common Stock Value [Roll Forward]
Common Stock, Value, Issued, Beginning Balance	$ 5,601	$ 4,738
Conversion of Convertible Debentures	0	6
Issuance of common shares	22	680
Issued for cash under Purchase Plans at market rate	200	182
Discount on shares purchased under Dividend Reinvestment Plan Value	(9)	(9)
Options exercised under senior management share option plan	1	3
Stock-based compensation	1	1
Common Stock, Value, Issued, Ending Balance	$ 5,816	$ 5,601
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Percentage of Outstanding Stock Maximum	10.00%
Employee Stock Option [Member]
Increase (Decrease) In Common Stock Shares [Roll Forward]
Exercised	(23,800)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	1,000,000	1,300,000
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	6,500,000	6,500,000
Dividend Reinvestment [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	12,600,000	4,200,000

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) pure in Millions	Dec. 31, 2018
Emera Inc | Convertible Subordinated Debt [Member]
Debt Instrument [Line Items]
Number of depository receipt instruments issued	1.8

Earnings Per Share (Reconciliat

Earnings Per Share (Reconciliation of Basic and Diluted Earnings Per Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share Reconciliation [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 709.6	$ 266.1
Net Income (Loss) Available to Common Stockholders, Diluted, Total	$ 709.6	$ 266.1
Weighted Average Number of Shares Outstanding Reconciliation [Abstract]
Weighted Average Number of Shares Issued, Basic	231.7	212.3
Weighted Average Number of Shares deferred share units outstanding	1.3	1.1
Weighted Average Number of Shares Outstanding, Basic, Total	233	213.4
Incremental Weighted Average Shares Attributable to Dilutive Effect [Abstract]
IncrementalCommonSharesAttributableToShareBasedPaymentArrangements	0.4	0.6
IncrementalCommonSharesAttributableToConversionOfDebtSecurities	0.1	0.1
Weighted Average Number of Shares Outstanding, Diluted, Total	233.5	214.1
Basic	$ 3.05	$ 1.25
Diluted	$ 3.04	$ 1.24

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	$ (165)	$ 135
Other comprehensive income (loss) before reclassifications	504	(347)
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	(1)	47
Net current period other comprehensive income (loss)	503	(300)
Ending Balance	338	(165)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(3)	(21)
Other comprehensive income (loss) before reclassifications	2	10
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	(6)	8
Net current period other comprehensive income (loss)	(4)	18
Ending Balance	(7)	(3)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(243)	(283)
Other comprehensive income (loss) before reclassifications	0	0
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	9	40
Net current period other comprehensive income (loss)	9	40
Ending Balance	(234)	(243)
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	48	(49)
Other comprehensive income (loss) before reclassifications	(122)	97
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	0	0
Net current period other comprehensive income (loss)	(122)	97
Ending Balance	(74)	48
Accumulated Net Available For Sale Securities Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	3	(1)
Other comprehensive income (loss) before reclassifications	0	5
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	(4)	(1)
Net current period other comprehensive income (loss)	(4)	4
Ending Balance	(1)	3
Accumulated Foreign Currency Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	30	489
Other comprehensive income (loss) before reclassifications	624	(459)
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	0	0
Net current period other comprehensive income (loss)	624	(459)
Ending Balance	$ 654	$ 30

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Non-regulated fuel for generation and purchased power	$ 225	$ 209
Income (Loss) from Equity Method Investments	154	124
Operating, maintenance and general	1,564	1,372
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	816	819
Income tax expense (recovery)	69	520
Net income	747	299
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	(1)	47
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(6)	7
Income tax expense (recovery)	0	1
Net income	(6)	8
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Power and Gas Swaps [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Non-regulated fuel for generation and purchased power	(1)	(3)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Foreign Exchange Forward [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Regulated	(5)	10
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	7	36
Income tax expense (recovery)	2	4
Net income	9	40
Reclassification out of Accumulated Other Comprehensive Income [Member] | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating, maintenance and general	25	33
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating, maintenance and general	(1)	(8)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Transition Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Pension and Other Postretirement Benefit Expense	(17)	11
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Available For Sale Securities Gain Loss Including Portion Attributable To Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income (Expense)	0	(1)
Net income	$ (4)	$ (1)

Inventory (Details)

Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Inventory [Abstract]
Fuel	$ 213	$ 180
Raw Materials	241	216
Emission Credits	20	22
Inventory, Net, Total	$ 474	$ 418

Derivatives (Derivative Assets

Derivatives (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 293	$ 434
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(126)	(181)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	491	491
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	(126)	(181)
Current Derivative Assets or Liabilities [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Total	148	141
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Total	260	227
Long term derivative assets or liabilities [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Total	19	112
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Total	105	83
Cash Flow Hedging [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	7
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	5	7
Cash Flow Hedging [Member] | Power swaps [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	5
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	2
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	2
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	5	5
Regulatory Deferral Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	105	195
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	7	28
Regulatory Deferral Hedge [Member] | Power swaps [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	2	5
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	1	3
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	29	32
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	4
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases.
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	71	137
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	1	10
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	2	6
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	4	7
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	1	15
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	1	4
Held for Trading Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	187	230
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	479	456
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	62	125
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	76	162
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	125	105
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	403	294
Other Derivatives Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	1	2
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	1	2
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(1)	(14)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	(1)	(14)
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(125)	(167)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ (125)	$ (167)

Derivatives (Master Netting Agr

Derivatives (Master Netting Agreements) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 126	$ 181
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	126	181
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	1	14
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	1	14
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	125	167
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ 125	$ 167

Derivatives (Derivative Cash Fl

Derivatives (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, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 4
Cash Flow Hedging [Member] | Power swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1	$ 3
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion	(1)	0
Cash Flow Hedging [Member] | Power swaps [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1	3
Cash Flow Hedging [Member] | Power swaps [Member] | Regulated [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion	0	0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Regulated [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	5	(10)
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion	(6)	(3)
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Regulated [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	5	(10)
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2019 [Member}
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount			$ 30
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2020 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount			30
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2021 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount			$ 0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (1)	$ 2

Derivatives (Changes in Realize

Derivatives (Changes in Realized and Unrealized Gains (Losses) with Respect to Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (55)	$ 157
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(70)	28
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Regulatory Assets [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	(34)	(33)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Regulatory Liabilities [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	29	83
Derivative, Gain (Loss) on Derivative, Net	(8)	(2)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Inventory [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(55)	(17)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(2)	(3)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Assets [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	0	(1)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Liabilities [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	0	1
Derivative, Gain (Loss) on Derivative, Net	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Inventory [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1	(78)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Regulatory Assets [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	4	(4)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Regulatory Liabilities [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	24	(30)
Derivative, Gain (Loss) on Derivative, Net	0	0
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Inventory [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(18)	(30)
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (9)	$ (14)

Derivatives (Notional Volumes o

Derivatives (Notional Volumes of Commodity Swaps and Forward Contracts Designated for Regulatory Deferral) (Details) - Designated as Hedging Instrument [Member] - Regulatory Deferral Hedge [Member] - Commodity swaps and forwards [Member] bbl in Millions, T in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2018MMBTUTbbl
Coal [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | T	1
Coal [Member] | 2020-2023 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | T	1
Natural Gas [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	16
Natural Gas [Member] | 2020-2023 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
CrudeOilMember | 2019 [Member}
Derivative [Line Items]
DerivativeNonmonetaryNotionalAmountVolume | bbl	0
CrudeOilMember | 2020-2023 [Member}
Derivative [Line Items]
DerivativeNonmonetaryNotionalAmountVolume | bbl	1

Derivatives (Notional Volumes_2

Derivatives (Notional Volumes of Foreign Exchange Swaps and Forward Contracts Related to Commodity Contracts) (Details) - Foreign Exchange Swaps and Forward Contracts [Member] - Fuel [Member] $ in Millions	Dec. 31, 2018USD ($)
2020-2023 [Member}
Derivative [Line Items]
Derivative, Notional Amount	$ 111
Derivative, Average Forward Exchange Rate	1.3027
Derivative, Percent of USD Required to Purchase	48.00%
Regulatory Deferral Hedge [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Notional Amount	$ 121
Derivative, Average Forward Exchange Rate	1.1621
Derivative, Percent of USD Required to Purchase	66.00%

Derivatives (Realized and Unrea

Derivatives (Realized and Unrealized Gains (Losses) with Respect to HFT Derivatives) (Details) - Designated as Hedging Instrument [Member] - Held for Trading Hedge [Member] - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net	$ 195	$ 420
Power swaps and physical contracts [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net	2	2
Power swaps and physical contracts [Member] | Other Operating Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net	(12)	7
Natural gas swaps, futures, forwards, physical contracts [Member] | Non-regulated fuel for generation and purchased power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net	0	10
Natural gas swaps, futures, forwards, physical contracts [Member] | Other Operating Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net	$ 205	$ 401

Derivatives (Notional Volumes_3

Derivatives (Notional Volumes of Outstanding HFT Derivatives) (Details) MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBTUMWh
Foreign Exchange Option [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Notional Amount | $	$ 0
Foreign Exchange Option [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	0
Foreign Exchange Option [Member] | 2021 [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	0
Foreign Exchange Option [Member] | 2022 [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	0
Foreign Exchange Option [Member] | 2023 [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	$ 0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	247
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	42
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2021 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	9
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2022 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	2
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2023 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	308
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	108
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2021 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	71
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2022 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	50
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2023 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	41
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	5
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2021 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2022 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2023 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2019 [Member}
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	6
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2021 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2022 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2023 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	0

Derivatives (Realized and Unr_2

Derivatives (Realized and Unrealized Gains (Losses) with Respect to Cash Flow Hedges) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (55)	$ 157
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | Line of Credit [Member] | Brunswick Pipeline [Member] | TECO Energy Inc [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Convertible Subordinated Debt	250
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(1)	2
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (1)	$ 2
Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Option [Member] | Interest Expense [Member] | Line of Credit [Member] | Brunswick Pipeline [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Line of Credit Facility, Expiration Date	Mar. 31, 2019

Derivatives (Credit Risk Exposu

Derivatives (Credit Risk Exposure) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Credit Derivatives [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 1,382	$ 1,394
Total cash deposits/collateral on hand	103	119
Accounts Receivable [Member]
Credit Derivatives [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 1,215	$ 1,141

Derivatives (Concentration Risk

Derivatives (Concentration Risk) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Concentration Risk	$ 1,382	$ 1,394
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	88.00%	81.00%
Concentration Risk	$ 1,215	$ 1,141
Accounts Receivable [Member] | A- Rating [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	4.00%	4.00%
Concentration Risk	$ 49	$ 55
Accounts Receivable [Member] | BBB- to BBB+ Rating [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%	4.00%
Concentration Risk	$ 70	$ 61
Accounts Receivable [Member] | Not Rated [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	8.00%	7.00%
Concentration Risk	$ 108	$ 96
Accounts Receivable [Member] | CCC- to CCC+ [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%	0.00%
Concentration Risk	$ 8	$ 0
Accounts Receivable, Residential [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	28.00%	23.00%
Concentration Risk	$ 384	$ 326
Accounts Receivable, Commercial [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%	11.00%
Concentration Risk	$ 182	$ 161
Accounts Receivable, Industrial [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	4.00%	3.00%
Concentration Risk	$ 57	$ 46
Accounts Receivable, Other [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	6.00%	7.00%
Concentration Risk	$ 84	$ 96
Regulated utilities [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	51.00%	44.00%
Concentration Risk	$ 707	$ 629
Trading group [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	15.00%
Concentration Risk	$ 235	$ 212
Other Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%	22.00%
Concentration Risk	$ 273	$ 300
Derivative [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%	19.00%
Concentration Risk	$ 167	$ 253
Derivative [Member] | A- Rating [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	9.00%	15.00%
Concentration Risk	$ 130	$ 207
Derivative [Member] | BBB- to BBB+ Rating [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	1.00%	1.00%
Concentration Risk	$ 9	$ 10
Derivative [Member] | Not Rated [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	2.00%	3.00%
Concentration Risk	$ 28	$ 36
Assets, Total [Member] | Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	100.00%	100.00%

Derivatives (Cash Collateral) (

Derivatives (Cash Collateral) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments [Abstract]
Derivative, Collateral, Obligation to Return Cash	$ 103	$ 119
Derivative, Collateral, Right to Reclaim Cash	77	99
Collateral Already Posted, Aggregate Fair Value	$ 365	$ 310

Fair Values (Fair Value - Deriv

Fair Values (Fair Value - Derivatives) (Details) - Fair Value, Measurements, Recurring [Member] - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		$ 2
Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Designated as Hedging Instrument [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	$ 167	253
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	365	310
Fair Value, Net Asset (Liability), Total	(198)	(57)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		7
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	5	7
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		2
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	5	5
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	104	181
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	6	13
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	29	32
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		4
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases.
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	70	127
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3	6
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1	12
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1	3
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	62	63
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	354	290
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	7	12
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		50
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	21
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	55	51
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	333	240
Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1
Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1
Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	5	14
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	18	65
Fair Value, Net Asset (Liability), Total	(13)	(51)
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	2
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		2
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	9
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	4	8
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases.
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3	5
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	4
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1	3
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	3	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	14	55
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		49
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	14
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	6
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0
Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	141	205
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	41	62
Fair Value, Net Asset (Liability), Total	100	143
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	5	5
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		0
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		2
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	5	5
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	102	172
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	2	5
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	29	32
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		4
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases.
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	70	127
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	5
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	1
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1	8
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	38	29
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	34	52
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	2	3
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		5
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	6
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	36	26
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	28	47
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1
Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	21	34
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	306	183
Fair Value, Net Asset (Liability), Total	(285)	(149)
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases.
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	21	34
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	306	183
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	3	9
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability		(4)
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member]
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	1
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	18	25
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	305	$ 187
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	$ 0

Fair Values (fair value of the

Fair Values (fair value of the Level 3 financial assets) (Details) - Designated as Hedging Instrument [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 34
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(13)
Ending Balance	21
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	25
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(7)
Ending Balance	18
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	9
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(6)
Ending Balance	$ 3

Fair Values (fair value of th_2

Fair Values (fair value of the Level 3 financial Liabilities) (Details) - Designated as Hedging Instrument [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 183
Total realized and unrealized gains (losses) included in non-regulated operating revenues	123
Net transfers out of Level 3	0
Ending Balance	306
Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Oil Financial Derivatives [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Net transfers out of Level 3	0
Ending Balance	0
Oil Financial Derivatives [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	0
Oil Financial Derivatives [Member] | Regulated fuel for generation and purchased power [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Oil Financial Derivatives [Member] | Non-regulated fuel for generation and purchased power [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Net transfers out of Level 3	0
Ending Balance	0
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulated fuel for generation and purchased power [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Non-regulated fuel for generation and purchased power [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	187
Total realized and unrealized gains (losses) included in non-regulated operating revenues	118
Net transfers out of Level 3	0
Ending Balance	305
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(4)
Total realized and unrealized gains (losses) included in non-regulated operating revenues	5
Net transfers out of Level 3	0
Ending Balance	1
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	0
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power	$ 0

Fair Values (Quantitative Infor

Fair Values (Quantitative Information Significant Unobservable Inputs - Assets & Liabilities) (Details) - Designated as Hedging Instrument [Member] - Fair Value, Inputs, Level 3 [Member] - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 306	$ 183
Derivative Assets (Liabilities), at Fair Value, Net, Total	(285)	(149)
Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure	$ 21	34
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 0.07
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	3.43
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	2.67
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	0.07
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	3.43
Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 1.88
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure		$ (6)
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 24.88
Fair Value Inputs, Comparability Adjustments		0.00%
Fair Value Inputs, Entity Credit Risk		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 117.9
Fair Value Inputs, Comparability Adjustments		0.01%
Fair Value Inputs, Entity Credit Risk		0.13%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 95.46
Fair Value Inputs, Comparability Adjustments		0.00%
Fair Value Inputs, Entity Credit Risk		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure		$ 1
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 24.88
Fair Value Inputs, Comparability Adjustments		0.00%
Fair Value Inputs, Probability of Default	0.03%
Fair Value Inputs, Entity Credit Risk		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 117.9
Fair Value Inputs, Comparability Adjustments		0.01%
Fair Value Inputs, Probability of Default	2.19%
Fair Value Inputs, Entity Credit Risk		0.13%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 92.93
Fair Value Inputs, Comparability Adjustments		0.00%
Fair Value Inputs, Entity Credit Risk		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 1
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 20.8
Fair Value Inputs, Correlation factor	0.08%
Fair Value Inputs, Probability of Default	0.03%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 50.29
Fair Value Inputs, Correlation factor	0.29%
Fair Value Inputs, Probability of Default	2.99%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 26.38
Fair Value Inputs, Correlation factor	0.15%
Fair Value Inputs, Probability of Default	1.65%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure	$ 3
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 24.31
Fair Value Inputs, Correlation factor	0.03%
Fair Value Inputs, Probability of Default	0.03%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 50.29
Fair Value Inputs, Correlation factor	0.13%
Fair Value Inputs, Probability of Default	2.19%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 31.43
Fair Value Inputs, Correlation factor	0.13%
Fair Value Inputs, Probability of Default	1.45%
Fair Value Inputs, Discount Rate	84.98%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure		$ 2
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure		$ 8
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 63.48
Fair Value Inputs, Comparability Adjustments		0.94%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 117
Fair Value Inputs, Comparability Adjustments		0.09%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 102.68
Fair Value Inputs, Comparability Adjustments		0.96%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 94.5
Fair Value Inputs, Comparability Adjustments		0.94%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 117
Fair Value Inputs, Comparability Adjustments		0.99%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes		$ 105.52
Fair Value Inputs, Comparability Adjustments		0.96%
Fair Value Inputs, Probability of Default		0.00%
Fair Value Inputs, Discount Rate		0.00%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 286	$ 172
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 1.48	$ 1.89
Fair Value Inputs, Entity Credit Risk	0.01%	0.00%
Fair Value Inputs, Discount Rate	0.01%	0.00%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 12.9	$ 11.81
Fair Value Inputs, Entity Credit Risk	2.94%	0.00%
Fair Value Inputs, Discount Rate	11.96%	0.12%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 5.75	$ 4.64
Fair Value Inputs, Entity Credit Risk	0.09%	0.00%
Fair Value Inputs, Discount Rate	2.35%	0.02%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure	$ 8	$ 18
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 1.8	$ 2.06
Fair Value Inputs, Probability of Default	0.01%	0.00%
Fair Value Inputs, Discount Rate	0.01%	0.00%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 12.21	$ 8.24
Fair Value Inputs, Probability of Default	2.94%	0.05%
Fair Value Inputs, Discount Rate	30.62%	0.29%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 4.75	$ 3.61
Fair Value Inputs, Probability of Default	0.24%	0.00%
Fair Value Inputs, Discount Rate	4.25%	0.06%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 19	$ 15
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 2.15	$ 2.15
Fair Value Inputs, Comparability Adjustments		0.08%
Fair Value Inputs, Entity Credit Risk	0.01%	0.00%
Fair Value Inputs, Discount Rate	0.01%	0.00%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 13.18	$ 12.52
Fair Value Inputs, Comparability Adjustments		0.71%
Fair Value Inputs, Entity Credit Risk	2.76%	0.00%
Fair Value Inputs, Discount Rate	7.61%	0.08%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 7.54	$ 8.94
Fair Value Inputs, Comparability Adjustments		0.53%
Fair Value Inputs, Entity Credit Risk	0.10%	0.00%
Fair Value Inputs, Discount Rate	1.38%	0.01%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets, Fair Value Disclosure	$ 10	$ 7
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 1.95	$ 2.04
Fair Value Inputs, Comparability Adjustments		0.08%
Fair Value Inputs, Probability of Default	0.01%	0.00%
Fair Value Inputs, Discount Rate	0.01%	0.00%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 12.9	$ 12.52
Fair Value Inputs, Comparability Adjustments		0.71%
Fair Value Inputs, Probability of Default	3.20%	0.00%
Fair Value Inputs, Discount Rate	7.61%	0.09%
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Fair Value Inputs, Offered Quotes	$ 8.68	$ 6.42
Fair Value Inputs, Comparability Adjustments		0.52%
Fair Value Inputs, Probability of Default	0.57%	0.00%
Fair Value Inputs, Discount Rate	0.42%	0.01%

Fair Values (Assets and Liabili

Fair Values (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 15,908	$ 15,217
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	15,411	13,881
Long-term Debt, Fair Value	15,908	15,217
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	0	69
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	14,991	14,346
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 917	$ 802

Fair Values (Hybrid Notes) (Det

Fair Values (Hybrid Notes) (Details) - Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - Foreign Currency Gain (Loss) [Member] $ in Billions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)
Hybrid Instruments [Line Items]
Hybrid Instruments at Fair Value, Net			$ 1.2
Other Comprehensive Income (Loss) [Member]
Hybrid Instruments [Line Items]
Unrealized Gain (Loss) on Foreign Currency Derivatives, Net, before Tax		$ 97,000,000
Gain (Loss) on Foreign Currency Cash Flow Hedge Ineffectiveness	$ 0	$ 0

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (ROE of Tampa Electric) (Details) - Tampa Electric Division [Member]	12 Months Ended
	Dec. 31, 2018
Florida Public Service Commission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Equity Capital Structure, Percentage	54.00%
Minimum [Member] | Florida Public Service Commission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage	9.25%
Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.25%
Maximum [Member] | Florida Public Service Commission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage	11.25%

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities (ROE of People Gas System Division) (Details) $ in Millions, $ in Millions	Sep. 12, 2018USD ($)	Jan. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2012USD ($)km	Dec. 31, 2017CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Assets			$ 1,569				$ 1,411
Regulatory Assets, Current			165				138
Environmental remediations [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets			$ 31				$ 41
Peoples Gas System Division [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage			10.75%
Length Of Pipeline, percentage						5.00%
Length Of Pipeline | km						800
Amortization of Regulatory Asset	$ 11
Replacement program						$ 80
Regulatory Asset Amortization Period						10 years
Peoples Gas System Division [Member] | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities Allowed Rate Base		$ 12
Increase (decrease) depreciation rates		$ (10)
Peoples Gas System Division [Member] | Environmental remediations [Member]
Public Utilities, General Disclosures [Line Items]
Reduction in annual depreciation				$ 16
Regulatory Assets					$ 32
Regulatory Assets, Current					21
Depreciation				$ 5	$ 16
Peoples Gas System Division [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage			11.75%
Public Utilities, Approved Equity Capital Structure, Percentage			54.70%
Peoples Gas System Division [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage			9.25%

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities (ROE of New Mexico Gas Company) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	$ 2,610		$ 2,468
New Mexico Gas Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.00%
Public Utilities, Approved Equity Capital Structure, Percentage	52.00%
Regulatory Liabilities		$ 8

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities (ROE of NSPI) (Details) - CAD ($) $ in Millions	Nov. 29, 2016	Jul. 19, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes					$ 53
Regulatory Liabilities					2,610	$ 2,468
Regulatory Assets					$ 1,569	$ 1,411
Public Utilities Act of Nova Scotia [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Settlement Amount				$ 111
Nova Scotia Power Inc. [Member] | Fuel Adjustment Mechanism Asset [Member]
Public Utilities, General Disclosures [Line Items]
Regulated common equity component					40.00%
Nova Scotia Power Inc. [Member] | Rate Stability Plan fuel costs for 2017 through 2019 [Member] | Fuel Adjustment Mechanism Asset [Member]
Public Utilities, General Disclosures [Line Items]
Approved average annual increase	1.50%	1.10%
Nova Scotia Power Inc. [Member] | Public Utilities Act of Nova Scotia [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Settlement Amount, Minimum Contribution Amount				10	$ 10
Nova Scotia Power Inc. [Member] | Minimum [Member] | Fuel Adjustment Mechanism Asset [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage					8.75%
Nova Scotia Power Inc. [Member] | Maximum [Member] | Fuel Adjustment Mechanism Asset [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage					9.25%
NSP Maritime Link Inc. [Member] | Nova Scotia Power Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Settlement Amount, Actual Contribution Amount					$ 17
NSP Maritime Link Inc. [Member] | Scenario, Forecast [Member] | Nova Scotia Power Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Settlement Amount, Actual Contribution Amount			$ 53	$ 36
NSP Maritime Link Inc. [Member] | Public Utilities Act of Nova Scotia [Member] | Nova Scotia Power Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities refunds payable to customers					2
Public Utilities, Settlement Amount					$ 96

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities (Emera Maine) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018CAD ($)Customerskm	Dec. 31, 2018USD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)Customerskm	Sep. 01, 2017Customers
Public Utilities, General Disclosures [Line Items]
Regulatory Assets		$ 1,569		$ 1,411
Income tax expense (recovery)		$ (69)		$ (520)
Bangor Hydro District [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Electric Transmission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage				10.57%
Bangor Hydro District [Member] | Minimum [Member] | Federal Energy Regulatory Commission (FERC) [Member] | ISO-New England (ISO-NE) [Member] | Electric Transmission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage				11.07%
Bangor Hydro District [Member] | Maximum [Member] | Federal Energy Regulatory Commission (FERC) [Member] | ISO-New England (ISO-NE) [Member] | Electric Transmission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage				11.74%
Maine Public Service District [Member] | Maine Public Utilities Commission (MPUC) [Member] | Electric Distribution [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		5.30%	5.30%
Public Utilities, Approved Return on Equity, Percentage		9.35%	9.35%	9.00%
Public Utilities, Approved Equity Capital Structure, Percentage		49.00%	49.00%	49.00%
Maine Public Service District [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Electric Transmission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage		9.60%	9.60%	9.60%
Barbados Light & Power Company Limited [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage		10.00%	10.00%	10.00%
Income tax expense (recovery)			$ 9.6
Deferred Tax Liabilities, Regulatory Assets					$ 6.9
Dominica Electricity Services Ltd. [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage		15.00%	15.00%	15.00%
Number of Customers | Customers		26,000			26,000	36,000
Grand Bahama Power Company Limited [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage		8.50%	8.50%	8.80%
Grand Bahama Power Company Limited [Member] | Scenario, Forecast [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage	8.44%
Brunswick Pipeline [Member]
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km		145			145

Regulatory Assets and Liabili_8

Regulatory Assets and Liabilities (Unamortized Defeance Costs and Standard Cost Recovery) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Nova Scotia Power Inc. [Member] | Defeased Debt [Member]
Public Utilities, General Disclosures [Line Items]
Long-term Debt		$ 759	$ 726
Grand Bahama Power Company Limited [Member] | Steam Plant [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment	$ 21

Regulatory Assets and Liabili_9

Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 165	$ 138
Regulatory Assets, Noncurrent	1,404	1,273
Regulatory Assets, Total	1,569	1,411
Deferred income tax regulatory assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	775	667
Pension and post-retirement medical plan [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	453	380	[1]
Pension and post-retirement medical plan [Member] | Prior period reclassification [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total		35
Cost Recovery Clauses [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	75	17
Environmental remediations [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	31	41
GBPC Hurricane Matthew restoration [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	28	28
Stranded cost recovery [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	28	25
Unamortized Defeasance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	26	32
Demand Side Management [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	24	28
Demand Side Management [Member] | Nova Scotia Utility and Review Board [Member] | NSPI [Member]
Regulatory Assets [Line Items]
DSM deferral					$ 35
Demand Side Management [Member] | EfficiencyOne [Member] | NSPI [Member]
Regulatory Assets [Line Items]
DSM deferral				$ 31
Deferrals related to derivative instruments [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	10	15
Storm Reserve [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	4	59
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Total	$ 115	$ 119
[1]	The December 31, 2017 pension and post-retirement medical plan regulatory asset includes a prior period reclassification of $35 million from AOCI, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to note 10 for further details.

Regulatory Assets and Liabil_10

Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 251	$ 226
Regulatory Liability, Noncurrent	2,359	2,242
Regulatory Liabilities, Total	2,610	2,468
Deferred income tax regulatory assets [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	1,218	1,116
Accumulated reserve - cost of removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	955	894
Deferrals related to derivative instruments [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	116	182
Fuel Adjustment Mechanism Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	161	177
Cost Recovery Clauses Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	30	51
Self Insurance Fund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	30	28
Storm Reserve [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	76	0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	$ 24	$ 20

Regulatory Assets and Liabil_11

Regulatory Assets and Liabilities (FAM Roll Forward) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fuel Adjustment Mechanism [Roll Forward]
Regulatory Assets, Current	$ 165	$ 138
Regulatory Liability, Current	251	226
Regulatory Liability, Noncurrent	$ 2,359	$ 2,242

Regulatory Assets and Liabil_12

Regulatory Assets and Liabilities (Other) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory Assets	$ 1,569	$ 1,411

Regulatory Assets and Liabil_13

Regulatory Assets and Liabilities (Storm reserve & Solar investment) (Details) $ in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)MW	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Sep. 30, 2017USD ($)MW	Sep. 10, 2017USD ($)
Regulatory Assets [Line Items]
Regulatory Assets			$ 1,569	$ 1,411
Regulatory Liabilities			$ 2,610	$ 2,468
Tampa Electric Division [Member] | Hurricane Irma Restoration [Member] | Loss From Catastrophes [Member]
Regulatory Assets [Line Items]
Storm Reserve						$ 102
Tampa Electric Division [Member] | Hurricane Irma Restoration [Member] | OM&G [Member] | Other Regulatory Assets (Liabilities) [Member] | Loss From Catastrophes [Member]
Regulatory Assets [Line Items]
Storm cost	$ 19	$ 103
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 103
Tampa Electric Division [Member] | SoBRA [Member]
Regulatory Assets [Line Items]
Estimated revenue in MW | MW		260
Estimated revenue		$ 46
Tampa Electric Division [Member] | SoBRA [Member] | Capital Expenditures [Member]
Regulatory Assets [Line Items]
Estimated Investement in projects					$ 850
Capacity Of Utility Project | MW					600
Estimated revenue in MW | MW		145
Estimated revenue		$ 24

Related Paty Transactions (Tran

Related Paty Transactions (Transactions Between Emera and Associated Parties) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NSP Maritime Link Inc. [Member] | Regulated fuel for generation and purchased power [Member] | Regulated [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ 97
Maritimes and Northeast Pipline [Member] | Natural gas transportation capacity [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 29	$ 28

Receivables And Other Current_3

Receivables And Other Current Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract]
Customer accounts receivable - billed	$ 844	$ 805
Customer accounts receivable - unbilled	296	278
Allowance for Doubtful Accounts Receivable, Current	179	89
Other receivables	86	70
Capitalized transportation capacity	42	59
Prepaid expenses	175	24
Due From Related Parties	9	8
Net investment in direct financing lease	0	5
Income Taxes Receivable, Current	0	0
Other	(11)	(12)
Receivables and other current assets	$ 1,620	$ 1,326

Held For Sale (Details)

Held For Sale (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017CAD ($)
Long Lived Assets Held-for-sale [Line Items]
Property, Plant and Equipment, Net		$ 18,712		$ 16,995
New England Gas Generating Facilities [Member] | Emera Energy Services [Member]
Long Lived Assets Held-for-sale [Line Items]
Proceeds From Sale Of Property Plant And Equipment	$ 590
Property, Plant and Equipment, Net		$ 777	$ 570

Property, plant and equipment

Property, plant and equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 26,043	$ 24,197
Less: Accumulated depreciation	(8,567)	(7,824)
Property, Plant and Equipment, Net	18,712	16,995
Net Book Value	17,476	16,373
Electric Generation Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 11,092	11,010
Electric Generation Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Electric Generation Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	131 years
Electric Transmission [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 3,047	2,786
Electric Transmission [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	11 years
Electric Transmission [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	80 years
Electric Distribution [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 6,348	5,660
Electric Distribution [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	4 years
Electric Distribution [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	80 years
Gas, Transmission and Distribution Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 3,398	2,867
Gas, Transmission and Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Gas, Transmission and Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	85 years
Other Energy Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 2,158	1,874
Other Energy Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	2 years
Other Energy Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	60 years
Construction in Progress [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Total cost	$ 1,236	$ 622

Employee Benefit Plans (Changes

Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and the Funded Status) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance	$ 2,408,000,000
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance	2,300,000,000	$ 2,408,000,000
Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	2,683,000,000	2,607,000,000
Defined Benefit Plan, Service Cost	51,000,000	49,000,000
Defined Benefit Plan, Contributions by Plan Participants	8,000,000	8,000,000
Defined Benefit Plan, Interest Cost	95,000,000	99,000,000
Benefits Paid	(143,000,000)	(129,000,000)
Defined Benefit Plan, Actuarial Gain (Loss)	(133,000,000)	171,000,000
Special Termination	(18,000,000)	(35,000,000)
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss)	107,000,000	(87,000,000)
Defined Benefit Plan, Benefit Obligation, Ending Balance	2,650,000,000	2,683,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance	2,408,000,000	2,208,000,000
Defined Benefit Plan, Contributions by Employer	51,000,000	109,000,000
Defined Benefit Plan, Contributions by Plan Participants	8,000,000	8,000,000
Benefits Paid	(143,000,000)	(129,000,000)
Defined Benefit Plan, Actual Return on Plan Assets	(105,000,000)	313,000,000
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets	99,000,000	(67,000,000)
Special Termination	(18,000,000)	(34,000,000)
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance	2,300,000,000	2,408,000,000
Defined Benefit Plan, Funded Status of Plan [Abstract]
Defined Benefit Plan, Funded Status of Plan	(350,000,000)	(275,000,000)
Non-pension Benefit Plans [Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	356,000,000	358,000,000
Defined Benefit Plan, Service Cost	6,000,000	5,000,000
Defined Benefit Plan, Contributions by Plan Participants	5,000,000	4,000,000
Defined Benefit Plan, Interest Cost	13,000,000	14,000,000
Benefits Paid	(33,000,000)	(27,000,000)
Defined Benefit Plan, Actuarial Gain (Loss)	(25,000,000)	25,000,000
Special Termination	0	0
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss)	28,000,000	(23,000,000)
Defined Benefit Plan, Benefit Obligation, Ending Balance	350,000,000	356,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance	45,000,000	39,000,000
Defined Benefit Plan, Contributions by Employer	31,000,000	27,000,000
Defined Benefit Plan, Contributions by Plan Participants	5,000,000	4,000,000
Benefits Paid	(33,000,000)	(27,000,000)
Defined Benefit Plan, Actual Return on Plan Assets	(3,000,000)	5,000,000
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets	4,000,000	(3,000,000)
Special Termination	0	0
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance	49,000,000	45,000,000
Defined Benefit Plan, Funded Status of Plan [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (301,000,000)	$ (311,000,000)

Employee Benefit Plans (Plans w

Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Aggregate Projected Benefit Obligation	$ 2,623	$ 2,655
Aggregate Fair Value of Plan Assets	2,264	2,370
Funded Status	(359)	(285)
Non-pension Benefit Plans [Member
Defined Benefit Plan Disclosure [Line Items]
Aggregate Projected Benefit Obligation	318	325
Aggregate Fair Value of Plan Assets	6	6
Funded Status	$ (312)	$ (319)

Employee Benefit Plans (Accumul

Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - Pension Plan [Member] - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 2,527	$ 2,561
ABO	1,608	2,504
Fair Value of Plan Assets	1,409	2,264
Funded Status	$ (199)	$ (240)

Employee Benefit Plans (Amounts

Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets ) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Current Liabilities	$ (31)	$ (41)
Liabilities, Noncurrent	(641)	(559)
Pension Plan [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Current Liabilities	(12)	(23)
Liabilities, Noncurrent	(347)	(264)
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	9	10
Deferred Tax Assets, Defined Benefit Plan	(5)	(2)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	628	561
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total	283	286
Non-pension Benefit Plans [Member
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Current Liabilities	(19)	(18)
Liabilities, Noncurrent	(294)	(295)
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	11	0
Deferred Tax Assets, Defined Benefit Plan	2	0
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	60	74
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total	$ (244)	$ (239)

Employee Benefit Plans (Change

Employee Benefit Plans (Change in AOCI ) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	$ 563
Balance, December 31	633
Pension Plan [Member] | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	251
Amortized in current period, Net Actuarial Gain (Loss)	(37)
Current year addition to AOCI	32
Change in foreign exchange rate	0
Balance, December 31	246
Pension Plan [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	(3)
Amortized in current period, Net Actuarial Gain (Loss)	1
Current year addition to AOCI	0
Change in foreign exchange rate	0
Balance, December 31	(2)
Pension Plan [Member] | Regulatory Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	315
Amortized in current period, Net Actuarial Gain (Loss)	(26)
Current year addition to AOCI	73
Change in foreign exchange rate	27
Balance, December 31	389
Non-pension Benefit Plans [Member
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	74
Balance, December 31	58
Non-pension Benefit Plans [Member | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	(4)
Amortized in current period, Net Actuarial Gain (Loss)	1
Current year addition to AOCI	(4)
Change in foreign exchange rate	0
Balance, December 31	(7)
Non-pension Benefit Plans [Member | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	0
Amortized in current period, Net Actuarial Gain (Loss)	0
Current year addition to AOCI	0
Change in foreign exchange rate	0
Balance, December 31	0
Non-pension Benefit Plans [Member | Regulatory Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, January 1	78
Amortized in current period, Net Actuarial Gain (Loss)	2
Current year addition to AOCI	(17)
Change in foreign exchange rate	2
Balance, December 31	$ 65

Employee Benefit Plans (AOCI )

Employee Benefit Plans (AOCI ) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	$ (246)	$ (251)
Past service (gains)	(2)	(3)
Regulatory Assets	389	315
Accumulated Other Comprehensive Income (Loss), before Tax, Total	633	563
Deferred Tax Assets, Defined Benefit Plan	(5)	(2)
Net amount in AOCI after tax adjustment	628	561
Non-pension Benefit Plans [Member
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	7	4
Past service (gains)	0	0
Regulatory Assets	65	78
Accumulated Other Comprehensive Income (Loss), before Tax, Total	58	74
Deferred Tax Assets, Defined Benefit Plan	2	0
Net amount in AOCI after tax adjustment	$ 60	$ 74

Employee Benefit Plans (Benefit

Employee Benefit Plans (Benefit Cost Components) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	$ 51,000,000	$ 49,000,000
Defined Benefit Plan, Interest Cost	95,000,000	99,000,000
Defined Benefit Plan, Expected Return on Plan Assets	138,000,000	129,000,000
Defined Benefit Plan, Amortization of Gains (Losses)	(33,000,000)	(38,000,000)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(1,000,000)	0
Current year amortization of regulatory asset liabilities	26,000,000	17,000,000
Settlement, curtailment	4,000,000	(1,000,000)
Net Periodic Benefit Cost, Total	70,000,000	73,000,000
Non-pension Benefit Plans [Member
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	6,000,000	5,000,000
Defined Benefit Plan, Interest Cost	13,000,000	14,000,000
Defined Benefit Plan, Expected Return on Plan Assets	2,000,000	3,000,000
Defined Benefit Plan, Amortization of Gains (Losses)	1,000,000	(2,000,000)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	(8,000,000)
Current year amortization of regulatory asset liabilities	(2,000,000)	(1,000,000)
Settlement, curtailment	0	0
Net Periodic Benefit Cost, Total	$ 14,000,000	$ 9,000,000

Employee Benefit Plans (Asset C

Employee Benefit Plans (Asset Class) (Details) - Pension Plan [Member]	Dec. 31, 2018
Short-term securities | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.05%
Short-term securities | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.00%
Fixed Income Funds [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.50%
Fixed Income Funds [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.35%
Fixed Income Funds [Member] | Foreign Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.53%
Fixed Income Funds [Member] | Foreign Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.48%
Equity Securities, Canadian [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.22%
Equity Securities, Canadian [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.12%
Equity Securities, Non Canadian [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.55%
Equity Securities, Non Canadian [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.30%
Equity Securities, Non Canadian [Member] | Foreign Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.52%
Equity Securities, Non Canadian [Member] | Foreign Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	0.47%

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value of Investments) (Details) - CAD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 2,300	$ 2,408
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		796	1,048
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 234	$ 132
Cash and cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		1.00%	1.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 30	$ 32
Cash and cash equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		30	32
Cash and cash equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Net In Transit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		(2.00%)	(1.00%)
Defined Benefit Plan, Fair Value of Plan Assets		$ (56)	$ (36)
Net In Transit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		(56)	(36)
Net In Transit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Net Asset Value Member [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 1,270	$ 1,228
Open Ended Invesments Measured at NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		36.00%	34.00%
Defined Benefit Plan, Fair Value of Plan Assets	[1]	$ 820	$ 819
Open Ended Invesments Measured at NAV [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Open Ended Invesments Measured at NAV [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Collective Trust Measured at NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		19.00%	18.00%
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 450	$ 409
Collective Trust Measured at NAV [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Collective Trust Measured at NAV [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Equity Securities, Canadian [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		8.00%	9.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 191	$ 214
Equity Securities, Canadian [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		191	214
Equity Securities, Canadian [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Equity Securities, United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		14.00%	16.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 330	$ 390
Equity Securities, United States [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		330	390
Equity Securities, United States [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Equity Securities, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		7.00%	8.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 157	$ 197
Equity Securities, Other [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		157	197
Equity Securities, Other [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Government Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		5.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 119	$ 72
Government Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Government Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 119	$ 72
Corporate Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		5.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 108	$ 56
Corporate Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Corporate Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 108	$ 56
Other Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations
Defined Benefit Plan, Fair Value of Plan Assets		$ 7	$ 5
Other Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4	5
Other Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 3	$ 0
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		6.00%	10.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 132	$ 246
Mutual Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		132	246
Mutual Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations		1.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 12	$ 4
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		8	0
Other Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4	4
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		2,300	2,408	$ 2,208
Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 49	$ 45	$ 39
[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.

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2018CAD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in 2017	$ 53
Defined Benefit Plan, Expected Future Benefit Payments 2019 [Member]	149
Defined Benefit Plan, Expected Future Benefit Payments 2020 [Member]	152
Defined Benefit Plan, Expected Future Benefit Payments 2021 [Member]	162
Defined Benefit Plan, Expected Future Benefit Payments 2022 [Member]	169
Defined Benefit Plan, Expected Future Benefit Payments 2023 [Member]	175
Defined Benefit Plan, Expected Future Benefit Payments 2024-2028 [Member]	988
Non-pension Benefit Plans [Member
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in 2017	22
Defined Benefit Plan, Expected Future Benefit Payments 2019 [Member]	24
Defined Benefit Plan, Expected Future Benefit Payments 2020 [Member]	25
Defined Benefit Plan, Expected Future Benefit Payments 2021 [Member]	25
Defined Benefit Plan, Expected Future Benefit Payments 2022 [Member]	25
Defined Benefit Plan, Expected Future Benefit Payments 2023 [Member]	26
Defined Benefit Plan, Expected Future Benefit Payments 2024-2028 [Member]	$ 127

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, 2018	Dec. 31, 2017
Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.05%	3.55%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.30%	3.12%
Defined Benefit Plan, Benefit Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year	0.00%	0.00%
Defined Benefit Plan, Benefit Obligation, Ultimate Health Care Cost Trend Rate	0.00%	0.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.55%	3.96%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.38%	6.29%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.12%	2.82%
Defined Benefit Plan, Net Periodic Benefit Cost, Health Care Cost Trend Rate Assumed for Next Fiscal Year	0.00%	0.00%
Defined Benefit Plan, Net Periodic Benefit Cost, Ultimate Health Care Cost Trend Rate	0.00%	0.00%
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Increase	$ (9)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Decrease	9
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Increase	(6)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Decrease	$ 6
Non-pension Benefit Plans [Member
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.30%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.67%	3.28%
Defined Benefit Plan, Benefit Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year	6.39%	6.65%
Defined Benefit Plan, Benefit Obligation, Ultimate Health Care Cost Trend Rate	4.45%	4.45%
Defined Benefit Plan, Benefit Obligation, Year that Rate Reaches Ultimate Trend Rate	2035	2036
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.65%	4.18%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	3.73%	6.08%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.28%	2.54%
Defined Benefit Plan, Net Periodic Benefit Cost, Health Care Cost Trend Rate Assumed for Next Fiscal Year	6.65%	6.78%
Defined Benefit Plan, Net Periodic Benefit Cost, Ultimate Health Care Cost Trend Rate	4.45%	4.45%
Defined Benefit Plan, Net Periodic Benefit Cost, Year that Rate Reaches Ultimate Trend Rate	2036	2035
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 1
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(1)
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	17
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	$ (15)

Employee Benefit Plans narrativ

Employee Benefit Plans narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,300	$ 2,408
Contribution Amount	31	23
TECO Energy Inc [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,223	2,153
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,300	2,408	$ 2,208
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 49	$ 45	$ 39

Net Investment in Direct Fina_3

Net Investment in Direct Financing Lease (Direct Financing Lease and Future Minimum Capital Lease Payments) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Capital Leases, Net Investment in Direct Financing Leases, Minimum Payments to be Received	$ 1,066	$ 1,126
Capital Leases, Net Investment in Direct Financing Leases, Executory Costs	(201)	(211)
Minimum lease payments receivable	865	915
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property	183	183
Capital Leases, Net Investment in Direct Financing Leases, Deferred Income	(564)	(609)
Capital Leases, Net Investment in Direct Financing Leases, Total	484	489
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Current	9	8
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent	475	$ 481
Capital Leases, Future Minimum Payments Receivable, Fiscal Year Maturity [Abstract]
Capital Leases, Future Minimum Payments, Receivable in 2019	65
Capital Leases, Future Minimum Payments, Receivable in 2020	65
Capital Leases, Future Minimum Payments, Receivable in 2021	65
Capital Leases, Future Minimum Payments, Receivable in 2022	65
Capital Leases, Future Minimum Payments, Receivable in 2023	64
Capital Leases, Future Minimum Payments, estimated executory costs, Fiscal Year Maturity [Abstract]
Capital Leases, Future Minimum Payments, estimated executory costs 2019	(12)
Capital Leases, Future Minimum Payments, estimated executory costs 2020	(12)
Capital Leases, Future Minimum Payments, estimated executory costs 2021	(12)
Capital Leases, Future Minimum Payments, estimated executory costs 2022	(12)
Capital Leases, Future Minimum Payments, estimated executory costs 2023	(12)
Capital Leases, Future Minimum Payments, estimated executory costs 2023
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2019	53
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2020	53
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2021	53
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2022	53
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2023	$ 52

Goodwill (Details)

Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 5,805	$ 6,213
Goodwill, Foreign Currency Translation Gain (Loss)	508	(408)
Goodwill, Ending Balance	$ 6,313	$ 5,805

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, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Short-term Debt	$ 1,186	$ 1,241
Short-term Debt, Weighted Average Interest Rate	3.34%	2.42%
TECO Energy Inc. and TECO Finance Inc. [Member] | Line of Credit [Member]
Short-term Debt [Line Items]
Short-term Debt	$ 805	$ 820
Short-term Debt, Weighted Average Interest Rate	3.43%	2.58%
Tampa Electric Division [Member] | Line of Credit [Member]
Short-term Debt [Line Items]
Short-term Debt	$ 302	$ 382
Short-term Debt, Weighted Average Interest Rate	3.10%	2.07%
New Mexico Gas Company [Member] | Line of Credit [Member]
Short-term Debt [Line Items]
Short-term Debt	$ 79	$ 38
Short-term Debt, Weighted Average Interest Rate	3.40%	2.47%
Nova Scotia Power Inc. [Member] | Notes Payable to Banks [Member]
Short-term Debt [Line Items]
Short-term Debt	$ 0	$ 1
Short-term Debt, Weighted Average Interest Rate	0.00%	0.00%

Short Term Debt (short-term rev

Short Term Debt (short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Short term debt revolving and non revolving credit facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,065	$ 2,024
Credit Facility Advances	1,186	1,241
Letters of Credit Outstanding, Amount	3	3
Total advances under available facilities	1,189	1,244
Available capacity under existing agreements	876	780
TECO Energy Inc. and TECO Finance Inc. [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 546	376
Line of Credit Facility, Expiration Date	Mar. 22, 2022
TECO Energy Inc. and TECO Finance Inc. [Member] | Finance Term Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 682	502
Line of Credit Facility, Expiration Date	Mar. 22, 2019
Tampa Electric Division [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 443	408
Line of Credit Facility, Expiration Date	Mar. 22, 2022
Tampa Electric Division [Member] | Accounts Receivable Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 205	188
Line of Credit Facility, Expiration Date	Dec. 31, 2021
Tampa Electric Division [Member] | Finance Term Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 0	377
Line of Credit Facility, Expiration Date	Dec. 31, 2018
New Mexico Gas Company [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 171	157
Line of Credit Facility, Expiration Date	Mar. 22, 2022
Grand Bahama Power Company Limited [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 18	$ 16
Line of Credit Facility, Expiration Date	Dec. 31, 2019

Short Term Debt (Narrative) (De

Short Term Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Oct. 11, 2018	Mar. 23, 2018	Mar. 07, 2018	Mar. 22, 2017	Mar. 08, 2017
Revolving Credit Facility [Member] | TECO Energy Inc. and TECO Finance Inc. [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 400	$ 300
Line of Credit Facility, Additional Amount Available From Request					100
Accounts Receivable Revolving Credit Facility | Tampa Electric Division [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 150
Line of Credit Facility, Expiration Date	Mar. 22, 2021	Mar. 23, 2018
Finance Term Credit Facility [Member] | Tampa Electric Division [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 300
Finance Term Credit Facility [Member] | TECO Energy Inc. and TECO Finance Inc. [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					500		$ 400
Line of Credit Facility, Expiration Date	Mar. 8, 2019
Line of Credit Facility, Additional Amount Available From Request					$ 100

Other Current Liabilities (Deta

Other Current Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Current Liabilities [Abstract]
Accrued Liabilities, Current	$ 154	$ 134
Accrued interest on long-term debt	93	78
Income taxes payable	6	1
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	31	41
Sales and Excise Tax Payable, Current	9	11
Deferred Emission Credits, Current	8	21
Other Sundry Liabilities, Current	127	64
Other Liabilities, Current, Total	$ 428	$ 350

Long Term Debt (Long-term Debt)

Long Term Debt (Long-term Debt) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Fair Market Value Adjustments to Debt	$ 22	$ 31
Debt issuance costs	(113)	(98)
Amount due within one year	(1,119)	(741)
Long Term Debt, Adjustments	(1,210)	(808)
Long-term Debt and Capital Lease Obligations	14,292	13,140
Emera Inc
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,701	2,363
Emera Inc | Bankers Acceptances, LIBOR Loans [Member]
Debt Instrument [Line Items]
Variable rate	Variable
Long-term Debt, Gross	$ 339	$ 133
Emera Inc | Bankers Acceptances, LIBOR Loans [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2020
Emera Inc | Unsecured fixed rate notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	3.50%	3.50%
Long-term Debt, Gross	$ 725	$ 725
Emera Inc | Unsecured fixed rate notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2019
Emera Inc | Unsecured fixed rate notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2023
Emera Inc | Fixed to floating subordinated notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	6.75%
Long-term Debt, Gross	$ 1,637	$ 1,505
Emera Inc | Fixed to floating subordinated notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2076
Affiliated Entity [Member] | Fixed to floating subordinated notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate		6.75%
Emera US Finance LP [Member] | Unsecured senior notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	3.60%	3.60%
Long-term Debt, Gross	$ 4,434	$ 4,077
Emera US Finance LP [Member] | Unsecured senior notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2019
Emera US Finance LP [Member] | Unsecured senior notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2046
TECO Finance, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 409	690
TECO Finance, Inc. [Member] | Variable rate notes [Member]
Debt Instrument [Line Items]
Variable rate	Variable
Long-term Debt, Gross	$ 0	$ 314
TECO Finance, Inc. [Member] | Variable rate notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2018
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	5.15%	5.15%
Long-term Debt, Gross	$ 409	$ 376
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2020
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.64%	4.75%
Long-term Debt, Gross	$ 3,126	$ 2,410
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2049
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.66%	5.06%
Long-term Debt, Gross	$ 425	$ 328
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2049
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.53%	4.53%
Long-term Debt, Gross	$ 368	$ 339
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2026
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	3.41%	3.41%
Long-term Debt, Gross	$ 273	$ 251
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2019
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2024
Nova Scotia Power Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,576	2,424
Nova Scotia Power Inc. [Member] | Discount notes [Member]
Debt Instrument [Line Items]
Variable rate	Variable
Long-term Debt, Gross	$ 516	$ 364
Nova Scotia Power Inc. [Member] | Discount notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2023
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	5.73%	5.73%
Long-term Debt, Gross	$ 1,965	$ 1,965
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2025
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2097
Nova Scotia Power Inc. [Member] | Fixed rate debenture [Member]
Debt Instrument [Line Items]
Weighted average interest rate	9.75%	9.75%
Long-term Debt, Gross	$ 95	$ 95
Nova Scotia Power Inc. [Member] | Fixed rate debenture [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2019
Emera Maine [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 478	408
Emera Maine [Member] | LIBOR loans and demand loans [Member]
Debt Instrument [Line Items]
Variable rate	Variable
Long-term Debt, Gross	$ 28	$ 51
Emera Maine [Member] | LIBOR loans and demand loans [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2023
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	9.74%	9.74%
Long-term Debt, Gross	$ 68	$ 63
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2020
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2022
Emera Maine [Member] | Unsecured senior fixed rate notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.23%	4.15%
Long-term Debt, Gross	$ 382	$ 294
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2022
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2048
Emera Brunswick Pipeline Company Limited [Member] | Senior secured credit facility [Member]
Debt Instrument [Line Items]
Weighted average interest rate	3.08%	3.08%
Long-term Debt, Gross	$ 248	$ 248
Debt Instrument, Maturity Date	Jan. 1, 2022
Grand Bahama Power Company Limited [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 182	$ 166
Grand Bahama Power Company Limited [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	7.07%	7.07%
Long-term Debt, Gross	$ 68	$ 88
Grand Bahama Power Company Limited [Member] | Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2020
Grand Bahama Power Company Limited [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2023
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	3.83%	3.77%
Long-term Debt, Gross	$ 114	$ 78
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2022
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 258	244
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured senior notes [Member]
Debt Instrument [Line Items]
Variable rate	Variable
Long-term Debt, Gross	$ 159	$ 168
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured senior notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2021
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.74%	5.06%
Long-term Debt, Gross	$ 99	$ 76
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2020
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Dec. 31, 2035
Icd Utilities Limited [Member] | Fixed rate notes and bonds [Member]
Debt Instrument [Line Items]
Weighted average interest rate	4.00%	0.00%
Long-term Debt, Gross	$ 24	$ 0

Long Term Debt (Credit Faciliti

Long Term Debt (Credit Facilities) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,635	$ 1,624
Long-term Line of Credit	899	598
Letters of Credit Outstanding, Amount	77	44
Use Of Available Facilities	976	642
Line of Credit Facility, Remaining Borrowing Capacity	659	982
Emera Inc | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 900	900
Line of Credit Facility, Expiration Date	Jun. 30, 2020
Overdraft limit on lines of credit accounts		$ 50
Nova Scotia Power Inc. [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Oct. 1, 2023	Oct. 1, 2021
Nova Scotia Power Inc. [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 600	$ 600
Line of Credit Facility, Expiration Date	Oct. 31, 2023
Overdraft limit on lines of credit accounts		50
Emera Maine [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 109	100
Line of Credit Facility, Expiration Date	Feb. 28, 2023
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 26	$ 24
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Dec. 31, 2022
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Dec. 31, 2021

Long Term Debt (Debt Covenants)

Long Term Debt (Debt Covenants) (Details) - Syndicated Credit Facilities [Member]	Dec. 31, 2018
Debt Instrument [Line Items]
Debt Instrument Covenant Requirement	0.7
Ratio of Indebtedness to Net Capital	0.6

Long Term Debt (Long Term Matur

Long Term Debt (Long Term Maturities) (Details) $ in Millions	Dec. 31, 2018CAD ($)
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	$ 1,119
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	898
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	1,742
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	758
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	1,138
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	9,847
Total debt maturities including current portion	15,502
Emera Inc
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	225
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	339
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	500
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	1,637
Total debt maturities including current portion	2,701
Emera US Finance LP [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	682
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	1,023
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	2,729
Total debt maturities including current portion	4,434
TECO Finance, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	409
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	0
Total debt maturities including current portion	409
Emera Maine [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	41
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	123
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	28
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	286
Total debt maturities including current portion	478
Nova Scotia Power Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	95
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	516
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	1,965
Total debt maturities including current portion	2,576
EBP [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	248
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	0
Total debt maturities including current portion	248
Grand Bahama Power Company Limited [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	17
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	50
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	37
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	33
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	45
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	0
Total debt maturities including current portion	182
The Barbados Light and Power Company Limited [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	31
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	59
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	30
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	13
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	25
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	100
Total debt maturities including current portion	258
Tampa Electric Division [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	315
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	307
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	2,504
Total debt maturities including current portion	3,126
New Mexico Gas Company [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	273
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	95
Total debt maturities including current portion	368
Peoples Gas System Division [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	64
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	34
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	327
Total debt maturities including current portion	425
New Mexico Gas Incorporate [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	69
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	204
Total debt maturities including current portion	273
Icd Utilities Limited [Member]
Debt Instrument [Line Items]
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022	0
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2023	24
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter	0
Total debt maturities including current portion	$ 24

Long Term Debt (Narrative) (Det

Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Nov. 15, 2018USD ($)	Oct. 04, 2018USD ($)	Jun. 07, 2018USD ($)	May 16, 2018CAD ($)	Feb. 28, 2018USD ($)	Jan. 12, 2018BBD ($)
Debt Instrument [Line Items]
Proceeds from Issuance of Common Stock	$ 10	$ 682
Repayments of Long-term Debt	757	453
Issuance of preferred stock, net of issuance costs	291	0
Emera Inc
Debt Instrument [Line Items]
Long-term Debt, Gross	2,701	$ 2,363
Emera Inc | Debt and Preferred Equity Shelf Prospectus [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 450					$ 750
Debt Instrument, Maturity Date	Jun. 16, 2020
Issuance of preferred stock, net of issuance costs	$ 300
Nova Scotia Power Inc. [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Oct. 1, 2023	Oct. 1, 2021
Long-term Debt, Gross	$ 2,576	$ 2,424
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,965	$ 1,965
Emera Brunswick Pipeline Company Limited [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Feb. 1, 2022	Feb. 1, 2021
Tampa Electric Division [Member] | U.S. Notes, Due 2048 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					4.30%
Debt Instrument, Face Amount					$ 350
Debt Instrument, Maturity Date	Jun. 15, 2048
Tampa Electric Division [Member] | U.S. Notes, Due 2049 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.45%
Debt Instrument, Face Amount				$ 375
Debt Instrument, Maturity Date	Jun. 15, 2049
TECO Finance, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 409	$ 690
TECO Finance, Inc. [Member] | U.S. Notes [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 250
ECI [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								4.00%
Debt Instrument, Maturity Date	Jan. 12, 2023
Long-term Debt, Gross								$ 18
Emera Maine [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 478	$ 408
Emera Maine [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 80
Line of Credit Facility, Expiration Date	Feb. 28, 2023	Sep. 25, 2019
Emera Maine [Member] | U.S. Notes, Due 2048 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.71%
Debt Instrument, Face Amount			$ 50
Debt Instrument, Maturity Date	Nov. 15, 2048
Grand Bahama Power Company Limited [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 182	$ 166

Asset Retirement Obligation (AR

Asset Retirement Obligation (ARO Roll Forward) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance, January 1	$ 172	$ 170
Additions	25	2
Additions due to acquisition	0	0
Liabilities settled	(2)	(3)
Asset Retirement Obligation, Accretion Expense	6	6
Asset Retirement Obligation, Accretion Expense Deferred To Regulatory Asset	0	0
Asset Retirement Obligation, Revision of Estimate	(1)	1
ForeignCurrencyTranslationGainLoss	5	(4)
Balance, December 31	$ 205	$ 172

Commitments and Contingencies_2

Commitments and Contingencies (Contractual Obligations) (Details) $ in Millions	Dec. 31, 2018CAD ($)
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	$ 2,111
Contractual Obligation, Due in Second Year	1,207
Contractual Obligation, Due in Third Year	610
Contractual Obligation, Due in Fourth Year	480
Contractual Obligation, Due in Fifth Year	425
Contractual Obligation, Due after Fifth Year	4,015
Contractual Obligation	8,848
Nova Scotia Power Inc. [Member] | Maritime Link Project [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Second Year	111
Purchased Power [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	204	[1]
Contractual Obligation, Due in Second Year	203	[1]
Contractual Obligation, Due in Third Year	209	[1]
Contractual Obligation, Due in Fourth Year	208	[1]
Contractual Obligation, Due in Fifth Year	209	[1]
Contractual Obligation, Due after Fifth Year	2,194	[1]
Contractual Obligation	3,227	[1]
Fuel And Gas Supply [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	642
Contractual Obligation, Due in Second Year	237
Contractual Obligation, Due in Third Year	49
Contractual Obligation, Due in Fourth Year	7
Contractual Obligation, Due in Fifth Year	3
Contractual Obligation, Due after Fifth Year	0
Contractual Obligation	938
Demand Side Management [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	44
Contractual Obligation, Due in Second Year	1
Contractual Obligation, Due in Third Year	0
Contractual Obligation, Due in Fourth Year	0
Contractual Obligation, Due in Fifth Year	0
Contractual Obligation, Due after Fifth Year	0
Contractual Obligation	45
Transportation [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	569	[2],[3]
Contractual Obligation, Due in Second Year	347	[2],[3]
Contractual Obligation, Due in Third Year	255	[2],[3]
Contractual Obligation, Due in Fourth Year	215	[2],[3]
Contractual Obligation, Due in Fifth Year	170	[2],[3]
Contractual Obligation, Due after Fifth Year	1,492	[2],[3]
Contractual Obligation	3,048	[2],[3]
Transportation [Member] | NEGG [Member] | Independent Transmission and Distribution System [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	5
Contractual Obligation, Due in Second Year	5
Contractual Obligation, Due in Third Year	5
Contractual Obligation, Due in Fourth Year	4
Contractual Obligation, Due in Fifth Year	4
Contractual Obligation, Due after Fifth Year	59
Contractual Obligation	82
Long-term service agreements [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	110	[4],[5]
Contractual Obligation, Due in Second Year	67	[4],[5]
Contractual Obligation, Due in Third Year	42	[4],[5]
Contractual Obligation, Due in Fourth Year	30	[4],[5]
Contractual Obligation, Due in Fifth Year	33	[4],[5]
Contractual Obligation, Due after Fifth Year	246	[4],[5]
Contractual Obligation	528	[4],[5]
Long-term service agreements [Member] | NEGG [Member] | Independent Transmission and Distribution System [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	46
Contractual Obligation, Due in Second Year	9
Contractual Obligation, Due in Third Year	24
Contractual Obligation, Due in Fourth Year	16
Contractual Obligation, Due in Fifth Year	16
Contractual Obligation, Due after Fifth Year	137
Contractual Obligation	248
Capital projects [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	524	[6]
Contractual Obligation, Due in Second Year	147	[6]
Contractual Obligation, Due in Third Year	45	[6]
Contractual Obligation, Due in Fourth Year	11	[6]
Contractual Obligation, Due in Fifth Year	3	[6]
Contractual Obligation, Due after Fifth Year	8	[6]
Contractual Obligation	738	[6]
Capital projects [Member] | Tampa Electric Division [Member] | Independent Transmission and Distribution System [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	439
Equity investment commitments [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	0	[7]
Contractual Obligation, Due in Second Year	190	[7]
Contractual Obligation, Due in Third Year	0	[7]
Contractual Obligation, Due in Fourth Year	0	[7]
Contractual Obligation, Due in Fifth Year	0	[7]
Contractual Obligation, Due after Fifth Year	0	[7]
Contractual Obligation	190	[7]
Leases and other [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Obligation, Due in Next Fiscal Year	18	[8]
Contractual Obligation, Due in Second Year	15	[8]
Contractual Obligation, Due in Third Year	10	[8]
Contractual Obligation, Due in Fourth Year	9	[8]
Contractual Obligation, Due in Fifth Year	7	[8]
Contractual Obligation, Due after Fifth Year	75	[8]
Contractual Obligation	$ 134	[8]
[1]	Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
[2]	Includes $82 million related to NEGG transportation capacity ($5 million in 2019; $5 million in 2020; $5 million in 2021; $4 million in 2022; $4 million in 2023 and $59 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note ##NHFS for additional information.
[3]	Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
[4]	Includes $248 million related to various long-term service agreements NEGG has entered into for maintenance of certain generating equipment ($46 million in 2019; $9 million in 2020; $24 million in 2021; $16 million in 2022; $16 million in 2023 and $137 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note ##NHFS for additional information.
[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 $439 million of commitments related to Tampa Electric's solar and Big Bend Power Station modernization projects.
[7]	Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.
[8]	Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

Commitments and Contingencies_3

Commitments and Contingencies (Legal Proceedings) (Details) - 12 months ended Dec. 31, 2018 $ in Millions, $ in Millions	USD ($)	CAD ($)	USD ($)
Tampa Electric And Peoples Gas Division [Member] | Prime Rate [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss		$ 38	$ 28
Emera Maine [Member] | Prime Rate [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.41%
Emera Maine [Member] | ISO New England OATT [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 4
Emera Maine [Member] | ISO New England OATT [Member] | Prime Rate [Member]
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.57%
Emera Maine [Member] | ISO New England OATT [Member] | Prime Rate [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage	11.74%
TECO Guatemala Holdings [Member] | Prime Rate [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 21

Commitments and Contingencies_4

Commitments and Contingencies (Guarantees and Letters of Credit) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)
Nova Scotia Power Inc. [Member] | Jointly Owned Electricity Generation Plant [Member]
Guarantor Obligations [Line Items]
Utilities Operating Expense, Maintenance and Operations	$ 2	$ 3
Utilities Operating Expense, Purchased Power	19	$ 18
Payment Guarantee [Member] | SeaCoast Gas Transmission LLC [Member]
Guarantor Obligations [Line Items]
Guaranty Liabilities			$ 45
Letters of Credit Outstanding, Amount			27
Pension plan [Member] | Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 49
Reinsurance agreements [Member] | Emera Reinsurance Limited [Member]
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount			6
Surety bonds
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount			$ 67

Collaborative Arrangements (Det

Collaborative Arrangements (Details) - Nova Scotia Power Inc. [Member] - Jointly Owned Electricity Generation Plant [Member] - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Collaborative Arrangements [Line Items]
Utilities Operating Expense, Purchased Power	$ 19	$ 18
Utilities Operating Expense, Maintenance and Operations	$ 2	$ 3

Cumulative Preferred Stock (Det

Cumulative Preferred Stock (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2013
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	41,000,000	29,000,000
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 295
Series A Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 0.6388
Preferred Stock, Redemption Price Per Share	$ 25
Preferred stock, dividend rate, percentage	4.40%
Preferred Stock, Shares Outstanding	3,864,636	3,864,636
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 95	$ 95
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Redemption Price Per Share	$ 25
Preferred stock, dividend rate, percentage	2.393%
Preferred Stock, Shares Outstanding	2,135,364	2,135,364
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 52	$ 52
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 1.1802		$ 1.025
Preferred Stock, Redemption Price Per Share	$ 25
Preferred stock, dividend rate, percentage	4.10%
Preferred Stock, Shares Outstanding	10,000,000	10,000,000
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 245	$ 245
Series E Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 1.125
Preferred Stock, Redemption Price Per Share	$ 26
Preferred stock, dividend rate, percentage	4.50%
Preferred Stock, Shares Outstanding	5,000,000	5,000,000
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 122	$ 122
Series F Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 1.0625
Preferred Stock, Redemption Price Per Share	$ 25
Preferred stock, dividend rate, percentage	4.25%
Preferred Stock, Shares Outstanding	8,000,000	8,000,000
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 195	$ 195
Series H Preferred Stock [Member}
Class of Stock [Line Items]
Preferred Stock, Dividends Per Share, Declared	$ 1.225
Preferred Stock, Redemption Price Per Share	$ 25
Preferred stock, dividend rate, percentage	4.90%
Preferred Stock, Shares Outstanding	12,000,000
Proceeds From Issuance Of Preferred Stock And Preference Stock Net	$ 295	$ 0

Cumulative Preferred Stock (Cha

Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2013
Series A Preferred Stock [Member]
Class of Stock [Line Items]
Initial Yield	4.40%
Annual Dividend Per Share	$ 0.6388
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2020
Preferred Stock, Redemption Price Per Share	$ 25
Right to Convert on a one for one basis	1
Series A Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	1.84%
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Initial Yield	4.10%
Annual Dividend Per Share	$ 1.1802	$ 1.025
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2023
Preferred Stock, Redemption Price Per Share	$ 25
Right to Convert on a one for one basis	1
Series C Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	2.65%
Series F Preferred Stock [Member]
Class of Stock [Line Items]
Initial Yield	4.25%
Annual Dividend Per Share	$ 1.0625
Earliest Redemption and/or Conversion Option Date	Feb. 15, 2020
Preferred Stock, Redemption Price Per Share	$ 25
Right to Convert on a one for one basis	1
Series F Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	2.63%
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Initial Yield	2.393%
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2020
Preferred Stock, Redemption Price Per Share	$ 25
Right to Convert on a one for one basis	1
Series B Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	1.84%
Series H Preferred Stock [Member}
Class of Stock [Line Items]
Initial Yield	4.90%
Annual Dividend Per Share	$ 1.225
Earliest Redemption and/or Conversion Option Date	Aug. 15, 2023
Preferred Stock, Redemption Price Per Share	$ 25
Right to Convert on a one for one basis	1
Series H Preferred Stock [Member} | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	4.90%
Series I Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Initial Yield	2.54%
Perpetual fixed rate Series E Preferred Stock [Member]
Class of Stock [Line Items]
Initial Yield	4.50%
Annual Dividend Per Share	$ 1.125
Preferred Stock, Redemption Price Per Share	$ 26

Cumulative Preferred Stock (Nar

Cumulative Preferred Stock (Narrative) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2013
First Preferred Shares [Member]
Class of Stock [Line Items]
Preferred Stock Dividend Preference Or Restrictions	First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends is deducted on the Consolidated Statements of Income before arriving at “Net 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 [Member]
Class of Stock [Line Items]
Convertible Preferred Stock Terms Of Conversion	Series B
Annual Dividend Per Share	$ 0.6388
Outstanding share redemption price per share	$ 25
Preferred stock, dividend rate, percentage	4.40%
Series A Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	1.84%
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Convertible Preferred Stock Terms Of Conversion	Series D
Annual Dividend Per Share	$ 1.1802	$ 1.025
Outstanding share redemption price per share	$ 25
Preferred stock, dividend rate, percentage	4.10%
Series C Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	2.65%
Series F Preferred Stock [Member]
Class of Stock [Line Items]
Convertible Preferred Stock Terms Of Conversion	Series G
Annual Dividend Per Share	$ 1.0625
Outstanding share redemption price per share	$ 25
Preferred stock, dividend rate, percentage	4.25%
Series F Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	2.63%
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Convertible Preferred Stock Terms Of Conversion	Series A
Outstanding share redemption price per share	$ 25
Preferred stock, dividend rate, percentage	2.393%
Series B Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	1.84%
Series H Preferred Stock [Member}
Class of Stock [Line Items]
Convertible Preferred Stock Terms Of Conversion	Series I
Annual Dividend Per Share	$ 1.225
Outstanding share redemption price per share	$ 25
Preferred stock, dividend rate, percentage	4.90%
Series H Preferred Stock [Member} | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	4.90%
Series I Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock Dividend Payment Rate Variable	Government of Treasury Bill Rate on the applicable reset date
Series I Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	2.54%
Perpetual fixed rate Series E Preferred Stock [Member]
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.125
Outstanding share redemption price per share	26
Preferred Stock, Redemption Price, Annual Decrease	0.25
Preferred Stock, Redemption Price, Annual Decrease, After Year Five	$ 25
Preferred stock, dividend rate, percentage	4.50%

Non-controlling Interest In S_3

Non-controlling Interest In Subsidiaries (Narrative) (Details) - Grand Bahama Power Company Limited [Member] - Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares [Member]	12 Months Ended
	Dec. 31, 2018$ / shares
Noncontrolling Interest [Line Items]
Preferred Stock, Redemption Price Per Share	$ 1,000
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend 2013 to 2016	7.25%
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, 2017 to 2019	8.50%
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, 2020 and Thereafter	10.00%

Non-controlling Interest In S_4

Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries ) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 41	$ 92
Icd Utilities Limited [Member]
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	0	52
Grand Bahama Power Company Limited [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Amount Represented by Preferred Stock	19	19
Dominica Electricity Services Ltd. [Member]
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 22	$ 21

Non-controlling Interest In S_5

Non-controlling Interest In Subsidiaries (Preferred Shares Authorized) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Number of shares issued and outstanding	41,000,000	29,000,000
Grand Bahama Power Company Limited [Member] | Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares [Member]
Noncontrolling Interest [Line Items]
Preferred Stock, Shares Authorized	20,000
Number of shares issued and outstanding	20,000	20,000
Preferred Stock Value Outstanding	$ 19	$ 19

Supplementary Information To Co

Supplementary Information To Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Inventories	$ (44)	$ 31
Increase (Decrease) in Other Current Assets	(144)	(154)
Increase (Decrease) in Accounts Payable	59	3
Increase (Decrease) in Other Current Liabilities	13	16
Increase (Decrease) in Operating Capital, Total	(116)	(104)
Income Taxes Paid, Net	33	63
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Common share dividends reinvested	181	166
Change in accrued capital expenditures	(50)	13
Issuance of depository receipts	$ 22	$ 0

Stock-based Compensation (Narra

Stock-based Compensation (Narrative) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Conversion of Units	10,000	150,000
Employee Common Share Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	4,000,000
Allocated Share-based Compensation Expense		$ 1,000,000
Employee Common Share Purchase Plan [Member] | Scenario 1 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employer Matching Percentage	20.00%
Employee Common Share Purchase Plan [Member] | Scenario 2 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employer Matching Percentage	10.00%
Employee Common Share Purchase Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employee Contribution	$ 25
Employee Common Share Purchase Plan [Member] | Minimum [Member] | Scenario 2 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employee Contribution	3,000
Employee Common Share Purchase Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employee Contribution	8,000
Employee Common Share Purchase Plan [Member] | Maximum [Member] | Scenario 1 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employee Contribution	3,000
Employee Common Share Purchase Plan [Member] | Maximum [Member] | Scenario 2 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Stock Purchase Plan (ESSP), Employee Contribution	$ 8,000
Common Shareholders Dividend Reinvestment and Share Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend Reinvestment Plan Percentage Discount From Average Market Price Of Common Shares	5.00%
Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	11,700,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Contractual Term, Employee Retirement Or Termination For Other Than Just Cause	24 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Contractual Term, Employee Termination For Just Cause Or Resignation Or Death	6 months
Fair Value Assumptions, Historical Volatility Period	5 years
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 1,000,000	2,000,000
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Cash Received	1,000,000	3,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	$ 1,000,000	$ 2,000,000
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit	$ 21.99	$ 21.58
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Upper Range Limit	$ 46.19	$ 46.19
Stock Option Plan [Member] | First Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	25.00%
Deferred Share Unit Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 2,000,000	$ 7,000,000
Stock Issued During Period, Shares, Conversion of Units	1
Number Of Trading Days	10 days
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 1,000,000	2,000,000
Deferred Tax Liabilities, Regulatory Assets and Liabilities	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Outstanding	$ 37,000,000	35,000,000
Deferred Share Unit Plans [Member] | Scenario 1 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Share Unit Plan Percentage Of Value Of Actual Annual Incentive Award	25.00%
Deferred Share Unit Plans [Member] | Scenario 2 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Share Unit Plan Percentage Of Value Of Actual Annual Incentive Award	50.00%
Performance Share Unit Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 14,000,000	14,000,000
Number Of Trading Days	50 days
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 4,000,000	$ 4,000,000
Performance-based Share Unit Plan Performance Cycle Term	3 years

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, 2018	Dec. 31, 2017
Stock-Based Compensation [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 1.7	$ 2.37
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	6 years	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	2.13%	1.22%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	5.69%	4.60%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	13.71%	14.41%

Stock-based Compensatin (Stock

Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Exercised		(20,000)	(100,000)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period		20,000	100,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 1.7	$ 2.37
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options		$ 5	$ 3
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years 2 months 13 days	2 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		5 years 1 month 6 days	5 years 4 months 25 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$ 18	$ 22
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value		$ 2	$ 2
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Beginning Balance		3,643,575
Granted		627,600
Exercised		(23,800)
Forfeited		(11,700)
Expired		(10,100)
Ending Balance		4,225,575	3,643,575
Options exercisable	[1],[2]	2,546,250
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Beginning Balance		$ 39.42
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price		39.93
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price		24.98
ShareBasedCompensationArrangementsByShareBasedPaymentAwardOptionsForfeituresInPeriodWeightedAverageExercisePrice		45.1
ShareBasedCompensationArrangementsByShareBasedPaymentAwardOptionsExpirationsInPeriodWeightedAverageExercisePrice		39.93
Ending Balance		39.56	$ 39.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price		$ 37.15
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross		627,600
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period		23,800
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price		$ 24.98
Employee Non-vested Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Granted		627,600
Vested		(666,125)
Forfeited		(11,700)
Expired		(10,100)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price		$ 1.7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Weighted Average Grant Date Fair Value		2.51
ShareBasedCompensationArrangementsByShareBasedPaymentAwardOptionsForfeituresInPeriodWeightedAverageExercisePrice		2.54
ShareBasedCompensationArrangementsByShareBasedPaymentAwardOptionsExpirationsInPeriodWeightedAverageExercisePrice		$ 1.7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Beginning Balance	[3]	1,739,650
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross		627,600
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares		666,125
Ending Balance		1,679,325	1,739,650	[3]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance		$ 2.52
Sharebased Compensation Arrangement By Sharebased Payment Award Options Nonvested Options Forfeited Weighted Average Grant Date Fair Value		2.54
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Weighted Average Grant Date Fair Value		2.51
Ending Balance		$ 2.22	$ 2.52
[1]	As at December 31, 2018, the fair value of options that vested in the year was $2 million (2017 - $2 million).
[2]	As at December 31, 2018, the weighted average remaining term of vested options was 5.1 years with an aggregate intrinsic value of $18 million (2017 - 5.4 years, $22 million).
[3]	As at December 31, 2018, there was $5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.2 years (2017 - $3 million, 2.5 years).

Stock-based Compensation (Emplo

Stock-based Compensation (Employee and Director DSUs ) (Details) - Deferred Share Unit Plans [Member]	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Beginning Balance | shares	751,600
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares	90,549
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares	(5,040)
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares	0
Ending Balance | shares	837,109
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance | $ / shares	$ 28.44
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	38.72
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares	30.15
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares	0
Ending Balance | $ / shares	$ 29.54
Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Beginning Balance | shares	472,485
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares	101,676
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares	(10,640)
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares	0
Ending Balance | shares	563,521
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance | $ / shares	$ 35.33
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	43.93
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares	25.31
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares	0
Ending Balance | $ / shares	$ 37.07

Stock-based Compensation (Emp_2

Stock-based Compensation (Employee PSUs) (Details) - Performance Share Unit Plan [Member] - Employee [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Beginning Balance | shares	829,998
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares	486,181
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares	176,805
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares	12,260
Ending Balance | shares	1,127,114
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance | $ / shares	$ 43.41
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	47.84
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares	38.85
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares	44.88
Ending Balance | $ / shares	$ 46.02
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract]
Beginning Balance | $	$ 41.1
Ending Balance | $	$ 56.9

Variable Interest Entities (Det

Variable Interest Entities (Details) - Emera Inc - NSP Maritime Link Inc. [Member] - Available-for-sale Investment and Restricted Cash [Member] - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 545	$ 510
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	$ 51	$ 67

SUPPLEMENTAL FINANCIAL INFORM_3

SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statements of Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues [Abstract]
Regulated electric	$ 4,852	$ 4,721
Regulated	1,044	1,002
Non-regulated	628	503
Total operating revenues	6,524	6,226
Operating expenses
Regulated fuel for generation and purchased power	1,677	1,638
Regulated cost of natural gas	388	379
Regulated fuel adjustment	(46)	59
Non-regulated fuel for generation and purchased power	225	209
Non-regulated direct costs	16	28
Operating, maintenance and general	1,564	1,372
Provincial, state, and municipal taxes	340	326
Depreciation and amortization	916	856
Total operating expenses	5,126	4,808
Operating Income (Loss)	1,398	1,418
Income from equity investments	154	124
Other income (expenses), net	23	25
Interest expense, net	713	698
Income before provision for income taxes	816	819
Income tax expense (recovery)	69	520
Net income	747	299
Non-controlling interest in subsidiaries	1	5
Preferred stock dividends	36	28
Net income attributable to common shareholders	709.6	266.1
Comprehensive income attributable to common shareholders	1,249	(6)
Consolidation, Eliminations [Member]
Revenues [Abstract]
Total operating revenues	(54)	(57)
Operating expenses
Total operating expenses	(52)	(57)
Income from equity investments	(800)	(336)
Other income (expenses), net	(38)	(32)
Interest expense, net	0	0
Income before provision for income taxes	(840)	(368)
Income tax expense (recovery)	0	0
Net income	(840)	(368)
Non-controlling interest in subsidiaries	2	4
Preferred stock dividends	(42)	(42)
Net income attributable to common shareholders	(800)	(330)
Comprehensive income attributable to common shareholders	(1,468)	23
Parent Company [Member]
Revenues [Abstract]
Total operating revenues	0	0
Operating expenses
Total operating expenses	45	41
Income from equity investments	801	337
Other income (expenses), net	22	38
Interest expense, net	79	84
Income before provision for income taxes	699	250
Income tax expense (recovery)	(47)	(44)
Net income	746	294
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	36	28
Net income attributable to common shareholders	710	266
Comprehensive income attributable to common shareholders	1,249	(6)
Subsidiary Issuer [Member]
Revenues [Abstract]
Total operating revenues	0	0
Operating expenses
Total operating expenses	0	0
Income from equity investments	0	0
Other income (expenses), net	0	0
Interest expense, net	(40)	(40)
Income before provision for income taxes	40	40
Income tax expense (recovery)	9	17
Net income	31	23
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income attributable to common shareholders	31	23
Comprehensive income attributable to common shareholders	56	3
Guarantor Subsidiaries [Member]
Revenues [Abstract]
Total operating revenues	4,432	4,274
Operating expenses
Total operating expenses	3,468	3,241
Income from equity investments	3	1
Other income (expenses), net	20	15
Interest expense, net	456	451
Income before provision for income taxes	531	598
Income tax expense (recovery)	64	511
Net income	467	87
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	38	29
Net income attributable to common shareholders	429	58
Comprehensive income attributable to common shareholders	973	(291)
Non-Guarantor Subsidiaries [Member]
Revenues [Abstract]
Total operating revenues	2,146	2,009
Operating expenses
Total operating expenses	1,665	1,583
Income from equity investments	150	122
Other income (expenses), net	(27)	(46)
Interest expense, net	218	203
Income before provision for income taxes	386	299
Income tax expense (recovery)	43	36
Net income	343	263
Non-controlling interest in subsidiaries	(1)	1
Preferred stock dividends	4	13
Net income attributable to common shareholders	340	249
Comprehensive income attributable to common shareholders	$ 439	$ 265

SUPPLEMENTAL FINANCIAL INFORM_4

SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statement of Financial Position) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Assets, Current [Abstract]
Cash, Cash Equivalents, and Short-term Investments	$ 316	$ 438	$ 491
Restricted Cash and Cash Equivalents, Current	56	65
Inventory, Net	474	418
Derivative Instruments and Hedges, Assets	148	141
Regulatory Assets, Current	165	138
Receivables and other current assets	1,620	1,326
Total current assets	2,832	2,526
Property, Plant and Equipment, Net	18,712	16,995
Other Assets, Noncurrent [Abstract]
Deferred income taxes	175	138
Derivative instruments	19	112
Regulatory assets	1,404	1,273
Net investment in direct financing lease	475	481
Investments subject to significant influence	1,316	1,215
Goodwill	6,313	5,805	6,213
Other long term assets	291	261
Total other assets	10,770	9,285
Assets, Total	32,314	28,806
Liabilities, Current [Abstract]
Short-term debt	1,186	1,241
Current portion of long-term debt	1,119	741
Accounts payable	1,289	1,161
Derivative instruments	260	227
Regulatory liabilities	251	226
Other current liabilities	428	350
Total current liabilities	4,553	3,946
Liabilities, Noncurrent [Abstract]
Long-term debt	14,292	13,140
Deferred income taxes	1,320	1,023
Derivative instruments	105	83
Regulatory liabilities	2,359	2,242
Other long-term liabilities	686	609
Total long-term liabilities	19,403	17,656
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Value, Issued	5,816	5,601	4,738
Preferred Stock, Value, Issued	1,004	709
Contributed surplus	84	76
Accumulated other comprehensive Income	338	(165)
Retained earnings	1,075	891
Total Emera Incorporated equity	8,317	7,112
Non-controlling interest in subsidiaries	41	92
Total equity	8,358	7,204	$ 6,845
Liabilities and Equity, Total	32,314	28,806
Consolidation, Eliminations [Member]
Assets, Current [Abstract]
Total current assets	(244)	(173)
Property, Plant and Equipment, Net	(3)	0
Other Assets, Noncurrent [Abstract]
Regulatory assets	0	0
Goodwill	0	0
Other long term assets	(17,235)	(15,089)
Total other assets	(17,235)	(15,089)
Assets, Total	(17,482)	(15,262)
Liabilities, Current [Abstract]
Total current liabilities	(265)	(202)
Liabilities, Noncurrent [Abstract]
Long-term debt	(6,994)	(6,485)
Deferred income taxes	6	7
Regulatory liabilities	0	0
Other long-term liabilities	(21)	(24)
Total long-term liabilities	(7,009)	(6,502)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Total Emera Incorporated equity	(10,227)	(8,578)
Non-controlling interest in subsidiaries	19	20
Total equity	(10,208)	(8,558)
Liabilities and Equity, Total	(17,482)	(15,262)
Parent Company [Member]
Assets, Current [Abstract]
Total current assets	146	358
Property, Plant and Equipment, Net	24	17
Other Assets, Noncurrent [Abstract]
Regulatory assets	0	0
Goodwill	0	0
Other long term assets	11,457	9,761
Total other assets	11,457	9,761
Assets, Total	11,627	10,136
Liabilities, Current [Abstract]
Total current liabilities	368	129
Liabilities, Noncurrent [Abstract]
Long-term debt	2,906	2,861
Deferred income taxes	0	0
Regulatory liabilities	0	0
Other long-term liabilities	36	34
Total long-term liabilities	2,942	2,895
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Total Emera Incorporated equity	8,317	7,112
Non-controlling interest in subsidiaries	0	0
Total equity	8,317	7,112
Liabilities and Equity, Total	11,627	10,136
Subsidiary Issuer [Member]
Assets, Current [Abstract]
Total current assets	67	30
Property, Plant and Equipment, Net	0	0
Other Assets, Noncurrent [Abstract]
Regulatory assets	0	0
Goodwill	0	0
Other long term assets	4,660	4,285
Total other assets	4,660	4,285
Assets, Total	4,727	4,315
Liabilities, Current [Abstract]
Total current liabilities	695	12
Liabilities, Noncurrent [Abstract]
Long-term debt	3,709	4,034
Deferred income taxes	3	4
Regulatory liabilities	0	0
Other long-term liabilities	0	0
Total long-term liabilities	3,712	4,038
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Total Emera Incorporated equity	320	265
Non-controlling interest in subsidiaries	0	0
Total equity	320	265
Liabilities and Equity, Total	4,727	4,315
Guarantor Subsidiaries [Member]
Assets, Current [Abstract]
Total current assets	1,767	1,420
Property, Plant and Equipment, Net	13,745	12,258
Other Assets, Noncurrent [Abstract]
Regulatory assets	645	587
Goodwill	6,208	5,709
Other long term assets	971	156
Total other assets	7,824	6,452
Assets, Total	23,336	20,130
Liabilities, Current [Abstract]
Total current liabilities	2,829	3,293
Liabilities, Noncurrent [Abstract]
Long-term debt	10,243	8,468
Deferred income taxes	668	447
Regulatory liabilities	2,118	1,888
Other long-term liabilities	874	691
Total long-term liabilities	13,903	11,494
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Total Emera Incorporated equity	6,604	5,343
Non-controlling interest in subsidiaries	0	0
Total equity	6,604	5,343
Liabilities and Equity, Total	23,336	20,130
Non-Guarantor Subsidiaries [Member]
Assets, Current [Abstract]
Total current assets	1,096	891
Property, Plant and Equipment, Net	4,946	4,720
Other Assets, Noncurrent [Abstract]
Regulatory assets	759	686
Goodwill	105	96
Other long term assets	3,200	3,094
Total other assets	4,064	3,876
Assets, Total	10,106	9,487
Liabilities, Current [Abstract]
Total current liabilities	926	714
Liabilities, Noncurrent [Abstract]
Long-term debt	4,428	4,262
Deferred income taxes	643	565
Regulatory liabilities	241	354
Other long-term liabilities	543	550
Total long-term liabilities	5,855	5,731
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Total Emera Incorporated equity	3,303	2,970
Non-controlling interest in subsidiaries	22	72
Total equity	3,325	3,042
Liabilities and Equity, Total	$ 10,106	$ 9,487

SUPPLEMENTAL FINANCIAL INFORM_5

SUPPLEMENTAL FINANCIAL INFORMATION Company (Condensed Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	$ 1,690	$ 1,193
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	(2,162)	(1,529)
Purchase of investments subject to significant influence, inclusive of acquisition costs	(49)	(213)
Other investing activities	21	(19)
Net cash provided by (used in) investing activities	(2,190)	(1,761)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	99	(31)
Proceeds from (Repayments of) Short-term Debt	129	383
Proceeds from Issuance of Long-term Debt	1,055	129
Retirement of long-term debt	(757)	(453)
Proceeds from Long-term Lines of Credit	321	230
Issuance of common and preferred stock, net of issuance costs	301	682
Dividends on common and preferred stock	382	315
Proceeds from (Payments for) Other Financing Activities	(32)	(32)
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	344	593
Cash and Cash Equivalents, Period Increase (Decrease)	(131)	12
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	0	13
Purchase of investments subject to significant influence, inclusive of acquisition costs	0	0
Other investing activities	572	1,098
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	0	0
Proceeds from Issuance of Long-term Debt	(194)	13
Retirement of long-term debt	0	(15)
Proceeds from Long-term Lines of Credit	110	9
Issuance of common and preferred stock, net of issuance costs	(446)	1,898
Dividends on common and preferred stock	(348)	(314)
Proceeds from (Payments for) Other Financing Activities	(123)	(376)
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	0	0
Cash and Cash Equivalents, Period Increase (Decrease)	0	0
Beginning Balance	0	0
Ending Balance	0	0
Parent Company [Member]
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	(9)	5
Purchase of investments subject to significant influence, inclusive of acquisition costs	0	0
Other investing activities	(489)	742
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	0	0
Proceeds from Issuance of Long-term Debt	0	0
Retirement of long-term debt	0	0
Proceeds from Long-term Lines of Credit	136	(30)
Issuance of common and preferred stock, net of issuance costs	301	682
Dividends on common and preferred stock	382	315
Proceeds from (Payments for) Other Financing Activities	0	290
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	(4)	1
Cash and Cash Equivalents, Period Increase (Decrease)	(256)	76
Beginning Balance	276	200
Ending Balance	20	276
Subsidiary Issuer [Member]
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	0	0
Purchase of investments subject to significant influence, inclusive of acquisition costs	0	0
Other investing activities	0	26
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	0	0
Proceeds from Issuance of Long-term Debt	0	0
Retirement of long-term debt	0	0
Proceeds from Long-term Lines of Credit	0	0
Issuance of common and preferred stock, net of issuance costs	0	0
Dividends on common and preferred stock	0	0
Proceeds from (Payments for) Other Financing Activities	0	0
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	2	(3)
Cash and Cash Equivalents, Period Increase (Decrease)	37	(7)
Beginning Balance	21	28
Ending Balance	58	21
Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	(1,687)	1,031
Purchase of investments subject to significant influence, inclusive of acquisition costs	(16)	0
Other investing activities	3	5
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	(162)	365
Proceeds from Issuance of Long-term Debt	1,174	147
Retirement of long-term debt	(716)	413
Proceeds from Long-term Lines of Credit	(103)	59
Issuance of common and preferred stock, net of issuance costs	319	134
Dividends on common and preferred stock	37	29
Proceeds from (Payments for) Other Financing Activities	0	96
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	9	1
Cash and Cash Equivalents, Period Increase (Decrease)	50	(18)
Beginning Balance	54	72
Ending Balance	104	54
Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to property, plant and equipment	(466)	480
Purchase of investments subject to significant influence, inclusive of acquisition costs	(33)	213
Other investing activities	(65)	(1,852)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Change in short-term debt, net	0	(13)
Proceeds from Issuance of Long-term Debt	75	(31)
Retirement of long-term debt	(41)	55
Proceeds from Long-term Lines of Credit	178	192
Issuance of common and preferred stock, net of issuance costs	127	(2,032)
Dividends on common and preferred stock	311	285
Proceeds from (Payments for) Other Financing Activities	91	(42)
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	18	(12)
Cash and Cash Equivalents, Period Increase (Decrease)	38	(39)
Beginning Balance	152	191
Ending Balance	$ 190	$ 152