Emera (EMRAF) 40-F 24 Feb 23 2022 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2022 shares
Cover [Abstract]
Entity Central Index Key	0001127248
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Amendment Flag	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
Current Fiscal Year End Date	--12-31
Entity File Number	000-54516
Entity Registrant Name	EMERA INC
Entity Incorporation, State or Country Code	A5
Entity Listings [Line Items]
Entity Address, Address Line One	5151 Terminal Road
Entity Address, City or Town	Halifax
Entity Address, State or Province	NS
Entity Address, Country	CA
Entity Address, Postal Zip Code	B3J 1A1
City Area Code	902
Local Phone Number	428-6096
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor	false
Auditor Name	Ernst & Young LLP
Auditor Location	Halifax, Nova Scotia, Canada
Auditor Firm Id	1263
Business Contact [Member]
Entity Listings [Line Items]
Contact Personnel Name	Emera US Finance LP
Entity Address, Address Line One	c/o Corporation Service Company
Entity Address Address Line Two	251 Little Falls Drive
Entity Address, City or Town	Wilmington
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19808
City Area Code	302
Local Phone Number	636-5401
Common Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	269,944,308
Series A Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	4,866,814
Series B Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	1,133,186
Series C Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	10,000,000
Series E Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	5,000,000
Series F Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	8,000,000
Series H Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	12,000,000
Series J Preferred Stock [Member]
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	8,000,000
Series L Preferred Stock [Member]
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	9,000,000

Consolidated Statements of Inco

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating revenues
Total operating revenues (note 6)	$ 7,588	$ 5,765
Operating expenses
Operating, maintenance and general expenses ("OM&G")	1,596	1,368
Provincial, state, and municipal taxes	367	330
Depreciation and amortization	952	902
Impairment charge (note 22)	73	0
Total operating expenses	5,959	4,835
Income from operations	1,629	930
Income from equity investments (note 8)	129	143
Other income, net (note 9)	145	93
Interest expense, net	709	611
Income before provision for income taxes	1,194	555
Income tax expense (recovery) (note 10)	185	(6)
Net income	1,009	561
Non-controlling interest in subsidiaries	1	1
Preferred stock dividends	63	50
Net income attributable to common shareholders	$ 945.1	$ 510.5
Earnings per common share (note 12)
Basic	$ 3.56	$ 1.98
Diluted	$ 3.55	$ 1.98
Weighted average shares of common stock outstanding (in millions) (note 12)
Basic	265.5	257.2
Diluted	265.9	258
Dividends per common share declared	$ 2.6775	$ 2.5750
Regulated | Gas Revenue
Operating revenues
Total operating revenues (note 6)	$ 1,681	$ 1,261
Operating expenses
Fuel for generation and purchased power	800	472
Regulated | Electric Revenue
Operating revenues
Total operating revenues (note 6)	5,473	4,665
Operating expenses
Fuel for generation and purchased power	$ 2,171	$ 1,763

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Consolidated Statements of Comprehensive Income
Net income	$ 1,009	$ 561
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment	629	(42)
Unrealized (losses) gains on net investment hedges	(97)	5
Cash flow hedges
Net derivative gains	0	18
Less: reclassification adjustment for gains included in income	(2)	(1)
Net effects of cash flow hedges	(2)	17
Unrealized losses on available-for-sale investment	(1)	0
Net change in unrecognized pension and post-retirement benefit obligation	24	124
Other comprehensive income	553	104
Comprehensive income	1,562	665
Comprehensive income attributable to non-controlling interest	1	1
Comprehensive Income of Emera Incorporated	$ 1,561	$ 664

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Foreign currency translation, tax expense (recovery)	$ 7,000,000	$ 5,000,000
Hybrid Notes as a hedge of the foreign currency exposure	1,100,000,000	1,700,000,000
Unrealized gains (losses) on net investment hedges	(6,000,000)	1,000,000
Net derivative gain, tax	(1,000,000)	6,000,000
Net change in unrecognized pension and post-retirement benefit obligation	1,000,000	2,000,000
Other comprehensive loss, Tax	1,000,000	$ 14,000,000
Net investment in United States dollar denominated operations
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200,000,000

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 310	$ 394
Restricted cash (note 32)	22	23
Inventory (note 14)	769	538
Derivative instruments (notes 15 and 16)	296	195
Regulatory assets (note 7)	602	253
Receivables and other current assets (note 18)	2,897	1,733
Total current assets	4,896	3,136
Property, plant and equipment ("PP&E"), net of accumulated depreciation and amortization of $9,574 and $8,739, respectively	22,996	20,353
Other assets
Deferred income taxes (note 10)	237	295
Derivative instruments (notes 15 and 16)	100	106
Regulatory assets (note 7)	3,018	2,313
Net investment in direct finance and sales type leases (note 19)	604	503
Investments subject to significant influence (note 8)	1,418	1,382
Goodwill (note 22)	6,012	5,696
Other long-term assets (note 32)	461	460
Total other assets	11,850	10,755
Total assets	39,742	34,244
Current liabilities
Short-term debt (note 23)	2,726	1,742
Current portion of long-term debt (note 25)	574	462
Accounts payable	2,025	1,485
Derivative instruments (notes 15 and 16)	888	533
Regulatory liabilities (notes 7 and 32)	495	290
Other current liabilities (note 24)	579	366
Total current liabilities	7,287	4,878
Long-term liabilities
Long-term debt (note 25)	15,744	14,196
Deferred income taxes (note 10)	2,196	1,868
Derivative instruments (notes 15 and 16)	190	149
Regulatory liabilities (note 7)	1,778	1,765
Pension and post-retirement liabilities (note 21)	281	370
Other long-term liabilities (notes 8 and 26)	825	868
Total long-term liabilities	21,014	19,216
Equity
Common stock (note 11)	7,762	7,242
Cumulative preferred stock (note 28)	1,422	1,422
Contributed surplus	81	79
Accumulated other comprehensive income ("AOCI") (note 13)	578	25
Retained earnings	1,584	1,348
Total Emera Incorporated equity	11,427	10,116
Non-controlling interest in subsidiaries (note 29)	14	34
Total equity	11,441	10,150
Total liabilities and equity	$ 39,742	$ 34,244

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Consolidated Balance Sheets
Accumulated depreciation and amortization on property, plant and equipment	$ 9,574	$ 8,739

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net income	$ 1,009	$ 561
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	959	915
Income from equity investments, net of dividends	(61)	(69)
Allowance for equity funds used during construction	(52)	(61)
Deferred income taxes, net	152	(37)
Net change in pension and post-retirement liabilities	(48)	(23)
Fuel adjustment mechanism ("FAM")	(162)	(166)
Net changes in fair value of derivative instruments	206	404
Net change in regulatory assets and liabilities	(471)	(176)
Net change in capitalized transportation capacity	(445)	(107)
Impairment charge	73	0
Other operating activities, net	(13)	96
Changes in non-cash working capital (note 30)	(234)	(152)
Net cash provided by operating activities	913	1,185
Investing activities
Additions to PP&E	(2,596)	(2,359)
Other investing activities	27	27
Net cash used in investing activities	(2,569)	(2,332)
Financing activities
Change in short-term debt, net	1,028	(155)
Proceeds from short-term debt with maturities greater than 90 days	544	640
Repayment of short-term debt with maturities greater than 90 days	(680)	(377)
Proceeds from long-term debt, net of issuance costs	784	2,554
Retirement of long-term debt	(367)	(1,660)
Net proceeds under committed credit facilities	511	82
Issuance of common stock, net of issuance costs	277	317
Issuance of preferred stock, net of issuance costs (note 28)	0	416
Dividends on common stock	(472)	(443)
Dividends on preferred stock	(63)	(50)
Other financing activities	(7)	(13)
Net cash provided by financing activities	1,555	1,311
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	16	(1)
Net increase (decrease) in cash, cash equivalents, restricted cash	(85)	163
Cash, cash equivalents, and restricted cash, beginning of year	417	254
Cash, cash equivalents, and restricted cash, end of year	$ 332	$ 417

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Cash, cash equivalents and restricted cash consists of:
Cash	$ 302	$ 237
Short-term investments	8	157
Restricted cash	22	23
Cash, cash equivalents, and restricted cash	$ 332	$ 417

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common Stock [Member]	Preferred Stock	Contributed Surplus	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Non-Controlling Interest
Beginning Balance at Dec. 31, 2020	$ 9,238	$ 6,705	$ 1,004	$ 79	$ (79)	$ 1,495	$ 34
Net income of Emera Inc.	561	0	0	0	0	560	1
Other comprehensive income, net of tax expense	104	0	0	0	104	0	0
Issuance of preferred shares, net of after-tax issuance costs	418	0	418	0	0	0	0
Dividends declared on preferred stock (note 28)	(50)	0	0	0	0	(50)	0
Dividends declared on common stock	(657)	0	0	0	0	(657)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	284	284	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	215	215	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan	38	38	0	0	0	0	0
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2021	10,150	7,242	1,422	79	25	1,348	34
Net income of Emera Inc.	1,009	0	0	0	0	1,008	1
Other comprehensive income, net of tax expense	553	0	0	0	553	0	0
Dividends declared on preferred stock (note 28)	(63)	0	0	0	0	(63)	0
Dividends declared on common stock	(709)	0	0	0	0	(709)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	248	248	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	238	238	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan	36	34	0	2	0	0	0
Disposal of non-controlling interest of Dominica Electricity Services Ltd ("Domlec")	(20)	0	0	0	0	0	(20)
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2022	$ 11,441	$ 7,762	$ 1,422	$ 81	$ 578	$ 1,584	$ 14

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Consolidated Statements of Changes in Equity
Other comprehensive loss, tax expense/recovery	$ 1	$ 14
Dividends per common share declared	$ 2.6775	$ 2.5750

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
1. Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	1. 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, 2022, Emera’s reportable segments include the following: ● utility, serving approximately 827,000 ● ● primary electricity supplier in Nova Scotia, serving approximately 541,000 ● investments related to an 824 Falls on the Lower Churchill River in Labrador, owned and constructed by Nalcor Energy. ENL’s two investments are: ● 100 Maritime Link Project, a $ 1.8 construction (“AFUDC”)) transmission project; and ● 31.9 Partnership (“LIL”), a $ 3.7 Labrador. ● ● 468,000 ● approximately 545,000 ● 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 North America Canada Partnership, which expires in 2034; ● transmission company in Florida; and ● 12.9 1,400 -kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern United States. ● with regulated electric utilities that include: ● electric utility on the island of Barbados, serving approximately 133,000 ● utility on Grand Bahama Island, serving approximately 19,000 ● 19.5 integrated regulated electric utility on the island of St. Lucia. ● which includes: ● ● natural gas and electricity and provides related energy asset management services; ● 30 electricity facility in Brooklyn, Nova Scotia; and ● 50.0 Swamp”), a 660 Massachusetts. ● financing subsidiaries of Emera; ● deliver renewables and resilient energy to customers; ● located in the United States; and ● Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, 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 (“CAD”), unless otherwise indicated. Principles of Consolidation These consolidated financial statements 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 Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impacts its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 7. Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing 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 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 USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”). Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity and 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 megawatt hours (“MWh”) or therms delivered to customers at the established rates 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. Non-regulated Revenue: Marketing and trading margins are 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 the terms of the contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Leases The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets, as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. Franchise Fees and Gross Receipts Tampa through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” 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 fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. Property, Plant and Equipment PP&E are recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units are included in “Property, plant and equipment”. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase the overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “Property, plant and equipment,” consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded. 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 cash flow analysis which relies on management’s best estimate of the reporting units’ projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2022, $ 6,009 purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no impairment charges were recognized. In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro- economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $ 73 nil December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22. Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets 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 to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Tampa estimated service lives of the related properties, as required by regulatory practices. Tampa deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective 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. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10. Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified 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 normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory 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 when 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 future rates. Tampa Electric has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric’s will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory, economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” 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 Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral 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 investments with original maturities of three months or less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost will be recovered in future customer rates. Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates 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 operations 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 based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2022 or 2021. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of 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. No required in either 2022 or 2021. Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at fair value, with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation, using the Company’s credit 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 governmental 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 accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs which are not recognized in the consolidated financial statements, as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within 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 liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the fair value-based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite

Change in Accounting Policy

Change in Accounting Policy	12 Months Ended
	Dec. 31, 2022
2. Change in Accounting Policy
Change in Accounting Policy	2. CHANGE IN ACCOUNTING POLICY The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is described as follows: Facilitation of the Effects of Reference Rate Reform on Financial Reporting The Company adopted Accounting Standard Update (“ASU”) 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were amended during the current period. The Company’s transition from reference rates will not have a material impact on the consolidated financial statements.

Future Accounting Pronouncement

Future Accounting Pronouncements	12 Months Ended
	Dec. 31, 2022
3. Future Accounting Pronouncements
Future Accounting Pronouncements	3. The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2022
4. Dispositions
Dispositions	4. DISPOSITIONS On March 31, 2022, Emera completed the sale of its 51.9 approximated its carrying value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2022
5. Segment Information
Segment Information	5. Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expense), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 Impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2021 Operating revenues from external customers (1) $ 2,718 $ 1,501 $ 1,276 $ 445 $ (175) $ $ 5,765 Inter-segment revenues (1) 6 - 4 - 18 (28) 2,724 1,501 1,280 445 (157) (28) 5,765 Regulated fuel for generation and purchased power 894 654 - 218 - (3) 1,763 Regulated cost of natural gas - - 472 - - - 472 OM&G 536 291 325 140 106 (30) 1,368 Provincial, state and municipal taxes 212 43 69 4 2 - 330 Depreciation and amortization 469 246 121 58 8 - 902 Income from equity investments - 103 20 4 16 - 143 Other income (expenses), net 59 12 11 15 1 (5) 93 Interest expense, net (2) 138 132 64 21 256 - 611 Income tax expense (recovery) 72 9 62 1 (150) - (6) Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 50 - 50 Net income (loss) attributable to common shareholders $ 462 $ 241 $ 198 $ 21 $ (412) $ - $ 510 Capital expenditures $ 1,331 $ 366 $ 515 $ 111 $ 5 $ - $ 2,328 As at December 31, 2021 Total assets $ 17,903 $ 7,418 $ 6,666 $ 1,402 $ 2,034 $ (1,179) $ 34,244 Investments subject to significant influence $ - $ 1,215 $ 123 $ 44 $ - $ - $ 1,382 Goodwill $ 4,436 $ - $ 1,189 $ 68 $ 3 $ - $ 5,696 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes the elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2021, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2022 2021 United States $ 5,346 $ 3,754 Canada 1,725 1,566 Barbados 384 292 The Bahamas 122 110 Dominica 11 43 $ 7,588 $ 5,765 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2022 2021 United States $ 17,382 $ 14,978 Canada 4,689 4,440 Barbados 583 535 The Bahamas 342 322 Dominica - 78 $ 22,996 $ 20,353

Revenue

Revenue	12 Months Ended
	Dec. 31, 2022
6. Revenue
Revenue	6. The following disaggregates the Company’s revenue by major source: Electric Gas Other Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other regulatory deferrals 371 28 12 - - - 411 Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) $ 7,154 Non-Regulated Revenue Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) $ 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 For the year ended December 31, 2021 Regulated Revenue Residential $ 1,449 $ 797 $ 165 $ 642 $ - $ - $ 3,053 Commercial 754 407 232 379 - - 1,772 Industrial 215 237 26 65 - (2) 541 Other regulatory deferrals 289 27 7 - - - 323 Other (1) 17 33 15 122 - (8) 179 Finance income (2)(3) - - - 58 - - 58 $ 2,724 $ 1,501 $ 445 $ 1,266 $ - $ (10) 5,926 Non-Regulated Marketing and trading margin (4) - - - - 102 - 102 Other non-regulated operating revenue - - - 14 30 (21) 23 Mark-to-market (3) - - - - (289) 3 (286) $ - $ - $ - $ 14 $ (157) $ (18) (161) Total operating revenues $ 2,724 $ 1,501 $ 445 $ 1,280 $ (157) $ (28) $ 5,765 (1) Other includes rental revenues, which do not 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 customers. Remaining Performance Obligations Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of December 31, 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was $ 450 million (2021 – $ 437 144 to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2042 .

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2022
7. Regulatory Assets and Liabilities
Regulatory Assets and Liabilities	7. REGULATORY Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. As at December 31 December 31 millions of dollars 2022 2021 Regulatory assets Deferred income tax regulatory assets $ 1,166 $ 1,045 Cost recovery clauses 707 114 Tampa Electric capital cost recovery for early retired assets 674 657 Pension and post-retirement medical plan 369 291 FAM 307 145 Storm reserve 103 - NMGC winter event gas cost recovery 69 117 Storm restoration 35 35 Deferrals related to derivative instruments 30 23 Environmental remediations 27 27 Stranded cost recovery 27 26 Other 106 86 $ 3,620 $ 2,566 Current $ 602 $ 253 Long-term 3,018 2,313 Total regulatory assets $ 3,620 $ 2,566 Regulatory liabilities Accumulated reserve - cost of remova l 895 819 Deferred income tax regulatory liabilities 877 863 Deferrals related to derivative instruments 230 241 NMGC gas hedge settlements (note 18) 162 - Cost recovery clauses 70 35 Self-insurance fund (note 32) 30 28 Storm reserve - 58 Other 9 11 $ 2,273 $ 2,055 Current $ 495 $ 290 Long-term 1,778 1,765 Total regulatory liabilities $ 2,273 $ 2,055 Deferred Income Tax Regulatory Assets and Liabilities To years, a regulatory asset or liability is recognized as appropriate. Cost Recovery Clauses These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period. Tampa Electric Capital Cost Recovery for Early Retired Assets This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years . This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the Tampa Electric section below. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC as applicable. It is amortized over the remaining service life of plan participants. FAM This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year and deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods. For the years 2020 through 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from customers in future periods. The Nova Scotia Utility and Review Board’s (“UARB”) decision to approve the fuel stability plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM. 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 to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. Ian. For further information, refer to “Storm Reserve – Hurricane Ian” in both Tampa Electric and PGS sections below. NMGC Winter Event Gas Cost Recovery In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $ 108 NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause (“PGAC”). On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021, the NMPRC approved the recovery of $ 108 over a period of 30 months beginning July 1, 2021. Storm Restoration This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are not covered by commercial insurance. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $ 15 of costs related to Hurricane Dorian in 2019, over a five-year through rates on January 1, 2021. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in fair value of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by its regulator. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory, on the nature of the item being economically hedged. Environmental Remediations This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $ 21 million USD stranded cost through electricity rates; it is included in rate base and is expected to be included in rates in future years. Accumulated Reserve – Cost of Removal (“COR”) This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC and NSPI. AROs represent the fair value of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. rates to cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. NMGC Gas Hedge Settlements This regulatory liability represents the regulatory deferral of gas options exercised above strike price but will settle in cash in Q1 2023. The value from the cash settlement of this options will flow through to customers via the PGAC. Regulatory Environments and Updates Florida Electric Utility Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties. Tampa 9.25 to 11.25 54 10.20 (2021 - 10.25 Fuel Recovery and Other Cost Recovery Clauses: Tampa fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs, including a return on capital invested. Differences between the prudently incurred fuel costs and the cost- recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in subsequent periods. On January 23, 2023, Tampa under-recovery of $ 518 21 months . The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $ 170 by the FPSC in March 2023, and recovery is expected to begin in April 2023. The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $ 169 December 2022. Base Rates: On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The settlement agreement allows for an increase to rates of $ 191 2022. This increase consisted of $ 123 68 the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter assets. The settlement agreement further includes two subsequent year adjustments of $ 90 and $ 21 future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 agreement includes an allowed regulated ROE range of 9.0 11.0 9.95 midpoint. It also provides for a 25 10 million USD of additional revenue, if United States Treasury Bond yields exceed a specific threshold set on the date the FPSC approved the agreement. Under the agreement base rates are frozen from January 1, 2022 to December 31, 2024, unless Tampa Electric’s range during that time. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process. The settlement agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that Tampa file a new depreciation study no more than one year , nor less than 90 days , before the filing of its next general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending on December 31, 2024. On August 16, 2022, the FPSC approved Tampa Electric’s increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 9.25 11.25 Storm Reserve – Hurricane Ian: In September 2022, Tampa 126 million USD, with $ 119 storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $ 56 approximately $ 131 recovery is expected to begin in April 2023 through March 2024. Solar Base Rate Adjustments Included in Base Rates: During 2017 to 2021, Tampa 850 600 photovoltaic projects, which is recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 104 service projects. On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020. A $ 4 SoBRA tranche 4 was required. Storm Protection Cost Recovery Clause and Settlement Agreement: On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and Tampa years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP. Big Bend Modernization Project: Tampa 876 91 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective. At December 31, 2021, the balance sheet included $ 636 267 million USD in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s continued to account for its existing investment in Unit 1, 2 and 3 in electric utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet. Tampa two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years schedule for all three units was applied beginning January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2022 and 2021 was 8.75 9.25 quarter average regulated common equity component of up to 40 NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods. For the period of 2020 through 2022, NSPI operated under a three-year in an average annual overall rate increase of 1.5 recovery of Maritime Link costs. General Rate Application (“GRA”): On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 GRA to the UARB, excluding increases relating to demand side management (“DSM”) costs, to a total of 1.8 effective date of the UARB’s decision and the end of 2024. The legislation also: ● requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers, ● limits NSPI’s return on equity to 9.25 40 ● limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212, including the 1.8 cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate increase of 6.9 incremental revenue (fuel and non-fuel) of $ 105 115 under or over recovery of fuel costs will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be 8.75 9.25 average regulated common equity component of up to 40 establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $ 10 given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision. Maritime Link: The Maritime Link is a $ 1.8 two 170 -kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. As part of a three-year 164 $ 162 stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. Nova Scotia Cap-and-Trade (“Cap-and-Trade”) As at December 31, 2022, the FAM includes a recovery of $ 172 38 million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the 2019 through 2022 Cap-and-Trade compliance period. Emissions for the compliance period will not be finalized until the completion of the environmental audit which begins in March 2023. Emissions are currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for 2022. The total cost of compliance with the Cap-and-Trade program compliance period could change depending on the price paid for both credits at remaining provincial auctions and reserve credits purchased from the provincial government, and the results of the 2022 environmental emissions audit. Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $ 165 which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM. NSPML Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 9.25 based on an actual five-quarter average regulated common equity component of up to 30 Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and delivery will continue over the next 35 years In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 9 7 otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $ 168 million (2021 – $ 172 2022. This was subject to a holdback of up to $ 2 receiving at least 90 In December 2022, NSPML received UARB approval to collect up to $ 164 recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of up to $ 2 direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay NSPML approximately $ 4 14 million in aggregate has been held-back by NSPI. Determination of the allocation of the $ 14 between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to review the holdback mechanism. Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. PGS’s approved ROE range for 2022 and 2021 was 8.9 11.0 9.9 midpoint, based on an allowed equity capital structure of 54.7 Fuel Recovery: PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC. Recovery of Energy Conservation and Pipeline Replacement Programs: The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are required by Florida law and approved and monitored by the FPSC. PGS also has a 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. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under the rider. Storm Reserve – Hurricane Ian: In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The restoration costs were approximately $ 2 1 approved storm reserve. Base Rates: On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. agreement allows for an increase to base rates by $ 58 which is a $ 34 24 recovered through the cast iron and bare steel replacement rider. It provides PGS the ability to reverse a total of $ 34 14 million USD of the $ 34 In addition, the agreement sets new depreciation rates effective January 1, 2021. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.9 54.7 investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. NMGC’s approved ROE for 2022 and 2021 was 9.375 52 Fuel Recovery: NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any prior month under-recovery or over- recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024. Base Rates: On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $ 19 operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022. Weather Normalization Mechanism: In July 2019, the NMPRC approved changes to the company’s rate design to include a five-year pilot of Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts during the October through April heating seasons. The Weather Normalization Mechanism allows customer rates and company revenue to be more predictable by partially removing the impact of warmer than usual or colder than usual weather. Weather-related revenue increases or decreases experienced from October to April are adjusted annually in October of the following heating season. Integrity Management Programs (“IMP”) Regulatory Asset: A portion of NMGC’s annual spending on infrastructure is for IMP, legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25 -year firm service agreement commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator (“CER”). The CER Gas Transportation Tariff compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. Other Electric Utilities BLPC BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base was 10 Licenses: The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect in 2023 on completion of the legislative process. The Dispatch license will have a term of 5 years with the remaining licenses having terms ranging from 25 - 30 years . BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of the licenses once received. Fuel Recovery BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is adjusted on a monthly basis and reported to the FTC for approval. On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $ 23 million USD upon approval. The application includes a request for allowed regulatory ROE of 12.50 cent on an allowed equity capital structure of 65 BLPC interim rate relief, allowing an increase in base rates of approximately $ 3 remainder of 2022 and approximately $ 1 from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately $ 70 accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023. Fuel Hedging: On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50 /50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. A decision is expected from the FTC in 2023. GBPC GBPC is regulated by the GBPA. The GBPA franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.23 8.37 Fuel Recovery: GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner. Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted monthly, in-line with actual fuel costs. Base Rates: There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $ 3.5 12.84 cent. Storm Restoration Costs – Hurricane Matthew: In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s appli

Investments Subject to Signific

Investments Subject to Significant Influence and Equity Income	12 Months Ended
	Dec. 31, 2022
8. Investments Subject to Significant Influence and Equity Income
Investments Subject to Significant Influence and Equity Income	8. Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2022 2021 2022 2021 2022 LIL (1) $ 740 $ 682 $ 58 $ 54 31.9 NSPML 501 533 29 49 100.0 M&NP 128 123 21 20 12.9 Lucelec (2) 49 44 4 4 19.5 Bear Swamp - - 17 16 50.0 $ 1,418 $ 1,382 $ 129 $ 143 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $ 179 Bear Swamp's credit investment balance of $ 95 104 Consolidated Balance Sheets. Equity investments include a $ 9 investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2022 2021 Balance Sheets Current assets $ 17 $ 25 PP&E 1,517 1,587 Regulatory assets 265 247 Non-current assets 29 31 Total assets $ 1,828 $ 1,890 Current liabilities $ 48 $ 50 Long-term debt (1) 1,149 1,189 Non-current liabilities 130 118 Equity 501 533 Total liabilities and equity $ 1,828 $ 1,890 (1) The project debt has been guaranteed by the Government of Canada.

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2022
9. Other Income, Net
Other Income (Expenses), Net	9. For the Year ended December 31 millions of dollars 2022 2021 TECO Guatemala Holdings award (1) $ 63 $ - AFUDC 52 61 Other 30 32 $ 145 $ 93 (1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
10. Income Taxes
Income Taxes	10. The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2022 2021 Income before provision for income taxes $ 1,194 $ 555 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 346 161 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (70) (62) Foreign tax rate variance (44) (42) Amortization of deferred income tax regulatory liabilities (33) (33) GBPC impairment charge 21 - Tax effect (10) (16) Tax credits (18) (13) Other (7) (1) Income tax expense (recovery) $ 185 $ (6) Effective income tax rate 15% (1%) On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. During 2022, the Company recorded a $ 9 realized to customers. The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2022 2021 Current income taxes $ 25 $ 20 8 11 Deferred income taxes 120 (33) 252 118 - 2 Investment tax credits (7) (11) Operating loss carryforwards (92) (64) (121) (49) Income tax expense (recovery) $ 185 $ (6) The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2022 2021 Canada $ 173 $ 244 United States 1,063 289 Other (42) 22 Income before provision for income taxes $ 1,194 $ 555 The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2022 2021 Deferred income tax assets: Tax loss carryforwards $ 1,207 $ 873 Tax credit carryforwards 415 375 Regulatory liabilities - cost of removal 177 170 Derivative instruments 45 188 Other 428 434 Total deferred income tax assets before valuation allowance 2,272 2,040 Valuation allowance (312) (256) Total deferred income tax assets after valuation allowance $ 1,960 $ 1,784 Deferred income tax (liabilities): PP&E $ (2,981) $ (2,622) Regulatory assets (219) (78) Derivative instruments (125) (197) Other (594) (460) Total deferred income tax liabilities $ (3,919) $ (3,357) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 237 $ 295 Long-term deferred income tax liabilities (2,196) (1,868) Net deferred income tax liabilities $ (1,959) $ (1,573) 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 long-term debt and investments. A valuation allowance of $ 312 256 related to the loss carryforwards, long-term debt and investments. The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at December 31, 2022, $ 3.8 2.9 deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2022 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,372 $ (977) $ 1,395 2026 - 2042 79 (79) - Indefinite United States $ 2,082 $ - $ 2,082 2032 - Indefinite 1,489 - 1,489 2032 - Indefinite 415 - 415 2025 - 2042 Other $ 73 $ (33) $ 40 2023 - 2029 The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows: millions of dollars 2022 2021 Balance, January 1 $ 28 $ 30 Increases due to tax positions related to current year 5 4 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (2) (1) Decreases due to settlement with tax authorities - (6) Balance, December 31 $ 33 $ 28 The total amount of unrecognized tax benefits as at December 31, 2022 was $ 33 28 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $ 7 6 1 recognized in the Consolidated Statements of Income (2021 – nil ). No balance of unrecognized tax benefits could change in the next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time. During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 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 $ 126 62 55 – $ 23 On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. 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 difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years. Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time. Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31, 2022, the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2022
11. Common Stock
Common Stock	11. Authorized : 2022 2021 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, December 31, 2021 261.07 $ 7,242 251.43 $ 6,705 Issuance of common stock under ATM program (1)(2) 4.07 248 4.99 284 Issued under the DRIP, 4.21 238 3.90 215 Senior management stock options exercised and Employee Share Purchase Plan 0.60 34 0.75 38 Balance, December 31, 2022 269.95 $ 7,762 261.07 $ 7,242 (1) As at December 31, 2021, a total of 4,987,123 $ 57.63 287 284 (2) For the year ended December 31, 2022, 4,072,469 of $ 61.31 250 248 On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $ 600 million of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company's short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of $ 207 As at December 31, 2022, the following common shares were reserved for issuance: 6 6.2 million) under the senior management stock option plan, 2.7 3.1 employee common share purchase plan and 10 14.2 The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 Emera is in compliance with this requirement.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2022
12. Earnings Per Share
Earnings Per Share	12. Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the DRIP. The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2022 2021 Numerator Net income attributable to common shareholders $ 945.1 $ 510.5 Diluted numerator 945.1 510.5 Denominator Weighted average shares of common stock outstanding 265.5 255.9 Weighted average deferred share units outstanding - 1.3 Weighted average shares of common stock outstanding – basic 265.5 257.2 Stock-based compensation 0.4 0.4 Weighted average shares of common stock outstanding – diluted 265.9 Earnings per common share Basic $ 3.56 $ 1.98 Diluted $ 3.55 $ 1.98 (1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are in the calculation of earnings per common share.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2022
13. Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income	13. The components of AOCI are as follows: millions of dollars Unrealized gain (loss) on translation of self-sustaining foreign operations Net change in net investment hedges Gains on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 629 (97) - (1) - 531 - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 For the year ended December 31, 2021 Balance, January 1, 2021 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) (42) 5 18 - - (19) - - (1) - 124 123 Net current period other comprehensive income (loss) (42) 5 17 - 124 104 Balance, December 31, 2021 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of dollars 2022 2021 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (1) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 10 $ 24 Pension and post-retirement benefits 15 102 Total before tax 25 126 Income tax expense (1) (2) Total net of tax $ 24 $ 124 Total reclassifications out of AOCI, net of tax, for the period $ 22 $ 123

Inventory

Inventory	12 Months Ended
	Dec. 31, 2022
14. Inventory
Inventory	14. As at December 31 December 31 millions of dollars 2022 2021 Fuel $ 404 $ 255 Materials 365 283 Total $ 769 $ 538

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2022
15. Derivative Instruments
Derivative Instruments	15. 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 dollars 2022 2021 2022 2021 Regulatory deferral: $ 186 $ 146 $ 42 $ 16 18 7 1 8 52 88 - - 256 241 43 24 HFT derivatives: 89 33 77 32 340 208 1,224 818 429 241 1,301 850 Other derivatives: - 11 5 - 5 - 23 - 5 11 28 - Total gross current derivatives 690 493 1,372 874 Impact of master netting agreements: (18) (4) (18) (4) (276) (188) (276) (188) Total impact of master netting agreements (294) (192) (294) (192) Total derivatives $ 396 $ 301 $ 1,078 $ 682 Current (1) 296 195 888 533 Long-term (1) 100 106 190 149 Total derivatives $ 396 $ 301 $ 1,078 $ 682 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts. Cash Flow Hedges On May 26, 2021, the treasury lock was settled for a gain of $ 19 interest expense over 10 years unrealized gain in AOCI was $ 16 18 December 31, 2022, unrealized gains of $ 2 1 into interest expense. The Company expects $ 2 reclassified into net income within the next twelve months Regulatory Deferral The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral: Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2022 2021 Unrealized gain (loss) in regulatory assets $ - $ (69) $ 1 $ - $ (7) $ 9 Unrealized gain (loss) in regulatory liabilities 28 343 16 88 218 (3) Realized loss in regulatory assets - 48 - - - - Realized gain in regulatory liabilities - (41) - - (3) - Realized (gain) loss in inventory (1) - (121) 1 - (8) 5 Realized (gain) loss in regulated fuel for generation and purchased power (2) (64) (146) - - (39) 5 Total change in derivative instruments $ (36) $ 14 $ 18 $ 88 $ 161 $ 16 (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. As at December 31, 2022, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below: millions 2023 2024-2026 Physical natural gas purchases: Natural gas (Mmbtu) 6 - Commodity swaps and forwards purchases: Natural gas (Mmbtu) 18 12 Power (MWh) 1 1 FX swaps and forwards: FX contracts (millions of USD) $ 206 $ 123 Weighted average rate 1.2832 1.3064 % of USD requirements 50% 28% HFT Derivatives The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: For the Year ended December 31 millions of dollars 2022 2021 Power swaps and physical contracts in non-regulated operating revenues $ 17 $ 4 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 47 (142) Total gains (losses) in net income $ 64 $ (138) As at December 31, 2022, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: 2027 and millions 2023 2024 2025 2026 thereafter Natural gas purchases (Mmbtu) 319 92 42 36 131 Natural gas sales (Mmbtu) 492 205 105 6 19 Power purchases (MWh) 2 - - - - Power sales (MWh) 2 - - - - Other Derivatives As at December 31, 2022, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.8 combined notional amount of $ 448 The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives: For the Year ended December 31 millions of dollars 2022 2021 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ (5) $ - $ 11 Unrealized loss in other income, net (18) - (15) - Realized gain (loss) in OM&G - (17) - 15 Realized gain (loss) in other income, net (6) - 18 - Total gains (losses) in net income $ (24) $ (22) $ 3 $ 26 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 requested on any high-risk accounts. The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default 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 counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated. As at December 31, 2022, the maximum exposure the Company had to credit risk was $ 1.9 – $ 1.3 derivatives. It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate 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, 2022 was $ 386 341 mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company. The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default. As at December 31, 2022, the Company had $ 131 114 considered to be past due, which have been outstanding for an average 60 financial assets is $ 114 93 for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue. Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2022 December 31, 2021 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 455 19% $ 384 24% Commercial 192 8% 167 10% Industrial 121 5% 54 3% Other 122 5% 91 6% 890 37% 696 43% Trading group: Credit rating of A- or above 125 5% 66 4% Credit rating of BBB- to BBB+ 75 3% 107 7% Not rated 307 13% 132 8% 507 21% 305 19% Other accounts receivable 585 25% 329 20% 1,982 83% 1,330 82% Derivative Instruments (current and long-term) Credit rating of A- or above 202 9% 155 9% Credit rating of BBB- to BBB+ 8 0% 22 1% Not rated 186 8% 124 8% 396 17% 301 18% $ 2,378 100% $ 1,631 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of dollars 2022 2021 Cash collateral provided to others $ 224 $ 212 Cash collateral received from others $ 112 $ 100 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 adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization. As at December 31, 2022, the total fair value of derivatives in a liability position was $ 1,078 (December 31, 2021 – 682 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, 2022
16. Fair Value Measurements
Fair Value Measurements	16. The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 1) and uses 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 prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses. Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows: ● seasonal or monthly shaping and locational basis differentials. ● accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. ● 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, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 5 23 - 28 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) As at December 31, 2021 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 101 $ 41 $ - $ 142 - 7 - 7 - - 88 88 101 48 88 237 HFT derivatives: 4 5 4 13 (1) 29 12 40 3 34 16 53 Other derivatives: 11 - - 11 Total assets 115 82 104 301 Liabilities Regulatory deferral: 7 5 - 12 - 8 - 8 7 13 - 20 HFT derivatives: 4 5 3 12 13 122 515 650 17 127 518 662 Total liabilities 24 140 518 682 Net assets (liabilities) $ 91 $ (58) $ (414) $ (381) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2022 $ 88 $ 4 $ 12 $ 104 Realized gains included in fuel for generation and purchased power (64) - - (64) Unrealized gains included in regulatory liabilities 28 - - 28 Total realized and unrealized gains included in non- regulated operating revenues - - 22 22 Balance, December 31, 2022 $ 52 $ 4 $ 34 $ 90 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2022 $ 3 $ 515 $ 518 Total realized and unrealized gains (losses) included in non-regulated operating revenues (2) 310 308 Balance, December 31, 2022 $ 1 $ 825 $ 826 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. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. Other unobservable inputs used include 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. 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. The Company uses a modelled pricing valuation technique for determining the fair value of Level 3 derivative instruments. 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: December 31, 2022 As at Significant Weighted millions of dollars Fair Value Unobservable Input Low High average (1) Assets Liabilities Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (1) Unobservable inputs were weighted by the relative fair value of the instruments. December 31, 2021 As at Significant Weighted millions of dollars Fair Value Unobservable Input Low High average (1) Assets Liabilities Regulatory deferral – Physical $ 88 $ - Third-party pricing $4.51 $26.09 $9.74 natural gas purchases HFT derivatives – Power 4 3 Third-party pricing $37.05 $213.00 $99.34 swaps and physical contracts HFT derivatives – Natural 12 515 Third-party pricing $1.90 $21.53 $8.80 gas swaps, futures, forwards and physical contracts Total $ 104 $ 518 Net liability $ 414 (1) Unobservable inputs were weighted by the relative fair value of the instruments. Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 December 31, 2021 $ 14,658 $ 16,775 $ - $ 16,308 $ 467 $ 16,775 The Company has designated $ 1.2 currency exposure of its ne t investment are contingently convertible into preferred shares in the event of bankruptcy or other related events. A redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid Notes are classified as Level 2 financial assets. As at December 31, 2022, the fair value of the Hybrid Notes was $ 1.1 1.7 97 in AOCI for the year ended December 31, 2022 (2021 – $ 5

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
17. Related Party Transactions
Related Party Transactions	17. In the ordinary course of business, Emera provides energy 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 intercompany 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 amounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies are as follows: ● Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $ 157 149 NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $ 9 – $ 19 There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.

Receivables and Other Current A

Receivables and Other Current Assets	12 Months Ended
	Dec. 31, 2022
18. Receivables and Other Current Assets
Receivables and Other Current Assets	18. As at December 31 December 31 millions of dollars 2022 2021 Customer accounts receivable – billed $ 1,096 $ 767 Customer accounts receivable – unbilled 424 318 Allowance for credit losses (17) (21) Capitalized transportation capacity (1) 781 316 NMGC gas hedge settlement receivable (2) 162 - Income tax receivable 9 8 Prepaid expenses 82 65 Other 360 280 Total receivables and other current assets $ 2,897 $ 1,733 (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. (2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
19. Leases
Leases, Lessee	19. Lessee The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 63 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised. As at December 31 December 31 millions of dollars Classification 2022 2021 Right-of-use asset Other long-term assets $ 58 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 59 58 Total lease liabilities $ 62 $ 61 The Company has recorded lease expense of $ 138 – $ 150 131 142 facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income. Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Minimum lease payments $ 6 $ 6 $ 5 $ 3 $ 3 $ 116 $ 139 Less imputed interest (77) Total $ 62 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 7 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ - Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.98% 3.98% Lessor The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas (“CNG”) stations and heat pumps. The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset. Customers have the option to purchase CNG station assets by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee. Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 $ 100 16 These renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised. Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of Income. The total net investment in direct finance and sales-type leases consist of the following: As at December 31 December 31 millions of dollars 2022 2021 Total minimum lease payment to be received $ 1,393 $ 947 Less: amounts representing estimated executory costs (205) (165) Minimum lease payments receivable $ 1,188 $ 782 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (733) (443) Net investment in direct finance and sales-type leases $ 638 $ 522 Principal due within one year (included in "Receivables and other current assets") 34 19 Net Investment in direct finance and sales type leases - long-term $ 604 $ 503 As at December 31, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Minimum lease payments to be received $ 90 $ 92 $ 95 $ 94 $ 92 $ 930 $ 1,393 Less: executory costs (205) Total $ 1,188

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022
20. Property, Plant and Equipment
Property, Plant and Equipment	20. PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2022 2021 Generation 2 131 $ 13,083 $ 11,173 Transmission 10 80 2,731 2,532 Distribution 10 65 6,978 6,305 Gas transmission and distribution 13 83 5,061 4,385 General plant and other 2 71 2,723 2,473 Total cost 30,576 26,868 Less: Accumulated depreciation (1) (9,574) (8,739) 21,002 18,129 Construction work in progress (1) 1,994 2,224 Net book value $ 22,996 $ 20,353 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2022, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 1 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2022
21. Employee Benefit Plans
Employee Benefit Plans	21. Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island. Emera’s net periodic benefit cost included the following: Benefit Obligation and Plan Assets The changes in benefit obligation and plan assets, and the funded status for all plans were as follows: For the Year ended December 31 millions of dollars 2022 2021 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 $ 2,624 $ 318 $ 2,759 $ 339 Service cost 41 4 43 5 Plan participant contributions 6 6 6 4 Interest cost 80 9 67 8 Benefits paid (174) (31) (160) (27) Actuarial gains (480) (79) (89) (10) Settlements and curtailments (6) - - - Foreign currency translation adjustment 67 16 (2) (1) Balance, December 31 $ 2,158 $ 243 $ 2,624 $ 318 Change in plan assets Balance, January 1 $ 2,702 $ 51 $ 2,605 $ 52 Employer contributions 45 24 42 21 Plan participant contributions 6 6 6 4 Benefits paid (174) (31) (160) (27) Actual return on assets, net of expenses (489) (7) 214 2 Settlements and curtailments (6) - - - Foreign currency translation adjustment 79 3 (5) (1) Balance, December 31 $ 2,163 $ 46 $ 2,702 $ 51 Funded status, end of year $ 5 $ (197) $ 78 $ (267) The actuarial gains recognized in the period are primarily due to changes in the discount rate and compensation-related assumption changes. This was partially offset by losses associated with member experience and indexation. Plans with PBO/APBO in Excess of Plan Assets The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeds the plan assets for the years ended December 31 is as follows: millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 1,006 $ 221 $ 140 $ 290 Fair value of plan assets 914 - 35 - Funded status $ (92) $ (221) $ (105) $ (290) Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets The ABO for the defined benefit pension plans was $ 2,080 $ 2,507 for the years ended December 31 is as follows: millions of dollars 2022 2021 Defined benefit pension plans Defined benefit pension plans ABO $ 111 $ 133 Fair value of plan assets 33 35 Funded status $ (78) $ (98) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (13) $ (20) $ (7) $ (20) Long-term liabilities (80) (201) (100) (270) Other long-term assets 98 24 185 23 AOCI, net of tax and regulatory assets 358 22 230 90 Less: Deferred income tax (expense) recovery in AOCI (7) (1) (8) 1 Net amount recognized $ 356 $ (176) $ 300 $ (176) Amounts Recognized in AOCI and Regulatory Assets Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets: Regulatory assets Actuarial (gains) losses millions of dollars Defined Benefit Pension Plans Balance, January 1, 2022 $ 192 $ 30 Amortized in current period (21) (10) Current year addition to AOCI or regulatory assets 147 (5) Change in FX rate 18 - Balance, December 31, 2022 $ 336 $ 15 Non-pension benefits plans Balance, January 1, 2022 $ 91 $ - Amortized in current period (2) - Current year addition to AOCI or regulatory assets (62) (10) Change in FX rate 4 - Balance, December 31, 2022 $ 31 $ (10) As at December 31 December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 15 $ (10) $ 30 $ - Deferred income tax expense (recovery) 7 1 8 (1) AOCI, net of tax 22 (9) 38 (1) Regulatory assets 336 31 192 91 AOCI, net of tax and regulatory assets $ 358 $ 22 $ 230 $ 90 Benefit Cost Components Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 41 $ 4 $ 43 $ 5 Interest cost 80 9 67 8 Expected return on plan assets (144) - (132) (1) Current year amortization of: 8 - 21 3 21 2 24 2 Settlement, curtailments 2 - - - Total $ 8 $ 15 $ 23 $ 17 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,482 2,151 during the year. The market-related value of assets is based on a five-year 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 assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad range of investment and non-investment 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: 7% to 17% 36% to 60% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Fixed income 30% to 50% Equities 50% to 70% Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company. The following tables set out the classification of the methodology used by the Company to fair value its investments: millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % As at December 31, 2021 Cash and cash equivalents $ - $ 60 $ - $ 60 2 % Net in-transits - (84) - (84) (3) % Equity securities: - 97 - 97 4 % - 366 - 366 14 % - 215 - 215 8 % Fixed income securities: - - 132 132 5 % - - 117 117 4 % - 8 3 11 - % Mutual funds - 86 - 86 3 % Other - 1 (1) - - % Open-ended investments measured at NAV 952 - - 952 35 % Common collective trusts measured at NAV (2) 750 - - 750 28 % Total $ 1,702 $ 749 $ 251 $ 2,702 100 % (1) NAV investments are open-ended registered NAV’s are calculated at least monthly (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value. Post-Retirement Benefit Plans There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exceptions to this is the NMGC Retiree Medical Plan, which is fully funded. Investments in Emera As at December 31, 2022 and 2021, the assets related to the pension funds and post-retirement benefit plans did 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 dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2023 $ 44 $ 20 Expected benefit payments 2023 164 22 2024 161 23 2025 168 23 2026 172 22 2027 178 22 2028 – 2032 919 105 Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2022 2021 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Benefit cost for year ended December 31: Discount rate - past service 3.05 % 2.81 % 2.49 % 2.48 % Discount rate - future service 3.18 % 2.92 % 2.64 % 2.51 % Expected long-term return on plan assets 6.07 % 1.32 % 5.86 % - % Rate of compensation increase 3.31 % 3.29 % 2.89 % 3.04 % Health care trend - 5.09 % - 5.64 % - 3.77 % - 4.35 % 2042 2038 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. Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2022 was $ 41 45

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2022
22. Goodwill
Goodwill	22. The change in goodwill for the year ended December 31 is due to the following: millions of dollars 2022 2021 Balance, January 1 $ 5,696 $ 5,720 GBPC impairment charge (1) (73) - Change in FX rate 389 (24) Balance, December 31 $ 6,012 $ 5,696 (1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $ 30 Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated Balance Sheets at December 31, 2022, primarily relates to TECO Energy. Emera’s reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC. In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding that the fair value of the reporting units exceeded their respective carrying amounts, and as such, no quantitative assessments were performed and no reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income approach and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over carrying amount, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $ 73 to nil as at December 31, 2022. This non-cash charge is included in “Impairment charge” on the Consolidated Statements of Income.

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2022
23. Short-Term Debt
Short-Term Debt	23. Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non- revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following: millions of dollars 2022 Weighted average interest rate 2021 Weighted average interest rate Tampa Electric Company ("TEC") Advances on term, revolving and accounts receivable facilities $ 1,380 5.00 % $ 945 0.58 % Emera Non-revolving term facilities 796 5.19 % 400 0.96 % Bank indebtedness - - % 6 - % TECO Finance Advances on revolving credit and term facilities 481 5.47 % 355 1.20 % NMGC Advances on revolving credit facilities 59 5.15 % 25 1.20 % GBPC Advances on revolving credit facilities 10 5.25 % 10 5.25 % NSPI Bank indebtedness - - % 1 - % Short-term debt $ 2,726 $ 1,742 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 dollars Maturity 2022 2021 TEC - Unsecured committed revolving credit facility 2026 $ 1,084 $ 1,014 TECO Energy/TECO Finance - revolving credit facility 2026 542 507 Emera - non-revolving term facility 2023 400 400 Emera - non-revolving term facility 2023 400 - TEC - Unsecured non-revolving facility 2023 542 634 NMGC - revolving credit facility 2026 169 158 GBPC - revolving credit facility on demand 18 16 Total $ 3,155 $ 2,729 Less: Advances under revolving credit and term facilities 2,731 1,735 Letters of credit issued within the credit facilities 4 4 Total advances under available facilities 2,735 1,739 Available capacity under existing agreements $ 420 $ 990 The weighted average interest rate on outstanding short-term debt at December 31, 2022 was 5.01 cent (2021 – 0.83 Recent Significant Financing Activity by Segment Florida Electric Utilities On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the maturity date from December 16, 2022 December 13, 2023 500 million USD to $ 400 prior agreement. Other On December 16, 2022, Emera amended its $ 400 maturity from December 16, 2022 December 16, 2023 . There were no other significant changes in commercial terms from the prior agreement. On August 2, 2022, Emera entered into a $ 400 August 2, 2023 . The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2022
Other Current Liabilities
Other Current Liabilities	24. As at December 31 December 31 millions of dollars 2022 2021 Accrued charges $ 174 $ 157 Nova Scotia Cap-and-Trade Program provision (note 7) 172 - Accrued interest on long-term debt 97 75 Pension and post-retirement liabilities (note 21) 33 27 Sales and other taxes payable 14 6 Income tax payable 9 6 Other 80 95 $ 579 $ 366

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2022
25. Long-term Debt
Long-term Debt	25. Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the following: Weighted average interest rate (1) millions of dollars 2022 2021 Maturity 2022 2021 Emera Bankers acceptances, LIBOR loans Variable Variable 2027 $ 403 $ 378 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) (2) 6.75% 6.75% 2076 1,625 1,521 $ 2,528 $ 2,399 Emera Finance Unsecured senior notes (USD) 3.65% 3.65% 2024 - 2046 $ 3,725 $ 3,487 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.15% 4.15% 2024 - 2052 $ 4,341 $ 3,683 PGS Fixed rate notes and bonds (USD) 3.78% 3.78% 2024 - 2052 $ 772 $ 660 NMGC Fixed rate notes and bonds (USD) 3.11% 3.11% 2026 - 2051 $ 521 $ 488 Non-revolving term facility, floating rate Variable Variable 2024 108 101 $ 629 $ 589 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 203 $ 190 NSPI Discount notes Variable Variable 2024 - 2027 $ 881 $ 376 Medium term fixed rate notes 5.14% 5.14% 2025 - 2097 2,665 2,665 $ 3,546 $ 3,041 EBP Senior secured credit facility Variable Variable 2026 $ 249 $ 249 ECI Secured senior notes (USD) Variable Variable 2026 $ 86 $ 84 Amortizing fixed rate notes (USD) 3.97% 3.97% 2024 - 2026 100 $ 104 Non-revolving term facility, floating rate Variable Variable 2027 30 $ 28 Non-revolving term facility, fixed rate 2.05% 2.36% 2025 - 2026 91 $ 101 Secured fixed rate senior notes (4) 3.06% 4.43% 2023 - 2029 142 $ 161 $ 449 $ 478 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 2 $ 3 Debt issuance costs (126) (121) Amount due within one year (574) (462) $ (698) $ (580) Long-Term Debt $ 15,744 $ 14,196 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2022, the Company recognized $ 110 102 subordinated notes. (3) A substantial part of Tampa currently no bonds outstanding under Tampa (4) Notes are issued and payable in either USD or BBD. (5) On acquisition of TECO Energy, Emera recorded 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 dollars Maturity 2022 2021 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 NSPI - revolving credit facility (1) December 2027 800 600 NSPI - non-revolving credit facility July 2024 400 - NMGC - non-revolving credit facility March 2024 108 - ECI – revolving credit facilities 2023-2032 11 27 Total $ 2,219 $ 1,527 Less: Borrowings under credit facilities 1,396 770 Letters of credit issued inside credit facilities 12 124 Use of available facilities $ 1,408 $ 894 Available capacity under existing agreements $ 811 $ 633 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 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 significant covenants are listed below: As at Financial Covenant Requirement December 31, 2022 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 Recent Significant Financing Activity by Segment Florida Electric Utilities On September 15, 2022, TEC repaid a $ 250 existing credit facilities. On July 12, 2022, TEC completed an issuance of $ 600 $ 300 3.875 July 12, 2024 , and $ 300 5 July 15, 2052 . Canadian Electric Utilities On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date from December 16, 2026 December 16, 2027 600 to $ 800 On July 15, 2022, NSPI entered into a $ 400 July 15, 2024 . The credit facility contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Gas Utilities and Infrastructure On September 23, 2022, NMGC amended its $ 80 facility to extend the maturity from September 23, 2022 , to March 22, 2024 . There were no other changes in commercial terms from the prior agreement. On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity from June 30, 2025 June 30, 2026 . There were no other changes in commercial terms from the prior agreement. Other Electric Utilities On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 March 25, 2027 . There were no other changes in commercial terms from the prior agreement. Other On December 16, 2022, Emera amended its $ 900 maturity date from June 30, 2026 June 30, 2027 . There were no other significant changes in commercial terms from the prior agreement. Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Emera $ 500 $ - $ - $ 1,625 $ 403 $ - $ 2,528 Emera US Finance LP - 407 - 1,016 - 2,302 3,725 Tampa Electric - 356 - - - 3,985 4,341 PGS - 51 - - - 721 772 NMGC - 108 - 95 - 426 629 NMGI - 203 - - - - 203 NSPI - 398 125 40 483 2,500 3,546 EBP - - - 249 - - 249 ECI 74 90 137 85 60 3 449 Total $ 574 $ 1,613 $ 262 $ 3,110 $ 946 $ 9,937 $ 16,442

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
26. Asset Retirement Obligations
Asset Retirement Obligations	26. AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution 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 dollars 2022 2021 Balance, January 1 $ 174 $ 178 Accretion included in depreciation expense 9 10 Change in FX rate 3 (1) Additions 1 1 Accretion deferred to regulatory asset (included in PP&E) 1 (2) Liabilities settled (1) (1) (13) Revisions in estimated cash flows (13) - Other - 1 Balance, December 31 $ 174 $ 174 (1) Tampa Electric decrease in ARO in 2021 was due to the closure of CCR management facilities.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
27. Commitments and Contingencies Disclosure
Commitments and Contingencies	27. Commitments As at December 31, 2022, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Transportation (1) $ 693 $ 516 $ 423 $ 383 $ 367 $ 2,817 $ 5,199 Purchased power (2) 269 243 237 228 243 2,145 3,365 Fuel, gas supply and storage 1,161 282 138 40 5 1 1,627 Capital projects 264 89 4 1 - - 358 Equity investment commitments (3) 240 - - - - - 240 Other 149 142 132 49 42 189 703 $ 2,776 $ 1,272 $ 934 $ 701 $ 657 $ 5,152 $ 11,492 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 144 (2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths. (3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations relation to the Maritime Link and LIL. NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 UARB approved the collection of $ 164 The timing and amounts payable to NSPML for the remainder of the 38 -year commitment period are subject to UARB approval. Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the date the NS Block delivery obligation commenced, and continuing for 50 years . As transmission rights are contracted, the obligations are included within “Other” in the above table. Legal Proceedings TECO Guatemala Holdings (“TGH”) Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy, divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First Award”) and, in November 2020, Guatemala made a payment of approximately $ 38 and final satisfaction of the First Award. On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH additional damages and costs against Guatemala of more than $ 35 “Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in connection with the Second Award. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount was approximately $ 2 Guatemala filed an application with ICSID for annulment of the Second Award. On March 31, 2021, ICSID constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held before the ad hoc Committee beginning on July 27, 2022. On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the Second Award. Pursuant to the settlement agreement, on December 15, 2022, Guatemala paid TGH $ 46 million USD and the parties agreed to settle all outstanding disputes, concluding this matter. This amount was recognized in “Other Income, net” on the Consolidated Statements of Income. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa 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, 2022, TEC estimated its financial liability to be $ 17 13 primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs 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 respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are believed to be currently credit- worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings. Other Legal Proceedings Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 15 and note 16. Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. The Board of Directors established a Risk and Sustainability Committee (‘RSC”) in September 2021. The RSC’s mandate includes oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its sustainability objectives. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions. As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034, with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. Regulators administer legislation covering material aspects of the utilities’ businesses, including customer rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities. Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements. Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. State and local policies in some United States jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations, including electrification legislation, could adversely impact PGS and NMGC. Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors, or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect on the Company. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the CAD and, particularly, the USD, which could positively or adversely affect results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including FX. The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI. Liquidity and Capital Market Risk Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions, and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access 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 number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its regulatory framework and the legislative environment, political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation. General Economic Risk The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity and natural gas, and in turn the Company’s financial results. Adverse changes in general economic conditions and inflation may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs and regulatory assets. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. As with most other utilities and other similar yield-returning investments, Emera’s share price may be affected by changes in interest rates and could underperform the market in an environment of rising interest rates. Inflation Risk The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining agreements that mitigate the short-term impact of inflation on labour costs. Commodity Price Risk The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. These include the Company’s commercial arrangements, such as the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk. Regulated Utilities The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which are difficult to predict and may change rapidly, including but not limited to currency fluctuations, changes in global economic conditions, natural disasters, transportation or production disruptions, and geo-political risks such as political instability, conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales. Emera Energy Marketing and Trading Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business. To including an estimated VaR analysis of its exposures. The VaR potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2022 : TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $ 45 USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $ 27 TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $ 13 In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $ 13 USD. Emera Inc. has issued a guarantee of up to $ 35 relating to outstanding notes of GBPC . The guarantee for the notes will expire in May 2023 . Emera Inc. has issued a guarantee of $ 66 guarantee will automatically terminate on the date upon which the obligations have been repaid in full. NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), in the amount of $ 119 118 The Company has standby letters of credit and surety bonds in the amount of $ 145 (December 31, 2020 – $ 148 subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required. Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed as at December 31, 2022 was $ 63 64 Collaborative Arrangements For the years ended December 31, 2022 and 2021, 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. In 2022, NSPI recognized $ 12 18 purchased power” and $ 3 3

Cumulative Preferred Stock

Cumulative Preferred Stock	12 Months Ended
	Dec. 31, 2022
28. Cumulative Preferred Stock
Cumulative Preferred Stock	28. Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2022 December 31, 2021 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.1802 2.65 August 15, 2023 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A 4.900 1.2250 4.90 August 15, 2023 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (6) 4.600 1.1500 November 15, 2026 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 Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 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 Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.9 0 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable 1.84 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2023, February 15, 2025 and August 15, 2023, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) First Preferred Shares, Series E are redeemable at $ 25.00 (6) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00 First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

Non-Controlling Interest in Sub

Non-Controlling Interest in Subsidiaries	12 Months Ended
	Dec. 31, 2022
29. Non-Controlling Interest in Subsidiaries
Non-Controlling Interest in Subsidiaries	29. As at December 31 December 31 millions of dollars 2022 2021 Preferred shares of GBPC $ 14 $ 14 Domlec (1) - 20 $ 14 $ 34 (1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4. Preferred shares of GBPC: Authorized: 10,000 2022 2021 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually . The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of all of GBPC’s current and future common stock.

Supplemental Information to Con

Supplemental Information to Consolidated Statements of Cash Flows	12 Months Ended
	Dec. 31, 2022
30. Supplementary Information to Consolidated Statements of Cash Flows
Supplementary Information to Consolidated Statements of Cash Flows	30. SUPPLEMENTARY CASH FLOWS For the Year ended December 31 millions of dollars 2022 2021 Changes in non-cash working capital: $ (214) $ (84) (1) (636) (364) 423 289 (2) 193 7 Total non-cash working capital $ (234) $ (152) (1) Includes $( 162 ) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes $ 172 asset (FAM) balance is included in operating cash flow before working operating activities. Supplemental disclosure of cash paid (received): Interest $ 699 $ 603 Income taxes $ 67 $ 24 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 237 $ 214 Reclassification of long-term debt to short-term debt $ 500 $ - Decrease in accrued capital expenditures $ (13) $ (45) Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ (157) $ (108)

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2022
31. Stock-Based Compensation
Stock-based Compensation	31. Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 7 million common shares. As at December 31, 2022, Emera is in compliance with this requirement. Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year ended December 31, 2022 was $ 3 3 Consolidated Statements of Income. The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2022. Stock-Based Compensation Plans Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2022, Emera is in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the 27 months termination without just cause or death, and within sixty days cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised during the full term of the option following the option holders date of retirement, six months following a termination without just cause or death, and within sixty days following the date of termination for just cause or resignation. If stock options are not exercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted, for the year-ended December 31: 2022 2021 Weighted average fair value per option $ 5.35 $ 3.63 Expected term (1) 5 5 Risk-free interest rate (2) 1.79 % 0.60 % Expected dividend yield (3) 4.55 % 5.00 % Expected volatility (4) 18.87 % 19.14 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period 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 2022: Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2021 2,590,304 $ 48.48 1,452,475 $ 3.18 Granted 467,100 58.26 467,100 5.35 Exercised (203,525) 43.87 N/A N/A Vested N/A N/A (571,175) 2.83 Options outstanding December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Options exercisable December 31, 2022 (2)(3) 1,505,479 $ 46.59 (1) As at December 31, 2022, there was $ 4 expected to be recognized over a weighted average period of approximately 3 3 3 (2) As at December 31, 2022, the weighted average remaining term of vested options was 5 $ 10 6 21 (3) As at December 31, 2022, the fair value of options that vested in the year was $ 2 1 Compensation cost recognized for stock options for the year ended December 31, 2022 was $ 2 (2021 – $ 2 As at December 31, 2022, cash received from option exercises was $ 9 14 total intrinsic value of options exercised for the year ended December 31, 2022 was $ 4 6 million). The range of exercise prices for the options outstanding as at December 31, 2022 was $ 32.35 $ 60.03 32.35 60.03 ). Share Unit Plans The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. A summary of the activity related to employee and director DSUs for the year ended December 31, 2022 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, 2021 610,601 $ 39.22 614,365 $ 43.80 Granted including DRIP 76,252 52.42 104,465 57.89 Exercised (59,630) 31.57 (54,572) 46.04 Outstanding and exercisable as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83 Compensation cost recovery recognized for employee and director DSU’s for the year ended December 31, 2022 was $ 6 9 recovery for share units realized for the year ended December 31, 2022 was $ 2 3 tax recovery). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2022 for employees was $ 33 39 shares for the year ended December 31, 2022 for directors was $ 34 39 payments made during the year ended December 31, 2021 associated with the DSU plan was $ 8 (2021 – $ 11 Performance Share Unit Plan Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. A summary of the activity related to employee PSUs for the year ended December 31, 2022 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2021 951,935 $ 48.60 $ 66 Granted including DRIP 242,462 59.30 Exercised (357,960) 42.85 Forfeited (145,991) 44.28 Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $ 18 (2021 – $ 12 ended December 31, 2022 were $ 5 3 ended December 31, 2021 associated with the PSU plan was $ 24 29 Restricted Share Unit Plan Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. A summary of the activity related to employee RSUs for the year ended December 31, 2022 is presented in the following table: Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2021 343,952 $ 54.64 $ 24 Granted including DRIP 180,426 59.30 Exercised (134) 54.63 Forfeited (15,776) 56.08 Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30 Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $ 9 (2021 – $ 8 ended December 31, 2022 were $ 2 2 ended December 31, 2022 associated with the RSU plan was nil nil ).

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2022
32. Variable Interest Entities
Variable Interest Entities	32. 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 controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment. BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, 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, risks related to the activities of the SIF. Any 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 the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF. The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2022 December 31, 2021 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 501 $ 6 $ 533 $ 11

Comparative Information

Comparative Information	12 Months Ended
	Dec. 31, 2022
33. Comparative Information
Comparative Information	33. 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, 2022
34. Subsequent Events
Subsequent Events	34. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 23, 2023, the date the financial statements were issued.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
1. Summary of Significant Accounting Policies
Basis of Presentation	Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, 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 (“CAD”), unless otherwise indicated.
Principles of Consolidation	Principles of Consolidation These consolidated financial statements 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 Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impacts its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction.
Use of Management Estimates	Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.
Regulatory Matters	Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 7.
Foreign Currency Translation	Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing 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 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 USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”).
Revenue Recognition	Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity and 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 megawatt hours (“MWh”) or therms delivered to customers at the established rates 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. Non-regulated Revenue: Marketing and trading margins are 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 the terms of the contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue.
Lessee, Leases	The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets, as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component.
Lessor, Leases	Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component.
Franchise Fees and Gross Receipts	Franchise Fees and Gross Receipts Tampa through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” 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 fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.
Property, Plant and Equipment	Property, Plant and Equipment PP&E are recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units are included in “Property, plant and equipment”. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase the overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “Property, plant and equipment,” consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval.
Goodwill	Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded. 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 cash flow analysis which relies on management’s best estimate of the reporting units’ projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2022, $ 6,009 purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no impairment charges were recognized. In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro- economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $ 73 nil December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets 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 to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Tampa estimated service lives of the related properties, as required by regulatory practices. Tampa deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective 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. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified 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 normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory 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 when 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 future rates. Tampa Electric has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric’s will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory, economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” 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 Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition.
Receivables	Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
Allowance for Credit Losses	Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
Inventory	Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost will be recovered in future customer rates.
Asset Impairment	Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates 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 operations 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 based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2022 or 2021. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of 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. No required in either 2022 or 2021. Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at fair value, with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No
Asset Retirement Obligations and Cost of Removal	Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation, using the Company’s credit 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 governmental 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 accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs which are not recognized in the consolidated financial statements, as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within 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 liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays.
Stock-Based Compensation	Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the fair value-based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the 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 measured at fair value and re-measured at fair value at each reporting date, with the change in liability recognized in income.
Employee Benefits	Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets. The components of net periodic benefit cost other than the service cost component are included in “Other income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
5. Segment Information
Segment Information	Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expense), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 Impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2021 Operating revenues from external customers (1) $ 2,718 $ 1,501 $ 1,276 $ 445 $ (175) $ $ 5,765 Inter-segment revenues (1) 6 - 4 - 18 (28) 2,724 1,501 1,280 445 (157) (28) 5,765 Regulated fuel for generation and purchased power 894 654 - 218 - (3) 1,763 Regulated cost of natural gas - - 472 - - - 472 OM&G 536 291 325 140 106 (30) 1,368 Provincial, state and municipal taxes 212 43 69 4 2 - 330 Depreciation and amortization 469 246 121 58 8 - 902 Income from equity investments - 103 20 4 16 - 143 Other income (expenses), net 59 12 11 15 1 (5) 93 Interest expense, net (2) 138 132 64 21 256 - 611 Income tax expense (recovery) 72 9 62 1 (150) - (6) Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 50 - 50 Net income (loss) attributable to common shareholders $ 462 $ 241 $ 198 $ 21 $ (412) $ - $ 510 Capital expenditures $ 1,331 $ 366 $ 515 $ 111 $ 5 $ - $ 2,328 As at December 31, 2021 Total assets $ 17,903 $ 7,418 $ 6,666 $ 1,402 $ 2,034 $ (1,179) $ 34,244 Investments subject to significant influence $ - $ 1,215 $ 123 $ 44 $ - $ - $ 1,382 Goodwill $ 4,436 $ - $ 1,189 $ 68 $ 3 $ - $ 5,696 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes the elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2021, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2022 2021 United States $ 5,346 $ 3,754 Canada 1,725 1,566 Barbados 384 292 The Bahamas 122 110 Dominica 11 43 $ 7,588 $ 5,765 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2022 2021 United States $ 17,382 $ 14,978 Canada 4,689 4,440 Barbados 583 535 The Bahamas 342 322 Dominica - 78 $ 22,996 $ 20,353

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2022
6. Revenue
Revenue	Electric Gas Other Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other regulatory deferrals 371 28 12 - - - 411 Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) $ 7,154 Non-Regulated Revenue Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) $ 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 For the year ended December 31, 2021 Regulated Revenue Residential $ 1,449 $ 797 $ 165 $ 642 $ - $ - $ 3,053 Commercial 754 407 232 379 - - 1,772 Industrial 215 237 26 65 - (2) 541 Other regulatory deferrals 289 27 7 - - - 323 Other (1) 17 33 15 122 - (8) 179 Finance income (2)(3) - - - 58 - - 58 $ 2,724 $ 1,501 $ 445 $ 1,266 $ - $ (10) 5,926 Non-Regulated Marketing and trading margin (4) - - - - 102 - 102 Other non-regulated operating revenue - - - 14 30 (21) 23 Mark-to-market (3) - - - - (289) 3 (286) $ - $ - $ - $ 14 $ (157) $ (18) (161) Total operating revenues $ 2,724 $ 1,501 $ 445 $ 1,280 $ (157) $ (28) $ 5,765 (1) Other includes rental revenues, which do not 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 customers.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
7. Regulatory Assets and Liabilities
Regulatory Assets	As at December 31 December 31 millions of dollars 2022 2021 Regulatory assets Deferred income tax regulatory assets $ 1,166 $ 1,045 Cost recovery clauses 707 114 Tampa Electric capital cost recovery for early retired assets 674 657 Pension and post-retirement medical plan 369 291 FAM 307 145 Storm reserve 103 - NMGC winter event gas cost recovery 69 117 Storm restoration 35 35 Deferrals related to derivative instruments 30 23 Environmental remediations 27 27 Stranded cost recovery 27 26 Other 106 86 $ 3,620 $ 2,566 Current $ 602 $ 253 Long-term 3,018 2,313 Total regulatory assets $ 3,620 $ 2,566 Regulatory liabilities Accumulated reserve - cost of remova l 895 819 Deferred income tax regulatory liabilities 877 863 Deferrals related to derivative instruments 230 241 NMGC gas hedge settlements (note 18) 162 - Cost recovery clauses 70 35 Self-insurance fund (note 32) 30 28 Storm reserve - 58 Other 9 11 $ 2,273 $ 2,055 Current $ 495 $ 290 Long-term 1,778 1,765 Total regulatory liabilities $ 2,273 $ 2,055
Regulatory Liabilities	As at December 31 December 31 millions of dollars 2022 2021 Regulatory assets Deferred income tax regulatory assets $ 1,166 $ 1,045 Cost recovery clauses 707 114 Tampa Electric capital cost recovery for early retired assets 674 657 Pension and post-retirement medical plan 369 291 FAM 307 145 Storm reserve 103 - NMGC winter event gas cost recovery 69 117 Storm restoration 35 35 Deferrals related to derivative instruments 30 23 Environmental remediations 27 27 Stranded cost recovery 27 26 Other 106 86 $ 3,620 $ 2,566 Current $ 602 $ 253 Long-term 3,018 2,313 Total regulatory assets $ 3,620 $ 2,566 Regulatory liabilities Accumulated reserve - cost of remova l 895 819 Deferred income tax regulatory liabilities 877 863 Deferrals related to derivative instruments 230 241 NMGC gas hedge settlements (note 18) 162 - Cost recovery clauses 70 35 Self-insurance fund (note 32) 30 28 Storm reserve - 58 Other 9 11 $ 2,273 $ 2,055 Current $ 495 $ 290 Long-term 1,778 1,765 Total regulatory liabilities $ 2,273 $ 2,055

Investments Subject to Signif_2

Investments Subject to Significant Influence and Equity Income (Tables)	12 Months Ended
	Dec. 31, 2022
Variable Interest Entity [Line Items]
Investments subject to significant influence	Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2022 2021 2022 2021 2022 LIL (1) $ 740 $ 682 $ 58 $ 54 31.9 NSPML 501 533 29 49 100.0 M&NP 128 123 21 20 12.9 Lucelec (2) 49 44 4 4 19.5 Bear Swamp - - 17 16 50.0 $ 1,418 $ 1,382 $ 129 $ 143 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $ 179 Bear Swamp's credit investment balance of $ 95 104 Consolidated Balance Sheets.
NSPML
Variable Interest Entity [Line Items]
Investments subject to significant influence	Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2022 2021 Balance Sheets Current assets $ 17 $ 25 PP&E 1,517 1,587 Regulatory assets 265 247 Non-current assets 29 31 Total assets $ 1,828 $ 1,890 Current liabilities $ 48 $ 50 Long-term debt (1) 1,149 1,189 Non-current liabilities 130 118 Equity 501 533 Total liabilities and equity $ 1,828 $ 1,890 (1) The project debt has been guaranteed by the Government of Canada.

Other Income, Net (Table)

Other Income, Net (Table)	12 Months Ended
	Dec. 31, 2022
9. Other Income, Net
Components of other income (expense), net	For the Year ended December 31 millions of dollars 2022 2021 TECO Guatemala Holdings award (1) $ 63 $ - AFUDC 52 61 Other 30 32 $ 145 $ 93 (1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
10. Income Taxes
Income tax provision	The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2022 2021 Income before provision for income taxes $ 1,194 $ 555 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 346 161 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (70) (62) Foreign tax rate variance (44) (42) Amortization of deferred income tax regulatory liabilities (33) (33) GBPC impairment charge 21 - Tax effect (10) (16) Tax credits (18) (13) Other (7) (1) Income tax expense (recovery) $ 185 $ (6) Effective income tax rate 15% (1%)
Composition of taxes on income from continuing operations	millions of dollars 2022 2021 Current income taxes $ 25 $ 20 8 11 Deferred income taxes 120 (33) 252 118 - 2 Investment tax credits (7) (11) Operating loss carryforwards (92) (64) (121) (49) Income tax expense (recovery) $ 185 $ (6) The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2022 2021 Canada $ 173 $ 244 United States 1,063 289 Other (42) 22 Income before provision for income taxes $ 1,194 $ 555
Deferred income tax assets and liabilities	The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2022 2021 Deferred income tax assets: Tax loss carryforwards $ 1,207 $ 873 Tax credit carryforwards 415 375 Regulatory liabilities - cost of removal 177 170 Derivative instruments 45 188 Other 428 434 Total deferred income tax assets before valuation allowance 2,272 2,040 Valuation allowance (312) (256) Total deferred income tax assets after valuation allowance $ 1,960 $ 1,784 Deferred income tax (liabilities): PP&E $ (2,981) $ (2,622) Regulatory assets (219) (78) Derivative instruments (125) (197) Other (594) (460) Total deferred income tax liabilities $ (3,919) $ (3,357) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 237 $ 295 Long-term deferred income tax liabilities (2,196) (1,868) Net deferred income tax liabilities $ (1,959) $ (1,573)
Net operating loss ("NOL"), capital loss and tax credit carryforwards and their expiration periods	Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2022 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,372 $ (977) $ 1,395 2026 - 2042 79 (79) - Indefinite United States $ 2,082 $ - $ 2,082 2032 - Indefinite 1,489 - 1,489 2032 - Indefinite 415 - 415 2025 - 2042 Other $ 73 $ (33) $ 40 2023 - 2029
Details of the change in unrecognized tax benefits	millions of dollars 2022 2021 Balance, January 1 $ 28 $ 30 Increases due to tax positions related to current year 5 4 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (2) (1) Decreases due to settlement with tax authorities - (6) Balance, December 31 $ 33 $ 28

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2022
11. Common Stock
Common Stock	Authorized : 2022 2021 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, December 31, 2021 261.07 $ 7,242 251.43 $ 6,705 Issuance of common stock under ATM program (1)(2) 4.07 248 4.99 284 Issued under the DRIP, 4.21 238 3.90 215 Senior management stock options exercised and Employee Share Purchase Plan 0.60 34 0.75 38 Balance, December 31, 2022 269.95 $ 7,762 261.07 $ 7,242 (1) As at December 31, 2021, a total of 4,987,123 $ 57.63 287 284 (2) For the year ended December 31, 2022, 4,072,469 of $ 61.31 250 248

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
12. Earnings Per Share
Computation of basic and diluted earnings per share	The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2022 2021 Numerator Net income attributable to common shareholders $ 945.1 $ 510.5 Diluted numerator 945.1 510.5 Denominator Weighted average shares of common stock outstanding 265.5 255.9 Weighted average deferred share units outstanding - 1.3 Weighted average shares of common stock outstanding – basic 265.5 257.2 Stock-based compensation 0.4 0.4 Weighted average shares of common stock outstanding – diluted 265.9 Earnings per common share Basic $ 3.56 $ 1.98 Diluted $ 3.55 $ 1.98 (1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are in the calculation of earnings per common share.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2022
13. Accumulated Other Comprehensive Income
Components of accumulated other comprehensive income	The components of AOCI are as follows: millions of dollars Unrealized gain (loss) on translation of self-sustaining foreign operations Net change in net investment hedges Gains on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 629 (97) - (1) - 531 - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 For the year ended December 31, 2021 Balance, January 1, 2021 $ 52 $ 30 $ 1 $ (1) $ (161) $ (79) (42) 5 18 - - (19) - - (1) - 124 123 Net current period other comprehensive income (loss) (42) 5 17 - 124 104 Balance, December 31, 2021 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25
Reclassifications out of accumulated other comprehensive income (loss)	The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of dollars 2022 2021 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (1) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 10 $ 24 Pension and post-retirement benefits 15 102 Total before tax 25 126 Income tax expense (1) (2) Total net of tax $ 24 $ 124 Total reclassifications out of AOCI, net of tax, for the period $ 22 $ 123

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2022
14. Inventory
Inventory	As at December 31 December 31 millions of dollars 2022 2021 Fuel $ 404 $ 255 Materials 365 283 Total $ 769 $ 538

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
15. Derivative Instruments
Derivative assets and liabilities	Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2022 2021 2022 2021 Regulatory deferral: $ 186 $ 146 $ 42 $ 16 18 7 1 8 52 88 - - 256 241 43 24 HFT derivatives: 89 33 77 32 340 208 1,224 818 429 241 1,301 850 Other derivatives: - 11 5 - 5 - 23 - 5 11 28 - Total gross current derivatives 690 493 1,372 874 Impact of master netting agreements: (18) (4) (18) (4) (276) (188) (276) (188) Total impact of master netting agreements (294) (192) (294) (192) Total derivatives $ 396 $ 301 $ 1,078 $ 682 Current (1) 296 195 888 533 Long-term (1) 100 106 190 149 Total derivatives $ 396 $ 301 $ 1,078 $ 682 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Realized and unrealized gains (losses) with respect to derivatives	Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2022 2021 Unrealized gain (loss) in regulatory assets $ - $ (69) $ 1 $ - $ (7) $ 9 Unrealized gain (loss) in regulatory liabilities 28 343 16 88 218 (3) Realized loss in regulatory assets - 48 - - - - Realized gain in regulatory liabilities - (41) - - (3) - Realized (gain) loss in inventory (1) - (121) 1 - (8) 5 Realized (gain) loss in regulated fuel for generation and purchased power (2) (64) (146) - - (39) 5 Total change in derivative instruments $ (36) $ 14 $ 18 $ 88 $ 161 $ 16 (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. For the Year ended December 31 millions of dollars 2022 2021 Power swaps and physical contracts in non-regulated operating revenues $ 17 $ 4 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 47 (142) Total gains (losses) in net income $ 64 $ (138) For the Year ended December 31 millions of dollars 2022 2021 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ (5) $ - $ 11 Unrealized loss in other income, net (18) - (15) - Realized gain (loss) in OM&G - (17) - 15 Realized gain (loss) in other income, net (6) - 18 - Total gains (losses) in net income $ (24) $ (22) $ 3 $ 26
Notional volumes of derivatives designated for regulatory deferral that are expected to settle as outlined	millions 2023 2024-2026 Physical natural gas purchases: Natural gas (Mmbtu) 6 - Commodity swaps and forwards purchases: Natural gas (Mmbtu) 18 12 Power (MWh) 1 1 FX swaps and forwards: FX contracts (millions of USD) $ 206 $ 123 Weighted average rate 1.2832 1.3064 % of USD requirements 50% 28% 2027 and millions 2023 2024 2025 2026 thereafter Natural gas purchases (Mmbtu) 319 92 42 36 131 Natural gas sales (Mmbtu) 492 205 105 6 19 Power purchases (MWh) 2 - - - - Power sales (MWh) 2 - - - -
Concentration Risk	Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2022 December 31, 2021 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 455 19% $ 384 24% Commercial 192 8% 167 10% Industrial 121 5% 54 3% Other 122 5% 91 6% 890 37% 696 43% Trading group: Credit rating of A- or above 125 5% 66 4% Credit rating of BBB- to BBB+ 75 3% 107 7% Not rated 307 13% 132 8% 507 21% 305 19% Other accounts receivable 585 25% 329 20% 1,982 83% 1,330 82% Derivative Instruments (current and long-term) Credit rating of A- or above 202 9% 155 9% Credit rating of BBB- to BBB+ 8 0% 22 1% Not rated 186 8% 124 8% 396 17% 301 18% $ 2,378 100% $ 1,631 100%
Cash Collateral	As at December 31 December 31 millions of dollars 2022 2021 Cash collateral provided to others $ 224 $ 212 Cash collateral received from others $ 112 $ 100

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
16. Fair Value Measurements
Classification of the methodology used by the Company to fair value its derivatives	The following tables set out the classification of the methodology used by the Company to fair value its derivatives As at December 31, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 5 23 - 28 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) As at December 31, 2021 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 101 $ 41 $ - $ 142 - 7 - 7 - - 88 88 101 48 88 237 HFT derivatives: 4 5 4 13 (1) 29 12 40 3 34 16 53 Other derivatives: 11 - - 11 Total assets 115 82 104 301 Liabilities Regulatory deferral: 7 5 - 12 - 8 - 8 7 13 - 20 HFT derivatives: 4 5 3 12 13 122 515 650 17 127 518 662 Total liabilities 24 140 518 682 Net assets (liabilities) $ 91 $ (58) $ (414) $ (381)
Change in the fair value of the Level 3 financial assets	The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2022 $ 88 $ 4 $ 12 $ 104 Realized gains included in fuel for generation and purchased power (64) - - (64) Unrealized gains included in regulatory liabilities 28 - - 28 Total realized and unrealized gains included in non- regulated operating revenues - - 22 22 Balance, December 31, 2022 $ 52 $ 4 $ 34 $ 90
Change in the fair value of the Level 3 financial liabilities	The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2022 $ 3 $ 515 $ 518 Total realized and unrealized gains (losses) included in non-regulated operating revenues (2) 310 308 Balance, December 31, 2022 $ 1 $ 825 $ 826
Quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy	December 31, 2022 As at Significant Weighted millions of dollars Fair Value Unobservable Input Low High average (1) Assets Liabilities Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (1) Unobservable inputs were weighted by the relative fair value of the instruments. December 31, 2021 As at Significant Weighted millions of dollars Fair Value Unobservable Input Low High average (1) Assets Liabilities Regulatory deferral – Physical $ 88 $ - Third-party pricing $4.51 $26.09 $9.74 natural gas purchases HFT derivatives – Power 4 3 Third-party pricing $37.05 $213.00 $99.34 swaps and physical contracts HFT derivatives – Natural 12 515 Third-party pricing $1.90 $21.53 $8.80 gas swaps, futures, forwards and physical contracts Total $ 104 $ 518 Net liability $ 414 (1) Unobservable inputs were weighted by the relative fair value of the instruments.
Financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value	Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 December 31, 2021 $ 14,658 $ 16,775 $ - $ 16,308 $ 467 $ 16,775

Receivables and Other Current_2

Receivables and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2022
18. Receivables and Other Current Assets
Summary of Receivables And Other Current Assets	18. As at December 31 December 31 millions of dollars 2022 2021 Customer accounts receivable – billed $ 1,096 $ 767 Customer accounts receivable – unbilled 424 318 Allowance for credit losses (17) (21) Capitalized transportation capacity (1) 781 316 NMGC gas hedge settlement receivable (2) 162 - Income tax receivable 9 8 Prepaid expenses 82 65 Other 360 280 Total receivables and other current assets $ 2,897 $ 1,733 (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. (2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
19. Leases
Lessee, Operating Lease and additional information	As at December 31 December 31 millions of dollars Classification 2022 2021 Right-of-use asset Other long-term assets $ 58 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 59 58 Total lease liabilities $ 62 $ 61 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 7 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ - Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.98% 3.98%
Future minimum lease payments under non-cancellable operating leases	Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Minimum lease payments $ 6 $ 6 $ 5 $ 3 $ 3 $ 116 $ 139 Less imputed interest (77) Total $ 62
Net Investment in direct finance leases	As at December 31 December 31 millions of dollars 2022 2021 Total minimum lease payment to be received $ 1,393 $ 947 Less: amounts representing estimated executory costs (205) (165) Minimum lease payments receivable $ 1,188 $ 782 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (733) (443) Net investment in direct finance and sales-type leases $ 638 $ 522 Principal due within one year (included in "Receivables and other current assets") 34 19 Net Investment in direct finance and sales type leases - long-term $ 604 $ 503
Future minimum lease payments to be received for the next five years	As at December 31, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Minimum lease payments to be received $ 90 $ 92 $ 95 $ 94 $ 92 $ 930 $ 1,393 Less: executory costs (205) Total $ 1,188

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
20. Property, Plant and Equipment
Regulated and Non-Regulated Assets	PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2022 2021 Generation 2 131 $ 13,083 $ 11,173 Transmission 10 80 2,731 2,532 Distribution 10 65 6,978 6,305 Gas transmission and distribution 13 83 5,061 4,385 General plant and other 2 71 2,723 2,473 Total cost 30,576 26,868 Less: Accumulated depreciation (1) (9,574) (8,739) 21,002 18,129 Construction work in progress (1) 1,994 2,224 Net book value $ 22,996 $ 20,353 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2022, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 1 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2022
21. Employee Benefit Plans
Changes in benefit obligation and plan assets, and the funded status for all plans	For the Year ended December 31 millions of dollars 2022 2021 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 $ 2,624 $ 318 $ 2,759 $ 339 Service cost 41 4 43 5 Plan participant contributions 6 6 6 4 Interest cost 80 9 67 8 Benefits paid (174) (31) (160) (27) Actuarial gains (480) (79) (89) (10) Settlements and curtailments (6) - - - Foreign currency translation adjustment 67 16 (2) (1) Balance, December 31 $ 2,158 $ 243 $ 2,624 $ 318 Change in plan assets Balance, January 1 $ 2,702 $ 51 $ 2,605 $ 52 Employer contributions 45 24 42 21 Plan participant contributions 6 6 6 4 Benefits paid (174) (31) (160) (27) Actual return on assets, net of expenses (489) (7) 214 2 Settlements and curtailments (6) - - - Foreign currency translation adjustment 79 3 (5) (1) Balance, December 31 $ 2,163 $ 46 $ 2,702 $ 51 Funded status, end of year $ 5 $ (197) $ 78 $ (267)
Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets	millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 1,006 $ 221 $ 140 $ 290 Fair value of plan assets 914 - 35 - Funded status $ (92) $ (221) $ (105) $ (290) millions of dollars 2022 2021 Defined benefit pension plans Defined benefit pension plans ABO $ 111 $ 133 Fair value of plan assets 33 35 Funded status $ (78) $ (98)
Amounts recognized in the Consolidated Balance Sheets	As at December 31 December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (13) $ (20) $ (7) $ (20) Long-term liabilities (80) (201) (100) (270) Other long-term assets 98 24 185 23 AOCI, net of tax and regulatory assets 358 22 230 90 Less: Deferred income tax (expense) recovery in AOCI (7) (1) (8) 1 Net amount recognized $ 356 $ (176) $ 300 $ (176)
Amounts Recognized in AOCI and Regulatory Assets	Regulatory assets Actuarial (gains) losses millions of dollars Defined Benefit Pension Plans Balance, January 1, 2022 $ 192 $ 30 Amortized in current period (21) (10) Current year addition to AOCI or regulatory assets 147 (5) Change in FX rate 18 - Balance, December 31, 2022 $ 336 $ 15 Non-pension benefits plans Balance, January 1, 2022 $ 91 $ - Amortized in current period (2) - Current year addition to AOCI or regulatory assets (62) (10) Change in FX rate 4 - Balance, December 31, 2022 $ 31 $ (10) As at December 31 December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 15 $ (10) $ 30 $ - Deferred income tax expense (recovery) 7 1 8 (1) AOCI, net of tax 22 (9) 38 (1) Regulatory assets 336 31 192 91 AOCI, net of tax and regulatory assets $ 358 $ 22 $ 230 $ 90
Benefit Cost Components	As at Year ended December 31 millions of dollars 2022 2021 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 41 $ 4 $ 43 $ 5 Interest cost 80 9 67 8 Expected return on plan assets (144) - (132) (1) Current year amortization of: 8 - 21 3 21 2 24 2 Settlement, curtailments 2 - - - Total $ 8 $ 15 $ 23 $ 17
Pension Plan Asset Allocations	Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 5% Fixed income 35% to 50% Equities: 7% to 17% 36% to 60% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Fixed income 30% to 50% Equities 50% to 70%
Cassification of the methodology used by the Company to fair value its investments	millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % As at December 31, 2021 Cash and cash equivalents $ - $ 60 $ - $ 60 2 % Net in-transits - (84) - (84) (3) % Equity securities: - 97 - 97 4 % - 366 - 366 14 % - 215 - 215 8 % Fixed income securities: - - 132 132 5 % - - 117 117 4 % - 8 3 11 - % Mutual funds - 86 - 86 3 % Other - 1 (1) - - % Open-ended investments measured at NAV 952 - - 952 35 % Common collective trusts measured at NAV (2) 750 - - 750 28 % Total $ 1,702 $ 749 $ 251 $ 2,702 100 % (1) NAV investments are open-ended registered NAV’s are calculated at least monthly (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly.
Expected cash flows for defined benefit pension and other post-retirement benefit plans	millions of dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2023 $ 44 $ 20 Expected benefit payments 2023 164 22 2024 161 23 2025 168 23 2026 172 22 2027 178 22 2028 – 2032 919 105
Assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans	Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2022 2021 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Benefit cost for year ended December 31: Discount rate - past service 3.05 % 2.81 % 2.49 % 2.48 % Discount rate - future service 3.18 % 2.92 % 2.64 % 2.51 % Expected long-term return on plan assets 6.07 % 1.32 % 5.86 % - % Rate of compensation increase 3.31 % 3.29 % 2.89 % 3.04 % Health care trend - 5.09 % - 5.64 % - 3.77 % - 4.35 % 2042 2038 Actual assumptions used differ by plan.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
22. Goodwill
Change in goodwill	22. The change in goodwill for the year ended December 31 is due to the following: millions of dollars 2022 2021 Balance, January 1 $ 5,696 $ 5,720 GBPC impairment charge (1) (73) - Change in FX rate 389 (24) Balance, December 31 $ 6,012 $ 5,696 (1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $ 30

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
23. Short-Term Debt
Short-term debt and the related weighted-average interest rates	millions of dollars 2022 Weighted average interest rate 2021 Weighted average interest rate Tampa Electric Company ("TEC") Advances on term, revolving and accounts receivable facilities $ 1,380 5.00 % $ 945 0.58 % Emera Non-revolving term facilities 796 5.19 % 400 0.96 % Bank indebtedness - - % 6 - % TECO Finance Advances on revolving credit and term facilities 481 5.47 % 355 1.20 % NMGC Advances on revolving credit facilities 59 5.15 % 25 1.20 % GBPC Advances on revolving credit facilities 10 5.25 % 10 5.25 % NSPI Bank indebtedness - - % 1 - % Short-term debt $ 2,726 $ 1,742 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 dollars Maturity 2022 2021 TEC - Unsecured committed revolving credit facility 2026 $ 1,084 $ 1,014 TECO Energy/TECO Finance - revolving credit facility 2026 542 507 Emera - non-revolving term facility 2023 400 400 Emera - non-revolving term facility 2023 400 - TEC - Unsecured non-revolving facility 2023 542 634 NMGC - revolving credit facility 2026 169 158 GBPC - revolving credit facility on demand 18 16 Total $ 3,155 $ 2,729 Less: Advances under revolving credit and term facilities 2,731 1,735 Letters of credit issued within the credit facilities 4 4 Total advances under available facilities 2,735 1,739 Available capacity under existing agreements $ 420 $ 990

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Other Current Liabilities
Other Current Liabilities	As at December 31 December 31 millions of dollars 2022 2021 Accrued charges $ 174 $ 157 Nova Scotia Cap-and-Trade Program provision (note 7) 172 - Accrued interest on long-term debt 97 75 Pension and post-retirement liabilities (note 21) 33 27 Sales and other taxes payable 14 6 Income tax payable 9 6 Other 80 95 $ 579 $ 366

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
25. Long-term Debt
Long-term debt & long-term revolving credit facilities, outstanding borrowings and available capacity	Weighted average interest rate (1) millions of dollars 2022 2021 Maturity 2022 2021 Emera Bankers acceptances, LIBOR loans Variable Variable 2027 $ 403 $ 378 Unsecured fixed rate notes 2.90% 2.90% 2023 500 500 Fixed to floating subordinated notes (USD) (2) 6.75% 6.75% 2076 1,625 1,521 $ 2,528 $ 2,399 Emera Finance Unsecured senior notes (USD) 3.65% 3.65% 2024 - 2046 $ 3,725 $ 3,487 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.15% 4.15% 2024 - 2052 $ 4,341 $ 3,683 PGS Fixed rate notes and bonds (USD) 3.78% 3.78% 2024 - 2052 $ 772 $ 660 NMGC Fixed rate notes and bonds (USD) 3.11% 3.11% 2026 - 2051 $ 521 $ 488 Non-revolving term facility, floating rate Variable Variable 2024 108 101 $ 629 $ 589 NMGI Fixed rate notes and bonds (USD) 3.64% 3.64% 2024 $ 203 $ 190 NSPI Discount notes Variable Variable 2024 - 2027 $ 881 $ 376 Medium term fixed rate notes 5.14% 5.14% 2025 - 2097 2,665 2,665 $ 3,546 $ 3,041 EBP Senior secured credit facility Variable Variable 2026 $ 249 $ 249 ECI Secured senior notes (USD) Variable Variable 2026 $ 86 $ 84 Amortizing fixed rate notes (USD) 3.97% 3.97% 2024 - 2026 100 $ 104 Non-revolving term facility, floating rate Variable Variable 2027 30 $ 28 Non-revolving term facility, fixed rate 2.05% 2.36% 2025 - 2026 91 $ 101 Secured fixed rate senior notes (4) 3.06% 4.43% 2023 - 2029 142 $ 161 $ 449 $ 478 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 2 $ 3 Debt issuance costs (126) (121) Amount due within one year (574) (462) $ (698) $ (580) Long-Term Debt $ 15,744 $ 14,196 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2022, the Company recognized $ 110 102 subordinated notes. (3) A substantial part of Tampa currently no bonds outstanding under Tampa (4) Notes are issued and payable in either USD or BBD. (5) On acquisition of TECO Energy, Emera recorded 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 dollars Maturity 2022 2021 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 NSPI - revolving credit facility (1) December 2027 800 600 NSPI - non-revolving credit facility July 2024 400 - NMGC - non-revolving credit facility March 2024 108 - ECI – revolving credit facilities 2023-2032 11 27 Total $ 2,219 $ 1,527 Less: Borrowings under credit facilities 1,396 770 Letters of credit issued inside credit facilities 12 124 Use of available facilities $ 1,408 $ 894 Available capacity under existing agreements $ 811 $ 633 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 As at Financial Covenant Requirement December 31, 2022 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57
Long-Term Debt Maturities	millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Emera $ 500 $ - $ - $ 1,625 $ 403 $ - $ 2,528 Emera US Finance LP - 407 - 1,016 - 2,302 3,725 Tampa Electric - 356 - - - 3,985 4,341 PGS - 51 - - - 721 772 NMGC - 108 - 95 - 426 629 NMGI - 203 - - - - 203 NSPI - 398 125 40 483 2,500 3,546 EBP - - - 249 - - 249 ECI 74 90 137 85 60 3 449 Total $ 574 $ 1,613 $ 262 $ 3,110 $ 946 $ 9,937 $ 16,442

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
26. Asset Retirement Obligations
Change in ARO	The change in ARO for the years ended December 31 is as follows: millions of dollars 2022 2021 Balance, January 1 $ 174 $ 178 Accretion included in depreciation expense 9 10 Change in FX rate 3 (1) Additions 1 1 Accretion deferred to regulatory asset (included in PP&E) 1 (2) Liabilities settled (1) (1) (13) Revisions in estimated cash flows (13) - Other - 1 Balance, December 31 $ 174 $ 174 (1) Tampa Electric decrease in ARO in 2021 was due to the closure of CCR management facilities.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
27. Commitments and Contingencies Disclosure
Contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter	millions of dollars 2023 2024 2025 2026 2027 Thereafter Total Transportation (1) $ 693 $ 516 $ 423 $ 383 $ 367 $ 2,817 $ 5,199 Purchased power (2) 269 243 237 228 243 2,145 3,365 Fuel, gas supply and storage 1,161 282 138 40 5 1 1,627 Capital projects 264 89 4 1 - - 358 Equity investment commitments (3) 240 - - - - - 240 Other 149 142 132 49 42 189 703 $ 2,776 $ 1,272 $ 934 $ 701 $ 657 $ 5,152 $ 11,492 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 144 (2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths. (3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations relation to the Maritime Link and LIL.

Cumulative Preferred Stock (Tab

Cumulative Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2022
28. Cumulative Preferred Stock
Cumulative Preferred Stock	Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2022 December 31, 2021 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.1802 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.2250 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.1802 2.65 August 15, 2023 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A 4.900 1.2250 4.90 August 15, 2023 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (6) 4.600 1.1500 November 15, 2026 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 Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 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 Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.9 0 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable 1.84 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2023, February 15, 2025 and August 15, 2023, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) First Preferred Shares, Series E are redeemable at $ 25.00 (6) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00

Non-Controlling Interest in S_2

Non-Controlling Interest in Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2022
29. Non-Controlling Interest in Subsidiaries
Non-controlling Interest	29. As at December 31 December 31 millions of dollars 2022 2021 Preferred shares of GBPC $ 14 $ 14 Domlec (1) - 20 $ 14 $ 34 (1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4.
Preferred shares of GBPC	Preferred shares of GBPC: Authorized: 10,000 2022 2021 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14

Supplemental Information to C_2

Supplemental Information to Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2022
30. Supplementary Information to Consolidated Statements of Cash Flows
Supplementary Information to Consolidated Statement of Cash Flows	For the Year ended December 31 millions of dollars 2022 2021 Changes in non-cash working capital: $ (214) $ (84) (1) (636) (364) 423 289 (2) 193 7 Total non-cash working capital $ (234) $ (152) (1) Includes $( 162 ) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes $ 172 asset (FAM) balance is included in operating cash flow before working operating activities. Supplemental disclosure of cash paid (received): Interest $ 699 $ 603 Income taxes $ 67 $ 24 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 237 $ 214 Reclassification of long-term debt to short-term debt $ 500 $ - Decrease in accrued capital expenditures $ (13) $ (45) Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ (157) $ (108)

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
31. Stock-Based Compensation
Weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted	2022 2021 Weighted average fair value per option $ 5.35 $ 3.63 Expected term (1) 5 5 Risk-free interest rate (2) 1.79 % 0.60 % Expected dividend yield (3) 4.55 % 5.00 % Expected volatility (4) 18.87 % 19.14 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility.
Stock option information	Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2021 2,590,304 $ 48.48 1,452,475 $ 3.18 Granted 467,100 58.26 467,100 5.35 Exercised (203,525) 43.87 N/A N/A Vested N/A N/A (571,175) 2.83 Options outstanding December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Options exercisable December 31, 2022 (2)(3) 1,505,479 $ 46.59 (1) As at December 31, 2022, there was $ 4 expected to be recognized over a weighted average period of approximately 3 3 3 (2) As at December 31, 2022, the weighted average remaining term of vested options was 5 $ 10 6 21 (3) As at December 31, 2022, the fair value of options that vested in the year was $ 2 1
Activity related to the Deferred Share Unit Plans	Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2021 610,601 $ 39.22 614,365 $ 43.80 Granted including DRIP 76,252 52.42 104,465 57.89 Exercised (59,630) 31.57 (54,572) 46.04 Outstanding and exercisable as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83
Activity related to the Performance Share Unit Plan	Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2021 951,935 $ 48.60 $ 66 Granted including DRIP 242,462 59.30 Exercised (357,960) 42.85 Forfeited (145,991) 44.28 Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Employee RSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2021 343,952 $ 54.64 $ 24 Granted including DRIP 180,426 59.30 Exercised (134) 54.63 Forfeited (15,776) 56.08 Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2022
32. Variable Interest Entities
NSPML's consolidated summarized balance sheets	As at December 31, 2022 December 31, 2021 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 501 $ 6 $ 533 $ 11

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2022 CAD ($) Customers MW km
NSP Maritime Link Inc. | Equity Method Investee | NSP Maritime Link Inc Project
Nature of operations [Line items]
100% ownership	100%
Labrador-Island Link Limited Partnership | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	31.90%
Maritimes and Northeast Pipline | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	12.90%
Maritimes and Northeast Pipline | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	12.90%
Length Of Pipeline | km	1,400
St. Lucia Electricity Services Limited | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	19.50%
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	19.50%
Bear Swamp Power Company LLC | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	50%
Tampa Electric | Operating | Florida Electric Utility
Nature of operations [Line items]
Number of Customers	827,000
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Number of Customers	541,000
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	824
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities | NSP Maritime Link Inc Project
Nature of operations [Line items]
100% ownership	100%
Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Public Utilities, Equipment, Transmission and Distribution | $	$ 1.8
Length Of Pipeline | km	170
Emera Newfoundland and Labrador Holdings Inc. | Labrador-Island Link Limited Partnership | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	31.90%
Public Utilities, Equipment, Transmission and Distribution | $	$ 3.7
Barbados Light and Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers	133,000
Grand Bahama Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers	19,000
Peoples Gas System Division | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers	468,000
New Mexico Gas Company | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers	545,000
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Nature of operations [Line items]
Length Of Pipeline | km	145
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life	25 years
Emera Brunswick Pipeline Company Limited | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Length Of Pipeline | km	145
Emera Energy | Bear Swamp Power Company LLC | Other
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	50%
Public Utilities Property Plant And Equipment Generation Capacity | MW	660
Brooklyn Power Corporation | Operating | Other
Nature of operations [Line items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	30

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2020 CAD ($)
Asset Impairment Charges
Impairment charge	$ 73,000,000	$ 0
Goodwill
Goodwill		5,696,000,000		$ 6,012,000,000	$ 5,720,000,000
Goodwill impairment charge	73,000,000	0
Lease, Practical Expedient, Lessor Single Lease Component [true false]			true	true
Long-Lived Assets
Asset Impairment Charges
Impairment charge	0	0
Equity Method Investments
Asset Impairment Charges
Impairment charge	0	0
Financial Assets
Asset Impairment Charges
Impairment charge	0	$ 0
TECO Energy
Goodwill
Goodwill				$ 6,009,000,000
GBPC
Goodwill
Goodwill
Goodwill impairment charge	73,000,000
NMGC
Goodwill
Goodwill impairment charge	$ 0

Change in Accounting Policy (Na

Change in Accounting Policy (Narrative) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 11,441	$ 10,150	$ 9,238
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 1,584	$ 1,348	$ 1,495

Dispositions (Narrative) (Detai

Dispositions (Narrative) (Details)	Mar. 31, 2022
Dolmec [Member] | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Sale of ownership interest	51.90%

Segment Information (Reportable

Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 7,588	$ 5,765
OM&G	1,596	1,368
Provincial, state and municipal taxes	367	330
Depreciation and amortization	952	902
Income (loss) from equity investments and subsidiaries	129	143
Other income (expenses), net	145	93
Interest expense, net	709	611
Impairment charges	73	0
Income tax expense	185	(6)
Non-controlling interest in subsidiaries	1	1
Preferred stock dividends	63	50
Net income attributable to common shareholders	945.1	510.5
Capital expenditures	2,575	2,328
Segment Reporting Information, As at December 31
Total assets	39,742	34,244
Investments subject to significant influence	1,418	1,382
Goodwill	6,012	5,696	$ 5,720
Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Total operating revenues	5,473	4,665
Fuel for generation and purchased power	2,171	1,763
Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,681	1,261
Fuel for generation and purchased power	800	472
Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,287	2,724
Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,675	1,501
Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,704	1,280
Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	518	445
Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	440	(157)
Operating
Segment Reporting Information, For the year ended December 31
Total operating revenues	7,588	5,765
Operating | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,280	2,718
OM&G	625	536
Provincial, state and municipal taxes	235	212
Depreciation and amortization	507	469
Income (loss) from equity investments and subsidiaries	0	0
Other income (expenses), net	68	59
Interest expense, net	185	138
Impairment charges	0
Income tax expense	121	72
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income attributable to common shareholders	596	462
Capital expenditures	1,425	1,331
Segment Reporting Information, As at December 31
Total assets	21,053	17,903
Investments subject to significant influence	0	0
Goodwill	4,739	4,436
Operating | Florida Electric Utility | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	1,086	894
Operating | Florida Electric Utility | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Operating | Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,675	1,501
OM&G	338	291
Provincial, state and municipal taxes	43	43
Depreciation and amortization	259	246
Income (loss) from equity investments and subsidiaries	87	103
Other income (expenses), net	24	12
Interest expense, net	136	132
Impairment charges	0
Income tax expense	(8)	9
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income attributable to common shareholders	215	241
Capital expenditures	507	366
Segment Reporting Information, As at December 31
Total assets	8,223	7,418
Investments subject to significant influence	1,241	1,215
Goodwill	0	0
Operating | Canadian Electric Utilities | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	803	654
Operating | Canadian Electric Utilities | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Operating | Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,697	1,276
OM&G	365	325
Provincial, state and municipal taxes	83	69
Depreciation and amortization	118	121
Income (loss) from equity investments and subsidiaries	21	20
Other income (expenses), net	13	11
Interest expense, net	81	64
Impairment charges	0
Income tax expense	70	62
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income attributable to common shareholders	221	198
Capital expenditures	574	515
Segment Reporting Information, As at December 31
Total assets	7,737	6,666
Investments subject to significant influence	128	123
Goodwill	1,270	1,189
Operating | Gas Utilities and Infrastructure | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Operating | Gas Utilities and Infrastructure | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	800	472
Operating | Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	518	445
OM&G	123	140
Provincial, state and municipal taxes	3	4
Depreciation and amortization	61	58
Income (loss) from equity investments and subsidiaries	4	4
Other income (expenses), net	0	15
Interest expense, net	19	21
Impairment charges	73
Income tax expense	0	1
Non-controlling interest in subsidiaries	1	1
Preferred stock dividends	0	0
Net income attributable to common shareholders	(48)	21
Capital expenditures	63	111
Segment Reporting Information, As at December 31
Total assets	1,337	1,402
Investments subject to significant influence	49	44
Goodwill	0	68
Operating | Other Electric Utilities | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	290	218
Operating | Other Electric Utilities | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Operating | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	418	(175)
OM&G	156	106
Provincial, state and municipal taxes	3	2
Depreciation and amortization	7	8
Income (loss) from equity investments and subsidiaries	17	16
Other income (expenses), net	23	1
Interest expense, net	288	256
Impairment charges	0
Income tax expense	2	(150)
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	63	50
Net income attributable to common shareholders	(39)	(412)
Capital expenditures	6	5
Segment Reporting Information, As at December 31
Total assets	2,835	2,034
Investments subject to significant influence	0	0
Goodwill	3	3
Operating | Other | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Operating | Other | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Intersegment Eliminations
Segment Reporting Information, For the year ended December 31
Total operating revenues	(36)	(28)
OM&G	(11)	(30)
Provincial, state and municipal taxes	0	0
Depreciation and amortization	0	0
Income (loss) from equity investments and subsidiaries	0	0
Other income (expenses), net	17	(5)
Interest expense, net	0	0
Impairment charges	0
Income tax expense	0	0
Non-controlling interest in subsidiaries	0	0
Preferred stock dividends	0	0
Net income attributable to common shareholders	0	0
Capital expenditures	0	0
Segment Reporting Information, As at December 31
Total assets	(1,443)	(1,179)
Investments subject to significant influence	0	0
Goodwill	0	0
Financing costs	13	13
Intersegment Eliminations | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	(8)	(3)
Intersegment Eliminations | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0	0
Eliminations
Segment Reporting Information, For the year ended December 31
Total operating revenues	(36)	(28)
Eliminations | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	7	6
Eliminations | Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	0	0
Eliminations | Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	7	4
Eliminations | Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	0	0
Eliminations | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 22	$ 18

Segment Information (Geographic

Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 7,588	$ 5,765
Property, Plant and Equipment, Net	22,996	20,353
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	1,725	1,566
Property, Plant and Equipment, Net	4,689	4,440
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	5,346	3,754
Property, Plant and Equipment, Net	17,382	14,978
Barbados
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	384	292
Property, Plant and Equipment, Net	583	535
The Bahamas
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	122	110
Property, Plant and Equipment, Net	342	322
Dominica
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	11	43
Property, Plant and Equipment, Net	$ 0	$ 78

Segment Information (Narrative)

Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2022
5. Segment Information
Segment Reporting, Factors Used to Identify Entity's Reportable Segments	Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker.

Revenue (Disaggregation) (Detai

Revenue (Disaggregation) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 7,588	$ 5,765
Total operating revenues	7,588	5,765
Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	3,287	2,724
Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1,675	1,501
Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	518	445
Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1,704	1,280
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	440	(157)
Operating
Disaggregation of Revenue [Line Items]
Total operating revenues	7,588	5,765
Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,287	2,724
Total operating revenues	3,280	2,718
Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,675	1,501
Total operating revenues	1,675	1,501
Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	518	445
Total operating revenues	518	445
Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,704	1,280
Total operating revenues	1,697	1,276
Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	440	(157)
Total operating revenues	418	(175)
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(36)	(28)
Total operating revenues	(36)	(28)
Eliminations | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	7	6
Eliminations | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Eliminations | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Eliminations | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	7	4
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	22	18
Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	434	(161)
Total operating revenues	434	(161)
Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	16	14
Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	440	(157)
Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(22)	(18)
Electric Revenue | Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7,154	5,926
Total operating revenues	5,473	4,665
Electric Revenue | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,287	2,724
Electric Revenue | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,675	1,501
Electric Revenue | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	518	445
Electric Revenue | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,688	1,266
Electric Revenue | Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(14)	(10)
Electric Revenue | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,617	3,053
Electric Revenue | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,799	1,449
Electric Revenue | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	834	797
Electric Revenue | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	184	165
Electric Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	800	642
Electric Revenue | Regulated | Residential | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Residential | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,039	1,772
Electric Revenue | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	869	754
Electric Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	427	407
Electric Revenue | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	282	232
Electric Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	461	379
Electric Revenue | Regulated | Commercial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Commercial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	691	541
Electric Revenue | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	230	215
Electric Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	353	237
Electric Revenue | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	32	26
Electric Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	83	65
Electric Revenue | Regulated | Industrial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Industrial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(7)	(2)
Electric Revenue | Regulated | Other Electric And Regulatory
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	411	323
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	371	289
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	28	27
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	12	7
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric And Regulatory | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Gas Revenue | Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	1,681	1,261
Marketing and trading margin | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	143	102
Marketing and trading margin | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	143	102
Marketing and trading margin | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	22	23
Energy sales | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	16	14
Energy sales | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	16	30
Energy sales | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(10)	(21)
Finance Income | Regulated | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	61	58
Finance Income | Regulated | Operating | Florida Electric Utility | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Canadian Electric Utilities | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Other Electric Utilities | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Gas Utilities and Infrastructure | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	61	58
Finance Income | Regulated | Operating | Other | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Eliminations | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers		0
Other non-regulated operating revenue | Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	335	179
Other non-regulated operating revenue | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	18	17
Other non-regulated operating revenue | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	33	33
Other non-regulated operating revenue | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	8	15
Other non-regulated operating revenue | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	283	122
Other non-regulated operating revenue | Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Other non-regulated operating revenue | Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(7)	(8)
Mark-To-Market | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	269	(286)
Mark-To-Market | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	281	(289)
Mark-To-Market | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	$ (12)	$ 3

Revenue (Remaining Performance

Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
6. Revenue
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Explanation	2042
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 450	$ 437
SeaCoast Gas Transmission, LLC
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	144
SeaCoast Gas Transmission, LLC | PGS
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 144

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 602	$ 253
Regulatory Assets, Long-term	3,018	2,313
Total regulatory assets	3,620	2,566
Deferred income tax regulatory assets
Regulatory Assets [Line Items]
Total regulatory assets	1,166	1,045
Cost Recovery Clauses
Regulatory Assets [Line Items]
Total regulatory assets	707	114
Tampa Electric capital cost recovery for early retired assets
Regulatory Assets [Line Items]
Total regulatory assets	674	657
Pension and post-retirement medical plan
Regulatory Assets [Line Items]
Total regulatory assets	369	291
FAM
Regulatory Assets [Line Items]
Total regulatory assets	307	145
Storm reserve
Regulatory Assets [Line Items]
Total regulatory assets	103	0
NMGC winter event gas cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	69	117
Storm Restoration
Regulatory Assets [Line Items]
Total regulatory assets	35	35
Deferrals related to derivative instruments
Regulatory Assets [Line Items]
Total regulatory assets	30	23
Environmental Remediations
Regulatory Assets [Line Items]
Total regulatory assets	27	27
Stranded Cost Recovery
Regulatory Assets [Line Items]
Total regulatory assets	27	26
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 106	$ 86

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 495	$ 290
Regulatory Liability, Long-term	1,778	1,765
Total regulatory liabilities	2,273	2,055
Accumulated reserve - cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities	895	819
Deferred income tax regulatory liabilities
Regulatory Liabilities [Line Items]
Total regulatory liabilities	877	863
Deferrals related to derivative instruments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	230	241
NMGC gas hedge settlements
Regulatory Liabilities [Line Items]
Total regulatory liabilities	162	0
Cost Recovery Clauses
Regulatory Liabilities [Line Items]
Total regulatory liabilities	70	35
Self-insurance fund (note 32)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	30	28
Storm reserve
Regulatory Liabilities [Line Items]
Total regulatory liabilities	0	58
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 9	$ 11

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2021 USD ($)	Jan. 31, 2021	Jan. 31, 2020 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Jun. 15, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Assets					$ 3,620	$ 2,566
NMGC winter event gas cost recovery
Public Utilities, General Disclosures [Line Items]
Regulatory Assets					$ 69	$ 117
GBPC | Hurricane | Loss from Catastrophes
Public Utilities, General Disclosures [Line Items]
Storm cost			$ 15
Recovery Period		5 years
GBPC | Steam turbine
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment				$ 21
Tampa Electric
Public Utilities, General Disclosures [Line Items]
Recovery Period				15 years
NMGC
Public Utilities, General Disclosures [Line Items]
Incremental gas cost	$ 108
NMGC | NMGC winter event gas cost recovery
Public Utilities, General Disclosures [Line Items]
Regulatory Assets							$ 108

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Florida Electric Utility (Narrative) (Details) $ in Millions, $ in Millions

1 Months Ended

12 Months Ended

Jan. 23, 2023 USD ($)

Jul. 01, 2022

Jan. 19, 2022 USD ($)

Jan. 31, 2024 USD ($)

Jan. 31, 2023 USD ($)

Jan. 31, 2022 USD ($)

Dec. 31, 2022 CAD ($) MW

Dec. 31, 2022 USD ($) MW

Dec. 31, 2021 CAD ($)

Dec. 31, 2022 USD ($)

Sep. 30, 2022 USD ($)

Dec. 31, 2021 USD ($)

Public Utilities, General Disclosures [Line Items]

State income tax

0.15%

0.15%

(0.01%)

Utilities Operating Expense, Depreciation and Amortization

$ 952

$ 902

Regulatory Assets

3,620

2,566

Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Utilities Operating Expense, Depreciation and Amortization

507

469

Cost Recovery Clauses

Public Utilities, General Disclosures [Line Items]

Regulatory Assets

707

114

Restoration Costs

Public Utilities, General Disclosures [Line Items]

Regulatory Assets

27

27

Storm reserve

Public Utilities, General Disclosures [Line Items]

Regulatory Assets

$ 35

$ 35

Tampa Electric

Public Utilities, General Disclosures [Line Items]

Recovery Period

15 years

15 years

Tampa Electric | SoBRA | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Property, Plant and Equipment, Generation or Processing

$ 850

Estimated revenue in MW | MW

600

600

Tampa Electric | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Property, Plant and Equipment, Plant in Service

876

Public Utilities, Property, Plant and Equipment, Accumulated Depreciation

91

Recovery Period

15 years

15 years

Tampa Electric | Florida Public Service Commission

Public Utilities, General Disclosures [Line Items]

Recovery Period

15 years

15 years

Tampa Electric | Florida Public Service Commission | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.95%

9.95%

Increase in the allowed ROE

0.25%

0.25%

Allowed equity capital structure

54%

54%

Estimated additional revenue based on treasury bond's performance

$ 10

Tampa Electric | Florida Public Service Commission | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Disclosure of Rate Matters

Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Allowed equity capital structure

54%

54%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 4

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 169

$ 123

Tampa Electric | Florida Public Service Commission | Scenario Plan | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 21

$ 90

Tampa Electric | Florida Public Service Commission | Cost Recovery Clauses | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.20%

10.20%

10.25%

Public Utilities, Requested Rate Increase (Decrease), Amount

68

Tampa Electric | Florida Public Service Commission | Cost Recovery Clauses | Subsequent Event | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 518

Recovery Period

21 months

Tampa Electric | Florida Public Service Commission | SoBRA | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Estimated revenue in MW | MW

600

600

Estimated revenue

$ 104

Tampa Electric | Florida Public Service Commission | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Property, Plant and Equipment, Plant in Service

$ 636

Public Utilities, Property, Plant and Equipment, Accumulated Depreciation

$ 267

Tampa Electric | Florida Public Service Commission | Projected Fuel Costs | Subsequent Event | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (170)

Tampa Electric | Florida Public Service Commission | Restoration Costs | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Regulatory Assets

$ 126

Costs deferred as a regulatory asset for future recovery

$ 119

Tampa Electric | Florida Public Service Commission | Storm reserve | Subsequent Event | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Regulatory Assets

131

Approved reserve level

$ 56

Tampa Electric | Florida Public Service Commission | Mid Point | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.20%

Tampa Electric | Florida Public Service Commission | Range, Minimum

Public Utilities, General Disclosures [Line Items]

New depreciation study filing period

90 days

90 days

Tampa Electric | Florida Public Service Commission | Range, Minimum | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9%

9%

Tampa Electric | Florida Public Service Commission | Range, Minimum | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.25%

9.25%

9.25%

9.25%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 191

Tampa Electric | Florida Public Service Commission | Range, Maximum

Public Utilities, General Disclosures [Line Items]

New depreciation study filing period

1 year

1 year

Tampa Electric | Florida Public Service Commission | Range, Maximum | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11%

11%

Tampa Electric | Florida Public Service Commission | Range, Maximum | Florida Electric Utility | Operating

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11.25%

11.25%

11.25%

11.25%

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) $ in Millions		9 Months Ended	12 Months Ended
	Nov. 09, 2022	Dec. 31, 2022 CAD ($) km	Dec. 31, 2025	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($) km	Dec. 31, 2021 CAD ($)	Feb. 28, 2022 CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 2,273				$ 2,273	$ 2,055
Utilities Operating Expense, Depreciation and Amortization						952	902
Contractual Obligation, to be Paid, Year One		2,776				2,776
Contractual Obligation, to be Paid, Year Two		1,272				1,272
Regulatory Assets		3,620				3,620	2,566
Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Utilities Operating Expense, Depreciation and Amortization						$ 259	246
NSPI | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Recovery Period						3 years
NSPI | Canadian Electric Utilities | Operating | Nova Scotia Cap-and-Trade ("Cap-and-Trade") Program
Public Utilities, General Disclosures [Line Items]
Regulatory Assets		172				$ 172	$ 38
NSPI | Canadian Electric Utilities | Operating | Loss from Catastrophes [Member]
Public Utilities, General Disclosures [Line Items]
Loss Contingency, Estimate of Possible Loss		10				10
NSPI | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | Nova Scotia Cap-and-Trade ("Cap-and-Trade") Program
Public Utilities, General Disclosures [Line Items]
Regulatory Assets		165				$ 165
NSPI | Range, Minimum | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						8.75%	8.75%
NSPI | Range, Maximum | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						9.25%	9.25%
Regulated common equity component						40%	40%
NSPI | Range, Maximum | Canadian Electric Utilities | Operating | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Non-fuel rate increases				1.80%	1.80%
NSPI | Scenario Plan | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 115	$ 105
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			6.90%
NSPI | Public Utilities Act | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Non-fuel rate increases	1.80%
Approved regulated return on equity	9.25%
Equity ratio	40%
Rate used to accrue interest	1.75%
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage						1.50%
Emera Newfoundland and Labrador Holdings Inc. | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Recovery Period						3 years
Public Utilities, Equipment, Transmission and Distribution		$ 1,800				$ 1,800
Number of pipelines						2
Length Of Pipeline | km		170				170
Regulatory Liabilities								$ 1,800
Costs not recoverable for rate approval								9
Costs not recoverable for rate approval net of tax								$ 7
Approved payment in period						$ 168	$ 172
Holdback payable		$ 2				4
Payment of holdback						$ 14
Estimate of possible percentage of receiving deliveries		90%				90%
Contractual Obligation, to be Paid, Year One		$ 164				$ 164	$ 162
Energy Delivery Commitments and Contracts, Term						35 years
Emera Newfoundland and Labrador Holdings Inc. | Range, Minimum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						8.75%
Emera Newfoundland and Labrador Holdings Inc. | Range, Maximum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						9.25%
Equity ratio		30%				30%

Regulatory Assets and Liabili_8

Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions			1 Months Ended	6 Months Ended	12 Months Ended
	Feb. 15, 2023 USD ($)	Apr. 01, 2022 USD ($)	Jan. 31, 2022	Jun. 30, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)						$ (185)		$ 6
Regulatory Liabilities						2,273		2,055
Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Income tax expense (recovery)						$ 0		$ (1)
Barbados Light and Power Company Limited
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						10%	10%	10%
Barbados Light and Power Company Limited | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Cost sharing ratio						50%	50%
Barbados Light and Power Company Limited | Other Electric Utilities | Operating | Dispatch License
Public Utilities, General Disclosures [Line Items]
Recovery Period						5 years	5 years
Barbados Light and Power Company Limited | Range, Minimum | Operating | Transmission, Distribution & Supply License and a Generation License
Public Utilities, General Disclosures [Line Items]
Recovery Period						25 years	25 years
Barbados Light and Power Company Limited | Range, Maximum | Operating | Transmission, Distribution & Supply License and a Generation License
Public Utilities, General Disclosures [Line Items]
Recovery Period						30 years	30 years
Barbados Light and Power Company Limited | Fair Trading Commission | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						12.50%	12.50%
Allowed equity capital structure						65%	65%
Barbados Light and Power Company Limited | Fair Trading Commission | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 23
Barbados Light and Power Company Limited | Fair Trading Commission | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Interim Rate Increase (Decrease), Amount							$ 3
Barbados Light and Power Company Limited | Fair Trading Commission | Other Electric Utilities | Operating | Forecast
Public Utilities, General Disclosures [Line Items]
Public Utilities, Interim Rate Increase (Decrease), Amount					$ 1
GBPC | Fair Trading Commission | Other Electric Utilities | Operating | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity	11.75%
Allowed equity capital structure	55%
Regulatory Liabilities	$ 70
GBPC | GBPA | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 3.5
Approved regulated return on equity						8.23%	8.23%	8.37%
GBPC | GBPA | Other Electric Utilities | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			12.84%

Regulatory Assets and Liabili_9

Regulatory Assets and Liabilities - Gas Utilities and Infrastructure (Narrative) (Details) $ in Millions, $ in Millions		1 Months Ended			12 Months Ended
	May 20, 2022 USD ($)	Sep. 30, 2022 USD ($)	Feb. 28, 2021 USD ($)	Jan. 31, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 CAD ($) km	Dec. 31, 2022 USD ($) km
Public Utilities, General Disclosures [Line Items]
Accumulated depreciation						$ 8,739	$ 9,574
Regulatory assets						2,566	3,620
Storm reserve
Public Utilities, General Disclosures [Line Items]
Regulatory assets						$ 35	$ 35
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km							145	145
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km							145	145
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life					25 years
NMGC
Public Utilities, General Disclosures [Line Items]
Incremental gas cost			$ 108
NMGC | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					9.375%
Allowed equity capital structure					52%
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 19
PGS | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Allowed equity capital structure					54.70%
Accumulated depreciation								$ 34
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease)					$ 14
Public Utilities, Disclosure of Rate Matters					Base Rates: On November 19, 2020, the FPSC approved a settlement agreement filed by PGS.
Storm restoration costs		$ 2
PGS | Gas Utilities and Infrastructure | Operating | Storm reserve
Public Utilities, General Disclosures [Line Items]
Storm restoration costs paid from storm reserve		$ 1
PGS | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease)				$ 34
Phase-in Plan, Amount of Capitalized Costs Recovered				34
Public Utilities, Approved Rate Increase (Decrease), Amount				58
PGS | Gas Utilities and Infrastructure | Operating | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Capitalized Costs Recovered				$ 24
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					8.90%
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity				8.90%
Allowed equity capital structure				54.70%
PGS | Range, Maximum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					11%
PGS | Mid Point | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					9.90%
BPLC
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					10%	10%

Investments Subject to Signif_3

Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 1,418	$ 1,382
Income (loss) from equity investments and subsidiaries	129	143
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	825	868
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	1,418	1,382
Income (loss) from equity investments and subsidiaries	129	143
Equity Method Investee | Emera Inc.
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	9
LIL | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	740	682
Income (loss) from equity investments and subsidiaries	$ 58	54
Percentage of Ownership	31.90%
LIL | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	31.90%
LIL | Equity Method Investee | Class B units | NSP Maritime Link Inc Project
Schedule of Equity Method Investments [Line Items]
100% ownership	100%
LIL | Equity Method Investee | Total Units Issued [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	24.50%
NSPML | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 501	533
Income (loss) from equity investments and subsidiaries	$ 29	49
NSPML | Equity Method Investee | NSP Maritime Link Inc Project
Schedule of Equity Method Investments [Line Items]
100% ownership	100%
M&NP | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 128	123
Income (loss) from equity investments and subsidiaries	$ 21	20
Percentage of Ownership	12.90%
M&NP | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	12.90%
Lucelec | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 49	44
Income (loss) from equity investments and subsidiaries	$ 4	4
Percentage of Ownership	19.50%
Lucelec | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	19.50%
Bear Swamp
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	$ 95	104	$ 179
Bear Swamp | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	0	0
Income (loss) from equity investments and subsidiaries	$ 17	$ 16
Percentage of Ownership	50%
Bear Swamp | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	50%
Maritime Link And LIL | Plan, subject to approval
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	49%

Investments Subject to Signif_4

Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Balance Sheets
Current assets	$ 4,896	$ 3,136
Property, plant and equipment	22,996	20,353
Regulatory assets	3,018	2,313
Non-current assets	11,850	10,755
Total assets	39,742	34,244
Current liabilities	7,287	4,878
Non-current liabilities	21,014	19,216
Equity	11,441	10,150	$ 9,238
Total liabilities and equity	39,742	34,244
Variable Interest Entity, Not Primary Beneficiary | NSPML
Balance Sheets
Current assets	17	25
Property, plant and equipment	1,517	1,587
Regulatory assets	265	247
Non-current assets	29	31
Total assets	1,828	1,890
Current liabilities	48	50
Long-term debt	1,149	1,189
Non-current liabilities	130	118
Equity	501	533
Total liabilities and equity	$ 1,828	$ 1,890

Other Income, Net (Components o

Other Income, Net (Components of other income (expenses), net) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
9. Other Income, Net
Allowance for equity funds used during construction	$ 52	$ 61
TECO Guatemala Holdings award	63	0
Other	30	32
Other income (expenses), net	$ 145	$ 93

Income Taxes (Reconiliation of

Income Taxes (Reconiliation of Income tax provision) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income before provision for income taxes	$ 1,194	$ 555
Statutory income tax rate	0.29%	0.29%
Income taxes, at statutory income tax rates	$ 346	$ 161
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(70)	(62)
Foreign tax rate variance	(44)	(42)
Amortization of deferred income tax regulatory liabilities	(33)	(33)
GBPC impairment charge	21	0
Tax effect of equity earnings	(10)	(16)
Tax credits	(18)	(13)
Other	(7)	(1)
Income tax (recovery) expense	$ 185	$ (6)
Effective income tax rate	0.15%	(0.01%)
Regulatory Liabilities	$ 2,273	$ 2,055
Incremental tax benefits payable to customers [Member]
Regulatory Liabilities	$ 9

Income Taxes (Composition of ta

Income Taxes (Composition of taxes on income from continuing operations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ 152	$ (37)
Income tax expense	185	(6)
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	1,194	555
Canada
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	25	20
Deferred income taxes	120	(33)
Operating loss carry forwards	(92)	(64)
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	173	244
United States
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	8	11
Deferred income taxes	252	118
Investment tax credits	(7)	(11)
Operating loss carry forwards	(121)	(49)
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	1,063	289
Other
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	0	2
Supplemental Tax Information [Abstract]
Income (loss) before provision for income taxes	$ (42)	$ 22

Income Taxes (Deferred income t

Income Taxes (Deferred income tax assets and liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax assets:
Tax loss carryforwards	$ 1,207	$ 873
Tax credit carryforwards	415	375
Regulatory liabilities - cost of removal	177	170
Derivative instruments	45	188
Other	428	434
Total deferred income tax assets before valuation allowance	2,272	2,040
Valuation allowance	(312)	(256)
Total deferred income tax assets after valuation allowance	1,960	1,784
Deferred income tax (liabilities):
Property, plant and equipment	(2,981)	(2,622)
Regulatory assets	(219)	(78)
Derivative instruments	(125)	(197)
Other	(594)	(460)
Total deferred income tax liabilities	(3,919)	(3,357)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets	237	295
Long-term deferred income tax liabilities	(2,196)	(1,868)
Net deferred income tax liabilities	$ (1,959)	$ (1,573)

Income Taxes (Net operating los

Income Taxes (Net operating loss, capital loss and tax credit carryforwards and their expiration periods) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Canada | Capital loss
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 79
Unrecognized Amounts	(79)
Net Tax Credit Carryforwards	$ 0
Expiration period	Indefinite
Canada | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2,372
Unrecognized Amounts	(977)
Net Tax Credit Carryforwards	$ 1,395
Expiration period	2026 - 2042
United States | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2,082
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 2,082
Expiration period	2032 - Indefinite
United States | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 415
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 415
Expiration period	2025 - 2042
State | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,489
Unrecognized Amounts	0
Net Tax Credit Carryforwards	$ 1,489
Expiration period	2032 - Indefinite
Other | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 73
Unrecognized Amounts	(33)
Net Tax Credit Carryforwards	$ 40
Expiration period	2023 - 2029

Income Taxes (Change in unrecog

Income Taxes (Change in unrecognized tax benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 28	$ 30
Increases due to tax positions related to current year	5	4
Increases due to tax positions related to a prior year	2	1
Decreases due to tax positions related to a prior year	(2)	(1)
Decreases due to settlement with tax authorities	0	(6)
Balance, December 31	$ 33	$ 28

Income Taxes (Unrecognized tax

Income Taxes (Unrecognized tax benefits) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change	$ 3,800,000,000	$ 2,900,000
Net amount in dispute	126,000,000	62,000,000
Prepaid amount in dispute	55,000,000	23,000,000
Deferred Tax Assets, Allowance	312,000,000	256,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Amount that could affect effective tax rate	33,000,000	28,000,000
Accrued interest	7,000,000	6,000,000
Income Tax Examination, Interest Expense	1,000,000
Accrued penalties	$ 0

Common Stock (Common Stock Roll

Common Stock (Common Stock Rollfoward) (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 7,242
Issuance of common stock	248	$ 284
Senior management stock options exercised and Employee Share Purchase Plan	36	38
Ending Balance	$ 7,762	$ 7,242
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	261,070	251,430
Issuance of common stock	4,070	4,990
Issued under Purchase Plans at market rate	4,210	3,900
Options exercised under senior management share option plan	600	750
Ending Balance	269,950	261,070
Common Stock
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 7,242	$ 6,705
Issuance of common stock	248	284
Issued under Purchase Plans at market rate	238	215
Senior management stock options exercised and Employee Share Purchase Plan	34	38
Ending Balance	$ 7,762	$ 7,242

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2021 CAD ($) shares	Dec. 31, 2021 $ / shares shares	Aug. 12, 2021 CAD ($)
Debt Instrument [Line Items]
Issuance of common stock | shares	4,070,000	4,990,000
Gross proceeds from Issuance of Common Stock | $	$ 277	$ 317
Percentage of outstanding stock maximum	10%
ATM Program
Debt Instrument [Line Items]
Stock Repurchase Program, Authorized Amount | $				$ 600
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $	$ 207
ATM Program | Common Stock
Debt Instrument [Line Items]
Issuance of common stock | shares	4,072,469	4,987,123
Gross proceeds from Issuance of Common Stock | $	$ 250	$ 287
Net proceeds from issuance of common stock | $	$ 248	$ 284
Average price per share, issued | (per share)	$ 61.31		$ 57.63
Employee Stock Option Plan
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance | shares	6,000,000	6,200,000	6,200,000
Share Unit Plans
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance | shares	2,700,000	3,100,000	3,100,000
Dividend Reinvestment
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance | shares	10,000,000	14,200,000	14,200,000

Earnings Per Share (Computation

Earnings Per Share (Computation of basic and diluted earnings per share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Numerator
Net income attributable to common shareholders	$ 945.1	$ 510.5
Diluted numerator	$ 945.1	$ 510.5
Denominator
Weighted average shares of common stock outstanding	265.5	255.9
Weighted average deferred share units outstanding	0	1.3
Weighted average shares of common stock outstanding - basic	265.5	257.2
Stock-based compensation	0.4	0.4
Weighted average shares of common stock outstanding- diluted	265.9	258
Earnings per common share
Basic	$ 3.56	$ 1.98
Diluted	$ 3.55	$ 1.98

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	$ 10,150	$ 9,238
Net current period other comprehensive income (loss)	553	104
Ending Balance	11,441	10,150
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	25	(79)
Other comprehensive income (loss) before reclassifications	531	(19)
Amounts reclassified from accumulated other comprehensive income loss	22	123
Net current period other comprehensive income (loss)	553	104
Ending Balance	578	25
Unrealized gain (loss) on translation of self-sustaining foreign operations
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	10	52
Other comprehensive income (loss) before reclassifications	629	(42)
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	629	(42)
Ending Balance	639	10
Net change in net investment hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	35	30
Other comprehensive income (loss) before reclassifications	(97)	5
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	(97)	5
Ending Balance	(62)	35
(Losses) gains on derivatives recognized as cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	18	1
Other comprehensive income (loss) before reclassifications	0	18
Amounts reclassified from accumulated other comprehensive income loss	(2)	(1)
Net current period other comprehensive income (loss)	(2)	17
Ending Balance	16	18
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(1)	(1)
Other comprehensive income (loss) before reclassifications	(1)	0
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	(1)	0
Ending Balance	(2)	(1)
Net change in unrecognized pension and post-retirement benefit costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(37)	(161)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income loss	24	124
Net current period other comprehensive income (loss)	24	124
Ending Balance	$ (13)	$ (37)

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, 2022	Dec. 31, 2021
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total operating revenues	$ 7,588	$ 5,765
Interest expense, net	709	611
Other income, net (note 9)	145	93
Income tax expense (recovery)	(185)	6
Net income	1,009	561
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	22	123
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax expense (recovery)	(1)	(2)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | Interest rate hedge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense, net	(2)	(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in unrecognized pension and post-retirement benefit costs
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	25	126
Income tax expense (recovery)	1	2
Net income	24	124
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial losses (gains)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net (note 9)	10	24
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amounts reclassified into obligations
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Pension and post-retirement benefits	$ 15	$ 102

Inventory (Details)

Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
14. Inventory
Fuel	$ 404	$ 255
Materials	365	283
Inventory Total	$ 769	$ 538

Derivatives Instruments (Deriva

Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
HFT derivatives
Derivative Assets	$ 429	$ 241
Derivative Liabilities	1,301	850
Other derivatives
Other, Derivative Assets	5	11
Other, Derivative Liabilities	28	0
Derivative Assets
Total gross current derivative assets	690	493
Total impact of master netting agreements	(294)	(192)
Derivative Asset, Total	396	301
Derivative Assets, Current	296	195
Derivative Assets, Long-term	100	106
Derivative Liabilities
Total gross current derivative liabilities	1,372	874
Total impact of master netting agreements	(294)	(192)
Derivative Liabilities, Total	1,078	682
Derivative Liabilities, Current	888	533
Derivative Liabilities, Long-term	190	149
Equity derivatives
Other derivatives
Other, Derivative Assets	0	11
Other, Derivative Liabilities	5	0
FX forwards
Other derivatives
Other, Derivative Assets	5	0
Other, Derivative Liabilities	23	0
Power swaps and physical contracts
HFT derivatives
Derivative Assets	89	33
Derivative Liabilities	77	32
Natural gas swaps, futures, forwards, physical contracts
HFT derivatives
Derivative Assets	340	208
Derivative Liabilities	1,224	818
Regulatory deferral
HFT derivatives
Derivative Assets	256	241
Derivative Liabilities	43	24
Derivative Assets
Total impact of master netting agreements	(18)	(4)
Derivative Liabilities
Total impact of master netting agreements	(18)	(4)
Regulatory deferral | Commodity swaps and forwards
Regulatory deferral
Regulatory deferral, Derivative Assets	186	146
Regulatory deferral, Derivative Liabilities	42	16
Regulatory deferral | FX forwards
HFT derivatives
Derivative Assets	18	7
Derivative Liabilities	1	8
Regulatory deferral | Physical natural gas purchases and sales [Member]
HFT derivatives
Derivative Assets	88	52
Derivative Liabilities	0	0
HFT derivatives
Derivative Assets
Total impact of master netting agreements	(276)	(188)
Derivative Liabilities
Total impact of master netting agreements	$ (276)	$ (188)

Derivatives Instruments (Deri_2

Derivatives Instruments (Derivative Cash Flow Hedges Recorded in Income and AOCI and Notional Volumes of Outstanding Derivatives Designated as Cash Flow Hedges) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	May 26, 2021
FX forwards
Cash Flow Hedges
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle	$ 448
Cash flow hedges | Interest Expense [Member]
Cash Flow Hedges
Unrealized gains reclassified into interest expense	2	$ 1
Cash flow hedges | Treasury Lock [Member]
Cash Flow Hedges
Total unrealized gain (loss) in AOCI - effective portion, net of tax	16	$ 18	$ 19
Unrealized gains currently in AOCI to be reclassified into net income within the next twelve months	$ 2
Derivative gain loss amortization period	10 years

Derivatives Instruments (Change

Derivatives Instruments (Changes in Realized and Unrealized Gains (Losses) with Respect to Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	$ (206)	$ (404)
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(24)	3
Regulatory deferral | Physical natural gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(36)	88
Regulatory deferral | Physical natural gas purchases | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	0	9
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	16	(3)
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(64)	0
Regulatory deferral | Commodity swaps and forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	14	161
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(69)	0
Realized (gain) loss on derivatives receiving regulatory deferral	48	0
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	28	88
Realized (gain) loss on derivatives receiving regulatory deferral	(41)	(3)
Regulatory deferral | Commodity swaps and forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(121)	(8)
Regulatory deferral | Commodity swaps and forwards | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(146)	(39)
Regulatory deferral | FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	18	16
Regulatory deferral | FX forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	1	(7)
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | FX forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	343	218
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | FX forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	1	5
Regulatory deferral | FX forwards | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	$ 0	$ 5

Derivatives Instruments (Notion

Derivatives Instruments (Notional Volumes of Commodity Swaps and Forward Contracts Designated for Regulatory Deferral) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) MMBTU MWh
Commodity swaps and forwards | Natural gas | 2023
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	18
Commodity swaps and forwards | Natural gas | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	12
Commodity swaps and forwards | Power | 2023
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	1
Commodity swaps and forwards | Power | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	1
Physical natural gas purchases | Natural gas | 2023
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	6
Physical natural gas purchases | Natural gas | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	0
Foreign Exchange Swaps and Forward Contracts | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 206
Weighted average rate	1.2832
% of USD requirements	0.50%
Foreign Exchange Swaps and Forward Contracts | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 123
Weighted average rate	1.3064
% of USD requirements	0.28%

Derivatives Instruments (Realiz

Derivatives Instruments (Realized and Unrealized Gains (Losses) with Respect to HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 64	$ (138)
Operating revenues | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	17	4
Operating revenues | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 47	$ (142)

Derivatives Instruments (Noti_2

Derivatives Instruments (Notional Volumes of Outstanding HFT Derivatives) (Details) - HFT derivatives MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2022 MMBTU MWh
Power | Purchases | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	2
Power | Purchases | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2027 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	2
Power | Sales | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2027 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Natural gas | Purchases | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	319
Natural gas | Purchases | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	92
Natural gas | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	42
Natural gas | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	36
Natural gas | Purchases | 2027 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	131
Natural gas | Sales | 2023
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	492
Natural gas | Sales | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	205
Natural gas | Sales | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	105
Natural gas | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	6
Natural gas | Sales | 2027 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	19

Derivatives Instruments (Real_2

Derivatives Instruments (Realized and Unrealized Gains (Losses) with Respect to Other derivatives) (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Equity derivative hedges, return of shares	2.8
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	$ (24)	$ 3
Combined notional amount	448
FX forwards | OM&G
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	0	0
Realized gains (loss)	0	0
FX forwards | Other income, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	(18)	(15)
Realized gains (loss)	(6)	18
Equity derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	(22)	26
Equity derivatives | OM&G
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	(5)	11
Realized gains (loss)	(17)	15
Equity derivatives | Other income, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	0	0
Realized gains (loss)	$ 0	$ 0

Derivatives Instruments (Credit

Derivatives Instruments (Credit Risk) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) Days	Dec. 31, 2021 CAD ($)
Credit Derivatives [Line Items]
Total cash deposits/collateral on hand	$ 224	$ 212
Financial Asset, Past Due [Member]
Credit Derivatives [Line Items]
Financial assets, considered to be past due	131	114
Credit Concentration Risk
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	1,900	1,300
Total cash deposits/collateral on hand	386	341
Credit Concentration Risk | Receivables, net
Credit Derivatives [Line Items]
Fair Value, Financial assets, considered to be past due	$ 114	$ 93
Average number of days financial asset outstanding | Days	60

Derivatives Instruments (Concen

Derivatives Instruments (Concentration Risk) (Details) - Credit Concentration Risk - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,900,000	$ 1,300,000
Receivables, net | Other accounts receivable
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 585,000	$ 329,000
% of total exposure	0.25%	0.20%
Receivables, net | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 507,000	$ 305,000
% of total exposure	0.21%	0.19%
Receivables, net | Receivables
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,982,000	$ 1,330,000
% of total exposure	0.83%	0.82%
Receivables, net | Credit rating of A- or above | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 125,000	$ 66,000
% of total exposure	0.05%	0.04%
Receivables, net | Credit rating of BBB- to BBB+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 75,000	$ 107,000
% of total exposure	0.03%	0.07%
Receivables, net | Not rated | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 307,000	$ 132,000
% of total exposure	0.13%	0.08%
Derivative Instruments (current and long-term) | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 396,000	$ 301,000
% of total exposure	0.17%	0.18%
Derivative Instruments (current and long-term) | Receivables and Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 2,378,000	$ 1,631,000
% of total exposure	1%	1%
Derivative Instruments (current and long-term) | Credit rating of A- or above | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 202,000	$ 155,000
% of total exposure	0.09%	0.09%
Derivative Instruments (current and long-term) | Credit rating of BBB- to BBB+ | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 8,000	$ 22,000
% of total exposure		0.01%
Derivative Instruments (current and long-term) | Not rated | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 186,000	$ 124,000
% of total exposure	0.08%	0.08%
Regulated utilities | Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 890,000	$ 696,000
% of total exposure	0.37%	0.43%
Regulated utilities | Receivables, net | Residential
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 455,000	$ 384,000
% of total exposure	0.19%	0.24%
Regulated utilities | Receivables, net | Commercial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 192,000	$ 167,000
% of total exposure	0.08%	0.10%
Regulated utilities | Receivables, net | Industrial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 121,000	$ 54,000
% of total exposure	0.05%	0.03%
Regulated utilities | Receivables, net | Other
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 122,000	$ 91,000
% of total exposure	0.05%	0.06%

Derivatives Instruments (Cash C

Derivatives Instruments (Cash Collateral) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
15. Derivative Instruments
Cash collateral provided to others	$ 224	$ 212
Cash collateral received from others	112	100
Total fair value of these derivatives, in a liability position	$ 1,078	$ 682

Fair Value Measurements (Deriva

Fair Value Measurements (Derivatives) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Assets
Total assets	$ 396	$ 301
Liabilities
Total liabilities	1,078	682
Level 3
Assets
Total assets	90	104
Liabilities
Total liabilities	826	518
Net assets (liabilities)	736	414
Level 3 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	52	88
Liabilities
Total liabilities	0	0
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	4	4
Liabilities
Total liabilities	1	3
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	34	12
Liabilities
Total liabilities	825	515
Fair Value, Measurements, Recurring
Assets
Total assets	396	301
Liabilities
Total liabilities	1,078	682
Net assets (liabilities)	(682)	(381)
Fair Value, Measurements, Recurring | FX forwards
Assets
Total assets	5
Liabilities
Total liabilities	23
Fair Value, Measurements, Recurring | Equity derivatives
Assets
Total assets		11
Liabilities
Total liabilities	5
Fair Value, Measurements, Recurring | Other
Liabilities
Total liabilities	28
Fair Value, Measurements, Recurring | Regulatory deferral
Assets
Total assets	238	237
Liabilities
Total liabilities	25	20
Fair Value, Measurements, Recurring | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	168	142
Liabilities
Total liabilities	24	12
Fair Value, Measurements, Recurring | Regulatory deferral | FX forwards
Assets
Total assets	18	7
Liabilities
Total liabilities	1	8
Fair Value, Measurements, Recurring | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		88
Fair Value, Measurements, Recurring | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	52
Fair Value, Measurements, Recurring | HFT derivatives
Assets
Total assets	153	53
Liabilities
Total liabilities	1,025	662
Fair Value, Measurements, Recurring | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	44	13
Liabilities
Total liabilities	31	12
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	109	40
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	994	650
Fair Value, Measurements, Recurring | Level 1
Assets
Total assets	132	115
Liabilities
Total liabilities	73	24
Net assets (liabilities)	59	91
Fair Value, Measurements, Recurring | Level 1 | FX forwards
Assets
Total assets	0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives
Assets
Total assets		11
Liabilities
Total liabilities	5
Fair Value, Measurements, Recurring | Level 1 | Other
Liabilities
Total liabilities	5
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral
Assets
Total assets	120	101
Liabilities
Total liabilities	15	7
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	120	101
Liabilities
Total liabilities	15	7
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | FX forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	0
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives
Assets
Total assets	12	3
Liabilities
Total liabilities	53	17
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	9	4
Liabilities
Total liabilities	2	4
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	3	(1)
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	51	13
Fair Value, Measurements, Recurring | Level 2
Assets
Total assets	174	82
Liabilities
Total liabilities	179	140
Net assets (liabilities)	(5)	(58)
Fair Value, Measurements, Recurring | Level 2 | FX forwards
Assets
Total assets	5
Liabilities
Total liabilities	23
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives
Assets
Total assets		0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 2 | Other
Liabilities
Total liabilities	23
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral
Assets
Total assets	66	48
Liabilities
Total liabilities	10	13
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	48	41
Liabilities
Total liabilities	9	5
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | FX forwards
Assets
Total assets	18	7
Liabilities
Total liabilities	1	8
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	0
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives
Assets
Total assets	103	34
Liabilities
Total liabilities	146	127
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	31	5
Liabilities
Total liabilities	28	5
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	72	29
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	118	122
Fair Value, Measurements, Recurring | Level 3
Assets
Total assets	90	104
Liabilities
Total liabilities	826	518
Net assets (liabilities)	(736)	(414)
Fair Value, Measurements, Recurring | Level 3 | FX forwards
Assets
Total assets	0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 3 | Equity derivatives
Assets
Total assets		0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 3 | Other
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral
Assets
Total assets	52	88
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | FX forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		88
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	52
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives
Assets
Total assets	38	16
Liabilities
Total liabilities	826	518
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	4	4
Liabilities
Total liabilities	1	3
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	34	12
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	$ 825	$ 515

Fair Value Measurements (Fair v

Fair Value Measurements (Fair value of the Level 3 financial assets) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 104
Realized gains included in fuel for generation and purchased power	64
Unrealized gains included in regulatory liabilities	28
Total realized and unrealized gains (losses) included in non-regulated operating revenues	22
Ending Balance	90
Regulatory deferral | Physical natural gas purchases | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	88
Realized gains included in fuel for generation and purchased power	64
Unrealized gains included in regulatory liabilities	28
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Ending Balance	52
Not Designated as Hedging Instrument | Energy Related derivative | Non-regulated operating revenues
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	104
Realized gains included in fuel for generation and purchased power	64
HFT derivatives | Energy Related derivative | Non-regulated operating revenues
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	104
Realized gains included in fuel for generation and purchased power	(64)
Unrealized gains included in regulatory liabilities	28
Total realized and unrealized gains (losses) included in non-regulated operating revenues	22
Ending Balance	90
HFT derivatives | Power | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	4
Realized gains included in fuel for generation and purchased power	0
Unrealized gains included in regulatory liabilities	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Ending Balance	4
HFT derivatives | Natural gas | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	12
Realized gains included in fuel for generation and purchased power	0
Unrealized gains included in regulatory liabilities	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	22
Ending Balance	$ 34

Fair Value Measurements (Fair_2

Fair Value Measurements (Fair value of the Level 3 financial Liabilities) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 518
Total realized and unrealized gains (losses) included in non-regulated operating revenues	308
Ending Balance	826
Power
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	3
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(2)
Ending Balance	1
Natural gas
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	515
Total realized and unrealized gains (losses) included in non-regulated operating revenues	310
Ending Balance	$ 825

Fair Value Measurements (Quanti

Fair Value Measurements (Quantitative Information Significant Unobservable Inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy) (Details) - CAD ($)	Dec. 31, 2022	Dec. 31, 2021
Assets
Total assets	$ 396,000,000	$ 301,000,000
Liabilities
Total liabilities	1,078,000,000	682,000,000
Fair Value, Measurements, Recurring
Assets
Total assets	396,000,000	301,000,000
Liabilities
Total liabilities	1,078,000,000	682,000,000
Net liability	(682,000,000)	(381,000,000)
Regulatory deferral | Fair Value, Measurements, Recurring
Assets
Total assets	238,000,000	237,000,000
Liabilities
Total liabilities	25,000,000	20,000,000
Regulatory deferral | Physical natural gas purchases | Fair Value, Measurements, Recurring
Assets
Total assets	52,000,000
HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	153,000,000	53,000,000
Liabilities
Total liabilities	1,025,000,000	662,000,000
HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring
Assets
Total assets	44,000,000	13,000,000
Liabilities
Total liabilities	31,000,000	12,000,000
HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring
Liabilities
Total liabilities	994,000,000	650,000,000
Level 3
Assets
Total assets	90,000,000	104,000,000
Liabilities
Total liabilities	826,000,000	518,000,000
Net liability	736,000,000	414,000,000
Level 3 | Fair Value, Measurements, Recurring
Assets
Total assets	90,000,000	104,000,000
Liabilities
Total liabilities	826,000,000	518,000,000
Net liability	(736,000,000)	(414,000,000)
Level 3 | Regulatory deferral | Fair Value, Measurements, Recurring
Assets
Total assets	52,000,000	88,000,000
Liabilities
Total liabilities	0	0
Level 3 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets	52,000,000	88,000,000
Liabilities
Total liabilities	0	$ 0
Level 3 | Regulatory deferral | Physical natural gas purchases | Fair Value, Measurements, Recurring
Assets
Total assets	$ 52,000,000
Level 3 | Regulatory deferral | Range, Minimum | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input	5.79	4.51
Level 3 | Regulatory deferral | Range, Maximum | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input	31.85	26.09
Level 3 | Regulatory deferral | Weighted average | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input	12.27	9.74
Level 3 | HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	$ 38,000,000	$ 16,000,000
Liabilities
Total liabilities	826,000,000	518,000,000
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	4,000,000	4,000,000
Liabilities
Total liabilities	1,000,000	3,000,000
Level 3 | HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring
Assets
Total assets	4,000,000	4,000,000
Liabilities
Total liabilities	1,000,000	3,000,000
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	34,000,000	12,000,000
Liabilities
Total liabilities	825,000,000	515,000,000
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring
Liabilities
Total liabilities	$ 825,000,000	$ 515,000,000
Level 3 | HFT derivatives | Range, Minimum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	43.24	37.05
Level 3 | HFT derivatives | Range, Minimum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	2.45	1.90
Level 3 | HFT derivatives | Range, Maximum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	269.10	213
Level 3 | HFT derivatives | Range, Maximum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	33.88	21.53
Level 3 | HFT derivatives | Weighted average | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	138.79	99.34
Level 3 | HFT derivatives | Weighted average | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	12.01	8.80

Fair Value Measurements (Assets

Fair Value Measurements (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	$ 14,670	$ 16,775
Fair Value Measurement [Domain] | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	0	0
Fair Value Measurement [Domain] | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	14,284	16,308
Fair Value Measurement [Domain] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	386	467
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	16,318	14,658
Financial assets and liabilities	$ 14,670	$ 16,775

Fair Value Measurements (Hybrid

Fair Value Measurements (Hybrid Notes) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,100	$ 1,700
Net investment in United States dollar denominated operations
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	1,200
After-tax foreign currency gain (loss)	$ 97	$ 5

Related Paty Transactions (Narr

Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
NSPML | Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 157	$ 149
M&NP | Non-Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 9	$ 19

Receivables And Other Current_3

Receivables And Other Current Assets (Summary of Receivables And Other Current Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
18. Receivables and Other Current Assets
Customer accounts receivable - billed	$ 1,096	$ 767
Customer accounts receivable - unbilled	424	318
Allowance for credit losses	(17)	(21)
Capitalized transportation capacity	781	316
NMGC gas hedge settlement receivable	162	0
Income taxes receivable	9	8
Prepaid expenses	82	65
Other	360	280
Total receivables and other current assets	$ 2,897	$ 1,733

Leases (Narrative) (Details)

Leases (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee, Operating Leases
Lessee, Operating Lease, Description	The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 63 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.
Lease, Expense	$ 138	$ 150
Variable costs for power generation facility finance leases	$ 131	142
Lessee, Operating Lease, Existence of Option to Extend [true false]	true
Lessee, Operating Lease, Option to Extend	The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 63 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised
Lessee, Lease, Description [Line Items]
Net Investment in Lease	$ 638	$ 522
Lessor lease option to extend	65 years
Brunswick Pipeline Lease [Member]
Lessee, Lease, Description [Line Items]
Term of contract	34 years
Net Investment in Lease	$ 100
Lessor lease option to extend	16 years
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	63 years

Leases (Operating Leases) (Deta

Leases (Operating Leases) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Assets and Liabilities, Lessee
Right-of-use asset	$ 58	$ 58
Lease liabilities, Current	3	3
Lease liabilities, Long-term	59	58
Total lease liabilities	62	61
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	8	7
Right-of-use assets obtained in exchange for lease obligations: Operating leases	$ 1	$ 0
Weighted average remaining lease term (years)	44 years	44 years
Weighted average discount rate - operating leases	0.0398%	0.0398%

Leases (Future minimum lease pa

Leases (Future minimum lease payments under non-cancellable operating leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter
2023	$ 6
2024	6
2025	5
2026	3
2027	3
Thereafter	116
Minimum lease payments, Total	139
Less imputed interest	(77)
Total	$ 62	$ 61

Leases (Direct Finance and Sale

Leases (Direct Finance and Sales-type Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Net investment in direct finance and sales-type leases
Total minimum lease payments to be received	$ 1,393	$ 947
Less: amounts representing estimated executory costs	(205)	(165)
Minimum lease payments receivable	1,188	782
Estimated residual value of leased property (unguaranteed)	183	183
Less: unearned finance lease income	(733)	(443)
Net investment in direct finance and sales-type leases	638	522
Principal due within one year (included in "Receivables and other current assets")	34	19
Net Investment in direct finance leases - long-term	604	503
Future minimum lease payments to be received for each of the next five years and in aggregate thereafter
2023	90
2024	92
2025	95
2026	94
2027	92
Thereafter	930
Total minimum lease payments to be received	1,393	947
Less: executory costs	(205)	(165)
Minimum lease payments receivable	$ 1,188	$ 782

Property, plant and equipment_2

Property, plant and equipment (Regulated and Non-regulated Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment, Net
Total cost	$ 30,576	$ 26,868
Less: Accumulated depreciation	(9,574)	(8,739)
Total cost less: Accumulated depreciation	21,002	18,129
Construction work in progress	1,994	2,224
Property, Plant and Equipment, Net	22,996	20,353
Generation
Property, Plant and Equipment, Net
Total cost	$ 13,083	11,173
Generation | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
Generation | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	131 years
Transmission
Property, Plant and Equipment, Net
Total cost	$ 2,731	2,532
Transmission | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Transmission | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	80 years
Distribution
Property, Plant and Equipment, Net
Total cost	$ 6,978	6,305
Distribution | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Distribution | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	65 years
Gas transmission and distribution
Property, Plant and Equipment, Net
Total cost	$ 5,061	4,385
Gas transmission and distribution | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	13 years
Gas transmission and distribution | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	83 years
General plant and other
Property, Plant and Equipment, Net
Total cost	$ 2,723	$ 2,473
General plant and other | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
General plant and other | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	71 years

Property, plant and equipment_3

Property, plant and equipment (Regulated and Non-regulated Assets) (Narrative) (Details) - Pipleline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) mi	Dec. 31, 2021 USD ($)
Jointly Owned Pipleline lateral
Jointly Owned Utility Plant, Proportionate Ownership Share	50%	50%
Length of pipeline, in miles | mi	26
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 27	$ 27
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 1	$ 1

Employee Benefit Plans (Changes

Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and the Funded Status) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined benefit pension plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	$ 2,624	$ 2,759
Service cost	41	43
Plan participant contributions	6	6
Interest cost	80	67
Benefits Paid	(174)	(160)
Actuarial losses	(480)	(89)
Settlements and curtailments	(6)	0
Foreign currency translation adjustment	67	(2)
Benefit Obligation, Ending Balance	2,158	2,624
Change in plan assets
Plan Assets, Beginning Balance	2,702	2,605
Employer contributions	45	42
Plan participant contributions	6	6
Benefits paid	(174)	(160)
Actual return on assets, net of expenses	(489)	214
Settlements and curtailments	(6)	0
Foreign currency translation adjustment	79	(5)
Plan Assets, Ending Balance	2,163	2,702
Funded Status
Funded status, end of year	5	78
Non-pension Benefit Plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	318	339
Service cost	4	5
Plan participant contributions	6	4
Interest cost	9	8
Benefits Paid	(31)	(27)
Actuarial losses	(79)	(10)
Settlements and curtailments	0	0
Foreign currency translation adjustment	16	(1)
Benefit Obligation, Ending Balance	243	318
Change in plan assets
Plan Assets, Beginning Balance	51	52
Employer contributions	24	21
Plan participant contributions	6	4
Benefits paid	(31)	(27)
Actual return on assets, net of expenses	(7)	2
Settlements and curtailments	0	0
Foreign currency translation adjustment	3	(1)
Plan Assets, Ending Balance	46	51
Funded Status
Funded status, end of year	$ (197)	$ (267)

Employee Benefit Plans (Plans w

Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Defined benefit pension plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	$ 1,006	$ 140
Fair value of plan assets	914	35
Funded Status	(92)	(105)
Non-pension Benefit Plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	221	290
Fair value of plan assets	0	0
Funded Status	$ (221)	$ (290)

Employee Benefit Plans (Accumul

Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO for the defined benefit pension plans	$ 2,080	$ 2,507
Defined benefit pension plans
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO	111	133
Fair value of plan assets	33	35
Funded Status	$ (78)	$ (98)

Employee Benefit Plans (Amounts

Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Balance Sheet
Other current liabilities	$ (33)	$ (27)
Long-term liabilities	(281)	(370)
Defined benefit pension plans
Balance Sheet
Other current liabilities	(13)	(7)
Long-term liabilities	(80)	(100)
Other long-term assets	98	185
AOCI, net of tax and regulatory assets	358	230
Less: Deferred income tax (expense) recovery in AOCI	(7)	(8)
Net amount recognized	356	300
Non-pension Benefit Plans
Balance Sheet
Other current liabilities	(20)	(20)
Long-term liabilities	(201)	(270)
Other long-term assets	24	23
AOCI, net of tax and regulatory assets	22	90
Less: Deferred income tax (expense) recovery in AOCI	(1)	1
Net amount recognized	$ (176)	$ (176)

Employee Benefit Plans (Change

Employee Benefit Plans (Change in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined benefit pension plans
Change in AOCI and Regulatory Assets
Beginning Balance	$ 38
Amortized in current period	8	$ 21
Ending Balance	22	38
Defined benefit pension plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	192
Amortized in current period	(21)
Current year addition to AOCI or regulatory assets	147
Change in FX rate	18
Ending Balance	336	192
Defined benefit pension plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	30
Amortized in current period	(10)
Current year addition to AOCI or regulatory assets	(5)
Change in FX rate	0
Ending Balance	15	30
Non-pension Benefit Plans
Change in AOCI and Regulatory Assets
Beginning Balance	(1)
Amortized in current period	0	3
Ending Balance	(9)	(1)
Non-pension Benefit Plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	91
Amortized in current period	(2)
Current year addition to AOCI or regulatory assets	(62)
Change in FX rate	4
Ending Balance	31	91
Non-pension Benefit Plans | Actuarial losses (gains) | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year addition to AOCI or regulatory assets	(10)
Change in FX rate	0
Ending Balance	$ (10)	$ 0

Employee Benefit Plans (Net amo

Employee Benefit Plans (Net amount in AOCI and regulatory assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 3,620	$ 2,566
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	15	30
Deferred income tax expense (recovery)	7	8
AOCI, net of tax	22	38
Regulatory assets	336	192
AOCI, net of tax and regulatory assets	358	230
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Actuarial losses	(10)	0
Deferred income tax expense (recovery)	1	(1)
AOCI, net of tax	(9)	(1)
Regulatory assets	31	91
AOCI, net of tax and regulatory assets	$ 22	$ 90

Employee Benefit Plans (Net Per

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (2,482)	$ (2,151)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	41	43
Interest cost	80	67
Expected return on plan assets	(144)	(132)
Current year amortization of: Actuarial losses	8	21
Regulatory assets (liability)	21	24
Settlement, curtailments	2	0
Net Periodic Benefit Cost, Total	8	23
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	4	5
Interest cost	9	8
Expected return on plan assets	0	(1)
Current year amortization of: Actuarial losses	0	3
Regulatory assets (liability)	2	2
Settlement, curtailments	0	0
Net Periodic Benefit Cost, Total	$ 15	$ 17

Employee Benefit Plans (Asset C

Employee Benefit Plans (Asset Class) (Details) - Defined benefit pension plans	Dec. 31, 2022
Short-term securities | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0%
Short-term securities | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.05%
Fixed income | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.35%
Fixed income | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.50%
Fixed income | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.30%
Fixed income | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.50%
Equities: Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.07%
Equities: Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.17%
Equities: Non-Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.36%
Equities: Non-Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.60%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.50%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	0.70%

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value of Investments) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined benefit pension plans
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,163	$ 2,702	$ 2,605
Total
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,163	$ 2,702
Percentage	100%	100%
Total | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 70	$ 60
Percentage	3%	2%
Total | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (70)	$ (84)
Percentage	(3.00%)	(3.00%)
Total | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 87	$ 97
Percentage	4%	4%
Total | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 233	$ 366
Percentage	11%	14%
Total | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 186	$ 215
Percentage	8%	8%
Total | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 104	$ 132
Percentage	5%	5%
Total | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 83	$ 117
Percentage	4%	4%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 14	$ 11
Percentage	1%	0%
Total | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 68	$ 86
Percentage	3%	3%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (3)	$ 0
Percentage	0%	0%
Total | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 790	$ 952
Percentage	36%	35%
Total | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 601	$ 750
Percentage	28%	28%
NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,391	$ 1,702
NAV | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	790	952
NAV | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	601	750
Level 1
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	577	749
Level 1 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	70	60
Level 1 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(70)	(84)
Level 1 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	87	97
Level 1 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	233	366
Level 1 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	186	215
Level 1 | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	3	8
Level 1 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	68	86
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	1
Level 1 | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	195	251
Level 2 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	104	132
Level 2 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	83	117
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	11	3
Level 2 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(3)	(1)
Level 2 | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 0	$ 0

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Defined benefit pension plans
Expected employer contributions
Expected employer contributions, 2023	$ 44
Expected benefit payments
Expected benefit payments, 2023	164
Expected benefit payments, 2024	161
Expected benefit payments, 2025	168
Expected benefit payments, 2026	172
Expected benefit payments, 2027	178
Expected benefit payments, 2028 - 2032	919
Non-pension Benefit Plans
Expected employer contributions
Expected employer contributions, 2023	20
Expected benefit payments
Expected benefit payments, 2023	22
Expected benefit payments, 2024	23
Expected benefit payments, 2025	23
Expected benefit payments, 2026	22
Expected benefit payments, 2027	22
Expected benefit payments, 2028 - 2032	$ 105

Employee Benefit Plans (Assumpt

Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined benefit pension plans
Benefit obligation - December 31:
Discount rate - past service	5.33%	3.05%
Discount rate - future service	5.34%	3.18%
Rate of compensation increase	3.62%	3.31%
Health care trend - initial (next year)	0%	0%
Health care trend - ultimate	0%	0%
Benefit cost for year ended December 31:
Discount rate - past service	3.05%	2.49%
Discount rate - future service	3.18%	2.64%
Expected long-term return on plan assets	6.07%	5.86%
Rate of compensation increase	3.31%	2.89%
Health care trend - initial (next year)	0%	0%
Health care trend - ultimate	0%	0%
Non-pension Benefit Plans
Benefit obligation - December 31:
Discount rate - past service	5.31%	2.81%
Discount rate - future service	5.32%	2.92%
Rate of compensation increase	3.61%	3.29%
Health care trend - initial (next year)	5.40%	5.09%
Health care trend - ultimate	3.77%	3.77%
Health care trend - year ultimate reached	2043	2042
Benefit cost for year ended December 31:
Discount rate - past service	2.81%	2.48%
Discount rate - future service	2.92%	2.51%
Expected long-term return on plan assets	1.32%	0%
Rate of compensation increase	3.29%	3.04%
Health care trend - initial (next year)	5.09%	5.64%
Health care trend - ultimate	3.77%	4.35%
Health care trend - year ultimate reached	2042	2038

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined-Benefit Plans, information
Defined Benefit Plan, Description	Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.
Defined Benefit Plan, Plan Assets, Expected Long-term Rate-of-Return, Description	The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.
Defined Benefit Plan, Expected Return on Plan Assets	$ 2,482	$ 2,151
Contribution Amount	$ 41	45
Plan assets recognition period	5 years
Defined benefit pension plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	$ 144	132
Non-pension Benefit Plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	$ 0	$ 1

Goodwill (Details)

Goodwill (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Goodwill [Roll Forward]
Balance, January 1		$ 5,696,000,000	$ 5,720,000,000
GBPC impairment charge		(73,000,000)	0
Change in FX rate		389,000,000	(24,000,000)
Balance, December 31		6,012,000,000	$ 5,696,000,000
Accumulated impairment charges		30,000,000
Tampa Electric and PGS
Goodwill [Roll Forward]
GBPC impairment charge	$ 0
NMGC
Goodwill [Roll Forward]
GBPC impairment charge		0
GBPC
Goodwill [Roll Forward]
GBPC impairment charge		$ (73,000,000)
Balance, December 31

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, 2022	Dec. 31, 2021
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 2,726	$ 1,742
Weighted average interest rate	5.01%	0.83%
Advances on revolving credit and term facilities | TECO Finance
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 481	$ 355
Weighted average interest rate	5.47%	1.20%
Advances on term, revolving and accounts receivable facilities | TEC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 1,380	$ 945
Weighted average interest rate	5%	0.58%
Non-revolving term facilities | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 796	$ 400
Weighted average interest rate	5.19%	0.96%
Bank indebtedness | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 0	$ 6
Weighted average interest rate	0%	0%
Bank indebtedness | NSPI
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 0	$ 1
Weighted average interest rate	0%	0%
Advances on revolving credit facilities | GBPC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 10	$ 10
Weighted average interest rate	5.25%	5.25%
Advances on revolving credit facilities | NMGC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 59	$ 25
Weighted average interest rate	5.15%	1.20%

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, 2022	Dec. 31, 2021
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity	$ 3,155	$ 2,729
Total advances under available facilities	2,735	1,739
Available capacity under existing agreements	$ 420	990
Term credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2023
Total available capacity	$ 542	634
Revolving credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 542	507
Revolving credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 1,084	1,014
Revolving credit facility | NMGC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 169	158
Revolving credit facility | GBPC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	on demand
Total available capacity	$ 18	16
Non-revolving term loan | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2023
Total available capacity	$ 400	400
Non-revolving term loan II | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2023
Total available capacity	$ 400	0
Advances under revolving credit and term facilities
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total advances under available facilities	2,731	1,735
Letters of credit issued within the credit facilities
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total advances under available facilities	$ 4	$ 4

Short Term Debt (Narrative) (De

Short Term Debt (Narrative) (Details) - CAD ($) $ in Millions			12 Months Ended
	Dec. 15, 2022	Dec. 12, 2022	Dec. 31, 2022	Dec. 16, 2022	Dec. 13, 2022	Aug. 02, 2022	Dec. 31, 2021
Line of Credit Facility [Line Items]
Weighted average interest rate			5.01%				0.83%
Line of Credit Facility, Maximum Borrowing Capacity			$ 3,155				$ 2,729
Revolving credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,084				1,014
Revolving credit facility | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			169				158
Revolving credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			542				507
Term loan credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 542				$ 634
Non-revolving term facilities | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 400
Debt Instrument, Maturity Date	Dec. 16, 2022		Dec. 16, 2023
Non-revolving term facilities | TEC | Florida Electric Utility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 500			$ 400
Debt Instrument, Maturity Date		Dec. 16, 2022	Dec. 13, 2023
Non-revolving term facilities | Emera Inc.
Line of Credit Facility [Line Items]
Weighted average interest rate			5.19%				0.96%
Line of Credit Facility, Maximum Borrowing Capacity			$ 400				$ 400
Non-revolving term loan II | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 400
Debt Instrument, Maturity Date			Aug. 02, 2023
Non-revolving term loan II | Emera Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 400				$ 0

Other Current Liabilities (Deta

Other Current Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Other Current Liabilities
Accrued charges	$ 174	$ 157
Nova Scotia Cap-and-Trade Program Provision	172	0
Accrued interest on long-term debt	97	75
Pension and post-retirement liabilities (note 19)	33	27
Sales and other taxes payable	14	6
Income taxes payable	9	6
Other	80	95
Other current liabilities, Total	$ 579	$ 366

Long Term Debt (Details)

Long Term Debt (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Debt issuance costs	$ (126)	$ (121)
Amount due within one year	(574)	(462)
Long Term Debt, Adjustments	(698)	(580)
Long-Term Debt	15,744	14,196
Interest expense	110	102
Emera
Debt Instrument [Line Items]
Long-term debt	2,528	2,399
NMGC
Debt Instrument [Line Items]
Long-term debt	629	589
NSPI
Debt Instrument [Line Items]
Long-term debt	3,546	3,041
ECI
Debt Instrument [Line Items]
Long-term debt	449	478
TECO Energy
Debt Instrument [Line Items]
Fair market value adjustment	$ 2	$ 3
Bankers acceptances | LIBOR loans | Emera
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2027
Long-term debt	$ 403	$ 378
Unsecured fixed rate notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	0.029%	0.029%
Maturity	2023
Long-term debt	$ 500	$ 500
Unsecured fixed rate notes | Emera Finance
Debt Instrument [Line Items]
Maturity	2024 - 2046
Fixed to floating subordinated notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	0.0675%	0.0675%
Maturity	2076
Long-term debt	$ 1,625	$ 1,521
Unsecured senior notes | Emera Finance
Debt Instrument [Line Items]
Weighted average interest rate	0.0365%	0.0365%
Long-term debt	$ 3,725	$ 3,487
Fixed rate notes and bonds | TEC
Debt Instrument [Line Items]
Weighted average interest rate	0.0415%	0.0415%
Maturity	2024 - 2052
Long-term debt	$ 4,341	$ 3,683
Fixed rate notes and bonds | PGS
Debt Instrument [Line Items]
Weighted average interest rate	0.0378%	0.0378%
Maturity	2024 - 2052
Long-term debt	$ 772	$ 660
Fixed rate notes and bonds | NMGC
Debt Instrument [Line Items]
Weighted average interest rate	0.0311%	0.0311%
Maturity	2026 - 2051
Long-term debt	$ 521	$ 488
Fixed rate notes and bonds | NMGI
Debt Instrument [Line Items]
Weighted average interest rate	0.0364%	0.0364%
Maturity	2024
Long-term debt	$ 203	$ 190
Discount notes | NSPI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2024 - 2027
Long-term debt	$ 881	$ 376
Medium term fixed rate notes | NSPI
Debt Instrument [Line Items]
Weighted average interest rate	0.0514%	0.0514%
Maturity	2025 - 2097
Long-term debt	$ 2,665	$ 2,665
Senior secured credit facility | EBP
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2026
Long-term debt	$ 249	$ 249
Amortizing fixed rate notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	0.0397%	0.0397%
Maturity	2024 - 2026
Long-term debt	$ 100	$ 104
Secured senior notes | ECI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2026
Long-term debt	$ 86	$ 84
Secured fixed rate senior notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	0.0306%	0.0443%
Maturity	2023 - 2029
Long-term debt	$ 142	$ 161
Non-revolving term facility, floating rate | NMGC
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2024
Long-term debt	$ 108	$ 101
Non-revolving term facility, floating rate | ECI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2027
Long-term debt	$ 30	$ 28
Non-revolving term facility, fixed rate | ECI
Debt Instrument [Line Items]
Weighted average interest rate	0.0205%	0.0236%
Maturity	2025 - 2026
Long-term debt	$ 91	$ 101

Long Term Debt (Revolving credi

Long Term Debt (Revolving credit facilities, outstanding borrowings and available capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 3,155	$ 2,729
Use of available facilities	1,408	894
Available capacity under existing agreements	420	990
Revolving credit facility
Debt Instrument [Line Items]
Available capacity under existing agreements	2,219	1,527
Available capacity under existing agreements	811	633
Advances on the revolving credit facility	50
Revolving credit facility | Emera
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 900	900
Maturity	June 2027
Revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 800	600
Maturity	December 2027
Revolving credit facility | ECI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 11	27
Maturity	2023-2032
Non-revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 400	0
Maturity	July 2024
Non-revolving credit facility | NMGC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 108	0
Maturity	March 2024
Borrowings under credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 1,396	770
Letters of credit issued within the credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 12	$ 124

Long Term Debt (Debt Covenants)

Long Term Debt (Debt Covenants) (Details)	Dec. 31, 2022
Maximum
Debt Instrument [Line Items]
Debt to capital ratio	0.70
Syndicated credit facilities
Debt Instrument [Line Items]
Debt to capital ratio	0.57

Long Term Debt (Long Term Matur

Long Term Debt (Long Term Maturities) (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Subsidiaries
Debt Instrument [Line Items]
2023	$ 574
2024	1,613
2025	262
2026	3,110
2027	946
Thereafter	9,937
Total, long-term debt maturities, including capital lease obligations	16,442
Emera
Debt Instrument [Line Items]
2023	500
2024	0
2025	0
2026	1,625
2027	403
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	2,528
Emera US Finance LP
Debt Instrument [Line Items]
2023	0
2024	407
2025	0
2026	1,016
2027	0
Thereafter	2,302
Total, long-term debt maturities, including capital lease obligations	3,725
Tampa Electric
Debt Instrument [Line Items]
2023	0
2024	356
2025	0
2026	0
2027	0
Thereafter	3,985
Total, long-term debt maturities, including capital lease obligations	4,341
PGS
Debt Instrument [Line Items]
2023	0
2024	51
2025	0
2026	0
2027	0
Thereafter	721
Total, long-term debt maturities, including capital lease obligations	772
NMGC
Debt Instrument [Line Items]
2023	0
2024	108
2025	0
2026	95
2027	0
Thereafter	426
Total, long-term debt maturities, including capital lease obligations	629
NMGI
Debt Instrument [Line Items]
2023	0
2024	203
2025	0
2026	0
2027	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	203
NSPI
Debt Instrument [Line Items]
2023	0
2024	398
2025	125
2026	40
2027	483
Thereafter	2,500
Total, long-term debt maturities, including capital lease obligations	3,546
EBP
Debt Instrument [Line Items]
2023	0
2024	0
2025	0
2026	249
2027	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	249
ECI
Debt Instrument [Line Items]
2023	74
2024	90
2025	137
2026	85
2027	60
Thereafter	3
Total, long-term debt maturities, including capital lease obligations	$ 449

Long Term Debt (Narrative) (Det

Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions						6 Months Ended	12 Months Ended
	Dec. 15, 2022 CAD ($)	Sep. 22, 2022	Sep. 15, 2022 USD ($)	Jul. 12, 2022 USD ($)	Mar. 24, 2022	Jun. 30, 2022	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Jul. 15, 2022 CAD ($)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 3,155	$ 2,729
Proceeds from issuance of long-term debt							784	2,554
Repayments of Long-term Debt							367	1,660
Florida Electric Utility [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt				$ 600
Canadian Electric Utilities | Revolving credit facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 600						$ 800
Line of Credit Facility, Expiration Date	Dec. 16, 2026						Dec. 16, 2027
Canadian Electric Utilities | Non-revolving term loan
Debt Instrument [Line Items]
Debt Instrument, Maturity Date							Jul. 15, 2024
Line of Credit Facility, Maximum Borrowing Capacity										$ 400
Gas Utilities and Infrastructure [Member] | Revolving credit facility
Debt Instrument [Line Items]
Debt Instrument, Maturity Date						Jun. 30, 2025	Jun. 30, 2026
Gas Utilities and Infrastructure [Member] | Non-revolving term loan
Debt Instrument [Line Items]
Debt Instrument, Maturity Date		Sep. 23, 2022					Mar. 22, 2024
Line of Credit Facility, Maximum Borrowing Capacity									$ 80
Emera
Debt Instrument [Line Items]
Long-term Debt, Gross							$ 2,528	2,399
Emera | Revolving credit facility
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2026						Jun. 30, 2027
Line of Credit Facility, Maximum Borrowing Capacity							$ 900
NSPI
Debt Instrument [Line Items]
Long-term Debt, Gross							3,546	3,041
NMGC
Debt Instrument [Line Items]
Long-term Debt, Gross							$ 629	$ 589
Note Maturity Date Of September 15, 2022 | Florida Electric Utility [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 250
Senior Note Maturity Date Of July 12, 2024 | Florida Electric Utility [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date							Jul. 12, 2024
Stated interest rate				3.875%
Proceeds from issuance of long-term debt				$ 300
Senior Note Maturity Date Of July 15, 2052 | Florida Electric Utility [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date							Jul. 15, 2052
Stated interest rate				5%
Proceeds from issuance of long-term debt				$ 300
Floating rate note | Other Electric Utilities [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date					Mar. 25, 2022		Mar. 25, 2027

Asset Retirement Obligation (Ch

Asset Retirement Obligation (Change in ARO) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in ARO
Balance, January 1	$ 174	$ 178
Accretion included in depreciation expense	9	10
Change in FX rate	3	(1)
Additions	1	1
Accretion deferred to regulatory asset (included in PP&E)	1	2
Liabilities settled	(1)	(13)
Revisions in estimated cash flows	(13)	0
Other	0	1
Balance, December 31	$ 174	$ 174

Commitments and Contingencies_2

Commitments and Contingencies (Contractual Commitments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Recorded Unconditional Purchase Obligation [Line Items]
2023	$ 2,776
2024	1,272
2025	934
2026	701
2027	657
Thereafter	5,152
Contractual Commitments	11,492
NSPI Contractual obligation for use of the Maritime Link
Regulatory Liabilities	2,273	$ 2,055
Revenue, Remaining Performance Obligation, Amount	$ 450	$ 437
Nalcor Energy
NSPI Contractual obligation for use of the Maritime Link
Long-term Purchase Commitment, Period	50 years
SeaCoast Gas Transmission, LLC
NSPI Contractual obligation for use of the Maritime Link
Revenue, Remaining Performance Obligation, Amount	$ 144
SeaCoast Gas Transmission, LLC | PGS
NSPI Contractual obligation for use of the Maritime Link
Revenue, Remaining Performance Obligation, Amount	$ 144
Maritime Link Project
NSPI Contractual obligation for use of the Maritime Link
Long-term Purchase Commitment, Period	38 years
Maritime Link Project | NSPML
NSPI Contractual obligation for use of the Maritime Link
Regulatory Liabilities	$ 1,800
Maritime Link Project | NSPI
Recorded Unconditional Purchase Obligation [Line Items]
2023	164
Purchased power
Recorded Unconditional Purchase Obligation [Line Items]
2023	693
2024	516
2025	423
2026	383
2027	367
Thereafter	2,817
Contractual Commitments	5,199
Transportation
Recorded Unconditional Purchase Obligation [Line Items]
2023	269
2024	243
2025	237
2026	228
2027	243
Thereafter	2,145
Contractual Commitments	3,365
Fuel, gas supply and storage
Recorded Unconditional Purchase Obligation [Line Items]
2023	1,161
2024	282
2025	138
2026	40
2027	5
Thereafter	1
Contractual Commitments	1,627
Capital projects
Recorded Unconditional Purchase Obligation [Line Items]
2023	264
2024	89
2025	4
2026	1
2027	0
Thereafter	0
Contractual Commitments	358
Equity Method Investments
Recorded Unconditional Purchase Obligation [Line Items]
2023	240
2024	0
2025	0
2026	0
2027	0
Thereafter	0
Contractual Commitments	240
Other Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
2023	149
2024	142
2025	132
2026	49
2027	42
Thereafter	189
Contractual Commitments	$ 703

Commitments and Contingencies_3

Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions, $ in Millions			1 Months Ended	12 Months Ended
	Oct. 16, 2020 USD ($)	May 13, 2020 USD ($)	Nov. 30, 2020 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)
Loss Contingencies [Line Items]
Litigation Settlement, Amount				$ 63		$ 0
Prime Rate [Member] | Tampa Electric
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss				$ 17			$ 13
United States Free Trade Agreement Award One [Member] | TGH
Loss Contingencies [Line Items]
Proceeds from settlement of claims			$ 38
United States Free Trade Agreement Award two [Member] | TGH
Loss Contingencies [Line Items]
Litigation Settlement, Amount		$ 35			$ 46
Litigation Settlement Interest	$ 2

Commitments and Contingencies_4

Commitments and Contingencies (Guarantees and Letters of Credit) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Guaranty Liabilities	$ 119		$ 118
Letters of Credit Outstanding, Amount		$ 63		$ 64
Emera Reinsurance Limited
Guarantor Obligations [Line Items]
Guaranty Liabilities	$ 35
Guarantor Obligations, Origin and Purpose	relating to outstanding notes of GBPC
Guarantor Obligations, Term	expire in May 2023
TECO Energy
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 13
Guarantor Obligations, Maximum Exposure, Undiscounted	13
TECO Energy | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	45
ECI
Guarantor Obligations [Line Items]
Guaranty Liabilities	66
Payment Guarantee | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	27
Surety Bonds
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 145		$ 148

Commitments and Contingencies_5

Commitments and Contingencies (Collaborative Arrangements) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Regulated fuel for generation and purchased power	$ 12	$ 18
Operating, maintenance and general (OM&G)	$ 3	$ 3

Cumulative Preferred Stock (Aut

Cumulative Preferred Stock (Authorized) (Details) - CAD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Aug. 15, 2020	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Issued and Outstanding		58,000,000	58,000,000
Net Proceeds		$ 1,422	$ 1,422
Series A Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 0.5456	$ 0.5456
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		4,866,814	4,866,814
Net Proceeds		$ 119	$ 119
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		1,133,186	1,133,186
Net Proceeds		$ 28	$ 28
Preferred Stock Dividend Payment Rate Variable		Floating
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	1.1802	$ 1.1802
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		10,000,000	10,000,000
Net Proceeds		$ 245	$ 245
Series E Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		$ 1.1250
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		5,000,000	5,000,000
Net Proceeds		$ 122	$ 122
Series F Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.0505	$ 1.0505
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		8,000,000	8,000,000
Net Proceeds		$ 195	$ 195
Series H Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		$ 1.2250
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		12,000,000	12,000,000
Net Proceeds		$ 295	$ 295
Series J Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		$ 1.0625
Preferred Stock, Redemption Price Per Share		$ 25
Issued and Outstanding		8,000,000	8,000,000
Net Proceeds		$ 196	$ 196
Series L Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share		$ 1.1500
Preferred Stock, Redemption Price Per Share		$ 26
Issued and Outstanding		9,000,000	9,000,000
Net Proceeds		$ 222	$ 222

Cumulative Preferred Stock (Cha

Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - $ / shares		12 Months Ended
	Aug. 15, 2020	Dec. 31, 2022
Series A Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.40%
Current Annual Dividend	$ 0.5456	$ 0.5456
Earliest Redemption and/or Conversion Option Date		August 15, 2025
Redemption Value		$ 25
Preferred Stock, Conversion Basis		Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted		Series B
Series A Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		1.84%
Series C Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.10%
Current Annual Dividend	1.1802	$ 1.1802
Earliest Redemption and/or Conversion Option Date		August 15, 2023
Redemption Value		$ 25
Preferred Stock, Conversion Basis		Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted		Series D
Series C Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		2.65%
Series F Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.202%
Current Annual Dividend	$ 1.0505	$ 1.0505
Earliest Redemption and/or Conversion Option Date		February 15, 2025
Redemption Value		$ 25
Preferred Stock, Conversion Basis		Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted		Series G
Series F Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		2.63%
Series B Preferred Stock
Class of Stock [Line Items]
Initial Yield		2.393%
Earliest Redemption and/or Conversion Option Date		August 15, 2025
Redemption Value		$ 25
Preferred Stock, Conversion Basis		Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted		Series A
Series B Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		1.84%
Series H Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.90%
Current Annual Dividend		$ 1.2250
Earliest Redemption and/or Conversion Option Date		August 15, 2023
Redemption Value		$ 25
Preferred Stock, Conversion Basis		Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted		Series I
Series H Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		4.90%
Series J Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.25%
Current Annual Dividend		$ 1.0625
Earliest Redemption and/or Conversion Option Date		May 15, 2026
Redemption Value		$ 25
Right to Convert on a one for one basis		Series K
Series J Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		4.25%
Series E Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.50%
Current Annual Dividend		$ 1.1250
Redemption Value		25
Series E Preferred Stock | After August 15, 2022
Class of Stock [Line Items]
Redemption Value		$ 25
Series L Preferred Stock
Class of Stock [Line Items]
Initial Yield		4.60%
Current Annual Dividend		$ 1.1500
Earliest Redemption and/or Conversion Option Date		November 15, 2026
Redemption Value		$ 26
Series L Preferred Stock | On Or After November 15, 2026 to November 15, 2027
Class of Stock [Line Items]
Redemption Value		26
Series L Preferred Stock | After November 15, 2027 To November 15, 2030
Class of Stock [Line Items]
Preferred Stock, Redemption Price, Annual Decrease		0.25
Series L Preferred Stock | After November 15, 2030
Class of Stock [Line Items]
Redemption Value		25
Series D Preferred Stock
Class of Stock [Line Items]
Redemption Value		25
Series D Preferred Stock | After August 15, 2023
Class of Stock [Line Items]
Redemption Value		25.50
Series G Preferred Stock
Class of Stock [Line Items]
Redemption Value		25
Series G Preferred Stock | After February 15, 2025
Class of Stock [Line Items]
Redemption Value		25.5
Series I Preferred Stock
Class of Stock [Line Items]
Redemption Value		$ 25
Series I Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield		2.54%
Series I Preferred Stock | After August 15, 2023
Class of Stock [Line Items]
Redemption Value		$ 25.5

Cumulative Preferred Stock (Nar

Cumulative Preferred Stock (Narrative) (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Issuance of common stock	4,070	4,990
Proceeds from issuance of preferred stock, net of issuance costs	$ 0	$ 416
First Preferred Shares
Class of Stock [Line Items]
Preferred Stock Dividend Preference Or Restrictions	First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.
Series J Preferred Stock
Class of Stock [Line Items]
Percentage rate used to determine dividend rate	4.25%
Series L Preferred Stock
Class of Stock [Line Items]
Percentage rate used to determine dividend rate	4.60%

Non-controlling Interest In S_3

Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 14	$ 34
Domlec
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	0	20
GBPC
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Amount Represented by Preferred Stock	$ 14	$ 14

Non-controlling Interest In S_4

Non-controlling Interest In Subsidiaries (Preferred shares of GBPC) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Noncontrolling Interest [Line Items]
Number of shares issued and outstanding	58,000,000	58,000,000
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC
Noncontrolling Interest [Line Items]
Preferred Stock, Shares Authorized	10,000
Number of shares issued and outstanding	10,000	10,000
Outstanding as at December 31	$ 14	$ 14

Non-controlling Interest In S_5

Non-controlling Interest In Subsidiaries (Narrative) (Details) - GBPC	12 Months Ended
	Dec. 31, 2022 $ / shares
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Payment Terms	6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually
Preferred Stock, Redemption Terms	The preferred shares are redeemable by GBPC after June 17, 2021
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares
Noncontrolling Interest [Line Items]
Preferred Stock, Redemption Price Per Share	$ 1,000
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD preferred shares
Noncontrolling Interest [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6%

Supplementary Information To Co

Supplementary Information To Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Changes in non-cash working capital
Inventory	$ (214)	$ (84)
Receivables and other current assets	(636)	(364)
Accounts payable	423	289
Other current liabilities	193	7
Total non-cash working capital	(234)	(152)
Supplemental disclosure of cash paid:
Interest	699	603
Income Taxes	67	24
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	237	214
Reclassification of long-term debt to short-term debt	500	0
(Decrease) Increase in accrued capital expenditures	(13)	(45)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	(157)	$ (108)
January 2023 Settlement Of NMGC Gas Hedges [Member]
Changes in non-cash working capital
Receivables and other current assets	162
Nova Scotia Cap-And-Trade Program [Member]
Changes in non-cash working capital
Other current liabilities	$ (172)

Stock-based Compensation (Emplo

Stock-based Compensation (Employee Common Share Purchase Plan and Dividend Reinvestment Plan) (Details) shares in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 CAD ($)
Employee Common Share Purchase Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Common Share Purchase Plan, Description	Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law.	Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law.
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount	$ 25
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount	$ 20,000	$ 15,000
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	20%	20%
Compensation cost for shares issued	$ 3,000,000		$ 3,000,000
Dividend Reinvestment Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Common Share Purchase Plan, Description	The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2022.	The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2022.
Maximum aggregate number of common shares reserved for issuance | shares	7	7
Discount from Market Price, Purchase Date	2%	2%
Dividend Reinvestment Plan | Maximum
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Discount from Market Price, Purchase Date	5%	5%

Stock-based Compensation (Narra

Stock-based Compensation (Narrative) (Details) $ / shares in Units, $ in Thousands, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2021 CAD ($) $ / shares shares	Dec. 31, 2021 USD ($)
Stock option plan, Additional information
Percentage of outstanding stock maximum	10%
Dividend Reinvestment Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance | shares	7
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	7
DSU Plan
Share Unit Plans
Cash payments made during the year	$ 8,000	$ 11,000
Employee Stock Option Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance | shares	6	6.2
Terms of award	P10Y
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	6	6.2
Share Unit Plans
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance | shares	2.7	3.1
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	2.7	3.1
First Anniversary | DSU Plan | Executive and senior management
Stock option plan, Additional information
Vesting rights, percentage	25%
First Anniversary | DSU Plan | Executive and senior management | Minimum
Stock option plan, Additional information
Vesting rights, percentage	50%
Vesting Period After Date Of Retirement Or Termination For Other Than Just Cause | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period	27 months
Vesting Period After Date Of Termination For Just Cause | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period	60 days
Stock Option Plan
Stock option plan, Additional information
Share-based payment award, description	The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2022, Emera is in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.
Maximum aggregate number of common shares reserved for issuance | shares	14.7
Vesting rights	The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued.
Percentage of outstanding stock maximum	5%
Policy for issuing shares upon exercise	The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.
Cash received for options exercised	$ 9,000	$ 14,000
Total intrinsic value of options exercised	$ 4,000	$ 6,000
Exercise price range, lower range limit | $ / shares	$ 32.35	$ 32.35
Exercise price range, upper range limit | $ / shares	$ 60.03	$ 60.03
Fair value assumptions, method used	The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis.
Share Unit Plans
Compensation cost recognized for employee and director	$ 2,000	$ 2,000
Maximum aggregate number of common shares reserved for issuance | shares	14.7
Stock Option Plan, Granted 2021 | First Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25%
Stock Option Plan, Granted 2021 | Second Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25%
Stock Option Plan, Granted 2021 | Third Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25%
Stock Option Plan, Granted 2021 | Fourth Anniversary
Stock option plan, Additional information
Vesting rights, percentage	25%
Stock Option Plan, Granted 2022 | First Anniversary
Stock option plan, Additional information
Vesting rights, percentage	20%
Stock Option Plan, Granted 2022 | Second Anniversary
Stock option plan, Additional information
Vesting rights, percentage	20%
Stock Option Plan, Granted 2022 | Third Anniversary
Stock option plan, Additional information
Vesting rights, percentage	20%
Stock Option Plan, Granted 2022 | Fourth Anniversary
Stock option plan, Additional information
Vesting rights, percentage	20%
Stock Option Plan, Granted 2022 | Fifth Anniversary
Stock option plan, Additional information
Vesting rights, percentage	20%
Share Unit Plans | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period.
Deferred Share Unit Plans
Share Unit Plans
Compensation cost recognized for employee and director	$ 6,000	9,000
Tax Benefit related to compensation costs for share units realized	2,000	3,000
Deferred Share Unit Plans | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	33,000	39,000
Deferred Share Unit Plans | Director
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 34,000	39,000
Deferred Share Unit Plans | Share Unit Plans | DSU Plan
Share Unit Plans
Deferred share unit plan, description	When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives.
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management
Share Unit Plans
Deferred share unit plan, description	Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met.
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Director
Share Unit Plans
Deferred share unit plan, description	Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed.
Performance Share Unit Plan
Stock option plan, Additional information
Award service period	3 years
Share Unit Plans
Tax Benefit related to compensation costs for share units realized	$ 5,000	3,000
Cash payments made during the year	24,000	29,000
Performance Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 40,000	66,000
Performance Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.
Compensation cost recognized for stock options	$ 18,000	12,000
Restricted Share Unit Plan
Stock option plan, Additional information
Award service period	3 years
Share Unit Plans
Tax Benefit related to compensation costs for share units realized	$ 2,000		$ 2
Share Unit Plans: Aggregate intrinsic value	30,000
Cash payments made during the year
Restricted Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value		24,000
Restricted Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.
Compensation cost recognized for stock options	$ 9,000	$ 8,000

Stock-based Compensation (Weigh

Stock-based Compensation (Weighted Average Fair Values, Assumptions in Valuation Models for Options Granted) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
31. Stock-Based Compensation
Weighted average fair value per option	$ 5.35	$ 3.63
Expected term	5 years	5 years
Risk-free interest rate	1.79%	0.60%
Expected dividend yield	4.55%	5%
Expected volatility	18.87%	19.14%

Stock-based Compensatin (Stock

Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Total Options, Number of Options
Total Options: Number of Options, Exercised	(600,000)	(750,000)
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Granted	$ 5.35	$ 3.63
Stock option plan, Additional information
Non-Vested options: Unrecognized compensation	$ 4	$ 3
Non-vested options: Weighted average recognition period	3 years	3 years
Vested Options: Weighted average remaining term	5 years	6 years
Vested Options: Aggregate intrinsic value	$ 10	$ 21
Vested Options: Fair value	$ 2	$ 1
Employee Stock Option Plan
Total Options, Number of Options
Total Options: Number of Options, Outstanding, Beginning Balance	2,590,304
Granted	467,100
Total Options: Number of Options, Exercised	(203,525)
Total Options: Number of Options, Outstanding, Ending Balance	2,853,879	2,590,304
Total Options: Number of Options, Options exercisable	1,505,479
Total Options, Weighted average exercise price per share
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 48.48
Total Options: Weighted average exercise price per share, Granted	58.26
Total Options: Weighted average exercise price per share, Exercised	43.87
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance	50.41	$ 48.48
Total Options: Weighted average exercise price per share, Options exercisable	$ 46.59
Non-Vested Options, Number of Options
Non-Vested Options: Number of Options, Outstanding, Beginning Balance	1,452,475
Granted	467,100
Non-Vested Options: Number of Options, Vested	571,175
Non-Vested Options: Number of Options, Ending Balance	1,348,400	1,452,475
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 3.18
Non-Vested Options: Weighted average exercise price per share, Granted	5.35
Non-Vested Options: Weighted average exercise price per share, Vested	2.83
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance	$ 4.08	$ 3.18

Stock-based Compensation (Defer

Stock-based Compensation (Deferred Share Unit Plans) (Details) - DSU Plan - Deferred Share Unit Plans	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	610,601
Share Unit Plans: Granted including DRIP | shares	76,252
Share Unit Plans: Exercised | shares	(59,630)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	627,223
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 39.22
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	52.42
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	31.57
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 41.55
Director
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	614,365
Share Unit Plans: Granted including DRIP | shares	104,465
Share Unit Plans: Exercised | shares	(54,572)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	664,258
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 43.80
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	57.89
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	46.04
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 45.83

Stock-based Compensation (Perfo

Stock-based Compensation (Performance Share Unit Plan) (Details) - Performance Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	951,935
Share Unit Plans: Granted including DRIP	242,462
Share Unit Plans: Exercised	(357,960)
Share Unit Plans: Forfeited	(145,991)
Share Unit Plans: Outstanding and exercisable, Ending Balance	690,446
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 48.60
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	59.30
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	42.85
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	44.28
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 56.24
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 40	$ 66

Stock-based Compensation (Restr

Stock-based Compensation (Restricted Share Unit Plan) (Details) - Restricted Share Unit Plan - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 30
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	343,952
Share Unit Plans: Granted including DRIP	180,426
Share Unit Plans: Exercised	(134)
Share Unit Plans: Forfeited	(15,776)
Share Unit Plans: Outstanding and exercisable, Ending Balance	508,468
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 54.64
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	59.30
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	54.63
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	56.08
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 56.25
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value		$ 24

Variable Interest Entities (Det

Variable Interest Entities (Details) - NSPML - NSPML - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Equity Method Investment, Underlying Equity in Net Assets	$ 501	$ 533
Maximum exposure to losss	$ 6	$ 11