Emera (ERRAF) 40-F 21 Feb 25 2024 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2024 shares
Entity Listings [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Entity File Number	000-54516
Entity Registrant Name	EMERA INCORPORATED
Entity Incorporation, State or Country Code	A5
Entity Address, Address Line One	5151 Terminal Road
Entity Address, City or Town	Halifax
Entity Address, State or Province	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
Document Fin Stmt Error Correction Flag	false
Entity Emerging Growth Company	false
ICFR Auditor	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2024
Auditor Firm Id	1263
Auditor Name	Ernst & Young LLP
Auditor Location	Halifax, Canada
Entity Central Index Key	0001127248
Amendment Flag	false
Document Fiscal Period Focus	FY
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	295,935,686
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, 2024	Dec. 31, 2023
Operating revenues
Total operating revenues (note 6)	$ 7,200	$ 7,563
Operating expenses
Operating, maintenance and general expenses ("OM&G")	1,918	1,879
Provincial, state, and municipal taxes	427	433
Depreciation and amortization	1,162	1,049
Impairment charges (note 23)	225	0
Total operating expenses	6,120	5,769
Income from operations	1,080	1,794
Income from equity investments (note 8)	99	146
Other income, net (note 9)	203	158
Interest expense, net (note 10)	(973)	(925)
Income before provision for income taxes	409	1,173
Income tax (recovery) expense (note 11)	(159)	128
Net income	568	1,045
Non-controlling interest in subsidiaries ("NCI")	1	1
Preferred stock dividends	73	66
Net income attributable to common shareholders	$ 493.6	$ 977.7
Earnings per common share (note 13)
Basic	$ 1.71	$ 3.57
Diluted	$ 1.71	$ 3.57
Weighted average shares of common stock outstanding (in millions) (note 13)
Basic	289.1	273.6
Diluted	289.2	273.8
Dividends per common share declared	$ 2.8775	$ 2.7875
Regulated | Gas Revenue
Operating revenues
Total operating revenues (note 6)	$ 1,575	$ 1,489
Operating expenses
Fuel for generation and purchased power	396	527
Regulated | Electric Revenue
Operating revenues
Total operating revenues (note 6)	5,872	5,746
Operating expenses
Fuel for generation and purchased power	1,992	1,881
Non-Regulated
Operating revenues
Total operating revenues (note 6)	$ (247)	$ 328

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Consolidated Statements of Comprehensive Income
Net income	$ 568	$ 1,045
Other comprehensive income (loss) ("OCI"), net of tax
Foreign currency translation adjustment	1,027	(270)
Unrealized (losses) gains on net investment hedges	(139)	38
Cash flow hedges - reclassification adjustment for gains included in income	(2)	(2)
Cash flow hedges
Unrealized gains on available-for-sale investment	2	0
Net change in unrecognized pension and post-retirement benefit obligation	68	(39)
OCI	956	(273)
Comprehensive income	1,524	772
Comprehensive income attributable to NCI	1	1
Comprehensive Income of Emera Incorporated	$ 1,523	$ 771

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Foreign currency translation, tax expense (recovery)	$ 10	$ (7)
Hybrid Notes as a hedge of the foreign currency exposure	1,200	1,200
Net change in unrecognized pension and post-retirement benefit obligation		1
OCI, tax expense (recovery)	10	(6)
Net investment in United States dollar denominated operations
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200	$ 1,200

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 196	$ 567
Restricted cash	17	21
Inventory (note 15)	781	790
Derivative instruments (notes 16 and 17)	115	174
Regulatory assets (note 7)	595	339
Receivables and other current assets (note 19)	1,811	1,817
Assets held for sale (note 4)	173	0
Total current assets	3,688	3,708
Property, plant and equipment ("PP&E"), net of accumulated depreciation and amortization of $10,442 and $9,994, respectively (note 21)	26,168	24,376
Other assets
Deferred income taxes (note 11)	392	208
Derivative instruments (notes 16 and 17)	51	66
Regulatory assets (note 7)	2,832	2,766
Net investment in direct finance and sales type leases (note 20)	610	621
Investments subject to significant influence (note 8)	654	1,402
Goodwill (note 23)	5,858	5,871
Other long-term assets (note 33)	538	462
Assets held for sale (note 4)	2,160	0
Total other assets	13,095	11,396
Total assets	42,951	39,480
Current liabilities
Short-term debt (note 24)	1,400	1,433
Current portion of long-term debt (note 26)	234	676
Accounts payable	1,992	1,454
Derivative instruments (notes 16 and 17)	526	386
Regulatory liabilities (note 7)	262	168
Other current liabilities (note 25)	489	427
Liabilities associated with assets held for sale (note 4)	212	0
Total current liabilities	5,115	4,544
Long-term liabilities
Long-term debt (note 26)	18,173	17,689
Deferred income taxes (note 11)	2,331	2,352
Derivative instruments (notes 16 and 17)	91	118
Regulatory liabilities (note 7)	1,618	1,604
Pension and post-retirement liabilities (note 22)	274	265
Other long-term liabilities (notes 8 and 27)	910	820
Liabilities associated with assets held for sale (note 4)	1,148	0
Total long-term liabilities	24,545	22,848
Equity
Common stock (note 12)	9,042	8,462
Cumulative preferred stock (note 29)	1,422	1,422
Contributed surplus	84	82
Accumulated other comprehensive income ("AOCI") (note 14)	1,261	305
Retained earnings	1,468	1,803
Total Emera Incorporated equity	13,277	12,074
NCI (note 30)	14	14
Total equity	13,291	12,088
Total liabilities and equity	42,951	39,480
Commitments and contingencies (note 28)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Consolidated Balance Sheets
Accumulated depreciation and amortization on property, plant and equipment	$ 10,442	$ 9,994

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Operating activities
Net income	$ 568	$ 1,045
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,165	1,060
Income from equity investments, net of dividends	(8)	(22)
Allowance for funds used during construction ("AFUDC") - equity	(53)	(38)
Deferred income taxes, net	(191)	97
Net change in pension and post-retirement liabilities	(46)	(68)
NSPI fuel adjustment mechanism ("FAM")	451	(88)
Net change in fair value ("FV") of derivative instruments	228	(666)
Net change in regulatory assets and liabilities	(226)	554
Net change in capitalized transportation capacity	175	434
Goodwill impairment charge	214	0
Gain on sale of LIL, excluding transaction costs	(191)	0
Other operating activities, net	108	28
Changes in non-cash working capital (note 31)	452	(95)
Net cash provided by operating activities	2,646	2,241
Investing activities
Additions to PP&E	(3,151)	(2,937)
Proceeds from disposal of investment subject to significant influence	927	0
Other investing activities	6	20
Net cash used in investing activities	(2,218)	(2,917)
Financing activities
Change in short-term debt, net	56	(66)
Proceeds from short-term debt with maturities greater than 90 days	0	548
Repayment of short-term debt with maturities greater than 90 days	0	(1,086)
Proceeds from long-term debt, net of issuance costs	1,361	1,932
Retirement of long-term debt	(1,086)	(151)
Net repayments under committed credit facilities	(825)	(96)
Issuance of common stock, net of issuance costs	284	424
Dividends on common stock	(538)	(488)
Dividends on preferred stock	(73)	(66)
Other financing activities	3	(12)
Net cash (used in) provided by financing activities	(818)	939
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	23	(7)
Net (decrease) increase in cash, cash equivalents, restricted cash and cash associated with assets held for sale	(367)	256
Cash, cash equivalents, and restricted cash, beginning of year	588	332
Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, end of year	$ 221	$ 588

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of:
Cash	$ 191	$ 559
Short-term investments	5	8
Restricted cash	17	21
Assets held for sale	8	0
Cash, cash equivalents, restricted cash and cash associated with assets held for sale	$ 221	$ 588

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	NCI
Beginning Balance at Dec. 31, 2022	$ 11,441	$ 7,762	$ 1,422	$ 81	$ 578	$ 1,584	$ 14
Net income of Emera Inc.	1,045	0	0	0	0	1,044	1
Other comprehensive income (loss), net of tax expense/recovery	(273)	0	0	0	(273)	0	0
Dividends declared on preferred stock (note 29)	(66)	0	0	0	0	(66)	0
Dividends declared on common stock	(759)	0	0	0	0	(759)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	397	397	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	272	272	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	32	31	0	1	0	0	0
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2023	12,088	8,462	1,422	82	305	1,803	14
Net income of Emera Inc.	568	0	0	0	0	567	1
Other comprehensive income (loss), net of tax expense/recovery	956	0	0	0	956	0	0
Dividends declared on preferred stock (note 29)	(73)	0	0	0	0	(73)	0
Dividends declared on common stock	(829)	0	0	0	0	(829)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	261	261	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	291	291	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	30	28	0	2	0	0	0
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2024	$ 13,291	$ 9,042	$ 1,422	$ 84	$ 1,261	$ 1,468	$ 14

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Consolidated Statements of Changes in Equity
OCI, tax expense (recovery)	$ 10	$ (6)
Dividends per common share declared	$ 2.8775	$ 2.7875

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2024
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an electricity generation, transmission and distribution, and At December 31, 2024, Emera’s reportable segments ● electric utility, serving 855,000 ● ● primary electricity supplier in Nova Scotia, serving approximately 557,000 ● 100 Maritime Link Project, a $ 1.8 island of Newfoundland and Nova Scotia. On June 4, 2024, Emera completed the sale of its 31.1 Labrador Island Link Partnership (“LIL”), which was previously Utilities segment. For further details, refer to note 4. ● ● 508,000 ● approximately 550,000 agreement to sell NMGC. The transaction is expected to approvals, including approval by the New Mexico Public For further details, refer to note 4. ● 145 -kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, States (“US”) border under a 25 -year firm service agreement with Repsol Energy America Canada Partnership (“Repsol Energy Canada”), ● transmission company offering services in Florida; ● 12.9 1,400 -kilometre pipeline that transports natural gas throughout markets northeastern US. ● with regulated electric utilities that include: ● electric utility on the island of Barbados, serving approximately 135,000 ● utility on Grand Bahama Island, serving approximately 19,500 ● 19.5 integrated regulated electric utility on the island of St. ● below the required threshold for reporting as separate items that are not directly allocated to the operations of Emera’s includes: ● ● natural gas and electricity and provides related energy ● 30 electricity facility in Brooklyn, Nova Scotia; and ● 50.0 Swamp”), a 660 Massachusetts. ● (“TECO Finance”), financing subsidiaries of Emera; ● located in the US; and ● Basis of Presentation These consolidated financial statements are prepared Generally Accepted Accounting Principles (“USGAAP”) adjustments that are of a recurring nature and necessary All dollar amounts are presented in Canadian dollars (“CAD”), Principles of Consolidation These consolidated financial statements include the accounts subsidiaries, and a variable interest entity (“VIE”) in which the equity method of accounting to record investments significant influence, and for VIEs in which Emera is not The Company performs ongoing analysis to assess whether reconsideration events have arisen with respect to existing To identify potential VIEs, management reviews contractual and ownership arrangements such tolling contracts, guarantees, jointly owned facilities and is deemed the primary beneficiary must be consolidated. power to direct the activities of the VIE that most significantly obligation to absorb losses or the right to receive benefits the VIE. In circumstances where Emera has an investment beneficiary, the VIE Intercompany balances and transactions have been on certain transactions between certain non-regulated and regulated accounting standards for rate-regulated entities. The net profit eliminated in the absence of the accounting standards regulated operating revenues. An offset is recorded generation and purchased power, Use of Management Estimates The preparation of consolidated financial statements to make estimates and assumptions. These may affect date of the financial statements and reported amounts periods. Significant areas requiring use of management liabilities, accumulated reserve for cost of removal, pension revenue, useful lives for depreciable assets, goodwill and long-lived income taxes, asset retirement obligations (“ARO”), and evaluates the Company’s estimates on an ongoing expected conditions and assumptions believed to be reasonable any adjustments recognized in income in the year they arise. Regulatory Matters Regulatory accounting applies where rates are established third-party regulator. Rates products or services and provide an opportunity for a reasonable applicable. For further detail, refer to note 7. Foreign Currency Translation Monetary assets and liabilities denominated in foreign exchange prevailing at the balance sheet date. The resulting differences original transaction date and the balance sheet date are Assets and liabilities of foreign operations whose functional translated using exchange rates in effect at the balance average exchange rate in effect for the period. The and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt hedges of net investments in USD denominated foreign these investments, measured at exchange rates in effect Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand clauses and riders, are recognized when obligations under the when electricity and gas are delivered to customers over and consumes the benefits. Electric and gas revenues billed and unbilled revenues. Revenues related to the approved by the respective regulators and recorded periodic, systematic basis, generally monthly or bi-monthly. and gas delivered to customers, but not billed, is estimated recognized. The Company’s estimate of unbilled by estimating the megawatt hours (“MWh”) or therms delivered expected to prevail in the upcoming billing cycle. This energy demand, weather, line Non-regulated Revenue: Marketing and trading margins are comprised of Emera natural gas and electricity, are recorded when obligations under terms of the contract reflecting the nature of contractual relationships with customers Energy sales are recognized when obligations under the when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations satisfied. Other: Sales, value add, and other taxes, except for gross receipts Company concurrent with revenue-producing activities Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, approved by the Florida Public Service Commission (“FPSC”). for franchise fees and gross receipt taxes are included revenues in the Consolidated Statements of Income. TEC and PGS are included as an expense on the Consolidated and municipal taxes”. NMGC is an agent in the collection and payment of franchise required by a tariff to present the amounts on receipt taxes are presented net with no line item impact PP&E PP&E is recorded at original cost, including AFUDC or aid of construction. The cost of additions, including betterments and replacements Consolidated Balance Sheets. When units of regulated PP&E plus removal or disposal costs, less salvage proceeds, gain or loss reflected in income. Where a disposition of included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, regulated property or interest for non-regulated property, project. Overhead includes corporate costs such as finance, along with other costs related to support functions, employee operating and maintenance. Expenditures for project development have a future economic benefit. Normal maintenance projects and major maintenance related assets are expensed as incurred. When a major the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based the depreciable assets in each functional class of depreciable regulated subsidiaries, depreciation is calculated using to the average investment, adjusted for anticipated costs depreciable property. Intangible assets, which are included in “PP&E” on the Consolidated computer software and land rights. Amortization is determined estimated remaining service lives of the asset in each category. subsidiaries, amortization is calculated using the amortizable value to date over the remaining life of those assets. The require regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price identifiable assets acquired and liabilities assumed at the cost less any write-down for impairment and is adjusted Goodwill is subject to assessment for impairment at the change in circumstances indicates that the FV of a reporting assessing goodwill for impairment, the Company has the option assessment to determine whether a quantitative assessment assessment management considers, among other factors, market considerations and overall financial performance. If the Company performs a qualitative assessment and less than its carrying amount, or if the Company chooses quantitative test is performed. The quantitative test compares value, including goodwill (“carrying amount”). If the carrying an impairment loss is recorded. Management estimates approach, or a combination of the income and market cash flow analysis which relies on management’s flows. The analysis includes an estimate of terminal values methodology which derives a valuation using an assumed residual cash flows. The discount rate used is a market participant traded comparable companies and represents the weighted companies. For the market approach, management estimates transactions within comparable industries, or in the case transactions involving the reporting unit. Significant assumptions unit using an income approach include discount and growth cost of capital, valuation of the reporting unit’s net capital cash flows. Adverse changes in these assumptions the goodwill assigned to Emera’s reporting units. As of December 31, 2024, Emera’s goodwill represented TECO Energy, Inc. acquired and liabilities assumed. In Q3 2024, Emera entered result, a quantitative goodwill impairment assessment Company recorded a goodwill impairment charge of $ 210 198 155 USD ($ 146 303 NMGC disposal unit classified as held for sale. For further In Q4 2024, a qualitative assessment was performed for carrying amounts calculated during the last quantitative test more likely than not that the FV of this reporting unit exceeded such, no quantitative testing was required. Given the length impairment test for the PGS reporting unit, Emera elected performed a quantitative impairment assessment in Q4 market approach. This assessment estimated that the amount, including goodwill, and as a result, no impairment Income Taxes and Emera recognizes deferred income tax assets and liabilities that have been included in financial statements or income tax liabilities are determined based on the difference the Consolidated Balance Sheets, and their respective year in which the differences are expected to reverse. deferred income tax assets and liabilities is recognized enacted, unless required to be offset to a regulatory Emera recognizes the effect of income tax positions realized. Management reviews all readily available current and looking information, and the likelihood that deferred income taxable income is assessed and assumptions are made income tax assets and liabilities. If management subsequently deferred income tax asset will not be realized, a valuation deferred income tax asset expected to be realized. Generally, investment future periods to the extent that realization of such benefit earned on regulated assets by TEC, PGS and NMGC are regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from taxes. NSPI, NSPML and Brunswick Pipeline collect income taxes that is currently payable, except for the deferred income taxes prescribed by regulators. For the balance of regulated Brunswick Pipeline recognize regulatory assets or liabilities expected to be recovered from or returned to customers liabilities are grossed up using the respective income tax future revenues that are required to fund these deferred associated with reduced revenues resulting from the realization not subject to income taxes. Emera classifies interest and penalties associated with operating expense, respectively. Derivatives and Hedging Activities The Company manages its exposure to normal operating and FX, interest rates and share prices through contractual and by using financial instruments consisting mainly of swaps, equity derivatives, and coal, oil and gas futures, Company has contracts for the physical purchase and sale of contracts are classified as HFT. derivatives. The Company recognizes the FV of all its derivatives on derivatives that meet the normal purchases and normal sales meet the NPNS exception are not recognized on the balance income when they settle. A physical contract generally is reasonable in relation to the Company’s business within the proximity to allow for physical delivery, commodity, and the contracts designated under the NPNS exception and will discontinue under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent proven to effectively hedge identified risk both at Specifically, for cash income in the same period the related hedged item is realized. requirements are not met, the derivatives are recognized income in the reporting period, unless deferred as a result Derivatives entered into by NSPI, NMGC and GBPC that which the NPNS exception has not been taken, are subject change in FV of the derivatives is deferred to a regulatory in the hedged item when the hedged item is settled. Management from settlement of these derivatives related to fuel for to or collected from customers in future rates. TEC and PGS Derivatives that do not meet any of the above criteria are normally recorded in net income of the period. The Company to be included in the HFT category where another accounting Emera classifies gains and losses on derivatives as a component fuel for generation and purchased power, nature of the item being economically hedged. Transportation and trading derivative transactions is recognized as an asset and amortized over the period of the transportation contract presented in the same category as the item being hedged within Statements of Cash Flows. Non-hedged derivatives are included Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance collateral with the same counterparty. and other current assets” and obligations to return cash Leases The Company determines whether a contract contains contract conveys the right to control the use of an identified consideration. Emera has leases with independent power producers (“IPP”) purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized based on the present value of the future minimum lease payments date. As most of Emera’s leases do not provide commencement of the lease is used in determining expense is recognized on a straight-line basis over the Consolidated Statements of Income. Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value, net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the FV and the carrying value 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. Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The to reduce accounts receivable for amounts expected to losses related to accounts receivable by considering historical current events, the characteristics of existing accounts affect the collectability of the reported amount. to maintain the allowance at a level considered adequate written off against the allowance when they are Inventory Fuel and materials inventories are valued at the lower unless evidence indicates the weighted-average cost Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment triggering event occurs, such as a significant market disruption The assessment involves comparing undiscounted expected asset. When the undiscounted cash flow analysis indicates amount of the impairment loss is determined by measuring lived asset over its estimated FV. other recoverable amounts, are based on a combination analysis, observable market activity and independent market regarding uses and holding periods of assets are based which consider external factors and market forces, as assumptions made are consistent with generally accepted valuation and pricing activities. In 2024, impairment charges of $ 19 14 8 million of which was included in Other income, net with $ 11 Consolidated Income Statement. No 2023. Equity Method Investments: The carrying value of investments accounted for under comparing the FV of these investments to their carrying values, reviewing for the presence of impairment indicators. If other-than-temporary, the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under changes in FV recognized in the Consolidated Statements of Income. have readily determinable FV are recorded at cost minus resulting from observable price changes in orderly transactions No impairment of financial assets was required in either Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection resulting from the permanent retirement, abandonment may exist under an existing or enacted law or statute, under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary the Company’s credit adjusted risk-free rate. The Estimated future cash flows are based on completed depreciation experience, estimated useful lives, and governmental regulatory liability is recorded and the carrying amount of the related long-lived The amount capitalized at inception is depreciated in the same Over time, the liability is accreted to its estimated future value. liabilities” and accretion expense is included as part of accretion expense not yet approved by the regulator is depreciation study. Some of the Company’s transmission and distribution recognized in the consolidated financial statements, as reasonably estimated, given insufficient information obligation to perform an asset retirement activity in which conditional on a future event that may or may not be monitors these obligations and a liability is recognized at FV determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR non-ARO COR represent funds received from customers future non-legally required COR of PP&E upon retirement. The the related assets based on depreciation studies approved estimated based on historical experience and future estimated future cash outlays. Stock-Based Compensation The Company has several stock-based compensation management; an employee common share purchase plan; performance share unit (“PSU”) plan; and a restricted its plans in accordance with the FV-based method of based compensation cost is measured at the grant date, recognized as an expense over the employee’s or vesting method. Stock-based compensation plans recognized as and re-measured at FV at each reporting date, with the Employee Benefits The costs of the Company’s pension and other expensed over the periods during which employees render service. status of its defined-benefit and other post-retirement plans on changes in funded status in the year the change occurs. and losses and past service costs in “AOCI” or “Regulatory The components of net periodic benefit cost other than income, net” on the Consolidated Statements of Income. Government Grants The Company accounts for government grants by applying International Accounting Standards (“IAS”) 20, Accounting Government Assistance. A grant relating to an asset is amount of the asset. A grant relating to income is presented intended to compensate. In 2024, the Company received an aggregate of $ 47 7 various Canadian and US government agencies towards PP&E . The capital projects receiving grants primarily relate to the Company’s compliance initiatives. Further details on significant grant programs below. Natural Resources Canada (“NRCan”) Smart Renewables On March 27, 2024, NSPI was approved for a grant under the three 33 cent of eligible project costs to a maximum $ 109 2027. For the year-end December 31, 2024, NSPI received 26 nil ) in funding under the grant, which has been recorded as a reduction to the carrying PP&E .

Change in Accounting Policy

Change in Accounting Policy	12 Months Ended
	Dec. 31, 2024
Change in Accounting Policy [Abstract]
Change in Accounting Policy	2. CHANGE IN ACCOUNTING POLICY The new USGAAP accounting policy that is applicable described as follows: Improvements to Reportable Segment Disclosures The Company adopted Accounting Standard Update (“ASU”) 2023-07, Improvements to Reportable Segment Disclosures. The change segment disclosure requirements, primarily through enhanced expenses. The changes improve financial reporting by information on an annual and interim basis for all public decision-useful financial analyses. The guidance was after December 15, 2023, and for interim periods beginning standard resulted in additional qualitative disclosures provided

Future Accounting Pronouncement

Future Accounting Pronouncements	12 Months Ended
	Dec. 31, 2024
Future Accounting Pronouncements [Abstract]
Future Accounting Pronouncements	3. FUTURE ACCOUNTING PRONOUNCEMENTS The Company considers the applicability and impact of Standards Board (“FASB”). The following not yet been adopted by Emera. Any ASUs not included below either not applicable to the Company or to have an insignificant statements. Disaggregation of Income Statement Expenses In November 2024, the FASB Income–Expense Disaggregation Disclosures (Subtopic Expenses. The standard update improves the disclosures about requiring more detailed information about the types of employee compensation, depreciation and amortization) captions. The guidance will be effective for annual and interim reporting periods beginning after December standard updates are to be applied prospectively with the option Company is currently evaluating the impact of adoption financial statements disclosures. Improvements to Income Tax In December 2023, the FASB Tax income tax disclosures by requiring consistent categories reconciliation of income taxes computed using the enacted tax provision and effective income tax rate, as well by jurisdiction. The standard also requires disclosure of income and income tax expense (recovery) in accordance with Regulation S-X 210.4-08(h), Rules of General Application Income Tax The guidance will be effective for annual reporting periods adoption is permitted. The standard will be applied on permitted. The Company is currently evaluating the impact of financial statements disclosures.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2024
Dispositions [Abstract]
Dispositions	4. DISPOSITIONS Pending Sale of NMGC On August 5, 2024, Emera entered into an agreement for a total enterprise value of approximately $ 1.3 transfer of debt and customary closing adjustments. The subject to certain approvals, including approval by the assets and liabilities are classified as held for sale. As the transaction proceeds will be lower than the carrying amount Emera assessed the NMGC reporting unit for goodwill impairment transaction proceeds to the carrying value of net assets, 366 carrying amount”). The goodwill of the reporting unit was goodwill impairment charge of $ 210 198 155 146 USD, after-tax) was recorded in “Impairment Charges” on the Consolidated 2024. Following the goodwill impairment assessment, the held for the lower of their carrying amount or fair value less costs additional loss for the estimated future transaction costs 16 12 incurred transaction costs of $ 9 7 Consolidated Statements of Income in Q3 2024. The Company will continue to record depreciation on the NMGC date, as the depreciation continues to be reflected in basis of the assets when sold. Depreciation and amortization 26 19 recorded on these assets from August 5, 2024, the date December 31, 2024. Details of the assets and liabilities classified as held for As at December 31 millions of dollars 2024 Cash and cash equivalents $ 8 Inventory 9 Derivative instruments 1 Regulatory assets 28 Receivables and other current assets 127 Current assets held for sale $ 173 PP&E 1,828 Regulatory assets 6 Goodwill 303 Other long-term assets 23 Long-term assets held for sale $ 2,160 Total assets held for sale $ 2,333 Short-term debt $ 46 Derivative instruments 1 Regulatory liabilities 10 Accounts payable and other current liabilities 155 Current liabilities associated with assets held for sale 212 Long-term debt 696 Deferred income taxes 167 Regulatory liabilities 274 Other long-term liabilities 11 Long-term liabilities associated with assets held for sale $ 1,148 Total liabilities associated with assets held for sale $ 1,360 Sale of LIL Equity Interest On June 4, 2024, Emera completed the sale of its 31.1 for a total transaction value of $ 1.2 957 235 assuming Emera’s contractual obligation to fund the additional LIL equity interest for the acquirer. 30 held in escrow pending finalization of certain agreements proceeds receivable is held at FV and included in the gain December 31, 2024, the estimated FV of the escrow proceeds 25 gain on sale, after transaction costs, of $ 182 107 million, after tax and transaction costs), was recognized in “Other Income, net” on the Consolidated segment. In Q4 2024, Emera recognized a $ 22 valuation allowance related to loss carryforwards applied against the sale of LIL. This tax benefit was recorded in “Income Tax Statements of Income in Q4 2024 and included in the

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2024
Segment Information [Abstract]
Segment Information	5. SEGMENT INFORMATION Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker (“CODM”). Emera’s CODM is the Chief Executive Officer. For the Company’s reportable segments, the CODM uses several measures to allocate capital and resources for each segment, predominantly in the annual budget and forecasting processes. The CODM evaluates segment performance by considering budget-to-actual variances for these measures monthly. The measure used by the CODM that is the most consistent with USGAAP measurement principles is net income attributable to common shareholders. 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, 2024 Operating revenues from external customers (1) $ 3,451 $ 1,855 $ 1,595 $ 566 $ (267) $ $ 7,200 Inter-segment revenues (1) 9 - 14 - 19 (42) 3,460 1,855 1,609 566 (248) (42) 7,200 Regulated fuel for generation and purchased power 852 859 - 295 - (14) 1,992 Regulated cost of natural gas - - 396 - - - 396 OM&G 779 408 454 143 154 (20) 1,918 Provincial, state and municipal taxes 273 48 103 3 - - 427 Depreciation and amortization 622 282 182 69 7 - 1,162 Impairment charges - - 11 - 214 - 225 Income from equity investments - 73 20 4 2 - 99 Other income, net 66 28 16 12 73 8 203 Interest expense, net (2) 265 168 151 22 367 - 973 Income tax expense (recovery) 94 (41) 89 1 (302) - (159) NCI in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 73 - 73 Net income (loss) attributable to common shareholders $ 641 $ 232 $ 259 $ 48 $ (686) $ - $ 494 Capital expenditures $ 1,942 $ 481 $ 619 $ 81 $ 4 $ - $ 3,127 As at December 31, 2024 Total assets $ 24,375 $ 7,609 $ 8,439 $ 1,444 $ 1,810 $ (726) $ 42,951 Investments subject to significant influence $ - $ 475 $ 124 $ 55 $ - $ - $ 654 Goodwill $ 5,035 $ - $ 823 $ - $ - $ - $ 5,858 (1) All significant inter-company balances and transactions between non-regulated and regulated entities. Management OM&G, or regulated fuel for generation and purchased measured at the amount of consideration established determining reportable segments. (2) Segment net income is reported on a basis 29 December 31, 2024, between the Gas Utilities 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, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 NCI in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (1) All significant inter-company balances and transactions between non-regulated and regulated entities. Management OM&G, or regulated fuel for generation and purchased measured at the amount of consideration established determining reportable segments. (2) Segment net income is reported on a basis 95 December 31, 2023, between the Florida Electric Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2024 2023 United States 4,712 $ 5,310 Canada 1,922 1,727 Barbados 427 389 The Bahamas 139 137 $ 7,200 $ 7,563 PP&E: As at December 31 December 31 millions of dollars 2024 2023 United States (1) $ 20,084 $ 18,588 Canada 5,068 4,878 Barbados 645 576 The Bahamas 371 334 $ 26,168 $ 24,376 (1) On August 5, 2024, Emera announced an agreement to sell for sale and excluded from the table above. For further

Revenue

Revenue	12 Months Ended
	Dec. 31, 2024
Revenue [Abstract]
Revenue	6. REVENUE The following disaggregates the Company’s 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, 2024 Regulated Revenue Residential $ 2,063 $ 997 $ 203 $ 712 $ - $ - $ 3,975 Commercial 939 499 300 496 - - 2,234 Industrial 223 276 28 94 - (14) 607 Other electric 372 41 7 - - - 420 Regulatory deferrals (157) - 15 - - - (142) Other (1) 20 42 13 224 - (9) 290 Finance income (2)(3) - - - 63 - 63 $ 3,460 $ 1,855 $ 566 $ 1,589 $ - $ (23) $ 7,447 Non-Regulated Revenue Marketing and trading margin (4) - - - - 77 - 77 Other non-regulated operating revenue - - - 20 32 (24) 28 Mark-to-market (3) - - - - (357) 5 (352) $ - $ - $ - $ 20 $ (248) $ (19) $ (247) Total operating revenues $ 3,460 $ 1,855 $ 566 $ 1,609 $ (248) $ (42) $ 7,200 For the year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) 7,235 Non-Regulated Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers. Remaining Performance Obligations: Remaining performance obligations primarily represent and long-term steam supply arrangements with fixed contract aggregate amount of the transaction price allocated to 495 million (2023 – $ 488 3 135 future performance obligations related to a gas transportation through 2040 . This amount excludes contracts with an original variable amounts for which Emera recognizes revenue at the for services performed. Emera expects to recognize revenue for through 2044 .

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2024
Regulatory Assets and Liabilities [Abstract]
Regulatory Assets and Liabilities	7. REGULATORY Regulatory assets represent prudently incurred costs that have will be recovered through future rates or tolls collected from customers. regulatory assets are probable for recovery either because the applicable regulator, or management no longer considers it probable that an asset to income. Regulatory liabilities represent obligations to make refunds previous collections. If management no longer considers related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization regulator. As at December 31 December 31 millions of dollars 2024 (1) 2023 Regulatory assets Deferred income tax regulatory assets $ 1,227 $ 1,233 TEC capital cost recovery for early retired assets 737 671 Storm cost recovery clauses 613 52 Pension and post-retirement medical plan 395 364 TEC capital cost recovery for retired Polk Unit 1 components 205 - Deferrals related to derivative instruments 42 88 Cost recovery clauses 33 151 Environmental remediations 29 26 Stranded cost recovery 27 25 NSPI FAM - 395 Other (2) 119 100 $ 3,427 $ 3,105 Current $ 595 $ 339 Long-term 2,832 2,766 Total $ 3,427 $ 3,105 Regulatory liabilities Deferred income tax regulatory liabilities 828 830 Accumulated reserve – COR 733 849 Cost recovery clauses 121 32 NSPI FAM 56 - Deferrals related to derivative instruments 44 17 BLPC Self-insurance fund ("SIF") (note 33) 32 29 Other (2) 66 15 $ 1,880 $ 1,772 Current $ 262 $ 168 Long-term 1,618 1,604 Total $ 1,880 $ 1,772 (1) On August 5, 2024, Emera announced an were classified as held for sale and excluded from (2) Comprised of regulatory assets and liabilities Deferred Income Tax To years, a regulatory asset or liability is recognized as appropriate TEC Capital Cost Recovery for Early Retired Assets Represents the remaining net book value of Big Bend Power assets that were early retired. The balance earns a rate of return recovered as a separate line item on customer bills for 15 Storm Cost Recovery Clauses TEC and PGS Storm Reserve: The storm reserve is for hurricanes and other named storms PGS systems. As allowed by the FPSC, if charges to the the excess is to be carried as a regulatory asset. TEC of restoration costs over a 12-month period or longer, the reserve. NSPI Storm Rider: NSPI has a UARB approved storm rider for each of 2023, apply to the UARB for recovery of costs if major storm 10 million in a given year. The date. The application for deferral and recovery of the storm rider the incurred cost, with recovery beginning in the year GBPC Storm Restoration: This asset includes storm restoration costs incurred by Hurricane Matthew in 2016. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and and, in 2023, NMGC. Deferred costs of postretirement recognized as cost of service for rate-making purposes Regulation Commission (“NMPRC”), as applicable and participants. TEC Capital Cost Recovery for Retired Polk Unit 1 This regulatory asset relates to the remaining net book value were early retired on December 31, 2024. The balance earns a and will be recovered through base rates over an 11 -year recovery period beginning on January 1, 2025. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in FV economic hedges or that do not qualify for NPNS exemption, by the UARB. The realized gain or loss is recognized generation and purchased power, being economically hedged. Cost Recovery Clauses These assets and liabilities are clauses and riders related to recovered or refunded through cost-recovery mechanisms applicable, on a dollar-for-dollar basis in a subsequent Environmental Remediations This asset is primarily related to PGS costs associated with environmental Gas Plant sites. The balance is included in rate base, partially rate of return as permitted by the FPSC. The timing of recovery approved by the FPSC. Stranded Cost Recovery Due to decommissioning of a GBPC steam turbine in 2012, 21 USD stranded cost through electricity rates; it is included in rates in future years. NSPI FAM NSPI has a FAM, approved related costs from customers through regularly scheduled prudently incurred fuel costs and amounts recovered from customers are deferred to a FAM regulatory subsequent periods. Accumulated Reserve – COR This regulatory asset or liability represents the non-ARO NMGC. AROs represent the FV of estimated cash flows retire its PP&E. rates to cover future COR of PP&E value upon retirement base for ratemaking purposes. This liability is reduced depreciation is recorded for existing assets and as new Regulatory Environments and Updates Florida Electric Utility TEC is regulated by the FPSC and is also subject to regulation Commission. The FPSC sets rates at a level that allows revenue requirements equal to their cost of providing service, capital. Base rates are determined in FPSC rate setting the FPSC or other interested parties. TEC’s approved regulated return on equity (“ROE”) 9.25 11.25 per cent based on an allowed equity capital structure of 54 10.20 10.20 Base Rates: On April 2, 2024, TEC filed a rate case with the FPSC for FPSC rendered a decision which includes annual base 185 adjustments of $ 87 9 the capital structure will continue to be 54 regulatory ROE range is 9.50 11.50 10.50 2025, the FPSC issued the final order approving the decision, 2025, a motion for reconsideration on certain aspects of the On August 16, 2023, TEC filed a petition to implement the provisions pursuant to the 2021 rate case settlement agreement. increase of $ 22 Fuel Recovery and Other Cost Recovery Clauses: TEC has a fuel recovery clause approved by the FPSC, fuel expenses from customers through annual fuel rate recovery rates for purchased power, on capital invested. Differences between prudently amounts recovered from customers through electricity liability and recovered from or returned to customers On April 2, 2024, TEC requested a mid-course adjustment $ 138 12 months , from June 2024 through May 2025. The requested was due to a decrease in actual and projected 2024 natural 2024 costs in the fall of 2023. On May 7, 2024, the FPSC On January 23, 2023, TEC requested an adjustment recovery of $ 518 21 months . The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas projected reduction of $ 170 FPSC on March 7, 2023, and were effective Storm Reserve: On September 26, 2024, Hurricane Helene passed 100 miles west approximately 200 miles north of Tampa, territory was impacted by the tropical storm force winds of customers out of 100,000. As of December 31, 2024, TEC 49 reserve for future recovery. On October 9, 2024, Hurricane Milton made landfall approximately Sarasota, and was the worst weather event to impact the hurricane had a significant impact on TEC’s service customers out of 600,000. As of December 31, 2024, TEC deferred 340 reserve for future recovery . As at December 31, 2024, total restoration costs charged the storm reserve balance, and therefore $ 377 future recovery. On February for the recovery of $ 466 Hurricane Helene and Hurricane Milton and the associated over an 18-month recovery period beginning March 2025. true-up mechanism with the FPSC. In September 2022, TEC was impacted by Hurricane Ian, with 119 charged against TEC’s FPSC approved storm reserve. for recovery of the storm reserve regulatory asset and the replenishment reserve to the approved storm reserve level of $ 56 131 cost recovery surcharge was approved by the FPSC on March surcharge in April 2023. Subsequently, August 16, 2023, to update the total storm cost collection 134 $ 29 Storm Protection Cost Recovery Clause and Settlement The Storm Protection Plan Cost Recovery Clause provides including TEC, to recover transmission and distribution not already included in base rates. Differences between amounts recovered from customers through electricity returned to customers in a subsequent year. and 2025 and was approved by the FPSC in October, Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities subject to regulation under the Public Utilities Act by the UARB. supervisory powers over NSPI’s operations and also subject to UARB approval. NSPI is not subject to participates in hearings held from time to time at NSPI’s NSPI is regulated under a cost-of-service model, with rates providing electricity service to customers and provide a regulated ROE range for 2024 and 2023 was 8.75 9.25 quarter average regulated common equity component 40 GRA: On February 2, 2023, the UARB approved the GRA settlement representatives and participating interest groups. This resulted 6.9 per cent effective on February 2, 2023, and further 6.5 with any under or over-recovery of fuel costs addressed through also established a storm rider and a demand-side management issued a final order approving the electricity rates effective Fuel Recovery: On April 17, 2024, the UARB approved the sale of $ 117 Nova Scotia, a provincial Crown corporation. On April 117 million was remitted to NSPI, which resulted in a corresponding NSPI is collecting the amortization and financing costs 117 behalf of Invest Nova Scotia over a 10 -year period, which began in Q2 2024, and is amounts to Invest Nova Scotia quarterly. Federal Loan Guarantee (“FLG”): On September 24, 2024, the Government of Canada finalized Province of Nova Scotia (the “Province”) on terms and 500 issued by NSPML to help Nova Scotia customers manage that was required during the several years of delay in the September 25, 2024, NSPI and NSPML filed applications November 29, 2024, the UARB approved NSPML’s NSPI as a refund of a portion of previous NSPML assessment assessment charge to NSPI to recover the refund and 28 -year period. On December 16, 2024, the net proceeds of the NSPML debt against the FAM regulatory to increase 2025 fuel rates to service the incremental Storm Rider: On December 2, 2024, the UARB approved the recovery 24 incremental financing costs deferred to NSPI’s storm 12 -month period beginning on January 1, 2025. Hurricane Fiona: On June 27, 2024, the UARB approved the deferred recognition 25 costs incurred during the Hurricane Fiona storm restoration approval, the $ 25 UARB also directed NSPI to reclassify $ 10 because of Hurricane Fiona to “Regulatory assets” from “PP&E” NSPI began amortizing both of these regulatory assets 10 -year period beginning July 1, 2024. Nova Scotia Cap-and-Trade On December 31, 2022, the FAM 166 purchase of emissions credits and $ 6 March 16, 2023, the Province provided NSPI with emissions for the 2019 through 2022 period. As such, compliance costs 166 2023. The credits NSPI purchased from provincial auctions 6 and no further costs were incurred to achieve compliance Extra Large Industrial Active Demand Tariff: On July 5, 2023, NSPI received approval from the UARB to recovery from an industrial customer is calculated. Due to significant 2022, the previous methodology did not result in a reasonable customer. The change in methodology, this industrial customer to the FAM. 51 increase to the FAM regulatory and other current assets. This adjustment had minimal NSPML Equity earnings from the Maritime Link are dependent performance of NSPML. NSPML’s 8.75 9.25 based on an actual five-quarter average regulated common 30 Newfoundland and Labrador Hydro’s (“NLH”) Nova commenced in 2021 and delivery will continue over the next 35 years On September 24, 2024, the Government of Canada finalized Province on terms and conditions for a FLG of $ 500 information, refer to the NSPI section above. On November 29, 2024, NSPML received approval from the 197 from NSPI; which includes $ 158 $ 39 Payments from NSPI are subject to a holdback of up to $ 4 no recorded for the year ended December 31, 2024. On December 21, 2023, NSPML received approval from the 164 from NSPI for the recovery of costs associated with the 4 per month. On October 4, 2023 and January 31, 2024, the UARB issued remaining aspects of the Maritime Link holdback mechanism future holdback amounts and requirements to end the holdback UARB agreed with the Company’s submission that 12 8 4 related to 2023) of the previously recorded holdback remain released to NSPML and recorded in Emera’s “Income confirmed that NSPML can apply for termination of the 90 Block deliveries being achieved for 12 consecutive months (subject or exceptional circumstances) and the net outstanding energy is less than 10 monthly holdback amount from $ 2 4 Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at total revenues or revenue requirements equal to their on invested capital. PGS’s approved ROE range for 2024 and 2023 9.15 11.15 10.15 midpoint, based on an allowed equity capital structure 54.7 Base Rates: On April 4, 2023, PGS filed a rate case with the FPSC September 2023. On November 9, 2023, the FPSC approved 118 revenues which includes $ 11 for a net incremental increase to base revenues of $ 107 10.15 midpoint ROE with an allowed equity capital structure of 54.7 December 27, 2023, with the new rates effective January Fuel Recovery: PGS recovers the costs it pays for gas supply and Purchased Gas Adjustment Clause (“PGAC”). This clause is designed PGS for purchased gas, gas storage services, interstate pipeline associated with the purchase, distribution, and sale of be adjusted monthly based on a cap approved annually Recovery of Energy Conservation and Pipeline Replacement The FPSC annually approves a conservation charge that incurred expenditures in developing and implementing are required by Florida law and approved and monitored Steel Pipe Replacement clause to recover the cost of accelerating steel distribution lines in the PGS system. In February 2017, Iron/Bare Steel clause to allow recovery of accelerated majority of cast iron and bare steel pipe has been removed plastic pipe continuing until 2028 under the rider. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC collect total revenues equal to its cost of providing service, NMGC’s approved ROE for 2024 and 2023 9.375 52 Base Rates: On September 14, 2023, NMGC filed a rate case with NMGC filed with the NMPRC a settlement with the support 30 million USD in annual base revenues and maintaining 9.375 the recovery of increased operating costs and capital investments infrastructure, as well as a new customer information and and to not reassert in a future rate case application, with its 2022 application for a certificate of public convenience storage facility in New Mexico. The NMPRC approved rates became effective October 1, 2024. Fuel Recovery: NMGC recovers gas supply costs through a PGAC. This gas storage services, interstate pipeline capacity, transmission, distribution, and sale of natural gas to its charges based on the next month’s expected cost recovery. The NMPRC recoveries. NMGC must file a PGAC Continuation Filing that the continued use of the PGAC is reasonable and Continuation in December 2024, for the four-year period Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Saint terminal near Saint John, New Brunswick to markets in into a 25 -year firm service agreement commencing in July agreement provides for a predetermined toll increase pipeline is considered a Group II pipeline regulated by Gas Transportation Tariff Act and sets forth the terms and conditions of the transportation Other Electric Utilities BLPC BLPC is regulated by the Fair Trading Rules 2003. BLPC is regulated under a cost-of-service model, costs of providing electricity service to customers plus approved regulated return on rate base was 10 Licenses: BLPC currently operates pursuant to a single integrated license electricity on the island of Barbados until 2028. In 2019, the Government requiring multiple licenses for the supply of electricity. the Government of Barbados for each of the license types, legislation. The timing of the final enactment is unknown at implementation of the licenses once enacted. Base Rates: In 2021, BLPC submitted a general rate review application granted BLPC interim rate relief, allowing an increase in base rates 1 month. On February 15, 2023, the FTC issued a decision significant items: an allowed regulatory ROE of 11.75 55 a directive to update the major components of rate base establish regulatory liabilities totalling approximately $ 71 Motion for Review and Variation subsequently granted. On November 20, 2023, the FTC Interim rates continue to be in effect through to On December 1, 2023, BLPC appealed certain aspects 2023, decisions to the Supreme Court of Barbados in the requested that they be stayed. On December 11, that the FTC made errors of law and jurisdiction in their is probable, and as a result, the adjustments to BLPC’s adjustments to regulatory assets and liabilities, have not been currently scheduled to be heard in 2025. Fuel Recovery: BLPC’s fuel costs flow through a fuel pass-through prudently incurred fuel costs from customers in a timely adjusted on a monthly basis and reported to the FTC for Clean Energy Transition On May 31, 2023, the FTC approved BLPC’s mechanism to recover prudently incurred costs associated mechanism is intended to facilitate the timely recovery between approved renewable energy assets. BLPC will be required recovery of costs of each asset through the cost recovery set out in the Decision. On October 5, 2023, BLPC applied storage system through the CETR. On May 6, 2024, the 15 storage system through the CETR. Barbados Domestic Tax On May 24, 2024, the Government of Barbados signed into law. The legislation, effective 9 cent, requiring BLPC to remeasure its deferred income the deferred recovery of the $ 5 over a period to be approved by the FTC during a future GBPC GBPC is regulated by the GBPA. franchise to produce, transmit and distribute electricity prudently incurred costs of providing electricity service base. GBPC’s approved regulated return on rate base 8.52 8.32 Electricity Act, 2024: On June 1, 2024, the Electricity Act, 2024 took effect. the GBPA over GBPC regulator, regulate GBPC. Base Rates: There is a fuel pass-through mechanism and tariff review years. On August 1, 2024, as required by the GBPA Agreement, GBPC filed a rate plan proposal and is awaiting Fuel Recovery: GBPC’s fuel costs flow through a fuel pass-through all prudently incurred fuel costs from customers in a timely through charge was adjusted monthly,

Investments Subject to Signific

Investments Subject to Significant Influence and Equity Income	12 Months Ended
	Dec. 31, 2024
Investments Subject to Significant Influence and Equity Income [Abstract]
Investments Subject to Significant Influence and Equity Income	8. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2024 2023 2024 2023 2024 NSPML $ 475 $ 489 $ 44 $ 46 100.0 M&NP 124 118 20 21 12.9 Lucelec (1) 55 48 4 4 19.5 LIL (2) - 747 29 63 - Bear Swamp - - 2 12 50.0 $ 654 $ 1,402 $ 99 $ 146 (1) Emera has significant influence over the operating and therefore, records its investment in these (2) On June 4, 2024, Emera completed the sale (3) The investment balance in Bear Swamp is 179 Bear Swamp's credit investment balance of $ 92 81 Consolidated Balance Sheets. Equity investments include a $ 9 investees' assets as at the date of acquisition. The excess Emera accounts for its variable interest investment in NSPML's consolidated summarized balance sheets are illustrated As at December 31 December 31 millions of dollars 2024 2023 Balance Sheets Current assets $ 37 $ 21 PP&E 1,425 1,473 Regulatory assets 778 272 Non-current assets 27 29 Total $ 2,267 $ 1,795 Current liabilities $ 55 $ 48 Long-term debt (2) 1,570 1,109 Non-current liabilities 167 149 Equity 475 489 Total $ 2,267 $ 1,795 (1) On November 29, 2024, the UARB approved 500 FLG. For further details, refer to note 7. (2) On December 16, 2024, NSPML issued a 500

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2024
Other Income, Net [Abstract]
Other Income, Net	9. OTHER INCOME, NET For the Year ended December 31 millions of dollars 2024 2023 Gain on sale of LIL, net of transaction costs $ 182 $ - AFUDC 53 38 Pension non-current service cost recovery 35 35 Interest income 23 43 Transaction costs related to the pending sale of NMGC (25) - Charges related to wind-down costs and certain asset impairments (2) (29) - FX (losses) gains (58) 20 Other 22 22 $ 203 $ 158 (1) For more information related to the gain pending sale of NMGC, refer to note 4. (2) Primarily related to the wind-down of Block

Interest Expense, Net

Interest Expense, Net	12 Months Ended
	Dec. 31, 2024
Interest Expense, Net [Abstract]
Interest Expense, Net	10. INTEREST EXPENSE, NET Interest expense, net consisted of the following: For the Year ended December 31 millions of dollars 2024 2023 Interest on debt $ 1,004 $ 954 Allowance for borrowed funds used during construction (23) (16) Other (8) (13) $ 973 $ 925

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
Income Taxes [Abstract]
Income Taxes	11. INCOME TAXES The income tax provision, for the years ended December enacted combined Canadian federal and provincial statutory millions of dollars 2024 2023 Income before provision for income taxes $ 409 $ 1,173 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 119 340 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (90) (72) Interest and financing expenses (58) - Valuation allowance (58) 3 Tax (57) (53) Goodwill impairment charge 49 - Amortization of deferred income tax regulatory liabilities (36) (33) Foreign tax rate variance (31) (36) Additional impact from the sale of LIL equity interest 22 - Tax (14) (15) Manufacturing allowance (9) (8) Other 4 2 Income tax (recovery) expense $ (159) $ 128 Effective income tax rate (39%) 11% Bahamian Domestic Minimum Top On November 28, 2024, the Domestic Top 2024.The Domestic Top Excessive Interest and Financing Expenses Limitation On June 20, 2024, Bill C-59, an Act to implement certain provisions in Parliament on November 21, 2023, and certain provisions 28, 2023, was enacted. applies to limit a company’s net interest and financing earnings before interest, income taxes, depreciation, and amortization interest and financing expenses under the EIFEL regime can During 2024, the Company incurred $ 185 specific financing structure. The interest and financing expenses as $ 88 regime. It was determined that the Company is more likely interest and financing expenses in future periods and therefore 79 has been recorded as at December 31, 2024. In Q4 2024, the 58 benefit related to the denied interest and financing expenses income tax liability in connection with the financing structure Canadian Global Minimum Tax On June 20, 2024, the GMTA have an impact on the Company. Barbados Domestic Tax On May 24, 2024, the Government of Barbados signed the into law. The legislation, effective 9 cent, requiring BLPC to remeasure its deferred income Barbados Corporation Top On May 24, 2024, the Top Tax . United States Inflation Reduction Act (“IRA”): On August 16, 2022, the IRA was signed into legislation. clean energy, such projects placed in service through 2024, and introduces credits beginning in 2025. As of December 31, 2024, the 82 31, 2023 – $ 30 obligation to pass the incremental tax benefits realized The following table reflects the composition of taxes on the Consolidated Statements of Income for the years ended millions of dollars 2024 2023 Current income taxes $ 29 $ 26 4 5 Deferred income taxes (200) 93 155 128 Adjustments to beginning of the year valuation allowance (61) - Investment tax credits (6) (29) Operating loss carryforwards (4) (93) (76) (2) Income tax (recovery) expense $ (159) $ 128 The following table reflects the composition of income Consolidated Statements of Income for the years ended millions of dollars 2024 2023 Canada $ 156 $ 171 United States 203 964 Other 50 38 Income before provision for income taxes $ 409 $ 1,173 The deferred income tax assets and liabilities presented in December 31 consisted of the following: millions of dollars 2024 2023 Deferred income tax assets: Tax $ 1,118 $ 1,195 Tax 534 454 Regulatory liabilities 225 175 Derivative instruments 144 205 Other 462 372 Total 2,483 2,401 Valuation allowance (322) (363) Total $ 2,161 $ 2,038 Deferred income tax liabilities: PP&E $ (3,421) $ (3,223) Regulatory assets (198) (196) Derivative instruments (105) (235) Investments subject to significant influence (46) (216) Other (330) (312) Total $ (4,100) $ (4,182) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 392 $ 208 Long-term deferred income tax liabilities (2,331) (2,352) Net deferred income tax liabilities $ (1,939) $ (2,144) Considering all evidence regarding the utilization of the Company’s been determined that Emera is more likely than not to realize except for certain loss carryforwards and unrealized capital valuation allowance of $ 322 363 related to the loss carryforwards, long-term debt and investments. a $ 58 a valuation allowance as at December 31, 2023. The Company intends to indefinitely reinvest earnings 4.7 billion as at December 31, 2024 (2023 – $ 4.7 deferred taxes might otherwise be required, have not amount of income and withholding tax that might be payable occurred. Emera’s NOL, capital loss and tax credit carryforwards 2024 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,420 $ (967) $ 1,453 2026 - 2044 55 (55) - Indefinite 2 (1) 1 2028 - 2042 United States $ 1,587 $ (1) $ 1,586 2036 - Indefinite 1,351 (1) 1,350 2026 - Indefinite 533 (3) 530 2025 - 2044 Other $ 91 $ (23) $ 68 2025 - 2031 The following table provides details of the change in unrecognized December 31 as follows: millions of dollars 2024 2023 Balance, January 1 $ 37 $ 33 Increases due to tax positions related to current year 6 5 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (3) (2) Balance, December 31 $ 42 $ 37 Unrecognized tax benefits relate to the timing of certain development tax credits primarily at TEC. The total amount 31, 2024 was $ 42 37 total amount of accrued interest with respect to unrecognized tax 10 9 million) with $ 1 2 million). No next 12 months as a result of resolving Canada Revenue audits. A reasonable estimate of any change cannot be made NSPI and the CRA are currently in a dispute with respect its 2006 through 2010 and 2013 through 2016 taxation deductions is not in dispute; rather, dispute to date is $ 126 126 55 (2023 – $ 55 On November 29, 2019, NSPI filed a Notice of Appeal dispute of the 2006 through 2010 taxation years. Should payments including applicable interest will be refunded. of its position, the resulting taxes and applicable interest with the difference, if any, available in subsequent years. Should NSPI be similarly reassessed by the CRA for years be required; however, the NSPI and its advisors believe that NSPI has reported assess its options to resolving the dispute; however, determinable at this time. Emera files a Canadian federal income tax return, which Emera’s subsidiaries file Canadian, US, Barbados, 2024, the Company’s tax years still open to examination subsequent years.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2024
Common Stock [Abstract]
Common Stock	12. COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2024 2023 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 284.12 $ 8,462 269.95 $ 7,762 Issuance of common stock under ATM program (1)(2) 5.12 261 8.29 397 Issued under the DRIP, 6.10 291 5.26 272 Senior management stock options exercised and Employee Share Purchase Plan 0.60 28 0.62 31 Balance, December 31 295.94 $ 9,042 284.12 $ 8,462 (1) For the year ended December 31, 2023, a 8,287,037 average price of $ 48.27 400 397 (2) For the year ended December 31, 2024, a 5,117,273 average price of $ 51.52 264 261 31, 2024, an aggregate gross sales limit of $ 336 As at December 31, 2024, the following common shares 6 6 million) under the senior management stock option plan, 2 2 common share purchase plan and 12 18 The issuance of common shares under the common share compensation the plans to exceed 10 Emera was in compliance with this requirement. ATM Equity Program On November 18, 2024, Emera increased the size of to $ 1 at the prevailing market price. The ATM 2024 to its prospectus supplement dated November 14, 2023 and 2024 to its short form base shelf prospectus dated October 3,

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
Earnings Per Share	13. EARNINGS PER SHARE Basic earnings per share is determined by dividing net income the weighted average number of common shares outstanding by dividing net income attributable to common shareholders shares outstanding during the period, adjusted for the exercise securities. Such dilutive items include Company contributions plan, convertible debentures and shares issued under the DRIP. The following table reconciles the computation of basic For the Year ended December 31 millions of dollars (except per share amounts) 2024 2023 Numerator Net income attributable to common shareholders $ 493.6 $ 977.7 Diluted numerator 493.6 977.7 Denominator Weighted average shares of common stock outstanding – basic 289.1 273.6 Stock-based compensation 0.1 0.2 Weighted average shares of common stock outstanding – diluted 289.2 273.8 Earnings per common share Basic $ 1.71 $ 3.57 Diluted $ 1.71 $ 3.57

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2024
Accumulated Other Comprehensive Income [Abstract]
Accumulated Other Comprehensive Income	14. ACCUMULATED OTHER 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 (losses) 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, 2024 Balance, January 1, 2024 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 OCI before reclassifications 1,027 (139) - 2 - 890 Amounts reclassified from AOCI - - (2) - 68 66 Net current period OCI 1,027 (139) (2) 2 68 956 Balance, December 31, 2024 $ 1,396 $ (163) $ 12 $ - $ 16 $ 1,261 For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 OCI before reclassifications (270) 38 - - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period OCI (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2024 2023 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 2 $ - Other income, net (2) 2 Pension and post-retirement benefits 68 (40) Total 68 (38) Income tax expense - (1) Total $ 68 $ (39) Total reclassifications out of AOCI, net of tax, for the period $ 66 $ (41)

Inventory

Inventory	12 Months Ended
	Dec. 31, 2024
Inventory [Abstract]
Inventory	15. INVENTORY As at December 31 December 31 millions of dollars 2024 2023 Materials $ 453 $ 408 Fuel 328 382 Total $ 781 $ 790

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2024
Derivative Instruments
Derivative Instruments	16. DERIVATIVE Derivative assets and liabilities relating to the foregoing categories Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2024 2023 2024 2023 Regulatory deferral: $ 25 $ 16 $ 44 $ 76 27 3 3 3 52 19 47 79 HFT derivatives: 34 29 30 36 236 319 660 531 270 348 690 567 Other derivatives: - 4 2 - - 18 34 7 - 22 36 7 Total 322 389 773 653 Impact of master netting agreements: (7) (3) (7) (3) (148) (146) (148) (146) Total (155) (149) (155) (149) Less: Derivatives classified as held for sale (1) (1) - (1) - Total derivatives $ 166 $ 240 $ 617 $ 504 Current (2) 115 174 526 386 Long-term (2) 51 66 91 118 Total derivatives $ 166 $ 240 $ 617 $ 504 (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details (2) Derivative assets and liabilities are classified Cash Flow Hedges On May 26, 2021, a treasury lock was settled for a 19 interest expense over 10 years unrealized gain in AOCI was $ 12 14 year ended December 31, 2024, unrealized gains of $ 2 2 from AOCI into interest expense, net. The Company expects 2 AOCI to be reclassified into net income within the next Regulatory Deferral The Company has recorded the following changes with deferral: Commodity Physical Commodity swaps and FX natural gas swaps and FX millions of dollars forwards forwards purchases forwards forwards For the year ended December 31 2024 2023 Unrealized gain (loss) in regulatory assets $ (27) $ 5 $ - $ (109) $ (3) Unrealized gain (loss) in regulatory liabilities 11 33 (3) (73) - Realized gain in regulatory assets (8) - - (5) - Realized loss in regulatory liabilities 4 - - 2 - Realized (gain) loss in inventory (1) 11 (8) - 4 (10) Realized (gain) loss in regulated fuel for generation and purchased power (2) 50 (6) (49) (9) (4) Other - - - (14) - Total $ 41 $ 24 $ (52) $ (204) $ (17) (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer As at December 31, 2024, the Company had the following deferral that are expected to settle as outlined below: millions 2025 2026-2027 Physical natural gas purchases: Natural gas (MMBtu) 6 - Commodity swaps and forwards purchases: Natural gas (MMBtu) 21 23 Power (MWh) 1 - Coal (metric tonnes) 1 - FX forwards: FX contracts (millions of USD) $ 208 $ 69 Weighted average rate 1.3361 1.3296 % of USD requirements 50% 17% HFT Derivatives The Company has recognized the following realized and derivatives: For the Year ended December 31 millions of dollars 2024 2023 Power swaps and physical contracts in non-regulated operating revenues $ 12 $ (6) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 195 1,043 Total $ 207 $ 1,037 As at December 31, 2024, the Company had the following derivatives that are expected to settle as outlined below: 2029 and millions 2025 2026 2027 2028 thereafter Natural gas purchases (Mmbtu) 262 111 43 30 73 Natural gas sales (Mmbtu) 299 69 16 8 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - Other Derivatives As at December 31, 2024, the Company had equity associated with forecasted future cash settlements of deferred in place to manage cash flow risk associated with forecasted The equity derivatives hedge the return on 2.9 combined notional amount of $ 520 For the Year ended December 31 millions of dollars 2024 2023 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ (2) $ - $ 4 Unrealized gain (loss) in other income, net (44) - 28 - Realized gain (loss) in OM&G - 16 - (13) Realized loss in other income, net (12) - (11) - Total $ (56) $ 14 $ 17 $ (9) Credit Risk The Company is exposed to credit risk with respect to marketing collateral deposits and derivative assets. Credit risk non-performance under an agreement. The Company manages for counterparty analysis, exposure measurement, and assessments are conducted on all new customers and requested on any high-risk accounts. The Company assesses the potential for credit losses maintains provisions. With respect to counterparties, the Company monitor the creditworthiness and credit exposure of counterparties valuing the counterparty positions. The Company monitors that are experiencing financial problems, have significant swings rating changes by external rating agencies, or have changes adjusted based on the Company’s current default probability. the counterparty’s current default probability. counterparties that are not rated. As at December 31, 2024, the maximum exposure the 1.3 – $ 1.2 derivatives. It is possible that volatility in commodity prices could cause exposures with one or more counterparties. If such counterparties one or more agreements, the Company could suffer counterparties as part of its risk management strategy for managing rate risk. Counterparties that exceed established credit to the Company for the value in excess of the credit limit where deposits/collateral on hand as at December 31, 2024 was 303 310 mitigated the Company’s maximum credit risk amount receivable or returns the deposit/collateral to the required by the Company. The Company enters into commodity master arrangements risks, including credit risk to these counterparties. The and Derivatives Association agreements, North American Energy Edison Electric Institute agreements. The Company believes protection by creating contractual rights relating to creditworthiness, default. As at December 31, 2024, the Company had $ 140 142 considered to be past due, which have been outstanding for 61 financial assets was $ 128 127 allowance for credit losses. These assets primarily relate revenue. Concentration Risk The Company's concentrations of risk consisted of the As at December 31, 2024 December 31, 2023 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 376 22% $ 476 31% Commercial 184 11% 194 13% Industrial 73 4% 84 5% Other 105 6% 103 7% Cash collateral 46 3% 94 6% 784 46% 951 62% Trading group: Credit rating of A- or above 88 5% 47 3% Credit rating of BBB- to BBB+ 42 2% 33 2% Not rated 165 10% 108 7% 295 17% 188 12% Other accounts receivable 331 20% 151 10% Classification as assets held for sale 118 7% - 0% 1,528 90% 1,290 84% Derivative Instruments (current and long-term) Credit rating of A- or above 91 5% 138 9% Credit rating of BBB- to BBB+ 1 0% 7 1% Not rated 74 5% 95 6% 166 10% 240 16% $ 1,694 100% $ 1,530 100% (1) On August 5, 2024, Emera announced the classified as held for sale. For further details, refer Cash Collateral The Company’s cash collateral positions consisted As at December 31 December 31 millions of dollars 2024 2023 Cash collateral provided to others $ 198 $ 101 Cash collateral received from others $ 5 $ 22 Collateral is posted in the normal course of business based its senior unsecured credit rating as determined by certain derivatives contain financial assurance provisions that require credit-related event occurs. If a material adverse event resulted investment grade, the counterparties to such derivatives As at December 31, 2024, the total FV of derivatives 617 2023 – 504 value of the net liability position could be required to be

FV Measurements

FV Measurements	12 Months Ended
	Dec. 31, 2024
FV Measurements [Abstract]
Fair Value Measurements	17. FV MEASUREMENTS The Company is required to determine the FV of all derivatives exemption (see note 1) and uses a market approach defined as follows: Level 1 – Where possible, the Company bases the fair valuation quoted prices in active markets (“quoted prices”) for identical Level 2 – Where quoted prices for identical assets and contracts must be based on quoted prices for similar assets location differences. Also, certain derivatives are valued houses. Level 3 – Where the information required for a Level 1 must be valued using unobservable or internally developed inputs. classification are as follows: ● seasonal or monthly shaping and locational basis differentials. ● accordingly, assumptions end of the transaction term. ● utilized in the valuations. Derivative assets and liabilities are classified in their entirety, significant to the FV measurement. The following tables set out the classification of the methodology derivatives: As at December 31, 2024 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 15 $ 3 $ - $ 18 - 27 - 27 15 30 - 45 HFT derivatives: 2 23 5 30 13 52 27 92 15 75 32 122 Less: Derivatives classified as held for sale (1) - (1) - (1) Total assets 30 104 32 166 Liabilities Regulatory deferral: $ 18 $ 19 $ - $ 37 - 3 - 3 18 22 - 40 HFT derivatives: 2 21 4 27 (11) 89 437 515 (9) 110 441 542 Other derivatives: - 34 - 34 2 - - 2 2 34 - 36 Less: Derivatives classified as held for sale (1) - (1) - (1) Total liabilities 11 165 441 617 Net assets (liabilities) $ 19 $ (61) $ (409) $ (451) (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264) The change in the FV of the Level 3 financial assets and liabilities was as follows: HFT Derivatives millions of dollars Power Natural gas Total Assets Balance, beginning of period $ - $ 34 $ 34 Total revenues 5 (7) (2) Balance, December 31, 2024 $ 5 $ 27 $ 32 Liabilities Balance, beginning of period $ - $ 365 $ 365 Total revenues 4 72 76 Balance, December 31, 2024 $ 4 $ 437 $ 441 Significant unobservable inputs used in the FV measurement derivatives include third-party sourced pricing for instruments based increases (decreases) in any of these inputs in isolation would result measurement. Other unobservable inputs used include internally differentials; own credit risk; and discount rates. are reviewed on a quarterly basis based on statistical analysis term markets. illiquid future price points to incorporate the inherent uncertainty long-term contracts are evaluated by observing similar peers. The Company uses a modelled pricing valuation technique for instruments. The following table outlines quantitative information inputs used in the FV measurements categorized within Level Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2024 HFT derivatives – Power 5 4 Third-party pricing $25.60 $139.65 $82.63 swaps and physical contracts HFT derivatives – Natural 27 437 Third-party pricing $2.20 $17.54 $8.57 gas swaps, futures, forwards and physical contracts Total $ 32 $ 441 Net liability $ 409 As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 (1) Unobservable inputs were weighted by the Long-term debt is a financial liability not measured at balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2024 $ 18,407 $ 17,941 $ - $ 17,688 $ 253 $ 17,941 December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621 The Company has designated $ 1.2 currency exposure of its ne t investment are contingently convertible into preferred shares in the redemption option on or after June 15, 2026 is available Notes are classified as Level 2 financial assets. As at was $ 1.2 1.2 139 AOCI for the year ended December 31, 2024 (2023 38

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
Related Party Transactions	18. RELATED PARTY In the ordinary course of business, Emera provides energy transactions with its subsidiaries, associates and other offered to non-related parties. Intercompany balances eliminated on consolidation, except for the net profit on regulated entities in accordance with accounting standards amounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies ● Consolidated Statements of Income. NSPI’s expense purchased power, totalling 324 $ 163 earnings related to this revenue are reflected in Income Natural gas transportation capacity purchases from M&NP Statements of Income. Purchases from M&NP reported totalled $ 11 – $ 14 There were no significant receivables or payables between on Emera’s Consolidated Balance Sheets as at December

Receivables and Other Current A

Receivables and Other Current Assets	12 Months Ended
	Dec. 31, 2024
Receivables and Other Current Assets [Abstract]
Receivables and Other Current Assets	19. RECEIVABLES AND OTHER CURRENT ASSETS As at December 31 December 31 millions of dollars 2024 2023 Customer accounts receivable – billed $ 834 $ 805 Customer accounts receivable – unbilled 342 363 Capitalized transportation capacity (1) 216 358 Cash collateral provided to others 198 101 Prepaid expenses 105 105 Income tax receivable 22 10 Allowance for credit losses (12) (15) Other 106 90 Total $ 1,811 $ 1,817 (1) Capitalized transportation capacity represents the agreements at the inception of the contracts. The

Leases

Leases	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Leases	20. LEASES Lessee The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 61 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 they will be exercised. As at December 31 December 31 millions of dollars Classification 2024 2023 Right-of-use asset Other long-term assets $ 52 $ 54 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 54 55 Total $ 57 $ 58 The Company recorded lease expense of $ 123 $ 127 112 119 facility finance leases, recorded in “Regulated fuel for Consolidated Statements of Income. Future minimum lease payments under non-cancellable operating and in aggregate thereafter are as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments $ 5 $ 3 $ 3 $ 3 $ 3 $ 115 $ 132 Less imputed interest (75) Total $ 57 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: $ 10 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ - $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- 3.96% 3.93% Lessor The Company’s net investment in direct finance Pipeline, Seacoast, compressed natural gas (“CNG”) and heat pumps. The Company manages its risk associated with the residual through proper routine maintenance of the asset. Customers have the option to purchase CNG station assets of the purchase based on a targeted internal rate of return asset at the end of the lease term for no cost. Customers end of the lease term for a nominal fee. Commencing in October 2023, the Company leased a RNG as a sales-type lease. The term of the facility lease is 15 years , with a nominal value purchase at the end of the term and a net investment of approximately $ 35 Direct finance and sales-type lease unearned income is recognized using a constant rate of interest equal to the internal “Operating revenues – regulated gas” and “Other income, Income. The total net investment in direct finance and sales-type As at December 31 December 31 millions of dollars 2024 2023 Total $ 1,310 $ 1,360 Less: amounts representing estimated executory costs (182) (190) Minimum lease payments receivable $ 1,128 $ 1,170 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) (2) Less: unearned finance lease income (655) (693) Net investment in direct finance and sales-type leases $ 654 $ 658 Principal due within one year (included in "Receivables and other current assets") 44 37 Net Investment in direct finance and sales type leases – long-term $ 610 $ 621 As at December 31, 2024, future minimum lease payments and in aggregate thereafter were as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments to be received $ 99 $ 100 $ 99 $ 97 $ 96 $ 819 $ 1,310 Less: executory costs (182) Total $ 1,128

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	21. PROPERTY, PP&E consisted of the following regulated and non-regulated As at December 31 December 31 millions of dollars Estimated useful life 2024 (1) 2023 Generation 5 131 $ 14,297 $ 13,500 Transmission 10 80 3,106 2,835 Distribution 10 65 8,512 7,417 Gas transmission and distribution 15 75 4,658 5,536 General plant and other 2 60 3,078 2,985 Total 33,651 32,273 Less: Accumulated depreciation (2) (10,442) (9,994) 23,209 22,279 Construction work in progress (2) 2,959 2,097 Net book value $ 26,168 $ 24,376 (1) On August 5, 2024, Emera announced an were classified as held for sale and excluded from (2) SeaCoast owns a 50 % undivided ownership interest in a jointly 26 -mile pipeline lateral located in Florida, which went service in 2020. At December 31, 2024, SeaCoast’s 27 27 accumulated depreciation of $ 3 2 funds and all operations are accounted for as expenses of the jointly owned pipeline is included

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2024
Employee Benefit Plans [Abstract]
Employee Benefit Plans	22. EMPLOYEE BENEFIT PLANS Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. The Company also provides non-pension benefits for its retirees. Emera’s net periodic benefit cost included the following: Benefit Obligation and Plan Assets: Changes in the benefit obligation and plan assets, and For the Year ended December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO"): Balance, January 1 $ 2,273 $ 227 $ 2,158 $ 243 Service cost 35 3 30 3 Plan participant contributions 6 5 6 6 Interest cost 110 12 111 13 Plan amendments - - - (14) Benefits paid (153) (21) (147) (29) Actuarial losses (gains) (1) 13 (3) 146 10 Settlements and curtailments - - (8) - FX translation adjustment 83 18 (23) (5) Balance, December 31 $ 2,367 $ 241 $ 2,273 $ 227 Change in plan assets: Balance, January 1 $ 2,298 $ 48 $ 2,163 $ 46 Employer contributions 36 13 42 23 Plan participant contributions 6 5 6 6 Benefits paid (153) (21) (147) (29) Actual return on assets, net of expenses 226 4 262 3 Settlements and curtailments - - (8) - FX translation adjustment 80 5 (20) (1) Balance, December 31 $ 2,493 $ 54 $ 2,298 $ 48 Funded status, end of year $ 126 $ (187) $ 25 $ (179) (1) The actuarial losses recognized in the period and compensation-related assumption changes. Plans with PBO/APBO in Excess of Plan Assets: The aggregate financial position for pension plans where plans) exceeded the plan assets for the years ended December millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans PBO/APBO $ 95 $ 219 $ 120 $ 205 FV of plan assets 11 - 37 - Funded status $ (84) $ (219) $ (83) $ (205) Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets: The ABO for the DB pension plans was $ 2,255 2,172 The aggregate financial position for those plans with an ABO ended December 31 were as follows: millions of dollars 2024 2023 DB pension plans DB pension plans ABO $ 90 $ 114 FV of plan assets 11 37 Funded status $ (79) $ (77) Balance Sheet: The amounts recognized in the Consolidated Balance Sheets As at December 31 December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Other current liabilities $ (5) $ (21) $ (5) $ (18) Liabilities associated with assets held for sale - (1) - - Long-term liabilities (78) (196) (78) (187) Other long-term assets 208 - 108 26 Assets held for sale (1) 1 31 - - AOCI, net of tax and regulatory assets 354 22 385 20 Deferred income tax expense in AOCI (8) (1) (8) (1) Net amount recognized $ 472 $ (166) $ 402 $ (160) (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details Amounts Recognized in AOCI and Regulatory Assets: Unamortized gains and losses and past service costs AOCI or regulatory assets. The following table summarizes Regulatory assets Actuarial (gains) losses Past service gains millions of dollars DB Pension Plans: Balance, January 1, 2024 $ 324 $ 53 $ - Amortized in current period (9) (3) - Current year additions 19 (67) - Change in FX rate 29 - - Balance, December 31, 2024 $ 363 $ (17) $ - Non-pension benefits plans: Balance, January 1, 2024 $ 29 $ (8) $ (2) Amortized in current period 2 1 2 Current year reductions (5) (1) - Change in FX rate 3 - - Balance, December 31, 2024 $ 29 $ (8) $ - As at December 31 December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Actuarial (gains) losses $ (17) (8) $ 53 (8) Past service gains - - - (2) Deferred income tax expense 8 1 8 1 AOCI, net of tax (9) (7) 61 (9) Regulatory assets 363 29 324 29 AOCI, net of tax and regulatory assets $ 354 $ 22 $ 385 $ 20 Benefit Cost Components: Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Service cost $ 35 $ 3 $ 30 $ 3 Interest cost 110 12 111 13 Expected return on plan assets (160) (2) (161) (2) Current year amortization of: 3 (2) 1 (3) - (2) - - 9 (2) 6 (2) Settlement, curtailments - 1 2 - Total $ (3) $ 8 $ (11) $ 9 The expected return on plan assets is determined based on $ 2,571 2,577 during the year. The market-related value of assets is based on a 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 multi-year period. Pension Plan Asset Allocations: Emera’s investment policy includes discussion which the Company is prepared to accept with respect basis for measuring the performance of the assets. Central to major asset categories. The objective of the target asset allocation returns that meet or exceed the plan’s actuarial inherent risk in financial markets by requiring that assets Further, within each asset class, of investment and non-investment grade securities. Emera’s Asset Class Target Canadian Pension Plans: Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 5% to 15% 37% to 61% Non-Canadian Pension Plans: Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68% Pension plan assets are overseen by the respective companies. All pension investments are in accordance with policies Directors of each sponsoring company. The following tables set out the classification of the methodology investments (for more information on the FV hierarchy millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2024 Cash and cash equivalents $ - $ 39 $ - $ 39 2 % Net in-transits - (27) - (27) (1) % Equity securities: - 109 - 109 4 % - 312 - 312 12 % - 140 - 140 5 % Fixed income securities: - - 132 132 5 % - - 92 92 4 % - - 22 22 1 % Mutual funds - 13 - 13 1 % Open-ended investments measured at NAV 1,142 - - 1,142 46 % Common collective trusts measured at NAV (2) 519 - - 519 21 % Total $ 1,661 $ 586 $ 246 $ 2,493 100 % As at December 31, 2023 Cash and cash equivalents $ - 40 - 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % (1) Net asset value ("NAV") investments are open-ended registered and non-registered or pooled funds. NAV’s are calculated at least monthly and the funds honour (2) The common collective trusts are private funds securities. Since the prices are not published to external primarily in equity securities of domestic and income assets and seeks to increase return through subscription and redemption activity regularly. Non-Pension Benefit Plans: There are no assets set aside to pay for most of the Company’s practice, post-retirement health benefits are paid from is the NMGC Retiree Medical Plan, which is fully funded. Investments in Emera: As at December 31, 2024 and 2023, assets related to the did not hold any material investments in Emera or its subsidiaries portion of assets for the benefit plan are held in pooled securities. Cash Flows: The following table shows expected cash flows for DB pension millions of dollars DB pension plans Non-pension benefit plans Expected employer contributions 2025 $ 41 $ 21 Expected benefit payments 2025 175 23 2026 179 23 2027 182 23 2028 184 23 2029 186 22 2030 – 2034 950 103 Assumptions: The following table shows the assumptions that have been post-retirement benefit plans: 2024 2023 (weighted average assumptions) DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 5.07 % 4.91 % 4.89 % 4.89 % Discount rate - future service 5.12 % 5.00 % 4.88 % 4.89 % Rate of compensation increase 3.73 % 3.72 % 3.87 % 3.85 % Health care trend - 6.53 % - 6.04 % - 3.77 % - 3.76 % 2044 2043 Benefit cost for year ended December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Expected long-term return on plan assets 6.43 % 3.69 % 6.56 % 2.16 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Actual assumptions used differ by plan. The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate estimated cash flows from the pension plan. DC Pension Plan: Emera also provides a DC pension plan for certain employees. ended December 31, 2024 was $ 51 45

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2024
Goodwill [Abstract]
Goodwill	23. GOODWILL The change in goodwill for the year ended December 31 millions of dollars 2024 2023 Balance, January 1 $ 5,871 $ 6,012 Change in FX rate 504 (141) Impairment charges (214) - Classified as assets held for sale (1) (303) - Balance, December 31 $ 5,858 $ 5,871 (1) As at December 31, 2024, NMGC's assets transaction, refer to note 4. Goodwill is subject to an annual assessment for impairment Emera’s Consolidated Balance Sheets at December units with goodwill are TEC, PGS, and NMGC). On August 5, 2024, Emera announced an agreement to sell proceeds on the pending sale will be less than the NMGC carrying quantitative goodwill impairment assessment for the NMGC NMGC carrying amount exceeded the FV of the expected transaction cash goodwill impairment charge of $ 210 reporting unit goodwill balance to $ 303 included in “Impairment charges” on the Consolidated In 2024, a qualitative assessment was performed for TEC amounts calculated during the last quantitative test in than not that the FV of this reporting unit exceeded quantitative testing was required. Given the length of time test for the PGS reporting unit, Emera elected to bypass quantitative impairment assessment in Q4 2024 using a combination This assessment estimated that the FV of the PGS reporting goodwill, and as a result, no impairment charges were

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2024
Short-Term Debt [Abstract]
Short-Term Debt	24. SHORT-TERM DEBT Emera’s short-term borrowings consist of commercial revolving credit facilities and short-term notes. Short-term rates as at December 31 consisted of the following: millions of dollars 2024 Weighted average interest rate 2023 Weighted average interest rate Florida Electric Utility Advances on revolving credit facilities $ 915 4.77 % $ 277 5.68 % Gas Utilities and Infrastructure PGS – Advances on revolving credit facilities 199 5.36 % 73 6.36 % NMGC – Advances on revolving credit facilities 46 5.52 % 25 6.46 % Other Electric Utilities GBPC – Advances on revolving credit facilities 19 7.20 % 8 5.54 % Other TECO Finance – Advances on revolving credit and term facilities 265 5.53 % 245 6.54 % Emera – Bank indebtedness 2 - % 9 - % Emera – Non-revolving term facilities - - % 796 6.07 % $ 1,446 $ 1,433 Adjustment Classification as liabilities held for sale (1) (46) - Short-term debt $ 1,400 $ 1,433 (1) On August 5, 2024, Emera announced an agreement as held for sale. For further details on the pending The Company’s total short-term unsecured revolving borrowings and available capacity as at December 31 were millions of dollars Maturity 2024 2023 TEC – committed revolving credit facility 2028 $ 1,151 $ 401 TECO Finance – committed revolving credit facility 2028 576 529 PGS – revolving credit facility 2028 360 331 NMGC – revolving credit facility 2026 180 165 Emera – non-revolving term facility 2024 - 400 Emera – non-revolving term facility 2024 - 400 TEC – revolving facility 2024 - 265 TEC – revolving facility 2024 - 265 Other – committed revolving credit facilities Various 35 17 Total $ 2,302 $ 2,773 Less: Advances under revolving credit and term facilities 1,400 1,433 Letters of credit issued within the credit facilities 4 3 Total 1,404 1,436 Available capacity under existing agreements $ 898 $ 1,337 The weighted average interest rate on outstanding short-term 5.05 cent (2023 – 5.95 Recent Significant Financing Activity by Segment Florida Electric Utilities On April 1, 2024, TEC amended its $ 800 extend the maturity date from December 17, 2026 December 1, 2028 . There were no other changes in commercial terms from the prior agreement. Other On June 24, 2024, Emera repaid its $ 400 August 2024. On June 17, 2024, Emera repaid $ 200 facility, decreasing 400 200 $ 200 On April 1, 2024, TECO Finance amended its $ 400 facility to extend the maturity date from December 17, 2026 December 1, 2028 . There were no other changes in commercial terms from the prior agreement.

Other Current Liabilities

Other Current Liabilities	12 Months Ended
	Dec. 31, 2024
Other Current Liabilities
Other Current Liabilities	25. OTHER CURRENT LIABILITIES As at December 31 December 31 millions of dollars 2024 2023 Accrued charges $ 189 $ 172 Accrued interest on long-term debt 106 107 Pension and post-retirement liabilities (note 22) 26 23 Sales and other taxes payable 11 11 Income tax payable 4 2 Other 153 112 $ 489 $ 427

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2024
Long-term Debt [Abstract]
Long-term Debt	26. LONG-TERM DEBT Bonds, notes and debentures are at fixed interest rates are certain bankers’ acceptances and commercial paper unencumbered ability to refinance the obligations for a period Long-term debt as at December 31 consisted of the following: Weighted average interest rate (1) millions of dollars 2024 2023 Maturity 2024 2023 Florida Electric Utility Senior unsecured notes 4.36% 4.61% 2029 - 2051 $ 5,720 $ 5,654 Canadian Electric Utilities NSPI – Commercial paper (2) Variable Variable 2029 $ 177 $ 721 NSPI – Senior unsecured notes 5.12% 5.13% 2025 - 2097 3,184 3,165 $ 3,361 $ 3,886 Gas Utilities and Infrastructure PGS – Senior unsecured notes 5.63% 5.63% 2028 - 2053 $ 1,331 $ 1,223 NMGC – Senior unsecured notes 3.78% 3.78% 2026 - 2051 698 642 NMGC – Unsecured loan notes N/A Variable 2024 - 30 NMGI – Senior unsecured notes N/A 3.64% 2024 - 198 EBP – Secured loan notes Variable Variable 2028 250 246 $ 2,279 $ 2,339 Other Electric Utilities Unsecured loan notes 4.06% 4.78% 2025 - 2028 $ 143 $ 121 Unsecured loan notes Variable Variable 2025 - 2027 104 104 Secured senior notes and debentures 2.38% 3.06% 2026 - 2040 169 197 $ 416 $ 422 Other Unsecured loan notes Variable Variable 2026 - 2029 $ 992 $ 465 Senior unsecured notes 3.99% 3.65% 2026 - 2046 3,525 3,637 Senior unsecured notes 4.84% 4.84% 2030 500 500 Fixed to floating subordinated notes 6.75% 6.75% 2076 1,727 1,587 Junior subordinated notes 7.63% 0.00% 2054 720 - $ 7,464 $ 6,189 Adjustments Debt issuance costs (137) (125) Classification as liabilities held for sale (5) (696) - Amount due within one year (234) (676) $ (1,067) $ (801) Long-Term Debt $ 18,173 $ 17,689 (1) Weighted average interest rate of fixed rate long-term debt. (2) Discount notes are backed by a revolving (3) Notes are issued and payable in either USD (4) In 2024, the Company recognized $ 110 109 subordinated notes. (5) On August 5, 2024, Emera announced an classified as held for sale. (6) Excludes NMGC amounts which are classified The Company’s total long-term revolving credit facilities, at December 31 were as follows: millions of dollars Maturity 2024 2023 Emera – committed revolving credit facility (1) June 2029 $ 1,300 $ 900 NSPI – revolving credit facility (1) June 2029 800 800 Emera – Unsecured non-revolving credit facility February 2026 200 400 TEC – Unsecured committed revolving credit facility December 2026 - 657 NSPI – non-revolving credit facility July 2024 - 400 NMGC – Unsecured non-revolving credit facility March 2024 - 30 ECI – revolving credit facilities October 2024 - 10 Total $ 2,300 $ 3,197 Less: Borrowings under credit facilities 1,169 1,884 Letters of credit issued inside credit facilities 12 6 Use of available facilities $ 1,181 $ 1,890 Available capacity under existing agreements $ 1,119 $ 1,307 (1) Advances on the revolving credit facility can be 50 Debt Covenants Emera and its subsidiaries have debt covenants associated tested regularly and the Company is in compliance with covenants are listed below: As at Financial Covenant Requirement December 31, 2024 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.55 Recent Significant Financing Activity by Segment Florida Electric Utility On July 12, 2024, TEC repaid a $ 300 proceeds from commercial paper. On January 30, 2024, TEC issued $ 500 4.90 per cent with a maturity date of March 1, 2029 . Proceeds from the issuance were primarily used for the repayment of short-term borrowings outstanding under the 5 -year credit facility. Canadian Electric Utilities On June 24, 2024, NSPI amended its unsecured non-revolving from July 15, 2024 June 24, 2025 400 300 December 16, 2024, NSPI repaid the $ 300 On June 24, 2024, NSPI amended its unsecured committed date from December 16, 2027 June 24, 2029 . There were no other material changes in commercial terms from the prior agreement. On June 13, 2024, NSPI entered a non-revolving credit Project. NSPI can request funds under the facility quarterly up to the total commitment of the lessor of $ 120 45.06 costs over the term of the agreement. The facility will be 6 project, not to exceed May 21, 2027 , and matures 20 December 31, 2024, NSPI had utilized $ 19 2.51 Gas Utilities and Infrastructure On December 10, 2024, Brunswick Pipeline amended date was extended to December 2028 and now includes On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid 150 maturity. Other Electric Utilities On May 2, 2024, BLPC amended its $ 92 46 the maturity date from February 19, 2025 July 19, 2028 . There were no other material changes in commercial terms from the prior agreement. Other On June 24, 2024, Emera amended its unsecured committed from $ 900 1,300 June 24, 2027 June 24, 2029 . There were no other material changes in commercial terms On June 15, 2024, Emera Finance repaid its $ 300 On June 18, 2024, EUSHI Finance, Inc., completed an issuance 500 rate junior subordinated notes. The notes initially bear 7.625 on December 15, 2029, and every five years treasury rate plus 3.136 December 15, 2054 . EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days semi-annual interest payment date thereafter, On February 16, 2024, Emera amended its $ 400 maturity date from February 19, 2024 February 19, 2025 . There were no other changes in commercial terms from the prior agreement. On July 19, 2024, Emera reduced 400 million to $ 200 February 2026 with no other changes in terms. This facility 31, 2024. Long-Term Debt Maturities As at December 31, 2024, long-term debt maturities, including next five years and in aggregate thereafter are as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Florida Electric Utility $ - $ - $ - $ - $ 720 $ 5,000 $ 5,720 Canadian Electric Utilities 125 40 - - 217 2,979 3,361 Gas Utilities and Infrastructure 31 132 31 535 31 1,519 2,279 Other Electric Utilities 78 101 89 116 4 28 416 Other - 3,006 - - 792 3,666 7,464 Total $ 234 $ 3,279 $ 120 $ 651 $ 1,764 $ 13,192 $ 19,240

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	27. ASSET RETIREMENT OBLIGATIONS AROs mostly relate to reclamation of land at the thermal, hydro disposal of polychlorinated biphenyls in transmission and distribution Certain hydro, transmission and distribution assets may have additional as these assets are expected to be used for an indefinite the FV of any related ARO cannot be made. The change in ARO for the years ended December 31 millions of dollars 2024 2023 Balance, January 1 $ 192 $ 174 Additions 11 - Accretion included in depreciation expense 10 9 Change in FX rate 5 (1) Revisions in estimated cash flows 2 - Accretion deferred to regulatory asset (included in PP&E) - 18 Classified as assets held for sale (1) - Liabilities settled (2) (8) Balance, December 31 $ 217 $ 192 (1) As at December 31, 2024, NMGC's assets transaction, refer to note 4.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	28. COMMITMENTS AND CONTINGENCIES Commitments As at December 31, 2024, contractual commitments (excluding obligations, long-term debt and asset retirement obligations) for aggregate thereafter consisted of the following: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Purchased power (1) $ 307 $ 277 $ 368 $ 368 $ 369 $ 4,487 $ 6,176 Transportation (2)(3) 742 545 544 454 412 3,228 5,925 Capital projects 604 287 24 - - - 915 Fuel, gas supply and storage (4) 591 94 21 5 - - 711 Other 160 95 80 59 59 264 717 $ 2,404 $ 1,298 $ 1,037 $ 886 $ 840 $ 7,979 $ 14,444 As detailed below, contractual obligations at December 31, 2024 includes NMGC, all remaining future contractual obligations will to note 4. (1) Annual requirement to purchase electricity production (2) Includes $ 86 30 24 16 12 4 (3) Purchasing commitments for transportation of $ 135 (4) Includes $ 177 109 52 13 3 NSPI has a contractual obligation to pay NSPML for use of the 38 years from its January 15, 2018 in-service date. In November $ 197 to NSPML for the remainder of the 38 -year commitment period are subject to UARB Emera has committed to obtain certain transmission rights (April through October, inclusive) 50 table. Legal Proceedings Superfund and Former Manufactured Gas Plant Sites Previously, TEC had Tampa through its PGS division. As a result of the separation of the PGS Peoples Gas System, Inc. is also now a PRP for those sites (in sites). result of the PGS legal separation, the sites continue to present costs. As at December 31, 2024, the aggregate financial $ 17 12 credit-worthy entities. This amount has been accrued and section under “Other long-term liabilities” on the Consolidated remediation costs associated with these sites are expected The estimated amounts represent only the portion of the cleanup The estimates to perform the work are based on the Florida adjusted for site-specific conditions and agreements with estimates are made in current dollars, are not discounted In instances where other PRPs are involved, most of those worthy and are likely to continue to be credit-worthy for those instances that they are not, the Florida utilities could be of the remediation costs. Other factors that could impact investigation which could expand the scope of the cleanup activities, from the cleanup activities themselves or changes in remediation. Under current regulations, these costs are recoverable in base rate proceedings. Other Legal Proceedings Emera and its subsidiaries may, litigation that arise in the ordinary course of business be expected to have a material adverse effect on the Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could have subsidiaries, or their business operations, liquidity or access prospects, and/or results of operations (herein considered a “Material with derivative instruments and FV measurements are Sound risk management is an essential discipline for running Company’s strategy successfully. its Enterprise Risk Management Committee (“ERMC”) risks are appropriately identified, assessed, monitored Directors has a Risk and Sustainability Committee (‘RSC”) sustainability oversight responsibilities. The RSC’s Enterprise Risk Management framework, including the management of enterprise risks. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain and regulatory frameworks that cover material aspects key factors such as rates and cost structures, revenue requirements, rate base and capital investments, and the recovery costs. Regulators also review the prudency of costs and make rates and the reliability of service. Emera’s cost material aspects of their businesses, including changing often require public hearing proceedings involving numerous the outcomes or impact of any regulatory process or decision. If Emera is unable to recover in a timely manner a material through regulatory mechanisms or otherwise, is disallowed regulatory penalties, is not permitted to make certain capital divest certain utility assets, it could result in a Material Adverse Regulatory lag, the time between the incurrence of costs costs by regulators, may also result in a Material Adverse Aspects of the acquisition, ownership, operations, siting, planning, electric generation, storage, transmission and distribution facilities distribution systems are also subject to regulatory processes departments and agencies, and other third parties. The failure approvals or significant changes in the terms and conditions The regulatory framework, process and regulatory decisions in government, shifts in government or public policy, changes, changes in the economic environment, or other regulatory process or regulatory decisions can undermine regulatory independence. Any such changes could have a Material Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. with a significant amount of the Company’s net exposed to movements in exchange rates between the positively or adversely affect results. Emera manages currency risks through matching US denominated may use foreign currency derivative instruments to hedge specific The Company may enter FX forward and swap contracts transactions such as fuel purchases, revenue streams earned outside of Canada. The regulatory framework for permits the recovery of prudently incurred costs, including The Company does not utilize derivative financial instruments purposes or to hedge the value of its investments in foreign subsidiaries. net investments in foreign subsidiaries do not impact net income Liquidity and Capital Markets Liquidity risk relates to Emera’s ability to ensure sufficient obligations. Emera’s access to capital and cost of financial market conditions, market disruptions and ratings assigned credit rating agencies. Disruptions in capital markets could cause the Company to issue securities with less than preferred plan requires significant capital investments in PP&E and the rates could have an adverse effect on the cost cost of borrowing may be impacted by various market disruptions capital could have a material impact on Emera’s Emera is subject to financial risk associated with changes factors that rating agencies evaluate to determine credit regulatory framework and legislative environment, political ability to recover costs and earn returns, diversification, climate change-related impacts, including increased frequency severe weather events. A decrease in a credit rating could financings, increased borrowing costs under certain existing commercial paper market, or limit the availability of adequate certain derivative instruments, if the credit ratings of the Company the full value of the net liability of these positions could The Company has exposure to its own common share stock-based compensation, which affect earnings period. The Company uses equity derivatives to reduce compensation. General Economic Risk The Company has exposure to the macro-economic conditions regions in which Emera operates. Like most utilities, economic employment and housing affect demand for electricity financial results. Adverse changes in general economic customers to afford rate increases arising from compliance, and other costs, and therefore could have higher credit and counterparty risk, adverse shifts in government risk to full and timely recovery of costs and regulatory Interest Rate Risk: Emera utilizes a combination of fixed and floating rate expenditures, resulting in an exposure to interest rate risk. For Emera’s regulated subsidiaries, the cost of costs are recovered from customers. Regulatory ROE such that regulatory ROEs are likely to fall in times of reducing increasing interest rates, albeit not directly and generally with process. Rising interest rates may also negatively affect and acquisition initiatives. Interest rates could also be impacted by changes in credit and Capital Markets As with most other utilities and other similar yield-returning affected by changes in interest rates and could underperform interest rates. Inflation Risk: The Company may be exposed to changes in inflation that maintenance costs, capital investment, and fuel costs rates. Commodity Price Risk The Company’s utility fuel supply and purchase In addition, Emera Energy is subject to commodity price risk and arrangements. Regulated Utilities: The Company’s utility fuel supply is exposed to impacts on delivery reliability and price, despite contracted terms. markets can be affected by a wide range of factors including but not limited to, currency fluctuations, changes disasters, transportation or production disruptions, and conflicts, changes to international trade agreements, tariffs, Prolonged and substantial increases in fuel prices could result risk of recovery of costs or regulatory assets, and/or negative and sales, any of which could result in a Material Adverse Emera Energy Marketing and Trading: The majority of Emera Energy’s portfolio of electricity particular, its natural gas asset avoiding any material long or short commodity positions. price risk, particularly with respect to basis point differentials operational issue, imposition of tariffs or counterparty result in increased collateral requirements associated with resulting in higher liquidity requirements and increased costs Income Tax Risk The computation of the Company’s provision for Canada, the US and the Caribbean and any such changes value of Emera’s existing deferred income tax and could be negatively impacted by changes in laws. Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third guarantees and letters of credit were not included within December 31, 2024 : TECO Holdings, Inc. (“TECO Holdings”) has a guarantee obligations under a gas transportation precedent agreement. amount of $ 45 five years after the gas transportation precedent agreement January 1, 2022. The counterparty has the right to require support either in the form of a substitute guarantee from or a letter of credit or cash deposit of $ 27 TECO Holdings has a guarantee in connection with SeaCoast’s service agreement, which expires December 31, 2055, counterparty with a final expiration date of December 31, 2071. amount of $ 13 counterparty has the right to require TECO Holdings to provide either a substitute guarantee from an affiliate cash deposit of $ 13 Emera has a guarantee of $ 66 automatically terminate on the date upon which the obligations NSPI has guarantees on behalf of its subsidiary, of $ 104 104 The Company has standby letters of credit and surety 105 (December 31, 2023 – $ 103 subsidiaries. These letters of credit and surety bonds typically annually as required. Emera, on behalf of NSPI, has a standby letter of credit to secure retirement plan. The expiry date of this letter of credit was as at December 31, 2024 was $ 58 56 Emera has provided an indemnity to a counterparty in arise from specific future changes in Canadian federal No such changes in law have been proposed at this time. of future payments that could result from future claims risk of having to make any significant payments under Collaborative Arrangements For the years ended December 31, 2024 and 2023, the collaborative arrangements: Through NSPI, the Company is a participant in three percentage ownership of the wind project assets is based on assets by the total project assets. NSPI has power output of the projects and, therefore, NSPI’s portion for generation and purchased power. Consolidated Statements of Income. In 2024, NSPI recognized 12 8 million) in “Regulated fuel for generation and purchased 3 3 “OM&G” on the Consolidated Statements of Income.

Cumulative Preferred Stock

Cumulative Preferred Stock	12 Months Ended
	Dec. 31, 2024
Cumulative Preferred Stock [Abstract]
Cumulative Preferred Stock	29. CUMULATIVE PREFERRED STOCK Authorized: Unlimited number of First Preferred shares, issuable in Unlimited number of Second Preferred shares, issuable in December 31, 2024 December 31, 2023 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 $ 1.6085 $ 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 $ 1.5810 $ 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) Annual Dividend Rate (%) 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) 2.182 0.5456 1.84 August 15, 2025 25.00 Series B 6.434 1.6085 2.65 August 15, 2028 25.00 Series D (5)(6) 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 6.324 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate (7) 4.500 1.1250 (8) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or (2) On or after the specified redemption dates, whole or in part, at the specified per share redemption redemption. (3) On the redemption and/or conversion option 25.00 by the annual fixed or floating dividend rate, Bond Yield on the applicable reset date, plus the applicable 4.90 cent) and for Series B equals the Government 1.84 (4) On each conversion option date, the holders equal number of Cumulative Redeemable the outstanding Preferred Shares, Series cash, in whole or in part at a price of 25.00 and $ 25.50 of redemptions on any other date after August Series I equals the Government of Treasury Bill Rate on 2.54 (5) On January 8, 2025, Emera announced the conversion period between January 15, right, at their option, to convert all or Series G on February 15, 2025. On February holders, no Series F were converted (6) On January 16, 2025, Emera announced 1.0505 1.4372 for the five-year period from and including (7) First Preferred Shares, Series E are redeemable 25.00 (8) First Preferred Shares, Series L are redeemable 26.00 0.25 year until November 15, 2030 and $ 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 Changes in 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, 2024
Non-Controlling Interest in Subsidiaries [Abstract]
Non-Controlling Interest in Subsidiaries	30. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of dollars 2024 2023 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14 Preferred shares of GBPC: Authorized: 10,000 2024 2023 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 GBPC Non–Voting The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually . The Preferred Shares rank behind GBPC’s current all of GBPC’s current and future common stock.

Supplementary Information to Co

Supplementary Information to Consolidated Statements of Cash Flows	12 Months Ended
	Dec. 31, 2024
Supplementary Information to Consolidated Statements of Cash Flows [Abstract]
Supplementary Information to Consolidated Statements of Cash Flows	31. SUPPLEMENTARY CASH FLOWS For the Year ended December 31 millions of dollars 2024 2023 Changes in non-cash working capital: $ 38 $ (31) (1) (154) 653 536 (538) (2) 32 (179) Total $ 452 $ (95) (1) The year ended December 31, 2023, includes $ 162 regulatory liabilities is included in operating cash activities. (2) The year ended December 31, 2023, includes ($ 166 ) million related to the decreased accrual for and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included working capital resulting in no impact to net For the Year ended December 31 millions of dollars 2024 2023 Supplemental disclosure of cash paid: Interest $ 989 $ 930 Income taxes $ 34 $ 43 Supplemental disclosure of non-cash activities: Accrued proceeds from disposal of investment subject to significant influence $ 25 $ - Common share dividends reinvested $ 291 $ 271 Reclassification of short-term debt to long-term debt $ - $ 657 Decrease in accrued capital expenditures $ - $ (19) Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ (118) $ 123

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2024
Stock-Based Compensation [Abstract]
Stock-based Compensation	32. STOCK-BASED COMPENSATION ECSPP and Common Shareholders DRIP Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees to make cash contributions of a minimum of $25 per month 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 reinvestment of dividends for all participants except for where prohibited by law. maximum aggregate number of Emera common shares 7 common shares. As at December 31, 2024, Emera was Compensation cost for shares issued under the ECSPP for the 4 million (2023 – $ 3 The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada 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 with the reinvestment of cash dividends. The discount was 2 per cent in 2024. 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, 2024, Emera was 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 and thereafter 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, exercised within the 27 months six months termination without just cause or death, and within sixty days cause or resignation. Commencing with the 2022 stock during the full term of the option following the option holders six months termination without just cause or death, and within sixty days cause or resignation. If stock options are not exercised The Company uses the Black-Scholes valuation model to estimate its stock-based compensation and recognizes the expense basis. The following table shows the weighted average FV per incorporated into the valuation models for options granted, for 2024 2023 Weighted average FV per option $ 4.66 $ 6.32 Expected term (1) 5 5 Risk-free interest rate (2) 3.56 % 3.53 % Expected dividend yield (3) 6.11 % 5.05 % Expected volatility (4) 20.67 % 20.07 % (1) The expected term of the option awards is that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government (3) Incorporates current dividend rates and historical (4) Estimated using the five-year historical volatility. The following table summarizes stock option information for Total Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Granted 792,600 46.97 792,600 4.66 Exercised (78,839) 39.86 N/A N/A Forfeited (13,325) 56.14 - N/A Vested N/A N/A (438,365) 4.58 Options outstanding December 31, 2024 3,796,040 $ 50.53 1,607,490 $ 5.08 Options exercisable December 31, 2024 (2)(3) 2,188,550 $ 50.07 (1) As at December 31, 2024, there was $ 6 expected to be recognized over a weighted 3 5 3 (2) As at December 31, 2024, the weighted 4 $ 11 5 8 (3) As at December 31, 2024, the FV of options 2 2 Compensation cost recognized for stock options for the year 2 (2023 – $ 2 As at December 31, 2024, cash received from option exercises 3 6 total intrinsic value of options exercised for the year ended 1 2 million). The range of exercise prices for the options outstanding 39.93 $ 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. Unless otherwise determined by the Management Resources and Compensation Committee (“MRCC”), 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 MRCC to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. A summary of the activity related to employee and director is presented in the following table: Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 Granted including DRIP 86,417 45.20 134,795 48.98 Exercised (10,292) 38.77 (34,997) 36.04 Outstanding and exercisable as at December 31, 2024 789,088 $ 42.65 828,856 $ 47.12 Compensation cost recognized for employee and director was $ 13 2 units realized for the year ended December 31, 2024 4 1 aggregate intrinsic value of the outstanding shares for the year was $ 43 36 ended December 31, 2024 for directors was $ 45 37 during the year ended December 31, 2024 associated with 2 3 million). Performance Share Unit Plan Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year cash payment. Unless otherwise determined by the MRCC, 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 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. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee PSUs for in the following table: Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 Granted including DRIP 354,793 48.69 Exercised (253,136) 54.66 Forfeited (12,929) 52.53 Outstanding as at December 31, 2024 832,093 $ 52.57 $ 50 Compensation cost recognized for the PSU plan for the 18 (2023 – $ 11 ended December 31, 2024 were $ 5 3 ended December 31, 2024 associated with the PSU plan were 14 19 Restricted Share Unit Plan Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year cash payment. Unless otherwise determined by the MRCC, 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 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. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee RSUs for in the following table: Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 Granted including DRIP 287,976 48.65 Exercised (183,241) 54.66 Forfeited (14,228) 52.45 Outstanding as at December 31, 2024 653,148 $ 52.36 $ 41 Compensation cost recognized for the RSU plan for the 15 (2023 – $ 10 ended December 31, 2024 were $ 4 3 ended December 31, 2024 associated with the RSU plan were 10 10

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2024
Variable Interest Entities [Abstract]
Variable Interest Entities	33. VARIABLE INTEREST ENTITIES Emera holds a variable interest in NSPML, a VIE for which primary beneficiary since it does not have the controlling milestones were achieved, NLH was deemed the primary purposes as it has impact the economic performance of the Maritime Link. Thus, as an equity investment. BLPC has established a SIF, consequential loss to certain generating, transmission interest in the SIF for which it was determined that ECI SIF must be consolidated by ECI. In its determination that that, in substance, the activities of the SIF are being conducted BLPC, alone, obtains the benefits from the SIF’s has rights to all the benefits of the SIF, Any withdrawal of SIF fund assets by the Company would consolidated VIE in the SIF is recorded as “Other long-term liabilities” on the Consolidated Balance Sheets. Amounts portion of funds required to be set aside for the BLPC The Company has identified certain long-term purchase power variable interests as the Company has to purchase all price. However, it was determined power to direct the activities of the entity, management decisions. The following table provides information about Emera’s As at December 31, 2024 December 31, 2023 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 475 $ 6 $ 489 $ 6

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
Subsequent Events	34. SUBSEQUENT EVENTS These financial statements and notes reflect the Company’s the balance sheet date through February 21, 2025, the date

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2024
Summary of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These consolidated financial statements are prepared Generally Accepted Accounting Principles (“USGAAP”) adjustments that are of a recurring nature and necessary All dollar amounts are presented in Canadian dollars (“CAD”),
Principles of Consolidation	Principles of Consolidation These consolidated financial statements include the accounts subsidiaries, and a variable interest entity (“VIE”) in which the equity method of accounting to record investments significant influence, and for VIEs in which Emera is not The Company performs ongoing analysis to assess whether reconsideration events have arisen with respect to existing To identify potential VIEs, management reviews contractual and ownership arrangements such tolling contracts, guarantees, jointly owned facilities and is deemed the primary beneficiary must be consolidated. power to direct the activities of the VIE that most significantly obligation to absorb losses or the right to receive benefits the VIE. In circumstances where Emera has an investment beneficiary, the VIE Intercompany balances and transactions have been on certain transactions between certain non-regulated and regulated accounting standards for rate-regulated entities. The net profit eliminated in the absence of the accounting standards regulated operating revenues. An offset is recorded generation and purchased power,
Use of Management Estimates	Use of Management Estimates The preparation of consolidated financial statements to make estimates and assumptions. These may affect date of the financial statements and reported amounts periods. Significant areas requiring use of management liabilities, accumulated reserve for cost of removal, pension revenue, useful lives for depreciable assets, goodwill and long-lived income taxes, asset retirement obligations (“ARO”), and evaluates the Company’s estimates on an ongoing expected conditions and assumptions believed to be reasonable any adjustments recognized in income in the year they arise.
Regulatory Matters	Regulatory Matters Regulatory accounting applies where rates are established third-party regulator. Rates products or services and provide an opportunity for a reasonable applicable. For further detail, refer to note 7.
Foreign Currency Translation	Foreign Currency Translation Monetary assets and liabilities denominated in foreign exchange prevailing at the balance sheet date. The resulting differences original transaction date and the balance sheet date are Assets and liabilities of foreign operations whose functional translated using exchange rates in effect at the balance average exchange rate in effect for the period. The and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt hedges of net investments in USD denominated foreign these investments, measured at exchange rates in effect
Revenue Recognition	Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand clauses and riders, are recognized when obligations under the when electricity and gas are delivered to customers over and consumes the benefits. Electric and gas revenues billed and unbilled revenues. Revenues related to the approved by the respective regulators and recorded periodic, systematic basis, generally monthly or bi-monthly. and gas delivered to customers, but not billed, is estimated recognized. The Company’s estimate of unbilled by estimating the megawatt hours (“MWh”) or therms delivered expected to prevail in the upcoming billing cycle. This energy demand, weather, line Non-regulated Revenue: Marketing and trading margins are comprised of Emera natural gas and electricity, are recorded when obligations under terms of the contract reflecting the nature of contractual relationships with customers Energy sales are recognized when obligations under the when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations satisfied. Other: Sales, value add, and other taxes, except for gross receipts Company concurrent with revenue-producing activities
Franchise Fees and Gross Receipts	Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, approved by the Florida Public Service Commission (“FPSC”). for franchise fees and gross receipt taxes are included revenues in the Consolidated Statements of Income. TEC and PGS are included as an expense on the Consolidated and municipal taxes”. NMGC is an agent in the collection and payment of franchise required by a tariff to present the amounts on receipt taxes are presented net with no line item impact
PP&E	PP&E PP&E is recorded at original cost, including AFUDC or aid of construction. The cost of additions, including betterments and replacements Consolidated Balance Sheets. When units of regulated PP&E plus removal or disposal costs, less salvage proceeds, gain or loss reflected in income. Where a disposition of included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, regulated property or interest for non-regulated property, project. Overhead includes corporate costs such as finance, along with other costs related to support functions, employee operating and maintenance. Expenditures for project development have a future economic benefit. Normal maintenance projects and major maintenance related assets are expensed as incurred. When a major the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based the depreciable assets in each functional class of depreciable regulated subsidiaries, depreciation is calculated using to the average investment, adjusted for anticipated costs depreciable property. Intangible assets, which are included in “PP&E” on the Consolidated computer software and land rights. Amortization is determined estimated remaining service lives of the asset in each category. subsidiaries, amortization is calculated using the amortizable value to date over the remaining life of those assets. The require regulatory approval.
Goodwill	Goodwill Goodwill is calculated as the excess of the purchase price identifiable assets acquired and liabilities assumed at the cost less any write-down for impairment and is adjusted Goodwill is subject to assessment for impairment at the change in circumstances indicates that the FV of a reporting assessing goodwill for impairment, the Company has the option assessment to determine whether a quantitative assessment assessment management considers, among other factors, market considerations and overall financial performance. If the Company performs a qualitative assessment and less than its carrying amount, or if the Company chooses quantitative test is performed. The quantitative test compares value, including goodwill (“carrying amount”). If the carrying an impairment loss is recorded. Management estimates approach, or a combination of the income and market cash flow analysis which relies on management’s flows. The analysis includes an estimate of terminal values methodology which derives a valuation using an assumed residual cash flows. The discount rate used is a market participant traded comparable companies and represents the weighted companies. For the market approach, management estimates transactions within comparable industries, or in the case transactions involving the reporting unit. Significant assumptions unit using an income approach include discount and growth cost of capital, valuation of the reporting unit’s net capital cash flows. Adverse changes in these assumptions the goodwill assigned to Emera’s reporting units. As of December 31, 2024, Emera’s goodwill represented TECO Energy, Inc. acquired and liabilities assumed. In Q3 2024, Emera entered result, a quantitative goodwill impairment assessment Company recorded a goodwill impairment charge of $ 210 198 155 USD ($ 146 303 NMGC disposal unit classified as held for sale. For further In Q4 2024, a qualitative assessment was performed for carrying amounts calculated during the last quantitative test more likely than not that the FV of this reporting unit exceeded such, no quantitative testing was required. Given the length impairment test for the PGS reporting unit, Emera elected performed a quantitative impairment assessment in Q4 market approach. This assessment estimated that the amount, including goodwill, and as a result, no impairment
Income Taxes and Investment Tax Credits	Income Taxes and Emera recognizes deferred income tax assets and liabilities that have been included in financial statements or income tax liabilities are determined based on the difference the Consolidated Balance Sheets, and their respective year in which the differences are expected to reverse. deferred income tax assets and liabilities is recognized enacted, unless required to be offset to a regulatory Emera recognizes the effect of income tax positions realized. Management reviews all readily available current and looking information, and the likelihood that deferred income taxable income is assessed and assumptions are made income tax assets and liabilities. If management subsequently deferred income tax asset will not be realized, a valuation deferred income tax asset expected to be realized. Generally, investment future periods to the extent that realization of such benefit earned on regulated assets by TEC, PGS and NMGC are regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from taxes. NSPI, NSPML and Brunswick Pipeline collect income taxes that is currently payable, except for the deferred income taxes prescribed by regulators. For the balance of regulated Brunswick Pipeline recognize regulatory assets or liabilities expected to be recovered from or returned to customers liabilities are grossed up using the respective income tax future revenues that are required to fund these deferred associated with reduced revenues resulting from the realization not subject to income taxes. Emera classifies interest and penalties associated with operating expense, respectively.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The Company manages its exposure to normal operating and FX, interest rates and share prices through contractual and by using financial instruments consisting mainly of swaps, equity derivatives, and coal, oil and gas futures, Company has contracts for the physical purchase and sale of contracts are classified as HFT. derivatives. The Company recognizes the FV of all its derivatives on derivatives that meet the normal purchases and normal sales meet the NPNS exception are not recognized on the balance income when they settle. A physical contract generally is reasonable in relation to the Company’s business within the proximity to allow for physical delivery, commodity, and the contracts designated under the NPNS exception and will discontinue under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent proven to effectively hedge identified risk both at Specifically, for cash income in the same period the related hedged item is realized. requirements are not met, the derivatives are recognized income in the reporting period, unless deferred as a result Derivatives entered into by NSPI, NMGC and GBPC that which the NPNS exception has not been taken, are subject change in FV of the derivatives is deferred to a regulatory in the hedged item when the hedged item is settled. Management from settlement of these derivatives related to fuel for to or collected from customers in future rates. TEC and PGS Derivatives that do not meet any of the above criteria are normally recorded in net income of the period. The Company to be included in the HFT category where another accounting Emera classifies gains and losses on derivatives as a component fuel for generation and purchased power, nature of the item being economically hedged. Transportation and trading derivative transactions is recognized as an asset and amortized over the period of the transportation contract presented in the same category as the item being hedged within Statements of Cash Flows. Non-hedged derivatives are included Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance collateral with the same counterparty. and other current assets” and obligations to return cash
Lessee, Leases	Leases The Company determines whether a contract contains contract conveys the right to control the use of an identified consideration. Emera has leases with independent power producers (“IPP”) purchase wind and hydro energy over varying contract These finance leases are not recorded on the Company’s associated with the leases are variable in nature and there expense associated with these leases is recorded as “Regulated power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized based on the present value of the future minimum lease payments date. As most of Emera’s leases do not provide commencement of the lease is used in determining expense is recognized on a straight-line basis over the Consolidated Statements of Income.
Lessor, Leases	Where the Company is the lessor, arrangement transfers control of the underlying asset are met due to the presence of a third-party residual value lease. For direct finance leases, a net investment in the lease minimum lease payments and residual value, net of estimated The difference between the gross investment income at the inception of the lease. Unearned income using a constant rate of interest equal to the internal For sales-type leases, the accounting is similar to the accounting difference between the FV and the carrying value 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.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments less at acquisition.
Receivables	Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The to reduce accounts receivable for amounts expected to losses related to accounts receivable by considering historical current events, the characteristics of existing accounts affect the collectability of the reported amount. to maintain the allowance at a level considered adequate written off against the allowance when they are
Allowance for Credit Losses	Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced payment terms for electricity and gas sales are approximately assessed on account balances after the due date. The to reduce accounts receivable for amounts expected to losses related to accounts receivable by considering historical current events, the characteristics of existing accounts affect the collectability of the reported amount. to maintain the allowance at a level considered adequate written off against the allowance when they are
Inventory	Inventory Fuel and materials inventories are valued at the lower unless evidence indicates the weighted-average cost
Asset Impairment	Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment triggering event occurs, such as a significant market disruption The assessment involves comparing undiscounted expected asset. When the undiscounted cash flow analysis indicates amount of the impairment loss is determined by measuring lived asset over its estimated FV. other recoverable amounts, are based on a combination analysis, observable market activity and independent market regarding uses and holding periods of assets are based which consider external factors and market forces, as assumptions made are consistent with generally accepted valuation and pricing activities. In 2024, impairment charges of $ 19 14 8 million of which was included in Other income, net with $ 11 Consolidated Income Statement. No 2023. Equity Method Investments: The carrying value of investments accounted for under comparing the FV of these investments to their carrying values, reviewing for the presence of impairment indicators. If other-than-temporary, the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under changes in FV recognized in the Consolidated Statements of Income. have readily determinable FV are recorded at cost minus resulting from observable price changes in orderly transactions No impairment of financial assets was required in either
Asset Retirement Obligations and Cost of Removal	Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection resulting from the permanent retirement, abandonment may exist under an existing or enacted law or statute, under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary the Company’s credit adjusted risk-free rate. The Estimated future cash flows are based on completed depreciation experience, estimated useful lives, and governmental regulatory liability is recorded and the carrying amount of the related long-lived The amount capitalized at inception is depreciated in the same Over time, the liability is accreted to its estimated future value. liabilities” and accretion expense is included as part of accretion expense not yet approved by the regulator is depreciation study. Some of the Company’s transmission and distribution recognized in the consolidated financial statements, as reasonably estimated, given insufficient information obligation to perform an asset retirement activity in which conditional on a future event that may or may not be monitors these obligations and a liability is recognized at FV determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR non-ARO COR represent funds received from customers future non-legally required COR of PP&E upon retirement. The the related assets based on depreciation studies approved estimated based on historical experience and future estimated future cash outlays.
Stock-Based Compensation	Stock-Based Compensation The Company has several stock-based compensation management; an employee common share purchase plan; performance share unit (“PSU”) plan; and a restricted its plans in accordance with the FV-based method of based compensation cost is measured at the grant date, recognized as an expense over the employee’s or vesting method. Stock-based compensation plans recognized as and re-measured at FV at each reporting date, with the
Employee Benefits	Employee Benefits The costs of the Company’s pension and other expensed over the periods during which employees render service. status of its defined-benefit and other post-retirement plans on changes in funded status in the year the change occurs. and losses and past service costs in “AOCI” or “Regulatory The components of net periodic benefit cost other than income, net” on the Consolidated Statements of Income.
Government Grants	Government Grants The Company accounts for government grants by applying International Accounting Standards (“IAS”) 20, Accounting Government Assistance. A grant relating to an asset is amount of the asset. A grant relating to income is presented intended to compensate. In 2024, the Company received an aggregate of $ 47 7 various Canadian and US government agencies towards PP&E . The capital projects receiving grants primarily relate to the Company’s compliance initiatives. Further details on significant grant programs below. Natural Resources Canada (“NRCan”) Smart Renewables On March 27, 2024, NSPI was approved for a grant under the three 33 cent of eligible project costs to a maximum $ 109 2027. For the year-end December 31, 2024, NSPI received 26 nil ) in funding under the grant, which has been recorded as a reduction to the carrying PP&E .

Dispositions (Tables)

Dispositions (Tables)	12 Months Ended
	Dec. 31, 2024
Dispositions [Abstract]
Details of Assets and Liabilities Classified as Held for Sale	Details of the assets and liabilities classified as held for As at December 31 millions of dollars 2024 Cash and cash equivalents $ 8 Inventory 9 Derivative instruments 1 Regulatory assets 28 Receivables and other current assets 127 Current assets held for sale $ 173 PP&E 1,828 Regulatory assets 6 Goodwill 303 Other long-term assets 23 Long-term assets held for sale $ 2,160 Total assets held for sale $ 2,333 Short-term debt $ 46 Derivative instruments 1 Regulatory liabilities 10 Accounts payable and other current liabilities 155 Current liabilities associated with assets held for sale 212 Long-term debt 696 Deferred income taxes 167 Regulatory liabilities 274 Other long-term liabilities 11 Long-term liabilities associated with assets held for sale $ 1,148 Total liabilities associated with assets held for sale $ 1,360

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Information [Abstract]
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, 2024 Operating revenues from external customers (1) $ 3,451 $ 1,855 $ 1,595 $ 566 $ (267) $ $ 7,200 Inter-segment revenues (1) 9 - 14 - 19 (42) 3,460 1,855 1,609 566 (248) (42) 7,200 Regulated fuel for generation and purchased power 852 859 - 295 - (14) 1,992 Regulated cost of natural gas - - 396 - - - 396 OM&G 779 408 454 143 154 (20) 1,918 Provincial, state and municipal taxes 273 48 103 3 - - 427 Depreciation and amortization 622 282 182 69 7 - 1,162 Impairment charges - - 11 - 214 - 225 Income from equity investments - 73 20 4 2 - 99 Other income, net 66 28 16 12 73 8 203 Interest expense, net (2) 265 168 151 22 367 - 973 Income tax expense (recovery) 94 (41) 89 1 (302) - (159) NCI in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 73 - 73 Net income (loss) attributable to common shareholders $ 641 $ 232 $ 259 $ 48 $ (686) $ - $ 494 Capital expenditures $ 1,942 $ 481 $ 619 $ 81 $ 4 $ - $ 3,127 As at December 31, 2024 Total assets $ 24,375 $ 7,609 $ 8,439 $ 1,444 $ 1,810 $ (726) $ 42,951 Investments subject to significant influence $ - $ 475 $ 124 $ 55 $ - $ - $ 654 Goodwill $ 5,035 $ - $ 823 $ - $ - $ - $ 5,858 (1) All significant inter-company balances and transactions between non-regulated and regulated entities. Management OM&G, or regulated fuel for generation and purchased measured at the amount of consideration established determining reportable segments. (2) Segment net income is reported on a basis 29 December 31, 2024, between the Gas Utilities 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, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 NCI in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (1) All significant inter-company balances and transactions between non-regulated and regulated entities. Management OM&G, or regulated fuel for generation and purchased measured at the amount of consideration established determining reportable segments. (2) Segment net income is reported on a basis 95 December 31, 2023, between the Florida Electric Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2024 2023 United States 4,712 $ 5,310 Canada 1,922 1,727 Barbados 427 389 The Bahamas 139 137 $ 7,200 $ 7,563 PP&E: As at December 31 December 31 millions of dollars 2024 2023 United States (1) $ 20,084 $ 18,588 Canada 5,068 4,878 Barbados 645 576 The Bahamas 371 334 $ 26,168 $ 24,376 (1) On August 5, 2024, Emera announced an agreement to sell for sale and excluded from the table above. For further

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue [Abstract]
Disaggregation of 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, 2024 Regulated Revenue Residential $ 2,063 $ 997 $ 203 $ 712 $ - $ - $ 3,975 Commercial 939 499 300 496 - - 2,234 Industrial 223 276 28 94 - (14) 607 Other electric 372 41 7 - - - 420 Regulatory deferrals (157) - 15 - - - (142) Other (1) 20 42 13 224 - (9) 290 Finance income (2)(3) - - - 63 - 63 $ 3,460 $ 1,855 $ 566 $ 1,589 $ - $ (23) $ 7,447 Non-Regulated Revenue Marketing and trading margin (4) - - - - 77 - 77 Other non-regulated operating revenue - - - 20 32 (24) 28 Mark-to-market (3) - - - - (357) 5 (352) $ - $ - $ - $ 20 $ (248) $ (19) $ (247) Total operating revenues $ 3,460 $ 1,855 $ 566 $ 1,609 $ (248) $ (42) $ 7,200 For the year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) 7,235 Non-Regulated Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 (1) Other includes rental revenues, which do not (2) Revenue related to Brunswick Pipeline's service agreement (3) Revenue which does not represent revenues (4) Includes gains (losses) on settlement of energy customers.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
Regulatory Assets and Liabilities [Abstract]
Regulatory Assets	As at December 31 December 31 millions of dollars 2024 (1) 2023 Regulatory assets Deferred income tax regulatory assets $ 1,227 $ 1,233 TEC capital cost recovery for early retired assets 737 671 Storm cost recovery clauses 613 52 Pension and post-retirement medical plan 395 364 TEC capital cost recovery for retired Polk Unit 1 components 205 - Deferrals related to derivative instruments 42 88 Cost recovery clauses 33 151 Environmental remediations 29 26 Stranded cost recovery 27 25 NSPI FAM - 395 Other (2) 119 100 $ 3,427 $ 3,105 Current $ 595 $ 339 Long-term 2,832 2,766 Total $ 3,427 $ 3,105 Regulatory liabilities Deferred income tax regulatory liabilities 828 830 Accumulated reserve – COR 733 849 Cost recovery clauses 121 32 NSPI FAM 56 - Deferrals related to derivative instruments 44 17 BLPC Self-insurance fund ("SIF") (note 33) 32 29 Other (2) 66 15 $ 1,880 $ 1,772 Current $ 262 $ 168 Long-term 1,618 1,604 Total $ 1,880 $ 1,772 (1) On August 5, 2024, Emera announced an were classified as held for sale and excluded from (2) Comprised of regulatory assets and liabilities
Regulatory Liabilities	As at December 31 December 31 millions of dollars 2024 (1) 2023 Regulatory assets Deferred income tax regulatory assets $ 1,227 $ 1,233 TEC capital cost recovery for early retired assets 737 671 Storm cost recovery clauses 613 52 Pension and post-retirement medical plan 395 364 TEC capital cost recovery for retired Polk Unit 1 components 205 - Deferrals related to derivative instruments 42 88 Cost recovery clauses 33 151 Environmental remediations 29 26 Stranded cost recovery 27 25 NSPI FAM - 395 Other (2) 119 100 $ 3,427 $ 3,105 Current $ 595 $ 339 Long-term 2,832 2,766 Total $ 3,427 $ 3,105 Regulatory liabilities Deferred income tax regulatory liabilities 828 830 Accumulated reserve – COR 733 849 Cost recovery clauses 121 32 NSPI FAM 56 - Deferrals related to derivative instruments 44 17 BLPC Self-insurance fund ("SIF") (note 33) 32 29 Other (2) 66 15 $ 1,880 $ 1,772 Current $ 262 $ 168 Long-term 1,618 1,604 Total $ 1,880 $ 1,772 (1) On August 5, 2024, Emera announced an were classified as held for sale and excluded from (2) Comprised of regulatory assets and liabilities

Investments Subject to Signif_2

Investments Subject to Significant Influence and Equity Income (Tables)	12 Months Ended
	Dec. 31, 2024
Variable Interest Entity [Line Items]
Summary of 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 2024 2023 2024 2023 2024 NSPML $ 475 $ 489 $ 44 $ 46 100.0 M&NP 124 118 20 21 12.9 Lucelec (1) 55 48 4 4 19.5 LIL (2) - 747 29 63 - Bear Swamp - - 2 12 50.0 $ 654 $ 1,402 $ 99 $ 146 (1) Emera has significant influence over the operating and therefore, records its investment in these (2) On June 4, 2024, Emera completed the sale (3) The investment balance in Bear Swamp is 179 Bear Swamp's credit investment balance of $ 92 81 Consolidated Balance Sheets.
NSP Maritime Link Inc. [Member]
Variable Interest Entity [Line Items]
Summary of Investments Subject to Significant Influence	Emera accounts for its variable interest investment in NSPML's consolidated summarized balance sheets are illustrated As at December 31 December 31 millions of dollars 2024 2023 Balance Sheets Current assets $ 37 $ 21 PP&E 1,425 1,473 Regulatory assets 778 272 Non-current assets 27 29 Total $ 2,267 $ 1,795 Current liabilities $ 55 $ 48 Long-term debt (2) 1,570 1,109 Non-current liabilities 167 149 Equity 475 489 Total $ 2,267 $ 1,795 (1) On November 29, 2024, the UARB approved 500 FLG. For further details, refer to note 7. (2) On December 16, 2024, NSPML issued a 500

Other Income, Net (Tables)

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2024
Other Income, Net [Abstract]
Components of Other Expense, Net	For the Year ended December 31 millions of dollars 2024 2023 Gain on sale of LIL, net of transaction costs $ 182 $ - AFUDC 53 38 Pension non-current service cost recovery 35 35 Interest income 23 43 Transaction costs related to the pending sale of NMGC (25) - Charges related to wind-down costs and certain asset impairments (2) (29) - FX (losses) gains (58) 20 Other 22 22 $ 203 $ 158 (1) For more information related to the gain pending sale of NMGC, refer to note 4. (2) Primarily related to the wind-down of Block

Interest Expense, Net (Tables)

Interest Expense, Net (Tables)	12 Months Ended
	Dec. 31, 2024
Interest Expense, Net [Abstract]
Components of Interest Expense, Net	Interest expense, net consisted of the following: For the Year ended December 31 millions of dollars 2024 2023 Interest on debt $ 1,004 $ 954 Allowance for borrowed funds used during construction (23) (16) Other (8) (13) $ 973 $ 925

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
Income Taxes [Abstract]
Reconciliation of Effective Income Tax Rate	The income tax provision, for the years ended December enacted combined Canadian federal and provincial statutory millions of dollars 2024 2023 Income before provision for income taxes $ 409 $ 1,173 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 119 340 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (90) (72) Interest and financing expenses (58) - Valuation allowance (58) 3 Tax (57) (53) Goodwill impairment charge 49 - Amortization of deferred income tax regulatory liabilities (36) (33) Foreign tax rate variance (31) (36) Additional impact from the sale of LIL equity interest 22 - Tax (14) (15) Manufacturing allowance (9) (8) Other 4 2 Income tax (recovery) expense $ (159) $ 128 Effective income tax rate (39%) 11%
Composition of Taxes on Income from Continuing Operations	millions of dollars 2024 2023 Current income taxes $ 29 $ 26 4 5 Deferred income taxes (200) 93 155 128 Adjustments to beginning of the year valuation allowance (61) - Investment tax credits (6) (29) Operating loss carryforwards (4) (93) (76) (2) Income tax (recovery) expense $ (159) $ 128 The following table reflects the composition of income Consolidated Statements of Income for the years ended millions of dollars 2024 2023 Canada $ 156 $ 171 United States 203 964 Other 50 38 Income before provision for income taxes $ 409 $ 1,173
Schedule of Deferred Income Tax Assets and Liabilities	The deferred income tax assets and liabilities presented in December 31 consisted of the following: millions of dollars 2024 2023 Deferred income tax assets: Tax $ 1,118 $ 1,195 Tax 534 454 Regulatory liabilities 225 175 Derivative instruments 144 205 Other 462 372 Total 2,483 2,401 Valuation allowance (322) (363) Total $ 2,161 $ 2,038 Deferred income tax liabilities: PP&E $ (3,421) $ (3,223) Regulatory assets (198) (196) Derivative instruments (105) (235) Investments subject to significant influence (46) (216) Other (330) (312) Total $ (4,100) $ (4,182) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 392 $ 208 Long-term deferred income tax liabilities (2,331) (2,352) Net deferred income tax liabilities $ (1,939) $ (2,144)
Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods	Emera’s NOL, capital loss and tax credit carryforwards 2024 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,420 $ (967) $ 1,453 2026 - 2044 55 (55) - Indefinite 2 (1) 1 2028 - 2042 United States $ 1,587 $ (1) $ 1,586 2036 - Indefinite 1,351 (1) 1,350 2026 - Indefinite 533 (3) 530 2025 - 2044 Other $ 91 $ (23) $ 68 2025 - 2031
Details of Change in Unrecognized Tax Benefits	millions of dollars 2024 2023 Balance, January 1 $ 37 $ 33 Increases due to tax positions related to current year 6 5 Increases due to tax positions related to a prior year 2 1 Decreases due to tax positions related to a prior year (3) (2) Balance, December 31 $ 42 $ 37

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2024
Common Stock [Abstract]
Summary of Issued and Outstanding Common Stock	Authorized : Unlimited number of non-par value common shares. 2024 2023 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 284.12 $ 8,462 269.95 $ 7,762 Issuance of common stock under ATM program (1)(2) 5.12 261 8.29 397 Issued under the DRIP, 6.10 291 5.26 272 Senior management stock options exercised and Employee Share Purchase Plan 0.60 28 0.62 31 Balance, December 31 295.94 $ 9,042 284.12 $ 8,462 (1) For the year ended December 31, 2023, a 8,287,037 average price of $ 48.27 400 397 (2) For the year ended December 31, 2024, a 5,117,273 average price of $ 51.52 264 261 31, 2024, an aggregate gross sales limit of $ 336

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings per Share	The following table reconciles the computation of basic For the Year ended December 31 millions of dollars (except per share amounts) 2024 2023 Numerator Net income attributable to common shareholders $ 493.6 $ 977.7 Diluted numerator 493.6 977.7 Denominator Weighted average shares of common stock outstanding – basic 289.1 273.6 Stock-based compensation 0.1 0.2 Weighted average shares of common stock outstanding – diluted 289.2 273.8 Earnings per common share Basic $ 1.71 $ 3.57 Diluted $ 1.71 $ 3.57

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2024
Accumulated Other Comprehensive Income [Abstract]
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 (losses) 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, 2024 Balance, January 1, 2024 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 OCI before reclassifications 1,027 (139) - 2 - 890 Amounts reclassified from AOCI - - (2) - 68 66 Net current period OCI 1,027 (139) (2) 2 68 956 Balance, December 31, 2024 $ 1,396 $ (163) $ 12 $ - $ 16 $ 1,261 For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 OCI before reclassifications (270) 38 - - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period OCI (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305
Reclassifications out of Accumulated Other Comprehensive Income (Loss)	The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2024 2023 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ 2 $ - Other income, net (2) 2 Pension and post-retirement benefits 68 (40) Total 68 (38) Income tax expense - (1) Total $ 68 $ (39) Total reclassifications out of AOCI, net of tax, for the period $ 66 $ (41)

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2024
Inventory [Abstract]
Components of Inventory	As at December 31 December 31 millions of dollars 2024 2023 Materials $ 453 $ 408 Fuel 328 382 Total $ 781 $ 790

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments
Derivative Assets and Liabilities	Derivative assets and liabilities relating to the foregoing categories Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2024 2023 2024 2023 Regulatory deferral: $ 25 $ 16 $ 44 $ 76 27 3 3 3 52 19 47 79 HFT derivatives: 34 29 30 36 236 319 660 531 270 348 690 567 Other derivatives: - 4 2 - - 18 34 7 - 22 36 7 Total 322 389 773 653 Impact of master netting agreements: (7) (3) (7) (3) (148) (146) (148) (146) Total (155) (149) (155) (149) Less: Derivatives classified as held for sale (1) (1) - (1) - Total derivatives $ 166 $ 240 $ 617 $ 504 Current (2) 115 174 526 386 Long-term (2) 51 66 91 118 Total derivatives $ 166 $ 240 $ 617 $ 504 (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details (2) Derivative assets and liabilities are classified
Changes in Realized and Unrealized Gains (Losses) on Derivatives	Commodity Physical Commodity swaps and FX natural gas swaps and FX millions of dollars forwards forwards purchases forwards forwards For the year ended December 31 2024 2023 Unrealized gain (loss) in regulatory assets $ (27) $ 5 $ - $ (109) $ (3) Unrealized gain (loss) in regulatory liabilities 11 33 (3) (73) - Realized gain in regulatory assets (8) - - (5) - Realized loss in regulatory liabilities 4 - - 2 - Realized (gain) loss in inventory (1) 11 (8) - 4 (10) Realized (gain) loss in regulated fuel for generation and purchased power (2) 50 (6) (49) (9) (4) Other - - - (14) - Total $ 41 $ 24 $ (52) $ (204) $ (17) (1) Realized (gains) losses will be recognized in (2) Realized (gains) losses on derivative instruments terminated or the hedged transaction is no longer For the Year ended December 31 millions of dollars 2024 2023 Power swaps and physical contracts in non-regulated operating revenues $ 12 $ (6) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 195 1,043 Total $ 207 $ 1,037 For the Year ended December 31 millions of dollars 2024 2023 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ (2) $ - $ 4 Unrealized gain (loss) in other income, net (44) - 28 - Realized gain (loss) in OM&G - 16 - (13) Realized loss in other income, net (12) - (11) - Total $ (56) $ 14 $ 17 $ (9)
Notional Volumes of Outstanding Derivatives	millions 2025 2026-2027 Physical natural gas purchases: Natural gas (MMBtu) 6 - Commodity swaps and forwards purchases: Natural gas (MMBtu) 21 23 Power (MWh) 1 - Coal (metric tonnes) 1 - FX forwards: FX contracts (millions of USD) $ 208 $ 69 Weighted average rate 1.3361 1.3296 % of USD requirements 50% 17% 2029 and millions 2025 2026 2027 2028 thereafter Natural gas purchases (Mmbtu) 262 111 43 30 73 Natural gas sales (Mmbtu) 299 69 16 8 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - -
Summary of Concentration Risk	Concentration Risk The Company's concentrations of risk consisted of the As at December 31, 2024 December 31, 2023 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 376 22% $ 476 31% Commercial 184 11% 194 13% Industrial 73 4% 84 5% Other 105 6% 103 7% Cash collateral 46 3% 94 6% 784 46% 951 62% Trading group: Credit rating of A- or above 88 5% 47 3% Credit rating of BBB- to BBB+ 42 2% 33 2% Not rated 165 10% 108 7% 295 17% 188 12% Other accounts receivable 331 20% 151 10% Classification as assets held for sale 118 7% - 0% 1,528 90% 1,290 84% Derivative Instruments (current and long-term) Credit rating of A- or above 91 5% 138 9% Credit rating of BBB- to BBB+ 1 0% 7 1% Not rated 74 5% 95 6% 166 10% 240 16% $ 1,694 100% $ 1,530 100% (1) On August 5, 2024, Emera announced the classified as held for sale. For further details, refer
Cash Collateral Positions	As at December 31 December 31 millions of dollars 2024 2023 Cash collateral provided to others $ 198 $ 101 Cash collateral received from others $ 5 $ 22

FV Measurements (Tables)

FV Measurements (Tables)	12 Months Ended
	Dec. 31, 2024
FV Measurements [Abstract]
Classification of Fair Value of Derivatives	As at December 31, 2024 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 15 $ 3 $ - $ 18 - 27 - 27 15 30 - 45 HFT derivatives: 2 23 5 30 13 52 27 92 15 75 32 122 Less: Derivatives classified as held for sale (1) - (1) - (1) Total assets 30 104 32 166 Liabilities Regulatory deferral: $ 18 $ 19 $ - $ 37 - 3 - 3 18 22 - 40 HFT derivatives: 2 21 4 27 (11) 89 437 515 (9) 110 441 542 Other derivatives: - 34 - 34 2 - - 2 2 34 - 36 Less: Derivatives classified as held for sale (1) - (1) - (1) Total liabilities 11 165 441 617 Net assets (liabilities) $ 19 $ (61) $ (409) $ (451) (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264)
Change in Fair Value of Level 3 Financial Assets and Liabilities	The change in the FV of the Level 3 financial assets and liabilities was as follows: HFT Derivatives millions of dollars Power Natural gas Total Assets Balance, beginning of period $ - $ 34 $ 34 Total revenues 5 (7) (2) Balance, December 31, 2024 $ 5 $ 27 $ 32 Liabilities Balance, beginning of period $ - $ 365 $ 365 Total revenues 4 72 76 Balance, December 31, 2024 $ 4 $ 437 $ 441
Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements	Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2024 HFT derivatives – Power 5 4 Third-party pricing $25.60 $139.65 $82.63 swaps and physical contracts HFT derivatives – Natural 27 437 Third-party pricing $2.20 $17.54 $8.57 gas swaps, futures, forwards and physical contracts Total $ 32 $ 441 Net liability $ 409 As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 (1) Unobservable inputs were weighted by the
Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets	Long-term debt is a financial liability not measured at balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2024 $ 18,407 $ 17,941 $ - $ 17,688 $ 253 $ 17,941 December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621

Receivables and Other Current_2

Receivables and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2024
Receivables and Other Current Assets [Abstract]
Summary of Receivables and Other Current Assets	19. RECEIVABLES AND OTHER CURRENT ASSETS As at December 31 December 31 millions of dollars 2024 2023 Customer accounts receivable – billed $ 834 $ 805 Customer accounts receivable – unbilled 342 363 Capitalized transportation capacity (1) 216 358 Cash collateral provided to others 198 101 Prepaid expenses 105 105 Income tax receivable 22 10 Allowance for credit losses (12) (15) Other 106 90 Total $ 1,811 $ 1,817 (1) Capitalized transportation capacity represents the agreements at the inception of the contracts. The

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Lessee, Operating Leases and Additional Information	As at December 31 December 31 millions of dollars Classification 2024 2023 Right-of-use asset Other long-term assets $ 52 $ 54 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 54 55 Total $ 57 $ 58 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: $ 10 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ - $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- 3.96% 3.93%
Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases	Future minimum lease payments under non-cancellable operating and in aggregate thereafter are as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments $ 5 $ 3 $ 3 $ 3 $ 3 $ 115 $ 132 Less imputed interest (75) Total $ 57
Lessor, Direct Finance and Sales-Type Leases	As at December 31 December 31 millions of dollars 2024 2023 Total $ 1,310 $ 1,360 Less: amounts representing estimated executory costs (182) (190) Minimum lease payments receivable $ 1,128 $ 1,170 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) (2) Less: unearned finance lease income (655) (693) Net investment in direct finance and sales-type leases $ 654 $ 658 Principal due within one year (included in "Receivables and other current assets") 44 37 Net Investment in direct finance and sales type leases – long-term $ 610 $ 621
Lessor, Future Minimum Lease Payments to be Received	As at December 31, 2024, future minimum lease payments and in aggregate thereafter were as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments to be received $ 99 $ 100 $ 99 $ 97 $ 96 $ 819 $ 1,310 Less: executory costs (182) Total $ 1,128

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Regulated and Non-Regulated Assets	PP&E consisted of the following regulated and non-regulated As at December 31 December 31 millions of dollars Estimated useful life 2024 (1) 2023 Generation 5 131 $ 14,297 $ 13,500 Transmission 10 80 3,106 2,835 Distribution 10 65 8,512 7,417 Gas transmission and distribution 15 75 4,658 5,536 General plant and other 2 60 3,078 2,985 Total 33,651 32,273 Less: Accumulated depreciation (2) (10,442) (9,994) 23,209 22,279 Construction work in progress (2) 2,959 2,097 Net book value $ 26,168 $ 24,376 (1) On August 5, 2024, Emera announced an were classified as held for sale and excluded from (2) SeaCoast owns a 50 % undivided ownership interest in a jointly 26 -mile pipeline lateral located in Florida, which went service in 2020. At December 31, 2024, SeaCoast’s 27 27 accumulated depreciation of $ 3 2 funds and all operations are accounted for as expenses of the jointly owned pipeline is included

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2024
Employee Benefit Plans [Abstract]
Changes in Benefit Obligation and Plan Assets and Funded Status	For the Year ended December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO"): Balance, January 1 $ 2,273 $ 227 $ 2,158 $ 243 Service cost 35 3 30 3 Plan participant contributions 6 5 6 6 Interest cost 110 12 111 13 Plan amendments - - - (14) Benefits paid (153) (21) (147) (29) Actuarial losses (gains) (1) 13 (3) 146 10 Settlements and curtailments - - (8) - FX translation adjustment 83 18 (23) (5) Balance, December 31 $ 2,367 $ 241 $ 2,273 $ 227 Change in plan assets: Balance, January 1 $ 2,298 $ 48 $ 2,163 $ 46 Employer contributions 36 13 42 23 Plan participant contributions 6 5 6 6 Benefits paid (153) (21) (147) (29) Actual return on assets, net of expenses 226 4 262 3 Settlements and curtailments - - (8) - FX translation adjustment 80 5 (20) (1) Balance, December 31 $ 2,493 $ 54 $ 2,298 $ 48 Funded status, end of year $ 126 $ (187) $ 25 $ (179) (1) The actuarial losses recognized in the period and compensation-related assumption changes.
Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets	millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans PBO/APBO $ 95 $ 219 $ 120 $ 205 FV of plan assets 11 - 37 - Funded status $ (84) $ (219) $ (83) $ (205) millions of dollars 2024 2023 DB pension plans DB pension plans ABO $ 90 $ 114 FV of plan assets 11 37 Funded status $ (79) $ (77)
Amounts Recognized in Consolidated Balance Sheets	As at December 31 December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Other current liabilities $ (5) $ (21) $ (5) $ (18) Liabilities associated with assets held for sale - (1) - - Long-term liabilities (78) (196) (78) (187) Other long-term assets 208 - 108 26 Assets held for sale (1) 1 31 - - AOCI, net of tax and regulatory assets 354 22 385 20 Deferred income tax expense in AOCI (8) (1) (8) (1) Net amount recognized $ 472 $ (166) $ 402 $ (160) (1) On August 5, 2024, Emera announced an were classified as held for sale. For further details
Amounts Recognized in AOCI and Regulatory Assets	Regulatory assets Actuarial (gains) losses Past service gains millions of dollars DB Pension Plans: Balance, January 1, 2024 $ 324 $ 53 $ - Amortized in current period (9) (3) - Current year additions 19 (67) - Change in FX rate 29 - - Balance, December 31, 2024 $ 363 $ (17) $ - Non-pension benefits plans: Balance, January 1, 2024 $ 29 $ (8) $ (2) Amortized in current period 2 1 2 Current year reductions (5) (1) - Change in FX rate 3 - - Balance, December 31, 2024 $ 29 $ (8) $ - As at December 31 December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Actuarial (gains) losses $ (17) (8) $ 53 (8) Past service gains - - - (2) Deferred income tax expense 8 1 8 1 AOCI, net of tax (9) (7) 61 (9) Regulatory assets 363 29 324 29 AOCI, net of tax and regulatory assets $ 354 $ 22 $ 385 $ 20
Net Periodic Benefit Cost	As at Year ended December 31 millions of dollars 2024 2023 DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Service cost $ 35 $ 3 $ 30 $ 3 Interest cost 110 12 111 13 Expected return on plan assets (160) (2) (161) (2) Current year amortization of: 3 (2) 1 (3) - (2) - - 9 (2) 6 (2) Settlement, curtailments - 1 2 - Total $ (3) $ 8 $ (11) $ 9
Pension Plan Asset Allocations	Asset Class Target Canadian Pension Plans: Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 5% to 15% 37% to 61% Non-Canadian Pension Plans: Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68%
Fair Value of Plan Assets	millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2024 Cash and cash equivalents $ - $ 39 $ - $ 39 2 % Net in-transits - (27) - (27) (1) % Equity securities: - 109 - 109 4 % - 312 - 312 12 % - 140 - 140 5 % Fixed income securities: - - 132 132 5 % - - 92 92 4 % - - 22 22 1 % Mutual funds - 13 - 13 1 % Open-ended investments measured at NAV 1,142 - - 1,142 46 % Common collective trusts measured at NAV (2) 519 - - 519 21 % Total $ 1,661 $ 586 $ 246 $ 2,493 100 % As at December 31, 2023 Cash and cash equivalents $ - 40 - 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % (1) Net asset value ("NAV") investments are open-ended registered and non-registered or pooled funds. NAV’s are calculated at least monthly and the funds honour (2) The common collective trusts are private funds securities. Since the prices are not published to external primarily in equity securities of domestic and income assets and seeks to increase return through subscription and redemption activity regularly.
Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans	millions of dollars DB pension plans Non-pension benefit plans Expected employer contributions 2025 $ 41 $ 21 Expected benefit payments 2025 175 23 2026 179 23 2027 182 23 2028 184 23 2029 186 22 2030 – 2034 950 103
Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans	Assumptions: The following table shows the assumptions that have been post-retirement benefit plans: 2024 2023 (weighted average assumptions) DB pension plans Non-pension benefit plans DB pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 5.07 % 4.91 % 4.89 % 4.89 % Discount rate - future service 5.12 % 5.00 % 4.88 % 4.89 % Rate of compensation increase 3.73 % 3.72 % 3.87 % 3.85 % Health care trend - 6.53 % - 6.04 % - 3.77 % - 3.76 % 2044 2043 Benefit cost for year ended December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Expected long-term return on plan assets 6.43 % 3.69 % 6.56 % 2.16 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Actual assumptions used differ by plan.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2024
Goodwill [Abstract]
Change in Goodwill	23. GOODWILL The change in goodwill for the year ended December 31 millions of dollars 2024 2023 Balance, January 1 $ 5,871 $ 6,012 Change in FX rate 504 (141) Impairment charges (214) - Classified as assets held for sale (1) (303) - Balance, December 31 $ 5,858 $ 5,871 (1) As at December 31, 2024, NMGC's assets transaction, refer to note 4.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2024
Short-Term Debt [Abstract]
Short-Term Debt and Related Weighted-Average Interest Rates	millions of dollars 2024 Weighted average interest rate 2023 Weighted average interest rate Florida Electric Utility Advances on revolving credit facilities $ 915 4.77 % $ 277 5.68 % Gas Utilities and Infrastructure PGS – Advances on revolving credit facilities 199 5.36 % 73 6.36 % NMGC – Advances on revolving credit facilities 46 5.52 % 25 6.46 % Other Electric Utilities GBPC – Advances on revolving credit facilities 19 7.20 % 8 5.54 % Other TECO Finance – Advances on revolving credit and term facilities 265 5.53 % 245 6.54 % Emera – Bank indebtedness 2 - % 9 - % Emera – Non-revolving term facilities - - % 796 6.07 % $ 1,446 $ 1,433 Adjustment Classification as liabilities held for sale (1) (46) - Short-term debt $ 1,400 $ 1,433 (1) On August 5, 2024, Emera announced an agreement as held for sale. For further details on the pending The Company’s total short-term unsecured revolving borrowings and available capacity as at December 31 were millions of dollars Maturity 2024 2023 TEC – committed revolving credit facility 2028 $ 1,151 $ 401 TECO Finance – committed revolving credit facility 2028 576 529 PGS – revolving credit facility 2028 360 331 NMGC – revolving credit facility 2026 180 165 Emera – non-revolving term facility 2024 - 400 Emera – non-revolving term facility 2024 - 400 TEC – revolving facility 2024 - 265 TEC – revolving facility 2024 - 265 Other – committed revolving credit facilities Various 35 17 Total $ 2,302 $ 2,773 Less: Advances under revolving credit and term facilities 1,400 1,433 Letters of credit issued within the credit facilities 4 3 Total 1,404 1,436 Available capacity under existing agreements $ 898 $ 1,337

Other Current Liabilities (Tabl

Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
Other Current Liabilities
Components of Other Current Liabilities	As at December 31 December 31 millions of dollars 2024 2023 Accrued charges $ 189 $ 172 Accrued interest on long-term debt 106 107 Pension and post-retirement liabilities (note 22) 26 23 Sales and other taxes payable 11 11 Income tax payable 4 2 Other 153 112 $ 489 $ 427

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2024
Long-term Debt [Abstract]
Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity	Weighted average interest rate (1) millions of dollars 2024 2023 Maturity 2024 2023 Florida Electric Utility Senior unsecured notes 4.36% 4.61% 2029 - 2051 $ 5,720 $ 5,654 Canadian Electric Utilities NSPI – Commercial paper (2) Variable Variable 2029 $ 177 $ 721 NSPI – Senior unsecured notes 5.12% 5.13% 2025 - 2097 3,184 3,165 $ 3,361 $ 3,886 Gas Utilities and Infrastructure PGS – Senior unsecured notes 5.63% 5.63% 2028 - 2053 $ 1,331 $ 1,223 NMGC – Senior unsecured notes 3.78% 3.78% 2026 - 2051 698 642 NMGC – Unsecured loan notes N/A Variable 2024 - 30 NMGI – Senior unsecured notes N/A 3.64% 2024 - 198 EBP – Secured loan notes Variable Variable 2028 250 246 $ 2,279 $ 2,339 Other Electric Utilities Unsecured loan notes 4.06% 4.78% 2025 - 2028 $ 143 $ 121 Unsecured loan notes Variable Variable 2025 - 2027 104 104 Secured senior notes and debentures 2.38% 3.06% 2026 - 2040 169 197 $ 416 $ 422 Other Unsecured loan notes Variable Variable 2026 - 2029 $ 992 $ 465 Senior unsecured notes 3.99% 3.65% 2026 - 2046 3,525 3,637 Senior unsecured notes 4.84% 4.84% 2030 500 500 Fixed to floating subordinated notes 6.75% 6.75% 2076 1,727 1,587 Junior subordinated notes 7.63% 0.00% 2054 720 - $ 7,464 $ 6,189 Adjustments Debt issuance costs (137) (125) Classification as liabilities held for sale (5) (696) - Amount due within one year (234) (676) $ (1,067) $ (801) Long-Term Debt $ 18,173 $ 17,689 (1) Weighted average interest rate of fixed rate long-term debt. (2) Discount notes are backed by a revolving (3) Notes are issued and payable in either USD (4) In 2024, the Company recognized $ 110 109 subordinated notes. (5) On August 5, 2024, Emera announced an classified as held for sale. (6) Excludes NMGC amounts which are classified The Company’s total long-term revolving credit facilities, at December 31 were as follows: millions of dollars Maturity 2024 2023 Emera – committed revolving credit facility (1) June 2029 $ 1,300 $ 900 NSPI – revolving credit facility (1) June 2029 800 800 Emera – Unsecured non-revolving credit facility February 2026 200 400 TEC – Unsecured committed revolving credit facility December 2026 - 657 NSPI – non-revolving credit facility July 2024 - 400 NMGC – Unsecured non-revolving credit facility March 2024 - 30 ECI – revolving credit facilities October 2024 - 10 Total $ 2,300 $ 3,197 Less: Borrowings under credit facilities 1,169 1,884 Letters of credit issued inside credit facilities 12 6 Use of available facilities $ 1,181 $ 1,890 Available capacity under existing agreements $ 1,119 $ 1,307 (1) Advances on the revolving credit facility can be 50 As at Financial Covenant Requirement December 31, 2024 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.55
Long-Term Debt Maturities	millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Florida Electric Utility $ - $ - $ - $ - $ 720 $ 5,000 $ 5,720 Canadian Electric Utilities 125 40 - - 217 2,979 3,361 Gas Utilities and Infrastructure 31 132 31 535 31 1,519 2,279 Other Electric Utilities 78 101 89 116 4 28 416 Other - 3,006 - - 792 3,666 7,464 Total $ 234 $ 3,279 $ 120 $ 651 $ 1,764 $ 13,192 $ 19,240

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligations [Abstract]
Change in Asset Retirement Obligations	The change in ARO for the years ended December 31 millions of dollars 2024 2023 Balance, January 1 $ 192 $ 174 Additions 11 - Accretion included in depreciation expense 10 9 Change in FX rate 5 (1) Revisions in estimated cash flows 2 - Accretion deferred to regulatory asset (included in PP&E) - 18 Classified as assets held for sale (1) - Liabilities settled (2) (8) Balance, December 31 $ 217 $ 192 (1) As at December 31, 2024, NMGC's assets transaction, refer to note 4.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Summary of Contractual Commitments	millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Purchased power (1) $ 307 $ 277 $ 368 $ 368 $ 369 $ 4,487 $ 6,176 Transportation (2)(3) 742 545 544 454 412 3,228 5,925 Capital projects 604 287 24 - - - 915 Fuel, gas supply and storage (4) 591 94 21 5 - - 711 Other 160 95 80 59 59 264 717 $ 2,404 $ 1,298 $ 1,037 $ 886 $ 840 $ 7,979 $ 14,444 As detailed below, contractual obligations at December 31, 2024 includes NMGC, all remaining future contractual obligations will to note 4. (1) Annual requirement to purchase electricity production (2) Includes $ 86 30 24 16 12 4 (3) Purchasing commitments for transportation of $ 135 (4) Includes $ 177 109 52 13 3

Cumulative Preferred Stock (Tab

Cumulative Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2024
Cumulative Preferred Stock [Abstract]
Summary of Cumulative Preferred Stock	Authorized: Unlimited number of First Preferred shares, issuable in Unlimited number of Second Preferred shares, issuable in December 31, 2024 December 31, 2023 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 $ 1.6085 $ 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 $ 1.5810 $ 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) Annual Dividend Rate (%) 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) 2.182 0.5456 1.84 August 15, 2025 25.00 Series B 6.434 1.6085 2.65 August 15, 2028 25.00 Series D (5)(6) 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 6.324 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate (7) 4.500 1.1250 (8) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or (2) On or after the specified redemption dates, whole or in part, at the specified per share redemption redemption. (3) On the redemption and/or conversion option 25.00 by the annual fixed or floating dividend rate, Bond Yield on the applicable reset date, plus the applicable 4.90 cent) and for Series B equals the Government 1.84 (4) On each conversion option date, the holders equal number of Cumulative Redeemable the outstanding Preferred Shares, Series cash, in whole or in part at a price of 25.00 and $ 25.50 of redemptions on any other date after August Series I equals the Government of Treasury Bill Rate on 2.54 (5) On January 8, 2025, Emera announced the conversion period between January 15, right, at their option, to convert all or Series G on February 15, 2025. On February holders, no Series F were converted (6) On January 16, 2025, Emera announced 1.0505 1.4372 for the five-year period from and including (7) First Preferred Shares, Series E are redeemable 25.00 (8) First Preferred Shares, Series L are redeemable 26.00 0.25 year until November 15, 2030 and $ 25.00

Non-Controlling Interest in S_2

Non-Controlling Interest in Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2024
Non-Controlling Interest in Subsidiaries [Abstract]
Components of Non-Controlling Interest	30. NON-CONTROLLING INTEREST IN SUBSIDIARIES As at December 31 December 31 millions of dollars 2024 2023 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14
Preferred Shares of GBPC	Preferred shares of GBPC: Authorized: 10,000 2024 2023 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

Supplementary Information to _2

Supplementary Information to Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2024
Supplementary Information to Consolidated Statements of Cash Flows [Abstract]
Summary of Supplementary Information to Consolidated Statement of Cash Flows	For the Year ended December 31 millions of dollars 2024 2023 Changes in non-cash working capital: $ 38 $ (31) (1) (154) 653 536 (538) (2) 32 (179) Total $ 452 $ (95) (1) The year ended December 31, 2023, includes $ 162 regulatory liabilities is included in operating cash activities. (2) The year ended December 31, 2023, includes ($ 166 ) million related to the decreased accrual for and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included working capital resulting in no impact to net For the Year ended December 31 millions of dollars 2024 2023 Supplemental disclosure of cash paid: Interest $ 989 $ 930 Income taxes $ 34 $ 43 Supplemental disclosure of non-cash activities: Accrued proceeds from disposal of investment subject to significant influence $ 25 $ - Common share dividends reinvested $ 291 $ 271 Reclassification of short-term debt to long-term debt $ - $ 657 Decrease in accrued capital expenditures $ - $ (19) Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ (118) $ 123

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2024
Stock-Based Compensation [Abstract]
Weighted Average Fair Values per Stock Option and Assumptions for Options Granted	2024 2023 Weighted average FV per option $ 4.66 $ 6.32 Expected term (1) 5 5 Risk-free interest rate (2) 3.56 % 3.53 % Expected dividend yield (3) 6.11 % 5.05 % Expected volatility (4) 20.67 % 20.07 % (1) The expected term of the option awards is that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government (3) Incorporates current dividend rates and historical (4) Estimated using the five-year historical volatility.
Summary of Stock Option Information	Total Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Granted 792,600 46.97 792,600 4.66 Exercised (78,839) 39.86 N/A N/A Forfeited (13,325) 56.14 - N/A Vested N/A N/A (438,365) 4.58 Options outstanding December 31, 2024 3,796,040 $ 50.53 1,607,490 $ 5.08 Options exercisable December 31, 2024 (2)(3) 2,188,550 $ 50.07 (1) As at December 31, 2024, there was $ 6 expected to be recognized over a weighted 3 5 3 (2) As at December 31, 2024, the weighted 4 $ 11 5 8 (3) As at December 31, 2024, the FV of options 2 2
Summary of Activity Related to Employee and Director Deferred Share Units	Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 Granted including DRIP 86,417 45.20 134,795 48.98 Exercised (10,292) 38.77 (34,997) 36.04 Outstanding and exercisable as at December 31, 2024 789,088 $ 42.65 828,856 $ 47.12
Summary of Activity Related to Employee Performance Share Units	Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 Granted including DRIP 354,793 48.69 Exercised (253,136) 54.66 Forfeited (12,929) 52.53 Outstanding as at December 31, 2024 832,093 $ 52.57 $ 50
Summary of Activity Related to Employee Restricted Share Units	Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 Granted including DRIP 287,976 48.65 Exercised (183,241) 54.66 Forfeited (14,228) 52.45 Outstanding as at December 31, 2024 653,148 $ 52.36 $ 41

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2024
Variable Interest Entities [Abstract]
Summary of Material Unconsolidated Variable Interest Entities	As at December 31, 2024 December 31, 2023 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 475 $ 6 $ 489 $ 6

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions		12 Months Ended
	Jun. 04, 2024	Dec. 31, 2024 CAD ($) MW Customers km
Labrador-Island Link Limited Partnership
Nature of operations [Line items]
Percent of equity interest sold	31.10%
Operating | Canadian Electric Utilities | NSP Maritime Link Inc Project
Nature of operations [Line items]
Public Utilities, Equipment, Transmission and Distribution | $		$ 1.8
100% ownership		100%
Labrador-Island Link Limited Partnership | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		0%
Maritimes and Northeast Pipeline | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		12.90%
Maritimes and Northeast Pipeline | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
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%
Bear Swamp Power Company LLC | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		50%
Public Utilities Property Plant And Equipment Generation Capacity | MW		660
Tampa Electric | Operating | Florida Electric Utility
Nature of operations [Line items]
Number of Customers		855,000
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Number of Customers		557,000
Barbados Light and Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers		135,000
Grand Bahama Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers		19,500
Peoples Gas System Division | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers		508,000
New Mexico Gas Company | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers		550,000
Emera Brunswick Pipeline Company Limited
Nature of operations [Line items]
Length Of Pipeline | km		145
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Nature of operations [Line items]
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		25 years
Emera Energy | Bear Swamp Power Company LLC | Other
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage		50%
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 II) (Details) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2024 CAD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2024 CAD ($) Item	Dec. 31, 2024 USD ($) Item	Dec. 31, 2023 CAD ($)	Aug. 05, 2024 CAD ($)	Dec. 31, 2022 CAD ($)
Asset Impairment Charges
Impairment charge			$ 225,000,000		$ 0
Goodwill
Goodwill			5,858,000,000		5,871,000,000		$ 6,012,000,000
Goodwill impairment charge			$ 214,000,000		0
Lease, Practical Expedient, Lessor Single Lease Component [true false]			true
New Mexico Gas Company [Member]
Goodwill
Goodwill						$ 366,000,000
Goodwill impairment charge	$ 210,000,000	$ 155	$ 210,000,000	$ 155
Goodwill impairment charge, net of tax	198,000,000	$ 146	198,000,000	$ 146
Various Canadian And US Government Agencies [Member]
Goodwill
Amount received from government funds			$ 47,000,000		$ 7,000,000
Government Assistance Asset Increase Noncurrent Statement Of Financial Position Extensible Enumeration			Property, Plant and Equipment, Net	Property, Plant and Equipment, Net	Property, Plant and Equipment, Net
Natural Resources Canada Smart Renewables & Electrification Pathways [Member]
Goodwill
Number of battery storage systems funded for construction | Item			3	3
Percent under grant for claims of eligible project costs			33%	33%
Maximum project costs eligible under grant for claims			$ 109,000,000
Amount received from government funds			$ 26,000,000
Government Assistance Asset Increase Noncurrent Statement Of Financial Position Extensible Enumeration			Property, Plant and Equipment, Net	Property, Plant and Equipment, Net	Property, Plant and Equipment, Net
Long-Lived Assets
Asset Impairment Charges
Impairment charge			$ 11,000,000		$ 0
Certain Long Lived Assets
Asset Impairment Charges
Impairment charge			19,000,000
Asset Impairment Charges, net of tax			14,000,000
Included In Other Income, Net
Asset Impairment Charges
Impairment charge			8,000,000
Equity Method Investments
Asset Impairment Charges
Impairment charge			0		0
Financial Assets
Asset Impairment Charges
Impairment charge			0		$ 0
NMGC
Goodwill
Goodwill	303,000,000		$ 303,000,000
Goodwill impairment charge	$ 210,000,000

Dispositions (Narrative) (Detai

Dispositions (Narrative) (Details) $ in Millions, $ in Millions		3 Months Ended				5 Months Ended		12 Months Ended
	Jun. 04, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Sep. 30, 2024 CAD ($)	Sep. 30, 2024 USD ($)	Jun. 30, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Aug. 05, 2024 CAD ($)	Dec. 31, 2022 CAD ($)
Details of the assets and liabilities classified as held for sale [Line items]
Goodwill		$ 5,858				$ 5,858		$ 5,858		$ 5,871		$ 6,012
Goodwill impairment charge								214		$ 0
NMGC
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Value											$ 1,300
Goodwill											$ 366
Goodwill impairment charge			$ 210	$ 155				210	$ 155
Goodwill impairment charge, net of tax			198	$ 146				198	$ 146
Estimated future transaction costs			16
Estimated future transaction costs, net of tax			12
Incurred transaction costs			9
Incurred transaction costs, net of tax			$ 7
Depreciation and amortization						26	$ 19
LIL
Details of the assets and liabilities classified as held for sale [Line items]
Disposition, Value	$ 1,200
Proceeds on disposition of business	$ 957
Percent of equity interest sold	31.10%
Amount of contractual obligation to fund the remaining initial capital investment	$ 235
Cash proceeds held in escrow	$ 30
Escrow proceeds receivable		25				$ 25		$ 25
Disposition, gain on disposition					$ 182
Disposition, gain on disposition, net of tax					$ 107
Tax benefit due to reversal of a prior year valuation allowance related to loss carryforwards		$ 22

Dispositions (Details of Assets

Dispositions (Details of Assets and Liabilities Classified as Held for Sale) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	$ 8	$ 0
Current assets held for sale	173	0
Long-term assets held for sale	2,160	0
Current liabilities associated with assets held for sale	212	0
Long-term debt	696	0
Long-term liabilities associated with assets held for sale	1,148	$ 0
NMGC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	8
Inventory	9
Derivative instruments	1
Regulatory assets	28
Receivables and other current assets	127
Current assets held for sale	173
Property, plant and equipment	1,828
Regulatory assets	6
Goodwill	303
Other long-term assets	23
Long-term assets held for sale	2,160
Total assets held for sale	2,333
Short-term debt	46
Derivative instrument	1
Regulatory liabilities	10
Accounts payable and other current liabilities	155
Current liabilities associated with assets held for sale	212
Long-term debt	696
Deferred income taxes	167
Regulatory liabilities	274
Other long-term liabilities	11
Long-term liabilities associated with assets held for sale	1,148
Total liabilities associated with assets held for sale	$ 1,360

Segment Information (Segment In

Segment Information (Segment Information) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 7,200	$ 7,563
OM&G	1,918	1,879
Provincial, state and municipal taxes	427	433
Depreciation and amortization	1,162	1,049
Impairment charges	225	0
Income from equity investments	99	146
Other income (expenses), net	203	158
Interest expense, net	973	925
Income tax expense (recovery)	(159)	128
NCI in subsidiaries	1	1
Preferred stock dividends	73	66
Net income (loss) attributable to common shareholders	493.6	977.7
Capital expenditures	3,127	2,921
Segment Reporting Information, As at December 31
Total assets	42,951	39,480
Investments subject to significant influence	654	1,402
Goodwill	5,858	5,871	$ 6,012
Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Total operating revenues	5,872	5,746
Fuel for generation and purchased power	1,992	1,881
Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,575	1,489
Fuel for generation and purchased power	396	527
Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,451	3,548
Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,855	1,671
Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,595	1,510
Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	566	526
Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	(267)	308
Operating
Segment Reporting Information, For the year ended December 31
Total operating revenues	7,200	7,563
Operating | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,460	3,556
OM&G	779	830
Provincial, state and municipal taxes	273	289
Depreciation and amortization	622	571
Impairment charges	0
Income from equity investments	0	0
Other income (expenses), net	66	69
Interest expense, net	265	271
Income tax expense (recovery)	94	117
NCI in subsidiaries	0	0
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	641	627
Capital expenditures	1,942	1,736
Segment Reporting Information, As at December 31
Total assets	24,375	21,119
Investments subject to significant influence	0	0
Goodwill	5,035	4,628
Operating | Florida Electric Utility | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	852	920
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	1,855	1,671
OM&G	408	384
Provincial, state and municipal taxes	48	45
Depreciation and amortization	282	276
Impairment charges	0
Income from equity investments	73	109
Other income (expenses), net	28	32
Interest expense, net	168	170
Income tax expense (recovery)	(41)	(9)
NCI in subsidiaries	0	0
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	232	247
Capital expenditures	481	450
Segment Reporting Information, As at December 31
Total assets	7,609	8,634
Investments subject to significant influence	475	1,236
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	859	699
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	1,609	1,524
OM&G	454	405
Provincial, state and municipal taxes	103	91
Depreciation and amortization	182	126
Impairment charges	11
Income from equity investments	20	21
Other income (expenses), net	16	11
Interest expense, net	151	129
Income tax expense (recovery)	89	64
NCI in subsidiaries	0	0
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	259	214
Capital expenditures	619	664
Segment Reporting Information, As at December 31
Total assets	8,439	7,735
Investments subject to significant influence	124	118
Goodwill	823	1,240
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	396	527
Operating | Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	566	526
OM&G	143	130
Provincial, state and municipal taxes	3	3
Depreciation and amortization	69	68
Impairment charges	0
Income from equity investments	4	4
Other income (expenses), net	12	7
Interest expense, net	22	23
Income tax expense (recovery)	1	0
NCI in subsidiaries	1	1
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	48	37
Capital expenditures	81	63
Segment Reporting Information, As at December 31
Total assets	1,444	1,311
Investments subject to significant influence	55	48
Goodwill	0	0
Operating | Other Electric Utilities | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	295	275
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	(248)	339
OM&G	154	151
Provincial, state and municipal taxes	0	5
Depreciation and amortization	7	8
Impairment charges	214
Income from equity investments	2	12
Other income (expenses), net	73	20
Interest expense, net	367	332
Income tax expense (recovery)	(302)	(44)
NCI in subsidiaries	0	0
Preferred stock dividends	73	66
Net income (loss) attributable to common shareholders	(686)	(147)
Capital expenditures	4	8
Segment Reporting Information, As at December 31
Total assets	1,810	1,938
Investments subject to significant influence	0	0
Goodwill	0	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	(42)	(53)
OM&G	(20)	(21)
Provincial, state and municipal taxes	0	0
Depreciation and amortization	0	0
Impairment charges	0
Income from equity investments	0	0
Other income (expenses), net	8	19
Interest expense, net	0	0
Income tax expense (recovery)	0	0
NCI in subsidiaries	0	0
Preferred stock dividends	0	0
Net income (loss) attributable to common shareholders	0	0
Capital expenditures	0	0
Segment Reporting Information, As at December 31
Total assets	(726)	(1,257)
Investments subject to significant influence	0	0
Goodwill	0	0
Financing costs	29	95
Intersegment Eliminations | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	(14)	(13)
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	(42)	(53)
Eliminations | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	9	8
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	14	14
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	$ 19	$ 31

Segment Information (Geographic

Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 7,200	$ 7,563
Property, Plant and Equipment, Net	26,168	24,376
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	4,712	5,310
Property, Plant and Equipment, Net	20,084	18,588
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	1,922	1,727
Property, Plant and Equipment, Net	5,068	4,878
Barbados
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	427	389
Property, Plant and Equipment, Net	645	576
The Bahamas
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	139	137
Property, Plant and Equipment, Net	$ 371	$ 334

Segment Information (Narrative)

Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2024
Segment Information [Abstract]
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 (“CODM”). Emera’s CODM is the Chief Executive Officer. For the Company’s reportable segments, the CODM uses several measures to allocate capital and resources for each segment, predominantly in the annual budget and forecasting processes. The CODM evaluates segment performance by considering budget-to-actual variances for these measures monthly. The measure used by the CODM that is the most consistent with USGAAP measurement principles is net income attributable to common shareholders.

Revenue (Disaggregation of Reve

Revenue (Disaggregation of Revenue by Major Source) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 7,200	$ 7,563
Total operating revenues	7,200	7,563
Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	3,451	3,548
Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1,855	1,671
Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	566	526
Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1,595	1,510
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	(267)	308
Operating
Disaggregation of Revenue [Line Items]
Total operating revenues	7,200	7,563
Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,460	3,556
Total operating revenues	3,460	3,556
Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,855	1,671
Total operating revenues	1,855	1,671
Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	566	526
Total operating revenues	566	526
Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,609	1,524
Total operating revenues	1,609	1,524
Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(248)	339
Total operating revenues	(248)	339
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(42)	(53)
Total operating revenues	(42)	(53)
Eliminations | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	9	8
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	14	14
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	19	31
Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7,447	7,235
Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,460	3,556
Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,855	1,671
Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	566	526
Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,589	1,503
Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(23)	(21)
Regulated | Other Electric And Regulatory
Disaggregation of Revenue [Line Items]
Total operating revenues	290	254
Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(247)	328
Total operating revenues	(247)	328
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	20	21
Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(248)	339
Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(19)	(32)
Electric Revenue | Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	5,872	5,746
Electric Revenue | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,975	4,124
Electric Revenue | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,063	2,307
Electric Revenue | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	997	910
Electric Revenue | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	203	183
Electric Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	712	724
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	2,234	2,256
Electric Revenue | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	939	1,083
Electric Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	499	463
Electric Revenue | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	300	285
Electric Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	496	425
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	607	606
Electric Revenue | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	223	274
Electric Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	276	219
Electric Revenue | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	28	33
Electric Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	94	93
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	(14)	(13)
Electric Revenue | Regulated | Other Electric
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	420	443
Electric Revenue | Regulated | Other Electric | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	372	395
Electric Revenue | Regulated | Other Electric | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	41	41
Electric Revenue | Regulated | Other Electric | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7	7
Electric Revenue | Regulated | Other Electric | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(142)	(510)
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(157)	(522)
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	15	12
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	20	19
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	42	38
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	13	6
Gas Revenue | Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	1,575	1,489
Gas Revenue | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	224	199
Marketing and trading margin | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	77	96
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	77	96
Marketing and trading margin | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Finance Income | Regulated | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	63	62
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	63	62
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 revenue | Regulated | Other Electric And Regulatory | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Other revenue | Regulated | Other Electric And Regulatory | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(9)	(8)
Other revenue | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	28	25
Other revenue | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	20	21
Other revenue | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	32	27
Other revenue | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(24)	(23)
Mark-To-Market | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	(352)	207
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	(357)	216
Mark-To-Market | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	$ 5	$ (9)

Revenue (Remaining Performance

Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 495	$ 488
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year)	2044
New Mexico Gas Company [Member]
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 3
SeaCoast Gas Transmission, LLC | PGS
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 135
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year)	2040

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 595	$ 339
Regulatory Assets, Long-term	2,832	2,766
Total regulatory assets	3,427	3,105
Deferred income tax regulatory assets
Regulatory Assets [Line Items]
Total regulatory assets	1,227	1,233
TEC capital cost recovery for early retired assets
Regulatory Assets [Line Items]
Total regulatory assets	737	671
Storm cost recovery clauses
Regulatory Assets [Line Items]
Total regulatory assets	613	52
Pension and post-retirement medical plan
Regulatory Assets [Line Items]
Total regulatory assets	395	364
TEC capital cost recovery for retired Polk Unit 1 components
Regulatory Assets [Line Items]
Total regulatory assets	205	0
Deferrals related to derivative instruments
Regulatory Assets [Line Items]
Total regulatory assets	42	88
Cost recovery clauses
Regulatory Assets [Line Items]
Total regulatory assets	33	151
Environmental remediations
Regulatory Assets [Line Items]
Total regulatory assets	29	26
Stranded cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	27	25
NSPI FAM
Regulatory Assets [Line Items]
Total regulatory assets	0	395
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 119	$ 100

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 262	$ 168
Regulatory Liability, Long-term	1,618	1,604
Total regulatory liabilities	1,880	1,772
Deferred income tax regulatory liabilities
Regulatory Liabilities [Line Items]
Total regulatory liabilities	828	830
Accumulated reserve - COR
Regulatory Liabilities [Line Items]
Total regulatory liabilities	733	849
Cost recovery clauses
Regulatory Liabilities [Line Items]
Total regulatory liabilities	121	32
NSPI FAM | Regulated
Regulatory Liabilities [Line Items]
Total regulatory liabilities	56	0
Deferrals related to derivative instruments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	44	17
BLPC Self-insurance fund ("SIF")
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	29
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 66	$ 15

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2022 USD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)
TEC capital cost recovery for retired Polk Unit 1 components
Public Utilities, General Disclosures [Line Items]
Recovery Period			11 years	11 years
GBPC | Steam turbine
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment				$ 21
NSPI
Public Utilities, General Disclosures [Line Items]
Storm cost			$ 10		$ 10
NSPI | Forecast
Public Utilities, General Disclosures [Line Items]
Storm cost		$ 10
Tampa Electric
Public Utilities, General Disclosures [Line Items]
Storm cost	$ 119
Recovery Period			15 years	15 years

Regulatory Assets and Liabili_6

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

1 Months Ended

12 Months Ended

Dec. 03, 2024 USD ($)

May 07, 2024 USD ($)

Nov. 17, 2023 USD ($)

Mar. 07, 2023 USD ($)

Sep. 30, 2022 USD ($)

Dec. 31, 2024 USD ($)

Dec. 31, 2023 USD ($)

Dec. 31, 2024 CAD ($)

Dec. 31, 2024 USD ($)

Dec. 31, 2023 CAD ($)

Aug. 16, 2023 USD ($)

Jan. 23, 2023 USD ($)

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 3,427

$ 3,105

Cost recovery clauses

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 33

$ 151

TEC

Public Utilities, General Disclosures [Line Items]

Allowed equity capital structure

54%

Approved rate increase (decrease)

$ 22

Storm cost

$ 119

TEC | 2025

Public Utilities, General Disclosures [Line Items]

Allowed equity capital structure

54%

TEC | 2026

Public Utilities, General Disclosures [Line Items]

Allowed equity capital structure

54%

TEC | 2027

Public Utilities, General Disclosures [Line Items]

Allowed equity capital structure

54%

TEC | Base rate | 2025

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ 185

TEC | Base rate | 2026

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

87

TEC | Base rate | 2027

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ 9

TEC | Cost recovery clauses

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.20%

10.20%

TEC | Fuel | 2023

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ (170)

TEC | Fuel | Starting April 1, 2023

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ (518)

Recovery period

21 months

TEC | Fuel | June 2024 to May 2025

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ (138)

Recovery period

12 months

TEC | Hurricane Helene

Public Utilities, General Disclosures [Line Items]

Storm reserve

$ 49

TEC | Hurricane Milton

Public Utilities, General Disclosures [Line Items]

Storm reserve

340

TEC | Storm reserve

Public Utilities, General Disclosures [Line Items]

Approved rate increase (decrease)

$ 466

Storm reserve

$ 56

Regulatory assets

$ 377

$ 134

$ 131

Storm cost

$ 29

TEC | Minimum

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.25%

9.25%

TEC | Minimum | 2025

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.50%

TEC | Minimum | 2026

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.50%

TEC | Minimum | 2027

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.50%

TEC | Maximum

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11.25%

11.25%

TEC | Maximum | 2025

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11.50%

TEC | Maximum | 2026

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11.50%

TEC | Maximum | 2027

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

11.50%

TEC | Midpoint | 2025

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.50%

TEC | Midpoint | 2026

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.50%

TEC | Midpoint | 2027

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

10.50%

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) - CAD ($)

12 Months Ended

24 Months Ended

Jun. 27, 2024

Apr. 30, 2024

Apr. 17, 2024

Jul. 05, 2023

Aug. 15, 2021

Dec. 31, 2024

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2023

Nov. 29, 2024

Sep. 24, 2024

Dec. 21, 2023

Mar. 31, 2023

Public Utilities, General Disclosures [Line Items]

Contractual Obligation, to be Paid, Year One

$ 2,404,000,000

NSPI

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage

6.50%

6.90%

Storm cost

$ 10,000,000

$ 10,000,000

NSPI | Nova Scotia Cap-and-Trade ("Cap-and-Trade") Program

Public Utilities, General Disclosures [Line Items]

Gas costs

$ 166,000,000

Credits purchased from provincial auctions

$ 6,000,000

6,000,000

Compliance costs accrued

$ (166,000,000)

NSPI | Fuel

Public Utilities, General Disclosures [Line Items]

Approved payment in period

$ 117,000,000

Holdback payable

$ 117,000,000

Amortization and financing costs

$ 117,000,000

Collection period of amortization and financing costs

10 years

NSPI | NSP Maritime Link Inc.

Public Utilities, General Disclosures [Line Items]

Federal loan guarantee issued amount

$ 500,000,000

$ 500,000,000

Recovery period for federal loan guarantee related financing costs

28 years

Storm cost

$ 24,000,000

Costs recovery period

12 months

NSPI | Range, Minimum

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

8.75%

8.75%

NSPI | Range, Maximum

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.25%

9.25%

Regulated common equity component

40%

NSPI | NSPI FAM

Public Utilities, General Disclosures [Line Items]

Increase to regulatory assets

$ 51,000,000

NSPI | UARB

Public Utilities, General Disclosures [Line Items]

Costs recovery period

10 years

Amount approved to defer operating costs incurred from storm restoration

$ 25,000,000

Amount reclassified from other long term assets to regulatory assets

25,000,000

Amount reclassified from undepreciated costs to regulatory assets

$ 10,000,000

NSPI | UARB | NSP Maritime Link Inc.

Public Utilities, General Disclosures [Line Items]

Estimate of possible percentage of receiving deliveries

90%

Emera Newfoundland and Labrador Holdings Inc.

Public Utilities, General Disclosures [Line Items]

Contractual Obligation, to be Paid, Year One

$ 197,000,000

Emera Newfoundland and Labrador Holdings Inc. | Debt and Financing Costs [Member]

Public Utilities, General Disclosures [Line Items]

Contractual Obligation, to be Paid, Year One

39,000,000

Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc.

Public Utilities, General Disclosures [Line Items]

Equity ratio

30%

Holdback payable

$ 0

$ 4,000,000

Contractual Obligation, to be Paid, Year One

$ 158,000,000

$ 164,000,000

Energy Delivery Commitments and Contracts, Term

35 years

Emera Newfoundland and Labrador Holdings Inc. | Range, Minimum | 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 | NSP Maritime Link Inc.

Public Utilities, General Disclosures [Line Items]

Approved regulated return on equity

9.25%

Emera Newfoundland and Labrador Holdings Inc. | UARB | NSP Maritime Link Inc.

Public Utilities, General Disclosures [Line Items]

Holdback payable

4,000,000

8,000,000

$ 12,000,000

Monthly holdback amount

$ 4,000,000

$ 2,000,000

Percent of contracted annual amount

10%

Regulatory Assets and Liabili_8

Regulatory Assets and Liabilities - Gas Utilities and Infrastructure (Narrative) (Details) $ in Millions			12 Months Ended
	Mar. 01, 2024 CAD ($)	Nov. 09, 2023	Dec. 31, 2024 CAD ($) km
Emera Brunswick Pipeline Company Limited
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km			145
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life			25 years
NMGC
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity	9.375%		9.375%
Allowed equity capital structure			52%
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 30
PGS
Public Utilities, General Disclosures [Line Items]
Allowed equity capital structure			54.70%
PGS | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Capitalized Costs Recovered			$ 11
Public Utilities, Approved Rate Increase (Decrease), Amount			118
PGS | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Allowed equity capital structure		54.70%
Phase-in Plan, Amount of Capitalized Costs Recovered			$ 107
PGS | Range, Minimum
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			9.15%
PGS | Range, Maximum
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			11.15%
PGS | Midpoint
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			10.15%
PGS | Midpoint | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		10.15%

Regulatory Assets and Liabili_9

Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions		1 Months Ended	12 Months Ended
	May 06, 2024 MW	Sep. 30, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Jul. 18, 2024 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities			$ 1,880	$ 1,772
Barbados Light and Power Company Limited
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			10%	10%
Barbados Light and Power Company Limited | Fair Trading Commission
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		11.75%
Allowed equity capital structure		55%
Deferred Tax Liabilities, Regulatory Assets and Liabilities					$ 5
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 1
Regulatory liabilities		$ 71
New corporate income tax rate			9%
Approved capacity for recovery of battery storage | MW	15
GBPC | Electric Transmission
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			8.52%	8.32%

Investments Subject to Signif_3

Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 654	$ 1,402
Income (loss) from equity investments and subsidiaries	99	146
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	910	820
Canadian Electric Utilities [Member] | Operating Segments [Member]
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments and subsidiaries	$ 73	109
NSP Maritime Link Inc Project | Canadian Electric Utilities [Member] | Operating Segments [Member]
Schedule of Equity Method Investments [Line Items]
100% ownership	100%
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 654	1,402
Income (loss) from equity investments and subsidiaries	99	146
Equity Method Investee | Emera Inc.
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	9
NSPML | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	475	489
Income (loss) from equity investments and subsidiaries	44	46
M&NP | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	124	118
Income (loss) from equity investments and subsidiaries	$ 20	21
Percentage of Ownership	12.90%
Lucelec | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 55	48
Income (loss) from equity investments and subsidiaries	$ 4	4
Percentage of Ownership	19.50%
LIL | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 0	747
Income (loss) from equity investments and subsidiaries	$ 29	63
Percentage of Ownership	0%
Bear Swamp
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	$ 92	81	$ 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	$ 2	$ 12
Percentage of Ownership	50%

Investments Subject to Signif_4

Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence - NSPML) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Balance Sheets
Current assets	$ 3,688	$ 3,708
Property, plant and equipment	26,168	24,376
Regulatory assets	2,832	2,766
Non-current assets	13,095	11,396
Total assets	42,951	39,480
Current liabilities	5,115	4,544
Non-current liabilities	24,545	22,848
Equity	13,291	12,088	$ 11,441
Total liabilities and equity	42,951	39,480
Canadian Electric Utilities [Member] | Operating Segments [Member]
Balance Sheets
Total assets	7,609	8,634
Variable Interest Entity, Not Primary Beneficiary | NSP Maritime Link Inc. [Member]
Balance Sheets
Current assets	37	21
Property, plant and equipment	1,425	1,473
Regulatory assets	778	272
Non-current assets	27	29
Total assets	2,267	1,795
Current liabilities	55	48
Long-term debt	1,570	1,109
Non-current liabilities	167	149
Equity	475	489
Total liabilities and equity	2,267	$ 1,795
Variable Interest Entity, Not Primary Beneficiary | NSP Maritime Link Inc. [Member] | Bond Under Federal Loan Guarantee [Member]
Balance Sheets
Long-term debt	500
Nova Scotia Power Inc. [Member] | Canadian Electric Utilities [Member] | NSP Maritime Link Inc. [Member] | Operating Segments [Member]
Balance Sheets
Approval to create regulatory asset for federal loan guarantee debt	$ 500

Other Income, Net (Components o

Other Income, Net (Components of Other Expense, Net) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Other Income, Net [Abstract]
Gain on sale of LIL, net of transaction costs	$ 182	$ 0
AFUDC	53	38
Pension non-current service cost recovery	35	35
Interest income	23	43
Transaction costs related to the pending sale of NMGC	(25)	0
Charges related to wind-down costs and certain asset impairments	(29)	0
FX (losses) gains	(58)	20
Other	22	22
Other income, net	$ 203	$ 158

Interest Expense, Net (Componen

Interest Expense, Net (Components of Interest Expense, Net) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Interest Expense, Net [Abstract]
Interest on debt	$ 1,004	$ 954
Allowance for borrowed funds used during construction	(23)	(16)
Other	(8)	(13)
Interest expense, net	$ 973	$ 925

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Effective Income Tax Rate) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 21, 2023
Income before provision for income taxes	$ 409	$ 1,173
Statutory income tax rate	29%	29%
Income taxes, at statutory income tax rates	$ 119	$ 340
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(90)	(72)
Interest and financing expenses	(58)	0
Valuation allowance	(58)	3
Tax credits	(57)	(53)
Goodwill impairment charge	49	0
Amortization of deferred income tax regulatory liabilities	(36)	(33)
Foreign tax rate variance	(31)	(36)
Additional impact from the sale of LIL equity interest	22	0
Tax effect of equity earnings	(14)	(15)
Manufacturing allowance	(9)	(8)
Other	4	2
Income tax (recovery) expense	$ (159)	$ 128
Effective income tax rate	(39.00%)	11%
Regulatory Liabilities	$ 1,880	$ 1,772
Interest and financing expenses	185
Other interest and financing expenses	88
Deferred tax asset, interest and financing expenses	79
Foreign Tax Authority [Member]
Income before provision for income taxes	$ 203	$ 964
Barbados
Statutory income tax rate	9%
Incremental tax benefits payable to customers [Member]
Regulatory Liabilities	$ 30		$ 82

Income Taxes (Composition of Ta

Income Taxes (Composition of Taxes on Income from Continuing Operations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ (191)	$ 97
Income tax expense	(159)	128
Canada
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	29	26
Deferred income taxes	(200)	93
Adjustments to valuation allowance	(61)	0
Operating loss carry forwards	(4)	(93)
United States
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	4	5
Deferred income taxes	155	128
Investment tax credits	(6)	(29)
Operating loss carry forwards	$ (76)	$ (2)

Income Taxes (Composition of In

Income Taxes (Composition of Income Before Provision for Income Taxes) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	$ 409	$ 1,173
Canada
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	156	171
United States
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	203	964
Other
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	$ 50	$ 38

Income Taxes (Schedule of Defer

Income Taxes (Schedule of Deferred Income Tax Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred income tax assets:
Tax loss carryforwards	$ 1,118	$ 1,195
Tax credit carryforwards	534	454
Regulatory liabilities	144	205
Derivative instruments	225	175
Other	462	372
Total deferred income tax assets before valuation allowance	2,483	2,401
Valuation allowance	(322)	(363)
Total deferred income tax assets after valuation allowance	2,161	2,038
Deferred income tax liabilities:
PP&E	(3,421)	(3,223)
Regulatory assets	(46)	(216)
Derivative instruments	(198)	(196)
Investments subject to significant influence	(105)	(235)
Other	(330)	(312)
Total deferred income tax liabilities	(4,100)	(4,182)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets	392	208
Long-term deferred income tax liabilities	(2,331)	(2,352)
Net deferred income tax liabilities	$ (1,939)	$ (2,144)

Income Taxes (Net Operating Los

Income Taxes (Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)
Canada | Capital loss
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 55
Subject to Valuation Allowance	(55)
Net Tax Credit Carryforwards	$ 0
Expiration period	Indefinite
Canada | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2,420
Subject to Valuation Allowance	(967)
Net Tax Credit Carryforwards	$ 1,453
Expiration period	2026 - 2044
Canada | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2
Subject to Valuation Allowance	(1)
Net Tax Credit Carryforwards	$ 1
Expiration period	2028 - 2042
United States | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,587
Subject to Valuation Allowance	(1)
Net Tax Credit Carryforwards	$ 1,586
Expiration period	2036 - Indefinite
United States | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 533
Subject to Valuation Allowance	(3)
Net Tax Credit Carryforwards	$ 530
Expiration period	2025 - 2044
State | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,351
Subject to Valuation Allowance	(1)
Net Tax Credit Carryforwards	$ 1,350
Expiration period	2026 - Indefinite
Other | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 91
Subject to Valuation Allowance	(23)
Net Tax Credit Carryforwards	$ 68
Expiration period	2025 - 2031

Income Taxes (Details of Change

Income Taxes (Details of Change in Unrecognized Tax Benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 37	$ 33
Increases due to tax positions related to current year	6	5
Increases due to tax positions related to a prior year	2	1
Decreases due to tax positions related to a prior year	(3)	(2)
Balance, December 31	$ 42	$ 37

Income Taxes (Unrecognized tax

Income Taxes (Unrecognized tax benefits) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change	$ 4,700,000,000	$ 4,700,000,000
Net amount in dispute	126,000,000	126,000,000
Prepaid amount in dispute	55,000,000	55,000,000
Tax benefit primarily due to utilization of certain loss carryforwards	58,000,000
Deferred Tax Assets, Allowance	322,000,000	363,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Amount that could affect effective tax rate	42,000,000	37,000,000
Accrued interest	10,000,000	9,000,000
Income Tax Examination, Interest Expense	1,000,000	$ 2,000,000
Accrued penalties	$ 0

Common Stock (Summary of Issued

Common Stock (Summary of Issued and Outstanding Common Stock) (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 8,462
Issuance of common stock	261	$ 397
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	30	32
Ending Balance	9,042	8,462
Common Stock
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	8,462	7,762
Issuance of common stock	261	397
Issued under Purchase Plans at market rate	291	272
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	28	31
Ending Balance	$ 9,042	$ 8,462
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	284,120	269,950
Issuance of common stock (shares)	5,120	8,290
Issued under Purchase Plans at market rate	6,100	5,260
Options exercised under senior management share option plan	600	620
Ending Balance	295,940	284,120

Common Stock (Narrative) (Detai

Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Gross proceeds from Issuance of Common Stock	$ 284	$ 424
Percentage of outstanding stock maximum	10%
Common Stock
Debt Instrument [Line Items]
Issuance of common stock (shares)	5,120,000	8,290,000
ATM Program
Debt Instrument [Line Items]
Maximum common stock issued from treasury amount	$ 1
ATM Program | Common Stock
Debt Instrument [Line Items]
Remaining available authorized amount for issuance	$ 336
Issuance of common stock (shares)	5,117,273	8,287,037
Gross proceeds from Issuance of Common Stock	$ 264	$ 400
Net proceeds from issuance of common stock	$ 261	$ 397
Average price per share, issued	$ 51.52	$ 48.27
Employee Stock Option Plan
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	6,000,000	6,000,000
Share Unit Plans
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	2,000,000	2,000,000
Dividend Reinvestment
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	12,000,000	18,000,000

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, 2024	Dec. 31, 2023
Numerator
Net income attributable to common shareholders	$ 493.6	$ 977.7
Diluted numerator	$ 493.6	$ 977.7
Denominator
Weighted average shares of common stock outstanding - basic	289.1	273.6
Stock-based compensation	0.1	0.2
Weighted average shares of common stock outstanding- diluted	289.2	273.8
Earnings per common share
Basic	$ 1.71	$ 3.57
Diluted	$ 1.71	$ 3.57

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	$ 12,088	$ 11,441
Net current period OCI	956	(273)
Ending Balance	13,291	12,088
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	305	578
OCI before reclassifications	890	(232)
Amounts reclassified from AOCI	66	(41)
Net current period OCI	956	(273)
Ending Balance	1,261	305
Unrealized gain (loss) on translation of self-sustaining foreign operations
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	369	639
OCI before reclassifications	1,027	(270)
Amounts reclassified from AOCI	0	0
Net current period OCI	1,027	(270)
Ending Balance	1,396	369
Net change in net investment hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(24)	(62)
OCI before reclassifications	(139)	38
Amounts reclassified from AOCI	0	0
Net current period OCI	(139)	38
Ending Balance	(163)	(24)
Gains (losses) on derivatives recognized as cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	14	16
OCI before reclassifications	0	0
Amounts reclassified from AOCI	(2)	(2)
Net current period OCI	(2)	(2)
Ending Balance	12	14
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(2)	(2)
OCI before reclassifications	2	0
Amounts reclassified from AOCI	0	0
Net current period OCI	2	0
Ending Balance	0	(2)
Net change in unrecognized pension and post-retirement benefit costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(52)	(13)
OCI before reclassifications	0	0
Amounts reclassified from AOCI	68	(39)
Net current period OCI	68	(39)
Ending Balance	$ 16	$ (52)

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, 2024	Dec. 31, 2023
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total operating revenues	$ 7,200	$ 7,563
Interest expense, net (note 9)	(973)	(925)
Other income, net (note 9)	203	158
Income tax recovery (expense)	159	(128)
Net income	568	1,045
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	66	(41)
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 recovery (expense)	0	(1)
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 (note 9)	(2)	(2)
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	68	(38)
Income tax recovery (expense)	0	1
Net income	68	(39)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial (gains) losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net (note 9)	2	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Past service costs (gains)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net (note 9)	(2)	2
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	$ 68	$ (40)

Inventory (Components of Invent

Inventory (Components of Inventory) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Inventory [Abstract]
Materials	$ 453	$ 408
Fuel	328	382
Inventory Total	$ 781	$ 790

Derivatives Instruments (Deriva

Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
HFT derivatives
Derivative Assets	$ 270	$ 348
Derivative Liabilities	690	567
Other derivatives
Other, Derivative Assets	0	22
Other, Derivative Liabilities	36	7
Derivative Assets
Total gross current derivative assets	322	389
Total impact of master netting agreements	(155)	(149)
Less: Derivatives classified as held for sale	(1)	0
Derivative Asset, Total	166	240
Derivative Assets, Current	115	174
Derivative Assets, Long-term	51	66
Derivative Liabilities
Total gross current derivative liabilities	773	653
Total impact of master netting agreements	(155)	(149)
Less: Derivatives classified as held for sale	(1)	0
Derivative Liabilities, Total	617	504
Derivative Liabilities, Current	526	386
Derivative Liabilities, Long-term	91	118
Equity derivatives
Other derivatives
Other, Derivative Assets	0	4
Other, Derivative Liabilities	2	0
FX forwards
Other derivatives
Other, Derivative Assets	0	18
Other, Derivative Liabilities	34	7
Power swaps and physical contracts
HFT derivatives
Derivative Assets	34	29
Derivative Liabilities	30	36
Natural gas swaps, futures, forwards, physical contracts
HFT derivatives
Derivative Assets	236	319
Derivative Liabilities	660	531
Regulatory deferral
HFT derivatives
Derivative Assets	52	19
Derivative Liabilities	47	79
Derivative Assets
Total impact of master netting agreements	(7)	(3)
Derivative Liabilities
Total impact of master netting agreements	(7)	(3)
Regulatory deferral | Commodity swaps and forwards
Regulatory deferral
Regulatory deferral, Derivative Assets	25	16
Regulatory deferral, Derivative Liabilities	44	76
Regulatory deferral | FX forwards
HFT derivatives
Derivative Assets	27	3
Derivative Liabilities	3	3
HFT derivatives
Derivative Assets
Total impact of master netting agreements	(148)	(146)
Derivative Liabilities
Total impact of master netting agreements	$ (148)	$ (146)

Derivatives Instruments (Cash F

Derivatives Instruments (Cash Flow Hedges Recorded in AOCI) (Details) - Cash flow hedges - Treasury lock - CAD ($) $ in Millions		12 Months Ended
	May 26, 2021	Dec. 31, 2024	Dec. 31, 2023
Cash Flow Hedges
Derivative gain loss amortization period	10 years
Total unrealized gain in AOCI - effective portion, net of tax	$ 19	$ 12	$ 14
Unrealized gains reclassified into interest expense		2	$ 2
Unrealized gains currently in AOCI to be reclassified into net income within the next twelve months		$ 2

Derivatives Instruments (Change

Derivatives Instruments (Changes in Realized and Unrealized Gains (Losses) on Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	$ (228)	$ 666
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(56)	17
Regulatory deferral | Physical natural gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral		(52)
Regulatory deferral | Physical natural gas purchases | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral		0
Realized (gain) loss on derivatives receiving regulatory deferral		0
Regulatory deferral | Physical natural gas purchases | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral		(3)
Realized (gain) loss on derivatives receiving regulatory deferral		0
Regulatory deferral | Physical natural gas purchases | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral		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		(49)
Regulatory deferral | Physical natural gas purchases | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral		0
Regulatory deferral | Commodity swaps and forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	41	(204)
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(27)	(109)
Realized (gain) loss on derivatives receiving regulatory deferral	(8)	(5)
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	11	(73)
Realized (gain) loss on derivatives receiving regulatory deferral	4	2
Regulatory deferral | Commodity swaps and forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	11	4
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	50	(9)
Regulatory deferral | Commodity swaps and forwards | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	0	(14)
Regulatory deferral | FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	24	(17)
Regulatory deferral | FX forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	5	(3)
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	33	0
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	(8)	(10)
Regulatory deferral | FX forwards | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(6)	(4)
Regulatory deferral | FX forwards | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	$ 0	$ 0

Derivatives Instruments (Notion

Derivatives Instruments (Notional Volumes of Outstanding Derivatives Designated for Regulatory Deferral) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($) MMBTU MWh T
Commodity swaps and forwards | Coal | 2025
Derivative [Line Items]
Coal (metric tonnes) | T	1
Commodity swaps and forwards | Coal | 2026-2027
Derivative [Line Items]
Coal (metric tonnes) | T	0
Commodity swaps and forwards | Natural gas | 2025
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	21
Commodity swaps and forwards | Natural gas | 2026-2027
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	23
Commodity swaps and forwards | Power | 2025
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	1
Commodity swaps and forwards | Power | 2026-2027
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	0
Physical natural gas purchases | Natural gas | 2025
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	6
Physical natural gas purchases | Natural gas | 2026-2027
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	0
Foreign Exchange Swaps and Forward Contracts | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 208
Weighted average rate	1.3361
% of USD requirements	50%
Foreign Exchange Swaps and Forward Contracts | 2026-2027
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 69
Weighted average rate	1.3296
% of USD requirements	17%

Derivatives Instruments (Realiz

Derivatives Instruments (Realized and Unrealized Gains (Losses) on HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 207	$ 1,037
Operating revenues | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	12	(6)
Operating revenues | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 195	$ 1,043

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, 2024 MMBTU MWh
Power | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2028
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2029 and thereafter
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	1
Power | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2028
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2029 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Natural gas | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	262
Natural gas | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	111
Natural gas | Purchases | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	43
Natural gas | Purchases | 2028
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	30
Natural gas | Purchases | 2029 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	73
Natural gas | Sales | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	299
Natural gas | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	69
Natural gas | Sales | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	16
Natural gas | Sales | 2028
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	8
Natural gas | Sales | 2029 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	4

Derivatives Instruments (Real_2

Derivatives Instruments (Realized and Unrealized Gains (Losses) on Other Derivatives) (Details) shares in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2024 USD ($) shares
Derivative Instruments, Gain (Loss) [Line Items]
Equity derivative hedges, return of shares | shares			2.9
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	$ (56)	$ 17
Combined notional amount			$ 520
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)	(44)	28
Realized gains (loss)	(12)	(11)
Equity derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	14	(9)
Equity derivatives | OM&G
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	(2)	4
Realized gains (loss)	16	(13)
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, 2024 CAD ($) Days	Dec. 31, 2023 CAD ($)
Credit Derivatives [Line Items]
Total cash deposits/collateral on hand	$ 198	$ 101
Financial Asset, Past Due [Member]
Credit Derivatives [Line Items]
Financial assets, considered to be past due	140	142
Credit Concentration Risk
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	1,300	1,200
Total cash deposits/collateral on hand	303	310
Credit Concentration Risk | Receivables, net
Credit Derivatives [Line Items]
Fair Value, Financial assets, considered to be past due	$ 128	$ 127
Average number of days financial asset outstanding | Days	61

Derivatives Instruments (Summar

Derivatives Instruments (Summary of Concentration Risk) (Details) - Credit Concentration Risk - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,300,000	$ 1,200,000
Receivables, net | Classification as assets held for sale
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 118,000	$ 0
% of total exposure	7%	0%
Receivables, net | Other accounts receivable
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 331,000	$ 151,000
% of total exposure	20%	10%
Receivables, net | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 295,000	$ 188,000
% of total exposure	17%	12%
Receivables, net | Receivables
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,528,000	$ 1,290,000
% of total exposure	90%	84%
Receivables, net | Credit rating of A- or above | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 88,000	$ 47,000
% of total exposure	5%	3%
Receivables, net | Credit rating of BBB- to BBB+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 42,000	$ 33,000
% of total exposure	2%	2%
Receivables, net | Not rated | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 165,000	$ 108,000
% of total exposure	10%	7%
Derivative Instruments (current and long-term) | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 166,000	$ 240,000
% of total exposure	10%	16%
Derivative Instruments (current and long-term) | Receivables and Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,694,000	$ 1,530,000
% of total exposure	100%	100%
Derivative Instruments (current and long-term) | Credit rating of A- or above | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 91,000	$ 138,000
% of total exposure	5%	9%
Derivative Instruments (current and long-term) | Credit rating of BBB- to BBB+ | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,000	$ 7,000
% of total exposure	0%	1%
Derivative Instruments (current and long-term) | Not rated | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 74,000	$ 95,000
% of total exposure	5%	6%
Regulated utilities | Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 784,000	$ 951,000
% of total exposure	46%	62%
Regulated utilities | Receivables, net | Residential
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 376,000	$ 476,000
% of total exposure	22%	31%
Regulated utilities | Receivables, net | Commercial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 184,000	$ 194,000
% of total exposure	11%	13%
Regulated utilities | Receivables, net | Industrial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 73,000	$ 84,000
% of total exposure	4%	5%
Regulated utilities | Receivables, net | Other
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 105,000	$ 103,000
% of total exposure	6%	7%
Regulated utilities | Receivables, net | Cash Collateral
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 46,000	$ 94,000
% of total exposure	3%	6%

Derivatives Instruments (Cash C

Derivatives Instruments (Cash Collateral Positions) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments
Cash collateral provided to others	$ 198	$ 101
Cash collateral received from others	5	22
Total fair value of these derivatives, in a liability position	$ 617	$ 504

FV Measurements (Classification

FV Measurements (Classification of Fair Value of Derivatives) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Assets
Less: Derivatives classified as held for sale	$ (1)	$ 0
Total assets	166	240
Liabilities
Less: Derivatives classified as held for sale	(1)	0
Total liabilities	617	504
Level 3
Assets
Total assets	32	34
Liabilities
Total liabilities	441	365
Net assets (liabilities)	(409)	(331)
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	5
Liabilities
Total liabilities	4
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	27	34
Liabilities
Total liabilities	437	365
Fair Value, Measurements, Recurring
Assets
Less: Derivatives classified as held for sale	(1)
Total assets	166	240
Liabilities
Less: Derivatives classified as held for sale	(1)
Total liabilities	617	504
Net assets (liabilities)	(451)	(264)
Fair Value, Measurements, Recurring | Other
Assets
Total assets		22
Liabilities
Total liabilities	36	7
Fair Value, Measurements, Recurring | FX forwards | Other
Assets
Total assets		18
Liabilities
Total liabilities	34	7
Fair Value, Measurements, Recurring | Equity derivatives | Other
Assets
Total assets		4
Liabilities
Less: Derivatives classified as held for sale	(2)
Fair Value, Measurements, Recurring | Regulatory deferral
Assets
Total assets	45	16
Liabilities
Total liabilities	40	76
Fair Value, Measurements, Recurring | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	18	13
Liabilities
Total liabilities	37	73
Fair Value, Measurements, Recurring | Regulatory deferral | FX forwards
Assets
Total assets	27	3
Liabilities
Total liabilities	3	3
Fair Value, Measurements, Recurring | HFT derivatives
Assets
Total assets	122	202
Liabilities
Total liabilities	542	421
Fair Value, Measurements, Recurring | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	30	18
Liabilities
Total liabilities	27	24
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	92	184
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	515	397
Fair Value, Measurements, Recurring | Level 1
Assets
Less: Derivatives classified as held for sale	0
Total assets	30	48
Liabilities
Less: Derivatives classified as held for sale	0
Total liabilities	11	56
Net assets (liabilities)	19	(8)
Fair Value, Measurements, Recurring | Level 1 | Other
Assets
Total assets		4
Liabilities
Total liabilities	2	0
Fair Value, Measurements, Recurring | Level 1 | FX forwards | Other
Assets
Total assets		0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives | Other
Assets
Total assets		4
Liabilities
Less: Derivatives classified as held for sale	(2)
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral
Assets
Total assets	15	7
Liabilities
Total liabilities	18	43
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	15	7
Liabilities
Total liabilities	18	43
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 | HFT derivatives
Assets
Total assets	15	37
Liabilities
Total liabilities	(9)	13
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	2	(5)
Liabilities
Total liabilities	2	0
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	13	42
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	(11)	13
Fair Value, Measurements, Recurring | Level 2
Assets
Less: Derivatives classified as held for sale	(1)
Total assets	104	158
Liabilities
Less: Derivatives classified as held for sale	(1)
Total liabilities	165	83
Net assets (liabilities)	(61)	75
Fair Value, Measurements, Recurring | Level 2 | Other
Assets
Total assets		18
Liabilities
Total liabilities	34	7
Fair Value, Measurements, Recurring | Level 2 | FX forwards | Other
Assets
Total assets		18
Liabilities
Total liabilities	34	7
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives | Other
Assets
Total assets		0
Liabilities
Less: Derivatives classified as held for sale	0
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral
Assets
Total assets	30	9
Liabilities
Total liabilities	22	33
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	3	6
Liabilities
Total liabilities	19	30
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | FX forwards
Assets
Total assets	27	3
Liabilities
Total liabilities	3	3
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives
Assets
Total assets	75	131
Liabilities
Total liabilities	110	43
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	23	23
Liabilities
Total liabilities	21	24
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	52	108
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	89	19
Fair Value, Measurements, Recurring | Level 3
Assets
Less: Derivatives classified as held for sale	0
Total assets	32	34
Liabilities
Less: Derivatives classified as held for sale	0
Total liabilities	441	365
Net assets (liabilities)	(409)	(331)
Fair Value, Measurements, Recurring | Level 3 | Other
Assets
Total assets		0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | FX forwards | Other
Assets
Total assets		0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Equity derivatives | Other
Assets
Total assets		0
Liabilities
Less: Derivatives classified as held for sale	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | 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 | HFT derivatives
Assets
Total assets	32	34
Liabilities
Total liabilities	441	365
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	5	0
Liabilities
Total liabilities	4	0
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	27	34
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	$ 437	$ 365

FV Measurements (Change in Fair

FV Measurements (Change in Fair Value of Level 3 Financial Assets) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 34
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(2)
Ending Balance	32
Physical natural gas purchases
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(7)
Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	5
Ending Balance	5
Natural gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	34
Ending Balance	$ 27

FV Measurements (Change in Fa_2

FV Measurements (Change in Fair Value of Level 3 Financial Liabilities) (Details) - Energy Related derivative - Non-regulated operating revenues $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)
Power
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total realized and unrealized gains included in non-regulated operating revenues	$ 4
HFT derivatives
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	365
Total realized and unrealized gains included in non-regulated operating revenues	76
Ending Balance	441
HFT derivatives | Power
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	0
Ending Balance	4
HFT derivatives | Natural gas
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	365
Total realized and unrealized gains included in non-regulated operating revenues	72
Ending Balance	$ 437

FV Measurements (Quantitative I

FV Measurements (Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements) (Details) - CAD ($)	Dec. 31, 2024	Dec. 31, 2023
Assets
Total assets	$ 166,000,000	$ 240,000,000
Liabilities
Total liabilities	617,000,000	504,000,000
Level 3
Assets
Total assets	32,000,000	34,000,000
Liabilities
Total liabilities	441,000,000	365,000,000
Net liability	409,000,000	331,000,000
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	5,000,000
Liabilities
Total liabilities	4,000,000
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	27,000,000	34,000,000
Liabilities
Total liabilities	$ 437,000,000	$ 365,000,000
Level 3 | HFT derivatives | Range, Minimum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	25.60
Level 3 | HFT derivatives | Range, Minimum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	2.20	1.27
Level 3 | HFT derivatives | Range, Maximum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	139.65
Level 3 | HFT derivatives | Range, Maximum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	17.54	16.25
Level 3 | HFT derivatives | Weighted average | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	82.63
Level 3 | HFT derivatives | Weighted average | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	8.57	4.85

FV Measurements (Financial Liab

FV Measurements (Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	$ 17,941	$ 16,621
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	17,688	16,363
Fair Value Measurement [Domain] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	253	258
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	18,407	18,365
Financial assets and liabilities	$ 17,941	$ 16,621

FV Measurements (Hybrid Notes)

FV Measurements (Hybrid Notes) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200	$ 1,200
Net investment in United States dollar denominated operations
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	1,200	1,200
After-tax foreign currency gain (loss)	$ (139)	$ 38

Related Paty Transactions (Narr

Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
NSPML | Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ (324)	$ 163
M&NP | Non-Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 11	$ 14

Receivables and Other Current_3

Receivables and Other Current Assets (Summary of Receivables and Other Current Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Receivables and Other Current Assets [Abstract]
Customer accounts receivable - billed	$ 834	$ 805
Customer accounts receivable - unbilled	342	363
Capitalized transportation capacity	216	358
Cash collateral provided to others	198	101
Prepaid expenses	105	105
Income taxes receivable	22	10
Allowance for credit losses	(12)	(15)
Other	106	90
Total receivables and other current assets	$ 1,811	$ 1,817

Leases (Narrative) (Details)

Leases (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Oct. 31, 2023 USD ($)
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 61 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 they will be exercised.
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 61 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 they will be exercised
Lessee, Operating Lease, Existence of Option to Extend [true false]	true
Lease, Expense	$ 123	$ 127
Variable costs for power generation facility finance leases	$ 112	$ 119
Renewable Natural Gas Facility [Member]
Lessor, Direct finance and sales-type leases
Lessor, sales-type lease, term of contract			15 years
Lessor Sales Type Lease Assumptions And Judgments Value Of Underlying Asset Amount			$ 35
Minimum
Lessee, Operating Leases
Lessee, Operating Lease, Remaining Lease Term	1 year
Maximum
Lessee, Operating Leases
Lessee, Operating Lease, Remaining Lease Term	61 years
Lessee, Operating Lease, Renewal Term	65 years

Leases (Lessee, Operating Lease

Leases (Lessee, Operating Leases and Additional Information) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Assets and Liabilities, Lessee
Right-of-use asset	$ 52	$ 54
Lease liabilities, Current	3	3
Lease liabilities, Long-term	54	55
Total lease liabilities	57	58
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	10	8
Right-of-use assets obtained in exchange for lease obligations: Operating leases	$ 0	$ 1
Weighted average remaining lease term (years)	44 years	44 years
Weighted average discount rate - operating leases	3.96%	3.93%

Leases (Lessee, Future Minimum

Leases (Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter
2025	$ 5
2026	3
2027	3
2028	3
2029	3
Thereafter	115
Minimum lease payments, Total	132
Less imputed interest	(75)
Total	$ 57	$ 58

Leases (Lessor, Direct Finance

Leases (Lessor, Direct Finance and Sales-Type Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Net investment in direct finance and sales-type leases
Total minimum lease payments to be received	$ 1,310	$ 1,360
Less: amounts representing estimated executory costs	(182)	(190)
Minimum lease payments receivable	1,128	1,170
Estimated residual value of leased property (unguaranteed)	183	183
Less: Credit loss reserve	(2)	(2)
Less: unearned finance lease income	(655)	(693)
Net investment in direct finance and sales-type leases	654	658
Principal due within one year (included in "Receivables and other current assets")	44	37
Net Investment in direct finance leases - long-term	$ 610	$ 621

Leases (Lessor, Future Minimum

Leases (Lessor, Future Minimum Lease Payments to be Received) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
2025	$ 99
2026	100
2027	99
2028	97
2029	96
Thereafter	819
Total minimum lease payments to be received	1,310	$ 1,360
Less: executory costs	(182)	(190)
Minimum lease payments receivable	$ 1,128	$ 1,170

Property, Plant and Equipment_2

Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment, Net
Total cost	$ 33,651	$ 32,273
Less: Accumulated depreciation	(10,442)	(9,994)
Total cost less: Accumulated depreciation	23,209	22,279
Construction work in progress	2,959	2,097
Property, Plant and Equipment, Net	26,168	24,376
Generation
Property, Plant and Equipment, Net
Total cost	$ 14,297	13,500
Generation | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Generation | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	131 years
Transmission
Property, Plant and Equipment, Net
Total cost	$ 3,106	2,835
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	$ 8,512	7,417
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	$ 4,658	5,536
Gas transmission and distribution | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Gas transmission and distribution | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	75 years
General plant and other
Property, Plant and Equipment, Net
Total cost	$ 3,078	$ 2,985
General plant and other | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
General plant and other | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	60 years

Property, Plant and Equipment_3

Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Narrative) (Details) - Pipeline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions	12 Months Ended
	Dec. 31, 2024 mi	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Jointly Owned Pipeline lateral
Jointly Owned Utility Plant, Proportionate Ownership Share		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		$ 3	$ 2

Employee Benefit Plans (Changes

Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and Funded Status) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined benefit pension plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	$ 2,273	$ 2,158
Service cost	35	30
Plan participant contributions	6	6
Interest cost	110	111
Plan amendments	0	0
Benefits Paid	(153)	(147)
Actuarial losses (gains)	13	146
Settlements and curtailments	0	(8)
Foreign currency translation adjustment	83	(23)
Benefit Obligation, Ending Balance	2,367	2,273
Change in plan assets
Plan Assets, Beginning Balance	2,298	2,163
Employer contributions	36	42
Plan participant contributions	6	6
Benefits paid	(153)	(147)
Actual return on assets, net of expenses	226	262
Settlements and curtailments	0	(8)
FX translation adjustment	80	(20)
Plan Assets, Ending Balance	2,493	2,298
Funded Status
Funded status, end of year	126	25
Non-pension Benefit Plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	227	243
Service cost	3	3
Plan participant contributions	5	6
Interest cost	12	13
Plan amendments	0	(14)
Benefits Paid	(21)	(29)
Actuarial losses (gains)	(3)	10
Settlements and curtailments	0	0
Foreign currency translation adjustment	18	(5)
Benefit Obligation, Ending Balance	241	227
Change in plan assets
Plan Assets, Beginning Balance	48	46
Employer contributions	13	23
Plan participant contributions	5	6
Benefits paid	(21)	(29)
Actual return on assets, net of expenses	4	3
Settlements and curtailments	0	0
FX translation adjustment	5	(1)
Plan Assets, Ending Balance	54	48
Funded Status
Funded status, end of year	$ (187)	$ (179)

Employee Benefit Plans (Plans w

Employee Benefit Plans (Plans with PBO/APBO in Excess of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Defined benefit pension plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	$ 95	$ 120
FV of plan assets	11	37
Funded Status	(84)	(83)
Non-pension Benefit Plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	219	205
FV of plan assets	0	0
Funded Status	$ (219)	$ (205)

Employee Benefit Plans (Plans_2

Employee Benefit Plans (Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO for the defined benefit pension plans	$ 2,255	$ 2,172
Defined benefit pension plans
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO	90	114
Fair value of plan assets	11	37
Funded Status	$ (79)	$ (77)

Employee Benefit Plans (Amounts

Employee Benefit Plans (Amounts Recognized in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Balance Sheet
Other current liabilities	$ (26)	$ (23)
Long-term liabilities	(274)	(265)
Defined benefit pension plans
Balance Sheet
Other current liabilities	(5)	(5)
Liabilities associated with assets held for sale	0	0
Long-term liabilities	(78)	(78)
Other long-term assets	208	108
Assets held for sale	1	0
AOCI, net of tax and regulatory assets	354	385
Deferred income tax expense in AOCI	(8)	(8)
Net amount recognized	472	402
Non-pension Benefit Plans
Balance Sheet
Other current liabilities	(21)	(18)
Liabilities associated with assets held for sale	(1)	0
Long-term liabilities	(196)	(187)
Other long-term assets	0	26
Assets held for sale	31	0
AOCI, net of tax and regulatory assets	22	20
Deferred income tax expense in AOCI	(1)	(1)
Net amount recognized	$ (166)	$ (160)

Employee Benefit Plans (Amoun_2

Employee Benefit Plans (Amounts Recognized in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Change in AOCI and Regulatory Assets
Beginning Balance	$ 12,088	$ 11,441
Ending Balance	13,291	12,088
Regulatory assets	3,427	3,105
Defined benefit pension plans
Change in AOCI and Regulatory Assets
Beginning Balance	61
Amortized in current period	3	1
Ending Balance	(9)	61
Actuarial (gains) losses	(17)	53
Past service gains	0	0
Deferred income tax expense (recovery)	8	8
AOCI, net of tax	(9)	61
Regulatory assets	363	324
AOCI, net of tax and regulatory assets	354	385
Defined benefit pension plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	324
Amortized in current period	(9)
Current year additions (reductions)	19
Change in FX rate	29
Ending Balance	363	324
Defined benefit pension plans | Actuarial (gains) losses
Change in AOCI and Regulatory Assets
Beginning Balance	53
Amortized in current period	(3)
Current year additions (reductions)	(67)
Change in FX rate	0
Ending Balance	(17)	53
Defined benefit pension plans | Past service costs (gains)
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year additions (reductions)	0
Change in FX rate	0
Ending Balance	0	0
Non-pension Benefit Plans
Change in AOCI and Regulatory Assets
Beginning Balance	(9)
Amortized in current period	(2)	(3)
Ending Balance	(7)	(9)
Actuarial (gains) losses	(8)	(8)
Past service gains	0	(2)
Deferred income tax expense (recovery)	1	1
AOCI, net of tax	(7)	(9)
Regulatory assets	29	29
AOCI, net of tax and regulatory assets	22	20
Non-pension Benefit Plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	29
Amortized in current period	2
Current year additions (reductions)	(5)
Change in FX rate	3
Ending Balance	29	29
Non-pension Benefit Plans | Actuarial (gains) losses
Change in AOCI and Regulatory Assets
Beginning Balance	(8)
Amortized in current period	1
Current year additions (reductions)	(1)
Change in FX rate	0
Ending Balance	(8)	(8)
Non-pension Benefit Plans | Actuarial (gains) losses | Assets
Change in AOCI and Regulatory Assets
Amortized in current period	2
Current year additions (reductions)	0
Change in FX rate	0
Non-pension Benefit Plans | Past service costs (gains)
Change in AOCI and Regulatory Assets
Beginning Balance	(2)
Amortized in current period	(2)
Current year additions (reductions)	0
Change in FX rate	0
Ending Balance	$ 0	$ (2)

Employee Benefit Plans (Net Per

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (2,571)	$ (2,577)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	35	30
Interest cost	110	111
Expected return on plan assets	(160)	(161)
Current year amortization of: Actuarial losses (gains)	3	1
Current year amortization of: Past service costs (gains)	0	0
Regulatory assets (liability)	9	6
Settlement, curtailments	0	2
Net Periodic Benefit Cost, Total	(3)	(11)
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	3
Interest cost	12	13
Expected return on plan assets	(2)	(2)
Current year amortization of: Actuarial losses (gains)	(2)	(3)
Current year amortization of: Past service costs (gains)	(2)	0
Regulatory assets (liability)	(2)	(2)
Settlement, curtailments	1	0
Net Periodic Benefit Cost, Total	$ 8	$ 9

Employee Benefit Plans (Pension

Employee Benefit Plans (Pension Plan Asset Allocations) (Details) - Defined benefit pension plans	Dec. 31, 2024
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0%
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	10%
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	10%
Fixed income | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	34%
Fixed income | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	49%
Fixed income | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	29%
Fixed income | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	49%
Equities: Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	5%
Equities: Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	15%
Equities: Non-Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	37%
Equities: Non-Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	61%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	48%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	68%

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined benefit pension plans
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,493	$ 2,298	$ 2,163
Total
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,493	$ 2,298
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	$ 39	$ 40
Percentage	2%	2%
Total | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (27)	$ (9)
Percentage	(1.00%)	0%
Total | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 109	$ 96
Percentage	4%	4%
Total | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 312	$ 141
Percentage	12%	6%
Total | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 140	$ 112
Percentage	5%	5%
Total | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 132	$ 172
Percentage	5%	8%
Total | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 92	$ 90
Percentage	4%	4%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 22	$ 9
Percentage	1%	0%
Total | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 13	$ 50
Percentage	1%	2%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets		$ 5
Percentage		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	$ 1,142	$ 1,006
Percentage	46%	44%
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	$ 519	$ 586
Percentage	21%	25%
NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,661	$ 1,592
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
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	1,142	1,006
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	519	586
Level 1
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	586	440
Level 1 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	39	40
Level 1 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(27)	(9)
Level 1 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	109	96
Level 1 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	312	141
Level 1 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	140	112
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	0	4
Level 1 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	13	50
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets		6
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	246	266
Level 2 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	132	172
Level 2 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	92	90
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	22	5
Level 2 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets		(1)
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 for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2024 CAD ($)
Defined benefit pension plans
Expected employer contributions
Expected employer contributions, 2025	$ 41
Expected benefit payments
Expected benefit payments, 2025	175
Expected benefit payments, 2026	179
Expected benefit payments, 2027	182
Expected benefit payments, 2028	184
Expected benefit payments, 2029	186
Expected benefit payments, 2030 - 2034	950
Non-pension Benefit Plans
Expected employer contributions
Expected employer contributions, 2025	21
Expected benefit payments
Expected benefit payments, 2025	23
Expected benefit payments, 2026	23
Expected benefit payments, 2027	23
Expected benefit payments, 2028	23
Expected benefit payments, 2029	22
Expected benefit payments, 2030 - 2034	$ 103

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, 2024	Dec. 31, 2023
Defined benefit pension plans
Benefit obligation - December 31:
Discount rate - past service	5.07%	4.89%
Discount rate - future service	5.12%	4.88%
Rate of compensation increase	3.73%	3.87%
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	4.89%	5.33%
Discount rate - future service	4.88%	5.34%
Expected long-term return on plan assets	6.43%	6.56%
Rate of compensation increase	3.87%	3.62%
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	4.91%	4.89%
Discount rate - future service	5%	4.89%
Rate of compensation increase	3.72%	3.85%
Health care trend - initial (next year)	6.53%	6.04%
Health care trend - ultimate	3.77%	3.76%
Health care trend - year ultimate reached	2044	2043
Benefit cost for year ended December 31:
Discount rate - past service	4.89%	5.31%
Discount rate - future service	4.89%	5.32%
Expected long-term return on plan assets	3.69%	2.16%
Rate of compensation increase	3.85%	3.61%
Health care trend - initial (next year)	6.04%	5.40%
Health care trend - ultimate	3.76%	3.77%
Health care trend - year ultimate reached	2043	2043

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined-Benefit Plans, information
Defined Benefit Plan, Description	Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. The Company also provides non-pension benefits for its retirees.
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	The market-related value of assets is based on a 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 multi-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	$ 2,571	$ 2,577
Contribution Amount	51	45
Defined benefit pension plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	160	161
Non-pension Benefit Plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	$ 2	$ 2

Goodwill (Change in Goodwill) (

Goodwill (Change in Goodwill) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Goodwill [Roll Forward]
Balance, January 1	$ 5,871	$ 6,012
Change in FX rate	504	(141)
Impairment charges	(214)	0
Classified as assets held for sale	(303)	0
Balance, December 31	$ 5,858	$ 5,871

Goodwill (Narrative) (Detail)

Goodwill (Narrative) (Detail) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Goodwill [Line Items]
Goodwill impairment charge		$ 214	$ 0
Goodwill		5,858	$ 5,871	$ 6,012
NMGC
Goodwill [Line Items]
Goodwill impairment charge	$ 210
Goodwill	$ 303	$ 303

Short-Term Debt (Short-Term Deb

Short-Term Debt (Short-Term Debt and Related Weighted-Average Interest Rates) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Short-term debt and the related weighted-average interest rates
Short-term borrowings, gross	$ 1,446	$ 1,433
Classification as liabilities held for sale	(212)	0
Short-term debt	$ 1,400	$ 1,433
Weighted average interest rate	5.05%	5.95%
NMGC
Short-term debt and the related weighted-average interest rates
Classification as liabilities held for sale	$ (46)	$ 0
Advances on revolving credit and term facilities | TECO Finance
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 265	$ 245
Weighted average interest rate	5.53%	6.54%
Non-revolving term facilities | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 0	$ 796
Weighted average interest rate	0%	6.07%
Bank indebtedness | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 2	$ 9
Weighted average interest rate	0%	0%
Advances on revolving credit facilities | TEC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 915	$ 277
Weighted average interest rate	4.77%	5.68%
Advances on revolving credit facilities | PGS
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 199	$ 73
Weighted average interest rate	5.36%	6.36%
Advances on revolving credit facilities | NMGC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 46	$ 25
Weighted average interest rate	5.52%	6.46%
Advances on revolving credit facilities | GBPC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 19	$ 8
Weighted average interest rate	7.20%	5.54%

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, 2024	Dec. 31, 2023
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total advances under available facilities	$ 1,404	$ 1,436
Available capacity under existing agreements	$ 898	1,337
Revolving credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2028
Total available capacity	$ 1,151	401
Revolving credit facility | TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2028
Total available capacity	$ 576	529
Revolving credit facility | PGS
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2028
Total available capacity	$ 360	331
Revolving credit facility | NMGC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 180	165
Revolving credit facility II | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 0	265
Revolving credit facility III | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 0	265
Revolving credit facility III | Other
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity	$ 35	17
Non-revolving term loan | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 0	400
Non-revolving term loan II | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 0	400
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	1,400	1,433
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	3
Short term credit facilities
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity	$ 2,302	$ 2,773

Short-Term Debt (Narrative) (De

Short-Term Debt (Narrative) (Details) - CAD ($) $ in Millions			1 Months Ended	12 Months Ended
	Jun. 24, 2024	Jun. 17, 2024	Dec. 31, 2024	Dec. 31, 2024	Apr. 01, 2024	Dec. 31, 2023
Line of Credit Facility [Line Items]
Weighted average interest rate			5.05%	5.05%		5.95%
Revolving credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,151	$ 1,151		$ 401
Revolving credit facility | TEC | Florida Electric Utility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 800
Debt Instrument, Maturity Date				Dec. 17, 2026
Debt Instrument, Maturity Date Extended				Dec. 01, 2028
Revolving credit facility | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			180	$ 180		165
Revolving credit facility | TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			576	$ 576		529
Revolving credit facility | TECO Finance | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 400
Debt Instrument, Maturity Date				Dec. 17, 2026
Debt Instrument, Maturity Date Extended				Dec. 01, 2028
Revolving credit facility | Peoples Gas System [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			360	$ 360		331
Revolving credit facility II | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			0	0		265
Revolving credit facility II | Emera Inc. | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 400	200	200
Repayments of credit facility		$ 200	200
Revolving credit facility III | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 0	$ 0		$ 265
Non-revolving term facilities | Emera Inc.
Line of Credit Facility [Line Items]
Weighted average interest rate			0%	0%		6.07%
Line of Credit Facility, Maximum Borrowing Capacity			$ 0	$ 0		$ 400
Non-revolving term facilities | Emera Inc. | Other Segments [Member]
Line of Credit Facility [Line Items]
Repayments of credit facility	$ 400
Non-revolving term loan II | Emera Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 0	$ 0		$ 400

Other Current Liabilities (Comp

Other Current Liabilities (Components of Other Current Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Other Current Liabilities
Accrued charges	$ 189	$ 172
Accrued interest on long-term debt	106	107
Pension and post-retirement liabilities	26	23
Sales and other taxes payable	11	11
Income taxes payable	4	2
Other	153	112
Other current liabilities, Total	$ 489	$ 427

Long-Term Debt (Summary of Long

Long-Term Debt (Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Debt issuance costs	$ (137)	$ (125)
Classification as liabilities held for sale (5)	(696)	0
Amount due within one year	(234)	(676)
Long Term Debt, Adjustments	(1,067)	(801)
Long-Term Debt	18,173	17,689
Interest expense	110	109
Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Long-term debt	2,279	2,339
Other Electric Utilities
Debt Instrument [Line Items]
Long-term debt	416	422
Other
Debt Instrument [Line Items]
Long-term debt	7,464	6,189
NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Long-term debt	$ 3,361	$ 3,886
Fixed to floating subordinated notes | Other
Debt Instrument [Line Items]
Weighted average interest rate	6.75%	6.75%
Maturity	2076
Long-term debt	$ 1,727	$ 1,587
Commercial Paper | NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2029
Long-term debt	$ 177	$ 721
Senior unsecured notes | Florida Electric Utility
Debt Instrument [Line Items]
Weighted average interest rate	4.36%	4.61%
Maturity	2029 - 2051
Long-term debt	$ 5,720	$ 5,654
Senior unsecured notes | Other
Debt Instrument [Line Items]
Weighted average interest rate	3.99%	3.65%
Maturity	2026 - 2046
Long-term debt	$ 3,525	$ 3,637
Senior unsecured notes | PGS | Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Weighted average interest rate	5.63%	5.63%
Maturity	2028 - 2053
Long-term debt	$ 1,331	$ 1,223
Senior unsecured notes | NMGC | Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Weighted average interest rate	3.78%	3.78%
Maturity	2026 - 2051
Long-term debt	$ 698	$ 642
Senior unsecured notes | NMGI | Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Weighted average interest rate		3.64%
Maturity	2024
Long-term debt	$ 0	$ 198
Senior unsecured notes | NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Weighted average interest rate	5.12%	5.13%
Maturity	2025 - 2097
Long-term debt	$ 3,184	$ 3,165
Senior unsecured notes | Other
Debt Instrument [Line Items]
Weighted average interest rate	4.84%	4.84%
Maturity	2030
Long-term debt	$ 500	$ 500
Unsecured loan notes | Other Electric Utilities
Debt Instrument [Line Items]
Weighted average interest rate	4.06%	4.78%
Maturity	2025 - 2028
Long-term debt	$ 143	$ 121
Unsecured loan notes | Other
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2026 - 2029
Long-term debt	$ 992	$ 465
Unsecured loan notes | NMGC | Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Interest Rate Terms		Variable
Maturity	2024
Long-term debt	$ 0	$ 30
Unsecured loan notes | Other Electric Utilities
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2025 - 2027
Long-term debt	$ 104	$ 104
Secured loan notes | EBP | Gas Utilities and Infrastructure
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2028
Long-term debt	$ 250	$ 246
Secured senior notes and debentures | Other Electric Utilities
Debt Instrument [Line Items]
Weighted average interest rate	2.38%	3.06%
Maturity	2026 - 2040
Long-term debt	$ 169	$ 197
Junior subordinated notes | Other
Debt Instrument [Line Items]
Weighted average interest rate	7.63%	0%
Maturity	2054
Long-term debt	$ 720	$ 0

Long-Term Debt (Revolving Credi

Long-Term Debt (Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Use of available facilities	$ 1,181	$ 1,890
Available capacity under existing agreements	898	1,337
Revolving credit facility
Debt Instrument [Line Items]
Available capacity under existing agreements	2,300	3,197
Available capacity under existing agreements	1,119	1,307
Advances on the revolving credit facility	50
Revolving credit facility | Emera
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 1,300	900
Maturity	June 2029
Revolving credit facility | TEC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 0	657
Maturity	December 2026
Revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 800	800
Maturity	June 2029
Revolving credit facility | ECI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 0	10
Maturity	October 2024
Non-revolving credit facility | Emera
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 200	400
Maturity	February 2026
Non-revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 0	400
Maturity	July 2024
Non-revolving credit facility | NMGC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 0	30
Maturity	March 2024
Borrowings under credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 1,169	1,884
Letters of credit issued within the credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 12	$ 6

Long-Term Debt (Significant Cov

Long-Term Debt (Significant Covenants) (Details)	Dec. 31, 2024
Maximum
Debt Instrument [Line Items]
Debt to capital ratio	0.70
Syndicated credit facilities
Debt Instrument [Line Items]
Debt to capital ratio	0.55

Long-Term Debt (Long-Term Debt

Long-Term Debt (Long-Term Debt Maturities) (Details) $ in Millions	Dec. 31, 2024 CAD ($)
Debt Instrument [Line Items]
2025	$ 234
2026	3,279
2027	120
2028	651
2029	1,764
Thereafter	13,192
Total, long-term debt maturities, including capital lease obligations	19,240
Florida Electric Utility
Debt Instrument [Line Items]
2025	0
2026	0
2027	0
2028	0
2029	720
Thereafter	5,000
Total, long-term debt maturities, including capital lease obligations	5,720
Canadian Electric Utilities
Debt Instrument [Line Items]
2025	125
2026	40
2027	0
2028	0
2029	217
Thereafter	2,979
Total, long-term debt maturities, including capital lease obligations	3,361
Gas Utilities and Infrastructure
Debt Instrument [Line Items]
2025	31
2026	132
2027	31
2028	535
2029	31
Thereafter	1,519
Total, long-term debt maturities, including capital lease obligations	2,279
Other Electric Utilities
Debt Instrument [Line Items]
2025	78
2026	101
2027	89
2028	116
2029	4
Thereafter	28
Total, long-term debt maturities, including capital lease obligations	416
Other
Debt Instrument [Line Items]
2025	0
2026	3,006
2027	0
2028	0
2029	792
Thereafter	3,666
Total, long-term debt maturities, including capital lease obligations	7,464
Subsidiaries
Debt Instrument [Line Items]
2025	234
2026	3,279
2027	120
2028	651
2029	1,764
Thereafter	13,192
Total, long-term debt maturities, including capital lease obligations	$ 19,240

Long-Term Debt (Narrative) (Det

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

12 Months Ended

Dec. 16, 2024 CAD ($)

Jul. 30, 2024 USD ($)

Jul. 12, 2024 USD ($)

Jun. 24, 2024 CAD ($)

Jun. 18, 2024 USD ($)

Jun. 15, 2024 USD ($)

May 02, 2024 USD ($)

Feb. 16, 2024 CAD ($)

Jan. 30, 2024 USD ($)

Dec. 31, 2024 CAD ($)

Dec. 31, 2023 CAD ($)

Jul. 19, 2024 CAD ($)

Jun. 13, 2024 CAD ($)

May 02, 2024 BBD ($)

Debt Instrument [Line Items]

Repayment of long-term debt

$ 1,086

$ 151

TEC

Debt Instrument [Line Items]

Repayment of long-term debt

$ 300

Senior unsecured bonds due March 1, 2029 | TEC | Florida Electric Utility [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

$ 500

Maturity date

Mar. 01, 2029

Stated interest rate

4.90%

Debt term

5 years

Unsecured non-revolving credit facility due June 24, 2025 | NSPI | Canadian Electric Utilities

Debt Instrument [Line Items]

Debt instrument, face amount

$ 300

$ 400

Maturity date

Jun. 24, 2025

Jul. 15, 2024

Repayment of long-term debt

$ 300

Unsecured committed revolving credit facility due June 24, 2029 | NSPI | Canadian Electric Utilities

Debt Instrument [Line Items]

Maturity date

Jun. 24, 2029

Dec. 16, 2027

Unsecured committed revolving credit facility due June 24, 2029 | Emera | Other [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

$ 1,300

$ 900

Maturity date

Jun. 24, 2029

Jun. 24, 2027

Non-revolving credit facility due 2047 | NSPI | Canadian Electric Utilities

Debt Instrument [Line Items]

Debt instrument, face amount

$ 120

Stated interest rate

2.51%

Debt term

20 years

Percentage of total eligible project costs available under credit facility

45.06%

Period of facility available after completion of project

6 months

Non-revolving term credit facility, expiration date

May 21, 2027

Amount utilized under credit facility

$ 19

Fixed rate notes and bonds | NMGI | Gas Utilities and Infrastructure [Member]

Debt Instrument [Line Items]

Repayment of long-term debt

$ 150

Unsecured loan notes due July 19, 2028 | BPLC | Other Electric Utilities [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

$ 46

$ 92

Maturity date

Jul. 19, 2028

Feb. 19, 2025

Unsecured senior notes | Emera Finance | Other [Member]

Debt Instrument [Line Items]

Repayment of long-term debt

$ 300

Fixed-to-fixed reset rate junior subordinated notes | EUSHI Finance, Inc [Member] | Other [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

$ 500

Maturity date

Dec. 15, 2054

Stated interest rate

7.625%

Term of reset

5 years

Basis spread

3.136%

Period before reset date where notes may be redeemed

90 days

Unsecured non-revolving facility February 19, 2024 | Emera | Other [Member]

Debt Instrument [Line Items]

Maturity date

Feb. 19, 2024

Unsecured non-revolving facility February 19, 2025 | Emera | Other [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

$ 400

$ 200

Maturity date

Feb. 19, 2025

Asset Retirement Obligation (Ch

Asset Retirement Obligation (Change in Asset Retirement Obligations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Change in ARO
Balance, January 1	$ 192	$ 174
Additions	11	0
Accretion included in depreciation expense	10	9
Change in FX rate	5	(1)
Revisions in estimated cash flows	2	0
Accretion deferred to regulatory asset (included in PP&E)	0	18
Classified as assets held for sale	(1)	0
Liabilities settled	(2)	(8)
Balance, December 31	$ 217	$ 192

Commitments and Contingencies_2

Commitments and Contingencies (Summary of Contractual Commitments) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)
Recorded Unconditional Purchase Obligation [Line Items]
2025	$ 2,404
2026	1,298
2027	1,037
2028	886
2029	840
Thereafter	7,979
Contractual Commitments	14,444
Other commitments
Commitment	1,880		$ 1,772
Revenue, Remaining Performance Obligation, Amount	$ 495		$ 488
Nalcor Energy
Other commitments
Long-term Purchase Commitment, Period	50 years
TEC
Other commitments
Approved payment	$ 17	$ 12
SeaCoast Gas Transmission, LLC | PGS
Other commitments
Revenue, Remaining Performance Obligation, Amount	$ 135
Maritime Link Project
Other commitments
Long-term Purchase Commitment, Period	38 years
Approved payment	$ 197
Purchased power
Recorded Unconditional Purchase Obligation [Line Items]
2025	307
2026	277
2027	368
2028	368
2029	369
Thereafter	4,487
Contractual Commitments	6,176
Transportation
Recorded Unconditional Purchase Obligation [Line Items]
2025	742
2026	545
2027	544
2028	454
2029	412
Thereafter	3,228
Contractual Commitments	5,925
Transportation | NMGC
Recorded Unconditional Purchase Obligation [Line Items]
2025	30
2026	24
2027	16
2028	12
2029	4
Contractual Commitments	86
Capital projects
Recorded Unconditional Purchase Obligation [Line Items]
2025	604
2026	287
2027	24
2028	0
2029	0
Thereafter	0
Contractual Commitments	915
Fuel, gas supply and storage
Recorded Unconditional Purchase Obligation [Line Items]
2025	591
2026	94
2027	21
2028	5
2029	0
Thereafter	0
Contractual Commitments	711
Fuel, gas supply and storage | NMGC
Recorded Unconditional Purchase Obligation [Line Items]
2025	109
2026	52
2027	13
2028	3
Contractual Commitments	177
Other
Recorded Unconditional Purchase Obligation [Line Items]
2025	160
2026	95
2027	80
2028	59
2029	59
Thereafter	264
Contractual Commitments	$ 717

Commitments and Contingencies_3

Commitments and Contingencies (Legal Proceedings) (Narrative) (Details) - Tampa Electric $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023	Dec. 31, 2024 USD ($)
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 17		$ 12
Maximum
Loss Contingencies [Line Items]
Public Utilities, Approved Return on Equity, Percentage	11.25%	11.25%

Commitments and Contingencies_4

Commitments and Contingencies (Guarantees and Letters of Credit) (Narrative) (Details) $ in Millions, $ in Millions	Dec. 31, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)
Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Guaranty Liabilities	$ 104		$ 104
Letters of Credit Outstanding, Amount		$ 58		$ 56
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	$ 105		$ 103

Commitments and Contingencies_5

Commitments and Contingencies (Collaborative Arrangements) (Narrative) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Regulated fuel for generation and purchased power	$ 12	$ 8
Operating, maintenance and general (OM&G)	$ 3	$ 3

Cumulative Preferred Stock (Sum

Cumulative Preferred Stock (Summary of Cumulative Preferred Stock Authorized) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
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
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	$ 1.6085
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
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	$ 1.5810
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)	12 Months Ended
	Dec. 31, 2024 $ / shares
Series A Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	2.182%
Current Annual Dividend	$ 0.5456
Minimum Reset Dividend Yield (%)	1.84%
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 C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	6.434%
Current Annual Dividend	$ 1.6085
Minimum Reset Dividend Yield (%)	2.65%
Earliest Redemption and/or Conversion Option Date	August 15, 2028
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 F Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	4.202%
Current Annual Dividend	$ 1.0505
Minimum Reset Dividend Yield (%)	2.63%
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 | From February 15, 2025
Class of Stock [Line Items]
Current Annual Dividend	$ 1.4372
Series B Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	2.393%
Minimum Reset Dividend Yield (%)	1.84%
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 H Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	6.324%
Current Annual Dividend	$ 1.5810
Minimum Reset Dividend Yield (%)	4.90%
Earliest Redemption and/or Conversion Option Date	August 15, 2028
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 J Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	4.25%
Current Annual Dividend	$ 1.0625
Minimum Reset Dividend Yield (%)	4.25%
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 E Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	4.50%
Current Annual Dividend	$ 1.1250
Redemption Value	$ 25
Series L Preferred Stock
Class of Stock [Line Items]
Annual Dividend Rate (%)	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, 2028
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]
Annual Dividend Rate (%)	2.54%
Redemption Value	$ 25
Series I Preferred Stock | After August 15, 2028
Class of Stock [Line Items]
Redemption Value	$ 25.5

Cumulative Preferred Stock (Nar

Cumulative Preferred Stock (Narrative) (Details)	12 Months Ended
	Dec. 31, 2024
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 Changes in 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 S_3

Non-Controlling Interest in Subsidiaries (Components of Non-Controlling Interest) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 14	$ 14
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, 2024	Dec. 31, 2023
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, 2024 $ / 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 _3

Supplementary Information to Consolidated Statements of Cash Flows (Summary of Supplementary Information to Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Changes in non-cash working capital
Inventory	$ 38	$ (31)
Receivables and other current assets	(154)	653
Accounts payable	536	(538)
Other current liabilities	32	(179)
Total non-cash working capital	(452)	95
Supplemental disclosure of cash paid:
Interest	989	930
Income Taxes	34	43
Supplemental disclosure of non-cash activities:
Accrued proceeds from disposal of investment subject to significant influence	25	0
Common share dividends reinvested	291	271
Reclassification of short-term debt to long-term debt	0	657
Decrease in accrued capital expenditures	0	(19)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	$ (118)	123
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		$ 166

Stock-Based Compensation (Emplo

Stock-Based Compensation (Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan) (Narrative) (Details) shares in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($) $ / mo shares	Dec. 31, 2024 USD ($) $ / mo shares	Dec. 31, 2023 CAD ($)
Employee Common Share Purchase Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Common Share Purchase Plan, Description	Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees to make cash contributions of a minimum of $25 per month 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 reinvestment of dividends for all participants except for where prohibited by law.	Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees to make cash contributions of a minimum of $25 per month 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 reinvestment of dividends for all participants except for where prohibited by law.
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount | $ / mo	25	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 | $	$ 4,000,000		$ 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 DRIP, which provides an opportunity for shareholders residing in Canada 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 with the reinvestment of cash dividends. The discount was 2 per cent in 2024.	The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada 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 with the reinvestment of cash dividends. The discount was 2 per cent in 2024.
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) - CAD ($) $ / shares in Units, $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
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	7
DSU Plan
Share Unit Plans
Cash payments made during the year	$ 2,000	$ 3,000
Employee Stock Option Plan
Stock option plan, Additional information
Maximum term	10 years
Maximum aggregate number of common shares reserved for issuance	6	6
Terms of award	P10Y
Share Unit Plans
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance	2	2
First Anniversary | DSU Plan | Executive and senior management
Stock option plan, Additional information
Vesting rights, percentage	25%
Vesting period after date of retirement | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period	27 months
Vesting period after termination without just cause or death | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period	6 months
Vesting period after termination for just cause or resignation | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period	60 days
After first year of program | DSU Plan | Executive and senior management | Minimum
Stock option plan, Additional information
Vesting rights, percentage	50%
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, 2024, Emera was 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 and thereafter 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	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	$ 3,000	$ 6,000
Total intrinsic value of options exercised	$ 1,000	$ 2,000
Exercise price range, lower range limit	$ 39.93	$ 32.35
Exercise price range, upper range limit	$ 60.03	$ 60.03
Share Unit Plans
Compensation cost recognized for employee and director	$ 2,000	$ 2,000
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	$ 13,000	2,000
Tax expense related to compensation costs for share units realized	4,000	1,000
Deferred Share Unit Plans | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	43,000	36,000
Deferred Share Unit Plans | Director
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 45,000	37,000
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. Unless otherwise determined by the Management Resources and Compensation Committee (“MRCC”), 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 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
Vesting period	3 years
Award service period	3 years
Share Unit Plans
Tax expense related to compensation costs for share units realized	$ 5,000	3,000
Cash payments made during the year	14,000	19,000
Performance Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 50,000	41,000
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 plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. Unless otherwise determined by the MRCC, 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. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement.
Compensation cost recognized for stock options	$ 18,000	11,000
Restricted Share Unit Plan
Stock option plan, Additional information
Vesting period	3 years
Award service period	3 years
Share Unit Plans
Tax expense related to compensation costs for share units realized	$ 4,000	3,000
Cash payments made during the year	10,000	10,000
Restricted Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 41,000	32,000
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 plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. Unless otherwise determined by the MRCC, 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. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement.
Compensation cost recognized for stock options	$ 15,000	$ 10,000

Stock-Based Compensation (Weigh

Stock-Based Compensation (Weighted Average Fair Values per Stock Option and Assumptions for Options Granted) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Stock-Based Compensation [Abstract]
Weighted average FV per option	$ 4.66	$ 6.32
Expected term	5 years	5 years
Risk-free interest rate	3.56%	3.53%
Expected dividend yield	6.11%	5.05%
Expected volatility	20.67%	20.07%

Stock-Based Compensation (Summa

Stock-Based Compensation (Summary of Stock Option Information) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Granted	$ 4.66	$ 6.32
Stock option plan, Additional information
Non-Vested options: Unrecognized compensation	$ 6	$ 5
Non-vested options: Weighted average recognition period	3 years	3 years
Vested Options: Weighted average remaining term	4 years	5 years
Vested Options: Aggregate intrinsic value	$ 11	$ 8
Vested Options: Fair value	$ 2	$ 2
Employee Stock Option Plan
Total Options, Number of Options
Total Options: Number of Options, Outstanding, Beginning Balance	3,095,604
Granted	792,600
Total Options: Number of Options, Exercised	(78,839)
Total Options: Number of Options, Forfeited	(13,325)
Total Options: Number of Options, Outstanding, Ending Balance	3,796,040	3,095,604
Total Options: Number of Options, Options exercisable	2,188,550
Total Options, Weighted average exercise price per share
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 51.20
Total Options: Weighted average exercise price per share, Granted	46.97
Total Options: Weighted average exercise price per share, Exercised	39.86
Total Options: Weighted average exercise price per share, Forfeited	56.14
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance	50.53	$ 51.20
Total Options: Weighted average exercise price per share, Options exercisable	$ 50.07
Non-Vested Options, Number of Options
Non-Vested Options: Number of Options, Outstanding, Beginning Balance	1,253,255
Granted	792,600
Non-Vested Options: Number of Options, Vested	438,365
Non-Vested Options: Number of options, Forfeited	0
Non-Vested Options: Number of Options, Ending Balance	1,607,490	1,253,255
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 5.17
Non-Vested Options: Weighted average exercise price per share, Granted	4.66
Non-Vested Options: Weighted average exercise price per share, Vested	4.58
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance	$ 5.08	$ 5.17

Stock-Based Compensation (Sum_2

Stock-Based Compensation (Summary of Activity Related to Employee and Director Deferred Share Units) (Details) - DSU Plan - Deferred Share Unit Plans	12 Months Ended
	Dec. 31, 2024 $ / shares shares
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	712,963
Share Unit Plans: Granted including DRIP | shares	86,417
Share Unit Plans: Exercised | shares	(10,292)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	789,088
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 42.29
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	45.20
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	38.77
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 42.65
Director
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	729,058
Share Unit Plans: Granted including DRIP | shares	134,795
Share Unit Plans: Exercised | shares	(34,997)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	828,856
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 46.24
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	48.98
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	36.04
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 47.12

Stock-Based Compensation (Sum_3

Stock-Based Compensation (Summary of Activity Related to Employee Performance Share Units) (Details) - Performance Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	743,365
Share Unit Plans: Granted including DRIP	354,793
Share Unit Plans: Exercised	(253,136)
Share Unit Plans: Forfeited	(12,929)
Share Unit Plans: Outstanding and exercisable, Ending Balance	832,093
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 55.13
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	48.69
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	54.66
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	52.53
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 52.57
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 50	$ 41

Stock-Based Compensation (Sum_4

Stock-Based Compensation (Summary of Activity Related to Employee Restricted Share Units) (Details) - Restricted Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	562,641
Share Unit Plans: Granted including DRIP	287,976
Share Unit Plans: Exercised	(183,241)
Share Unit Plans: Forfeited	(14,228)
Share Unit Plans: Outstanding and exercisable, Ending Balance	653,148
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 55.01
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	48.65
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	54.66
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	52.45
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 52.36
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 41	$ 32

Variable Interest Entities (Sum

Variable Interest Entities (Summary of Material Unconsolidated Variable Interest Entities) (Details) - NSPML - NSPML - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Variable Interest Entity [Line Items]
Equity Method Investment, Underlying Equity in Net Assets	$ 475	$ 489
Maximum exposure to loss	$ 6	$ 6