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 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 (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 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 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 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 |
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 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 |
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 |
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 |
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 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 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 |
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 |
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 |
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 |
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 |
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 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 |
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 |
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 |
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 |
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 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 |
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 |
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 |
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 |
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 |
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 |
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 |
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 |
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 |
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 |
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 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 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 |
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 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. 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 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. 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 |
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 |
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 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) |
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) |
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) |
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 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 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) |
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) |
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) |
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) |
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) |
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 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) |
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) |
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) |
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 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) |
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 (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) |
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) |
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) |
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 (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) |
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 (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 (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 (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 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 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 (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 (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 |
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) (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 (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 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 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 | |||
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 (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 (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 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 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 (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 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 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 |
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 |
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 (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 (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 (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 (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 (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) (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 (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 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) $ 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 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 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 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 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 (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 | 50.00% | ||
| 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 (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 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 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 (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 (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 (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) (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) - 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 | ||
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 (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 |
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 (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 (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 (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 (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 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 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 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 | 6.00% |
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 | 20.00% | 20.00% | |
| 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 | 2.00% | 2.00% | |
| Dividend Reinvestment Plan | Maximum | |||
| Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
| Discount from Market Price, Purchase Date | 5.00% | 5.00% | |
Stock-Based Compensation (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 | 10.00% | |
| Dividend Reinvestment Plan | ||
| Stock option plan, Additional information | ||
| Maximum aggregate number of common shares reserved for issuance | 7.0 | |
| 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 | 6.0 | 6.0 |
| Terms of award | P10Y | |
| Share Unit Plans | ||
| Stock option plan, Additional information | ||
| Maximum aggregate number of common shares reserved for issuance | 2.0 | 2.0 |
| First Anniversary | DSU Plan | Executive and senior management | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 25.00% | |
| 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 | 50.00% | |
| 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 | 5.00% | |
| Policy for issuing shares upon exercise | The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | |
| Cash received for options exercised | $ 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 | 25.00% | |
| Stock Option Plan, Granted 2021 | Second Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 25.00% | |
| Stock Option Plan, Granted 2021 | Third Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 25.00% | |
| Stock Option Plan, Granted 2021 | Fourth Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 25.00% | |
| Stock Option Plan, Granted 2022 | First Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 20.00% | |
| Stock Option Plan, Granted 2022 | Second Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 20.00% | |
| Stock Option Plan, Granted 2022 | Third Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 20.00% | |
| Stock Option Plan, Granted 2022 | Fourth Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 20.00% | |
| Stock Option Plan, Granted 2022 | Fifth Anniversary | ||
| Stock option plan, Additional information | ||
| Vesting rights, percentage | 20.00% | |
| Share Unit Plans | Share Unit Plans | ||
| Stock option plan, Additional information | ||
| Share-based payment award, description | The Company has DSU, PSU and RSU plans. 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 (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% |
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 |