40-F
FALSE 0001127248 --12-31 FY ☐ 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:OtherElectricAndRegulatoryMember 2023-01-01 2023-12-31 0001127248 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2023-12-31 0001127248 us-gaap:JointlyOwnedElectricityTransmissionAndDistributionSystemMember us-gaap:OtherEnergyEquipmentMember ema:SeacoastGasTransmissionLlcMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001127248 us-gaap:SeriesEPreferredStockMember 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatoryAssetsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2023-01-01 2023-12-31 0001127248 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:MutualFundMember 2023-12-31 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember 2024-01-01 2024-12-31 0001127248 us-gaap:EmployeeStockOptionMember 2023-12-31 0001127248 ema:TampaElectricDivisionMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember 2023-01-01 2023-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember 2024-12-31 0001127248 dei:BusinessContactMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember ema:ReceivablesMember 2023-01-01 2023-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:EquitySecuritiesOtherMember 2024-12-31 0001127248 us-gaap:EquityContractMember us-gaap:OtherNonoperatingIncomeExpenseMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001127248 us-gaap:SeriesFPreferredStockMember 2024-12-31 0001127248 country:BS 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001127248 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:TampaElectricDivisionMember ema:FloridaElectricUtilityMember 2024-12-31 0001127248 us-gaap:JointlyOwnedElectricityTransmissionAndDistributionSystemMember us-gaap:OtherEnergyEquipmentMember ema:SeacoastGasTransmissionLlcMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MaximumMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommonStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember 2022-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001127248 us-gaap:SeriesFPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2023-12-31 0001127248 ema:NspMaritimeLinkIncMember ema:NspMaritimeLinkIncMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedNetGainLossFromCashFlowHedgesIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommonStockMember 2023-01-01 2023-12-31 0001127248 us-gaap:AdditionalPaidInCapitalMember 2024-01-01 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2023-12-31 0001127248 us-gaap:IntersegmentEliminationMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2024-01-01 2024-12-31 0001127248 us-gaap:IntersegmentEliminationMember 2024-01-01 2024-12-31 0001127248 ema:StockOptionPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember ema:ReceivablesMember 2024-01-01 2024-12-31 0001127248 ema:DividendReinvestmentMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2023-01-01 2023-12-31 0001127248 us-gaap:EmployeeStockOptionMember 2024-01-01 2024-12-31 0001127248 ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:NspMaritimeLinkIncMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:EquityMethodInvestmentsMember 2024-01-01 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:RestrictedShareUnitPlanMember 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:BearSwampPowerCompanyLlcMember ema:EmeraEnergyMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatoryLiabilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:CashCollateralMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryLiabilitiesMember ema:PhysicalNaturalGasPurchasesMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatoryLiabilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember ema:NspMaritimeLinkIncMember 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 ema:TampaElectricDivisionMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember 2023-12-31 0001127248 ema:SeriesJPreferredStockMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2024-12-31 0001127248 us-gaap:SeriesHPreferredStockMember 2023-12-31 0001127248 country:BS 2024-01-01 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementNonemployeeMember ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:OtherElectricAndRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:EquitySecuritiesOtherMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2023-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2021-05-26 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember us-gaap:ParentMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember srt:ParentCompanyMember 2023-12-31 0001127248 ema:BorrowingsUnderCreditFacilitiesMember 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2024-01-01 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AssetsMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 ema:RestrictedShareUnitPlanMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FinancialAssetPastDueMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:EquitySecuritiesOtherMember 2024-12-31 0001127248 us-gaap:SeriesHPreferredStockMember 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember ema:PhysicalNaturalGasPurchasesMember ema:RegulatedFuelForGenerationAndPurchasedMember 2023-01-01 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:EmeraCaribbeanIncorporatedMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesMember srt:MaximumMember country:US 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheOneMember ema:StockOptionPlanGranted2021Member 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 srt:ConsolidationEliminationsMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:OtherElectricAndRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:NoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2024-01-01 2024-12-31 0001127248 ema:GrandBahamaPowerCompanyLimitedMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:GeneralAndAdministrativeExpenseMember us-gaap:EquityContractMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedTranslationAdjustmentMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommonStockMember ema:AtTheMarketEquityProgramMember 2023-01-01 2023-12-31 0001127248 us-gaap:NetInvestmentHedgingMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:DerivativesMember 2024-01-01 2024-12-31 0001127248 us-gaap:NoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:AociDerivativeQualifyingAsHedgeExcludedComponentParentMember 2022-12-31 0001127248 us-gaap:OtherRegulatoryAssetsLiabilitiesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:SeriesEPreferredStockMember 2023-12-31 0001127248 ema:SeriesJPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:EmployeeStockOptionMember ema:VestingPeriodAfterTerminationForJustCauseOrResignationMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaCapAndTradeProgramMember 2023-01-01 2023-12-31 0001127248 ema:StockOptionPlanMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:PerformanceShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2022-12-31 0001127248 ema:AdvancesOnRevolvingCreditFacilitiesMember ema:PeoplesGasSystemMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:EquitySecuritiesOtherMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:GeneralAndAdministrativeExpenseMember us-gaap:ForeignExchangeForwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:LabradorIslandLinkLimitedPartnershipMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:GasUtilitiesAndInfrastructureMember ema:OtherElectricAndRegulatoryMember 2024-01-01 2024-12-31 0001127248 us-gaap:GeneralAndAdministrativeExpenseMember us-gaap:ForeignExchangeForwardMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember 2024-12-31 0001127248 us-gaap:LetterOfCreditMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember 2023-01-01 2023-12-31 0001127248 srt:ConsolidationEliminationsMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2023-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementNonemployeeMember ema:DeferredShareUnitPlansMember 2024-12-31 0001127248 us-gaap:IntersegmentEliminationMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyCommoditiesAndServiceMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:StLuciaElectricityServicesLimitedMember 2024-12-31 0001127248 ema:OtherCommitmentMember 2024-12-31 0001127248 us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember 2022-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:ElectricDistributionMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2023-12-31 0001127248 us-gaap:ElectricDistributionMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2023-12-31 0001127248 us-gaap:SeriesCPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:PeoplesGasSystemMember 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodThreeMember 2024-01-01 2024-12-31 0001127248 us-gaap:EnvironmentalRestorationCostsMember 2023-12-31 0001127248 ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodFourMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommonStockMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2024-12-31 0001127248 us-gaap:AccumulatedTranslationAdjustmentMember 2023-01-01 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember srt:ParentCompanyMember 2024-12-31 0001127248 ema:StockOptionPlanMember 2024-12-31 0001127248 us-gaap:ElectricDistributionMember srt:MinimumMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember us-gaap:OtherCustomerMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember ema:ShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MinimumMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 ema:EmployeeCommonSharePurchasePlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignExchangeContractMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-12-31 0001127248 2022-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2023-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember 2024-12-31 0001127248 ema:FinancialAssetsMember 2023-01-01 2023-12-31 0001127248 ema:DeferredShareUnitPlansMember 2023-01-01 2023-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2024-12-31 0001127248 ema:FuelAndGasSupplyMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:SeriesBPreferredStockMember 2024-12-31 0001127248 ema:EquityDerivativesAndInterestRateSwapsMember 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-01-01 2024-12-31 0001127248 country:CA 2024-01-01 2024-12-31 0001127248 ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember ema:OtherAccountsReceivableMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherEnergyEquipmentMember srt:MaximumMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 srt:SubsidiariesMember 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:EquitySecuritiesOtherMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:EquitySecuritiesOtherMember 2023-12-31 0001127248 us-gaap:StockCompensationPlanMember ema:RestrictedShareUnitPlanMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2024-12-31 0001127248 us-gaap:InventoriesMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-01-01 2024-12-31 0001127248 ema:OtherTaxAuthorityMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:NetInTransitMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:OtherEquityMethodInvesmentsMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 us-gaap:CumulativePreferredStockMember ema:GrandBahamaPowerCompanyLimitedMember 2024-12-31 0001127248 country:BS 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember 2024-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:DeferredShareUnitPlansMember 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatedFuelForGenerationAndPurchasedMember 2023-01-01 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NovaScotiaPowerIncMember 2023-12-31 0001127248 us-gaap:MoneyMarketFundsMember us-gaap:PensionPlansDefinedBenefitMember srt:MinimumMember country:CA 2024-12-31 0001127248 srt:ConsolidationEliminationsMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:OtherElectricAndRegulatoryMember 2024-01-01 2024-12-31 0001127248 ema:GrandBahamaPowerCompanyLimitedMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2024-12-31 0001127248 us-gaap:ElectricGenerationEquipmentMember srt:MinimumMember 2024-01-01 2024-12-31 0001127248 us-gaap:ElectricTransmissionMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:BbbMinusToBbbPlusRatingMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:ElectricityPurchasedMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 ema:RestrictedShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:NotesPayableToBanksMember srt:ParentCompanyMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatoryAssetsMember 2023-01-01 2023-12-31 0001127248 us-gaap:DomesticCountryMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:RepsolEnergyCanadaMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:MaritimesAndNortheastPipelineMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryLiabilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember 2023-01-01 2023-12-31 0001127248 us-gaap:StockCompensationPlanMember ema:PerformanceShareUnitPlanMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:AMinusRatingMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesGPreferredStockMember ema:AfterFebruary152025Member 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:BearSwampPowerCompanyLlcMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesCPreferredStockMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:PeoplesGasSystemMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember 2024-01-01 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember ema:RestrictedShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommonStockMember 2024-12-31 0001127248 ema:GrandBahamaPowerCompanyLimitedMember 2024-01-01 2024-12-31 0001127248 us-gaap:RetainedEarningsMember 2023-01-01 2023-12-31 0001127248 ema:SelfInsruanceFundMember 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:OpenEndedInvesmentsMeasuredAtNavMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:AMinusRatingMember ema:DerivativesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:MaritimesAndNortheastPipelineMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember srt:ConsolidationEliminationsMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredDerivativeGainLossMember 2023-12-31 0001127248 us-gaap:CommonStockMember 2022-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain 2024-12-31 0001127248 us-gaap:SuretyBondMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedCompensationAwardTrancheOneMember srt:ManagementMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionAndOtherPostretirementPlansCostsMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:BearSwampPowerCompanyLlcMember 2023-01-01 2023-12-31 0001127248 srt:MaximumMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:BbbMinusToBbbPlusRatingMember ema:DerivativesMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCountryMember ema:TaxCreditCarryForwardsMember 2024-12-31 0001127248 us-gaap:CommonStockMember 2024-12-31 0001127248 us-gaap:PreferredStockMember 2022-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:LabradorIslandLinkLimitedPartnershipMember 2024-01-01 2024-12-31 0001127248 us-gaap:ElectricTransmissionMember srt:MinimumMember 2024-01-01 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember us-gaap:DeferredCompensationShareBasedPaymentsMember ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember ema:OtherAccountsReceivableMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesEPreferredStockMember 2024-01-01 2024-12-31 0001127248 ema:PerformanceShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:OtherEnergyEquipmentMember 2024-12-31 0001127248 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:SeriesBPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:EmployeeStockOptionMember 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember srt:MaximumMember country:CA 2024-12-31 0001127248 us-gaap:AociDerivativeQualifyingAsHedgeExcludedComponentParentMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:MaritimesAndNortheastPipelineMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:RestrictedShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:MaritimesAndNortheastPipelineMember ema:GasUtilitiesAndInfrastructureMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyCommoditiesAndServiceMember srt:ConsolidationEliminationsMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:BearSwampPowerCompanyLlcMember 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember 2024-12-31 0001127248 us-gaap:ForeignCountryMember ema:OperatingLossCarryforwardMember 2024-12-31 0001127248 us-gaap:SeriesAPreferredStockMember 2024-12-31 0001127248 ema:OtherTaxAuthorityMember ema:OperatingLossCarryforwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember 2024-01-01 2024-12-31 0001127248 us-gaap:OilAndGasServiceMember 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:OtherRegulatoryMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredDerivativeGainLossMember 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:GrandBahamaPowerCompanyLimitedMember ema:OtherElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember ema:PhysicalNaturalGasPurchasesMember ema:OtherRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member 2024-12-31 0001127248 srt:FuelMember ema:DerivativeInstrumentSettlementPeriodOneMember ema:PhysicalNaturalGasPurchasesMember 2024-01-01 2024-12-31 0001127248 ema:SeriesLPreferredStockMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NonRevolvingCreditAgreementMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredDerivativeGainLossMember 2024-12-31 0001127248 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember 2022-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyCommoditiesAndServiceMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:MutualFundMember 2024-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheTwoMember ema:StockOptionPlanGranted2021Member 2024-01-01 2024-12-31 0001127248 ema:SeriesLPreferredStockMember ema:AfterNovember152030Member 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatedFuelForGenerationAndPurchasedMember 2023-01-01 2023-12-31 0001127248 srt:ConsolidationEliminationsMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesHPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:OtherElectricAndRegulatoryMember 2024-01-01 2024-12-31 0001127248 ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:CumulativePreferredStockMember ema:GrandBahamaPowerCompanyLimitedMember 2023-12-31 0001127248 us-gaap:InterestRateContractMember us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedNetGainLossFromCashFlowHedgesIncludingPortionAttributableToNoncontrollingInterestMember 2023-01-01 2023-12-31 0001127248 country:BS 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2024-12-31 0001127248 ema:RenewableNaturalGasFacilityMember 2023-10-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2023-12-31 0001127248 us-gaap:LetterOfCreditMember 2024-12-31 0001127248 ema:FirstPreferredSharesMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:StLuciaElectricityServicesLimitedMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryLiabilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 ema:SeriesJPreferredStockMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:NetInTransitMember 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatedFuelForGenerationAndPurchasedMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:OtherElectricAndRegulatoryMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredIncomeTaxChargesMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember ema:PhysicalNaturalGasPurchasesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:OtherElectricUtilitiesMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:MutualFundMember us-gaap:FairValueInputsLevel12And3Member 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:OtherEquityMethodInvesmentsMember 2023-12-31 0001127248 us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NewMexicoGasCompanyMember 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:DeferredShareUnitPlansMember 2023-12-31 0001127248 us-gaap:StateAndLocalJurisdictionMember ema:OperatingLossCarryforwardMember 2024-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementNonemployeeMember ema:DeferredShareUnitPlansMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2024-12-31 0001127248 us-gaap:AdditionalPaidInCapitalMember 2023-01-01 2023-12-31 0001127248 us-gaap:ForeignCountryMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember ema:RepsolEnergyCanadaMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember 2024-12-31 0001127248 us-gaap:ForeignExchangeContractMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2022-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:GasUtilitiesAndInfrastructureMember ema:OtherElectricAndRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:AdditionalPaidInCapitalMember 2023-12-31 0001127248 us-gaap:PreferredStockMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TecoFinanceIncMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:AMinusRatingMember 2023-01-01 2023-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:ElectricTransmissionMember srt:MaximumMember 2024-01-01 2024-12-31 0001127248 us-gaap:MutualFundMember us-gaap:FairValueInputsLevel12And3Member 2024-12-31 0001127248 ema:NspMaritimeLinkIncMember ema:NspMaritimeLinkIncMember 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodFiveMember 2024-01-01 2024-12-31 0001127248 us-gaap:StockCompensationPlanMember us-gaap:DeferredCompensationShareBasedPaymentsMember srt:DirectorMember ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:FloridaElectricUtilityMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 ema:SeriesLPreferredStockMember 2023-12-31 0001127248 ema:EmployeeCommonSharePurchasePlanMember 2023-01-01 2023-12-31 0001127248 ema:TampaElectricPeoplesGasSystemDivisionAndNewMexicoGasCompanyMember 2024-12-31 0001127248 ema:GrandBahamaPowerCompanyLimitedMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiiMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedTranslationAdjustmentMember 2024-12-31 0001127248 us-gaap:EquityContractMember us-gaap:OtherNonoperatingIncomeExpenseMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:NotRatedMember ema:DerivativesMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2023-12-31 0001127248 us-gaap:RetainedEarningsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2024-12-31 0001127248 ema:SeriesLPreferredStockMember ema:OnOrAfterNovember152026ToNovember152027Member 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember 2023-12-31 0001127248 ema:ShareBasedCompensationAwardTrancheFourMember ema:StockOptionPlanGranted2022Member 2024-01-01 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember 2023-01-01 2023-12-31 0001127248 us-gaap:StateAndLocalJurisdictionMember ema:OperatingLossCarryforwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:OtherElectricAndRegulatoryMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MaximumMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:InventoriesMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-01-01 2023-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:AdvancesOnRevolvingCreditFacilitiesMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheThreeMember ema:StockOptionPlanGranted2022Member 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesAPreferredStockMember 2024-01-01 2024-12-31 0001127248 ema:PerformanceShareUnitPlanMember 2023-01-01 2023-12-31 0001127248 us-gaap:NoncontrollingInterestMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:EmployeeStockOptionMember ema:VestingPeriodAfterDateOfRetirementMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:IntersegmentEliminationMember us-gaap:ElectricityMember 2023-01-01 2023-12-31 0001127248 ema:CommonShareholdersDividendReinvestmentAndSharePurchasePlanMember 2024-12-31 0001127248 country:CA 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 country:US 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:CanadianElectricUtilitiesMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:NotRatedMember ema:DerivativesMember 2024-01-01 2024-12-31 0001127248 us-gaap:SuretyBondMember 2024-12-31 0001127248 us-gaap:RetainedEarningsMember 2022-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 ema:NonRevolvingCreditAgreementMember ema:NmgcMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2024-12-31 0001127248 us-gaap:FinancialAssetPastDueMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 ema:DividendReinvestmentMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:EmeraCaribbeanIncorporatedMember 2023-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2024-01-01 2024-12-31 0001127248 ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2023-12-31 0001127248 us-gaap:InventoriesMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember 2023-12-31 0001127248 us-gaap:PreferredStockMember 2023-12-31 0001127248 us-gaap:EquityContractMember 2024-01-01 2024-12-31 0001127248 us-gaap:IntersegmentEliminationMember 2024-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:ReceivablesAndDerivativesMember 2024-01-01 2024-12-31 0001127248 us-gaap:DeferredIncomeTaxChargesMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 ema:PeoplesGasSystemDivisionMember ema:SeacoastGasTransmissionLlcMember 2024-12-31 0001127248 us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:NetInTransitMember 2023-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:AMinusRatingMember ema:DerivativesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FixedIncomeSecuritiesMember us-gaap:PensionPlansDefinedBenefitMember srt:MaximumMember country:CA 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember 2023-01-01 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2023-12-31 0001127248 us-gaap:ForeignExchangeForwardMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:WeightedAverageMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 ema:SeacoastGasTransmissionLlcMember ema:TampaElectricPeoplesGasSystemDivisionAndNewMexicoGasCompanyMember 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:NetInTransitMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:FixedIncomeSecuritiesMember us-gaap:PensionPlansDefinedBenefitMember srt:MaximumMember country:US 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:EquitySecuritiesOtherMember 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember 2023-01-01 2023-12-31 0001127248 country:BB 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:StLuciaElectricityServicesLimitedMember 2023-12-31 0001127248 us-gaap:DomesticCountryMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesCPreferredStockMember 2024-12-31 0001127248 us-gaap:SeriesFPreferredStockMember 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:PerformanceShareUnitPlanMember 2024-12-31 0001127248 ema:AdvancesOnRevolvingCreditFacilitiesMember ema:PeoplesGasSystemMember 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RemovalCostsMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 us-gaap:StockCompensationPlanMember ema:PerformanceShareUnitPlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 us-gaap:ElectricDistributionMember srt:MaximumMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember 2024-01-01 2024-12-31 0001127248 us-gaap:PaymentGuaranteeMember ema:SeacoastGasTransmissionLlcMember 2024-12-31 0001127248 us-gaap:RetainedEarningsMember 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember srt:MinimumMember country:US 2024-12-31 0001127248 us-gaap:StrandedCostsMember 2023-12-31 0001127248 us-gaap:GasTransmissionAndDistributionEquipmentMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:StLuciaElectricityServicesLimitedMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:ForeignCountryMember 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:PerformanceShareUnitPlanMember 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodFourMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:ReceivablesAndDerivativesMember 2023-01-01 2023-12-31 0001127248 us-gaap:GeneralAndAdministrativeExpenseMember us-gaap:EquityContractMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember us-gaap:OtherCustomerMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:NspMaritimeLinkIncMember 2023-12-31 0001127248 us-gaap:DomesticCountryMember ema:OperatingLossCarryforwardMember 2024-12-31 0001127248 ema:EquityDerivativesAndInterestRateSwapsMember 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:AociDerivativeQualifyingAsHedgeExcludedComponentParentMember 2023-01-01 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:NspMaritimeLinkIncMember 2023-01-01 2023-12-31 0001127248 ema:OtherEntitiesMember ema:RevolvingCreditFacilityIiiMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:NotRatedMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember 2023-12-31 0001127248 ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember srt:ConsolidationEliminationsMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:BbbMinusToBbbPlusRatingMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:StormCostsMember 2024-12-31 0001127248 us-gaap:NoncontrollingInterestMember 2022-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2023-12-31 0001127248 ema:PowerSwapsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 ema:OtherTaxAuthorityMember ema:OperatingLossCarryforwardMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2024-12-31 0001127248 us-gaap:SeriesBPreferredStockMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember 2023-01-01 2023-12-31 0001127248 us-gaap:ElectricGenerationEquipmentMember 2023-12-31 0001127248 srt:ConsolidationEliminationsMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryAssetsMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:RestrictedShareUnitPlanMember 2024-12-31 0001127248 us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCountryMember 2023-01-01 2023-12-31 0001127248 ema:SelfInsruanceFundMember 2023-12-31 0001127248 us-gaap:NetInvestmentHedgingMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:ElectricityPurchasedMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:PreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:OtherEquityMethodInvesmentsMember 2023-12-31 0001127248 ema:OtherEntitiesMember ema:RevolvingCreditFacilityIiiMember 2023-12-31 0001127248 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2022-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:IntersegmentEliminationMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2023-12-31 0001127248 us-gaap:PensionAndOtherPostretirementPlansCostsMember 2024-12-31 0001127248 us-gaap:OtherRegulatoryAssetsLiabilitiesMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyServiceMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:RepsolEnergyCanadaMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:LetterOfCreditMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:MutualFundMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:OtherRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:JointlyOwnedElectricityTransmissionAndDistributionSystemMember us-gaap:OtherEnergyEquipmentMember ema:SeacoastGasTransmissionLlcMember 2022-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 country:BB 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember srt:ConsolidationEliminationsMember ema:OtherElectricAndRegulatoryMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:CashCollateralMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:NetInTransitMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:MutualFundMember 2024-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodFourMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:EmeraCaribbeanIncorporatedMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember 2023-12-31 0001127248 us-gaap:SeriesDPreferredStockMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember 2023-12-31 0001127248 us-gaap:SeriesGPreferredStockMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:MaritimesAndNortheastPipelineMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2023-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheTwoMember ema:StockOptionPlanGranted2022Member 2024-01-01 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:ElectricityPurchasedMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:ForeignExchangeForwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:FixedIncomeSecuritiesMember us-gaap:PensionPlansDefinedBenefitMember srt:MinimumMember country:US 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryAssetsMember ema:PhysicalNaturalGasPurchasesMember 2023-01-01 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember srt:MaximumMember country:US 2024-12-31 0001127248 us-gaap:CumulativePreferredStockMember ema:GrandBahamaPowerCompanyLimitedMember ema:UnitedStatesDollarPreferredStockMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:MaritimesAndNortheastPipelineMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember 2023-01-01 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TecoFinanceIncMember 2023-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember 2023-01-01 2023-12-31 0001127248 ema:SeriesIPreferredStockMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommodityContractMember srt:FuelMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:OilAndGasMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:GasUtilitiesAndInfrastructureMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 ema:ShareBasedCompensationAwardTrancheFourMember ema:StockOptionPlanGranted2021Member 2024-01-01 2024-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:GasUtilitiesAndInfrastructureMember ema:FinanceIncomeMember 2024-01-01 2024-12-31 0001127248 us-gaap:DomesticCountryMember ema:OperatingLossCarryforwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 ema:FinancialAssetsMember 2024-01-01 2024-12-31 0001127248 ema:SeriesLPreferredStockMember 2024-12-31 0001127248 us-gaap:ForeignCountryMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember 2023-01-01 2023-12-31 0001127248 country:BB 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember srt:ConsolidationEliminationsMember ema:RepsolEnergyCanadaMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:BrooklynPowerCorporationMember 2024-12-31 0001127248 us-gaap:ForeignExchangeForwardMember us-gaap:OtherNonoperatingIncomeExpenseMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member 2023-12-31 0001127248 us-gaap:DeferredIncomeTaxChargesMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementNonemployeeMember ema:DeferredShareUnitPlansMember 2023-12-31 0001127248 srt:FuelMember ema:DerivativeInstrumentSettlementPeriodTwoMember ema:PhysicalNaturalGasPurchasesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:DeferredIncomeTaxChargesMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2024-12-31 0001127248 ema:AdvancesUnderRevolvingCreditAndTermFacilitiesMember 2023-12-31 0001127248 ema:OtherTaxAuthorityMember 2024-01-01 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodThreeMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2023-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheOneMember ema:StockOptionPlanGranted2022Member 2024-01-01 2024-12-31 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember 2023-01-01 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel12And3Member 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:AociDerivativeQualifyingAsHedgeExcludedComponentParentMember 2024-12-31 0001127248 us-gaap:DomesticCountryMember 2023-12-31 0001127248 us-gaap:CommonStockMember ema:AtTheMarketEquityProgramMember 2024-01-01 2024-12-31 0001127248 us-gaap:SeriesDPreferredStockMember ema:AfterAugust152028Member 2024-12-31 0001127248 us-gaap:ForeignExchangeForwardMember us-gaap:OtherNonoperatingIncomeExpenseMember 2024-01-01 2024-12-31 0001127248 us-gaap:MutualFundMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2024-12-31 0001127248 us-gaap:NotesPayableToBanksMember srt:ParentCompanyMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:DeferredShareUnitPlansMember 2024-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 ema:NonRevolvingCreditAgreementMember ema:NmgcMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:OtherEquityMethodInvesmentsMember 2023-12-31 0001127248 us-gaap:InterestRateContractMember us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedNetGainLossFromCashFlowHedgesIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:LabradorIslandLinkLimitedPartnershipMember 2024-12-31 0001127248 ema:BearSwampPowerCompanyLlcMember 2015-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:PeoplesGasSystemMember 2024-12-31 0001127248 us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:FixedIncomeSecuritiesMember us-gaap:PensionPlansDefinedBenefitMember srt:MinimumMember country:CA 2024-12-31 0001127248 ema:EciMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember ema:NotRatedMember 2024-01-01 2024-12-31 0001127248 country:BB 2023-12-31 0001127248 us-gaap:StrandedCostsMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NonRevolvingCreditAgreementMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:LabradorIslandLinkLimitedPartnershipMember 2023-12-31 0001127248 us-gaap:NetInvestmentHedgingMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:CanadianElectricUtilitiesMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:DeferredCompensationShareBasedPaymentsMember us-gaap:ShareBasedPaymentArrangementEmployeeMember ema:DeferredShareUnitPlansMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2023-12-31 0001127248 srt:ConsolidationEliminationsMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesMember srt:MinimumMember country:US 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:OtherElectricUtilitiesMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:DerivativesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:DerivativeFinancialInstrumentsAssetsMember ema:BbbMinusToBbbPlusRatingMember ema:DerivativesMember 2023-01-01 2023-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:OtherElectricAndRegulatoryMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:CommonShareholdersDividendReinvestmentAndSharePurchasePlanMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCountryMember ema:TaxCreditCarryForwardsMember 2024-01-01 2024-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member 2024-12-31 0001127248 ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:OtherEnergyEquipmentMember srt:MinimumMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:NetInTransitMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 ema:CommonShareholdersDividendReinvestmentAndSharePurchasePlanMember 2024-01-01 2024-12-31 0001127248 srt:ConsolidationEliminationsMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyCommoditiesAndServiceMember srt:ConsolidationEliminationsMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2023-12-31 0001127248 ema:SyndicatedCreditFacilitiesMember 2024-12-31 0001127248 us-gaap:StormCostsMember 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member 2023-12-31 0001127248 srt:ConsolidationEliminationsMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:RemovalCostsMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:BarbadosLightAndPowerCompanyLimitedMember ema:OtherElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember srt:ConsolidationEliminationsMember ema:OtherElectricAndRegulatoryMember ema:OtherProjectAndServicesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:IndustrialCustomerClassMember 2023-01-01 2023-12-31 0001127248 ema:BearSwampPowerCompanyLlcMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityContractMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:RegulatoryAssetsMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2024-12-31 0001127248 ema:GrandBahamaPowerCompanyLimitedMember 2024-12-31 0001127248 ema:PeoplesGasSystemDivisionMember ema:GasUtilitiesAndInfrastructureMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2024-12-31 0001127248 us-gaap:OtherEnergyEquipmentMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:FloridaElectricUtilityMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 us-gaap:DomesticCountryMember us-gaap:CapitalLossCarryforwardMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherRegulatoryAssetsLiabilitiesMember 2023-12-31 0001127248 us-gaap:OtherRegulatoryAssetsLiabilitiesMember 2024-12-31 0001127248 us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 country:CA 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2023-12-31 0001127248 us-gaap:GasTransmissionAndDistributionEquipmentMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 us-gaap:ShareBasedCompensationAwardTrancheThreeMember ema:StockOptionPlanGranted2021Member 2024-01-01 2024-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember 2023-12-31 0001127248 us-gaap:ElectricGenerationEquipmentMember 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:TradingAssetsExcludingDebtAndEquitySecuritiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TecoFinanceIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member 2024-12-31 0001127248 ema:BorrowingsUnderCreditFacilitiesMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:RegulatedOperationMember us-gaap:AccountsReceivableMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:CanadianElectricUtilitiesMember ema:OtherElectricAndRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:StockCompensationPlanMember us-gaap:DeferredCompensationShareBasedPaymentsMember srt:ManagementMember ema:DeferredShareUnitPlansMember 2024-01-01 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodFiveMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:EnergyCommoditiesAndServiceMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesMember srt:MinimumMember country:CA 2024-12-31 0001127248 us-gaap:DomesticCountryMember us-gaap:CapitalLossCarryforwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:LetterOfCreditMember 2023-12-31 0001127248 us-gaap:AdditionalPaidInCapitalMember 2022-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 srt:ScenarioForecastMember ema:NovaScotiaPowerIncMember 2025-01-01 2025-12-31 0001127248 us-gaap:UnregulatedOperationMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NonRevolvingCreditAgreementMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-12-31 0001127248 us-gaap:FairValueDisclosureItemAmountsDomain 2023-12-31 0001127248 srt:ParentCompanyMember ema:NonRevolvingCreditAgreementMember 2024-01-01 2024-12-31 0001127248 ema:SeriesIPreferredStockMember 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2023-12-31 0001127248 srt:ConsolidationEliminationsMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:DesignatedAsHedgingInstrumentMember us-gaap:ForeignExchangeForwardMember ema:RegulatedFuelForGenerationAndPurchasedMember 2024-01-01 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesMember srt:MaximumMember country:CA 2024-12-31 0001127248 us-gaap:FairValueInputsLevel12And3Member ema:NetInTransitMember 2023-12-31 0001127248 us-gaap:ForeignCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2024-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2021-05-26 2021-05-26 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:EnergyCommoditiesAndServiceMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member 2023-12-31 0001127248 us-gaap:InventoriesMember us-gaap:DesignatedAsHedgingInstrumentMember ema:PhysicalNaturalGasPurchasesMember 2023-01-01 2023-12-31 0001127248 us-gaap:JointlyOwnedElectricityGenerationPlantMember ema:NovaScotiaPowerIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsPhysicalContractsMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:RegulatedOperationMember us-gaap:AssetsMember 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2023-12-31 0001127248 us-gaap:InventoriesMember us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:BearSwampPowerCompanyLlcMember 2023-12-31 0001127248 ema:BearSwampPowerCompanyLlcMember 2024-12-31 0001127248 ema:StockOptionPlanGranted2022Member ema:ShareBasedCompensationAwardTrancheFiveMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 ema:AdvancesUnderRevolvingCreditAndTermFacilitiesMember 2024-12-31 0001127248 us-gaap:ElectricTransmissionMember 2023-12-31 0001127248 us-gaap:ForeignCountryMember ema:OperatingLossCarryforwardMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NewMexicoGasCompanyMember 2023-12-31 0001127248 ema:AtTheMarketEquityProgramMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member ema:EquitySecuritiesOtherMember 2023-12-31 0001127248 us-gaap:JointlyOwnedElectricityGenerationPlantMember ema:NovaScotiaPowerIncMember 2023-01-01 2023-12-31 0001127248 us-gaap:EnvironmentalRestorationCostsMember 2024-12-31 0001127248 srt:ConsolidationEliminationsMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember ema:MarkToMarketMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember 2023-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member 2024-12-31 0001127248 us-gaap:ElectricGenerationEquipmentMember srt:MaximumMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:GasUtilitiesAndInfrastructureMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 country:US 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:RepsolEnergyCanadaMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember srt:ParentCompanyMember 2024-01-01 2024-12-31 0001127248 us-gaap:MoneyMarketFundsMember us-gaap:PensionPlansDefinedBenefitMember srt:MaximumMember country:CA 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:CommercialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:GasTransmissionAndDistributionEquipmentMember srt:MinimumMember 2024-01-01 2024-12-31 0001127248 us-gaap:GasTransmissionAndDistributionEquipmentMember srt:MaximumMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:IntersegmentEliminationMember us-gaap:OilAndGasMember 2023-01-01 2023-12-31 0001127248 us-gaap:SeriesAPreferredStockMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:ResidentialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NovaScotiaPowerIncMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodThreeMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:EnergyCommoditiesAndServiceMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 ema:MaritimeLinkProjectMember 2024-01-01 2024-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:MaritimesAndNortheastPipelineMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:OtherRegulatoryMember 2024-01-01 2024-12-31 0001127248 ema:LongLivedAssetsMember 2023-01-01 2023-12-31 0001127248 us-gaap:EmployeeStockOptionMember ema:VestingPeriodAfterTerminationWithoutJustCauseOrDeathMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:OilAndGasMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:AccumulatedTranslationAdjustmentMember 2022-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MinimumMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodThreeMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:RegulatoryDeferralsMember 2023-01-01 2023-12-31 0001127248 us-gaap:MutualFundMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember 2023-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 country:US 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiiMember 2024-12-31 0001127248 us-gaap:EquityMethodInvestmentsMember 2023-01-01 2023-12-31 0001127248 us-gaap:DomesticCountryMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:ForeignGovernmentDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedNetGainLossFromCashFlowHedgesIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:ShareBasedPaymentArrangementNonemployeeMember ema:DeferredShareUnitPlansMember 2024-12-31 0001127248 us-gaap:OtherDebtSecuritiesMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember srt:ConsolidationEliminationsMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 ema:TampaElectricDivisionMember ema:RevolvingCreditFacilityIiiMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:RepsolEnergyCanadaMember ema:FloridaElectricUtilityMember ema:FinanceIncomeMember 2023-01-01 2023-12-31 0001127248 us-gaap:CommodityContractMember srt:FuelMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member ema:OpenEndedInvesmentsMeasuredAtNavMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodFourMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:IndustrialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:ResidentialCustomerClassMember 2023-01-01 2023-12-31 0001127248 us-gaap:DeferredDerivativeGainLossMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NewMexicoGasCompanyMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember us-gaap:ElectricityMember ema:OtherElectricMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:WeightedAverageMember ema:NaturalGasSwapsFuturesForwardsAndPhysicalContractsMember 2023-12-31 0001127248 ema:SeriesLPreferredStockMember ema:AfterNovember152027ToNovember152030Member 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember srt:MinimumMember country:CA 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember srt:ConsolidationEliminationsMember ema:RegulatoryDeferralsMember 2024-01-01 2024-12-31 0001127248 us-gaap:ReclassificationOutOfAccumulatedOtherComprehensiveIncomeMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember 2024-01-01 2024-12-31 0001127248 us-gaap:SteamPlantMember ema:GrandBahamaPowerCompanyLimitedMember 2024-01-01 2024-12-31 0001127248 country:US 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember 2023-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:NovaScotiaPowerIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommodityContractMember us-gaap:DesignatedAsHedgingInstrumentMember ema:OtherRegulatoryMember 2023-01-01 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:NetInTransitMember 2023-12-31 0001127248 us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember ema:OpenEndedInvesmentsMeasuredAtNavMember 2023-12-31 0001127248 ema:SeriesIPreferredStockMember ema:AfterAugust152028Member 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:ElectricityMember ema:OtherElectricMember 2023-01-01 2023-12-31 0001127248 ema:NonRevolvingCreditAgreementMember ema:NmgcMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityMember ema:OtherElectricUtilitiesMember ema:CommercialCustomerClassMember 2024-01-01 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember ema:MarkToMarketMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember ema:OtherElectricAndRegulatoryMember ema:OtherProjectAndServicesMember 2024-01-01 2024-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:CostOfSalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember ema:DerivativeInstrumentSettlementPeriodFiveMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:ForeignExchangeForwardMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:EquityMethodInvesteeMember ema:NspMaritimeLinkIncMember 2024-12-31 0001127248 us-gaap:SalesMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember ema:DerivativeInstrumentSettlementPeriodFiveMember 2024-01-01 2024-12-31 0001127248 us-gaap:NetInvestmentHedgingMember 2024-12-31 0001127248 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2024-12-31 0001127248 us-gaap:AdditionalPaidInCapitalMember 2024-12-31 0001127248 us-gaap:NoncontrollingInterestMember 2024-12-31 0001127248 us-gaap:PreferredStockMember 2024-12-31 0001127248 us-gaap:RetainedEarningsMember 2024-12-31 0001127248 us-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember ema:NspMaritimeLinkIncMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:FloridaElectricUtilityMember ema:SeniorUnsecuredBondsDueMarch12029Member 2024-01-30 0001127248 ema:TampaElectricDivisionMember ema:FloridaElectricUtilityMember ema:SeniorUnsecuredBondsDueMarch12029Member 2024-01-30 2024-01-30 0001127248 ema:NalcorEnergyMember 2024-01-01 2024-12-31 0001127248 ema:LabradorIslandLinkLimitedPartnershipMember 2024-06-04 2024-06-04 0001127248 ema:NmgcMember 2024-12-31 0001127248 ema:CertainLongLivedAssetsMember 2024-01-01 2024-12-31 0001127248 ema:IncludedInOtherIncomeNetMember 2024-01-01 2024-12-31 0001127248 ema:LongLivedAssetsMember 2024-01-01 2024-12-31 0001127248 ema:VariousCanadianAndUsGovernmentAgenciesMember 2024-01-01 2024-12-31 0001127248 ema:VariousCanadianAndUsGovernmentAgenciesMember 2023-01-01 2023-12-31 0001127248 ema:NaturalResourcesCanadaSmartRenewablesElectrificationPathwaysMember 2024-01-01 2024-12-31 0001127248 ema:NaturalResourcesCanadaSmartRenewablesElectrificationPathwaysMember 2023-01-01 2023-12-31 0001127248 ema:NewMexicoGasCompanyMember 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember 2024-08-05 0001127248 ema:NewMexicoGasCompanyMember 2024-07-01 2024-09-30 0001127248 ema:NewMexicoGasCompanyMember 2024-08-05 2024-12-31 0001127248 ema:LabradorIslandLinkMember 2024-06-04 2024-06-04 0001127248 ema:LabradorIslandLinkMember 2024-06-04 0001127248 ema:LabradorIslandLinkMember 2024-12-31 0001127248 ema:LabradorIslandLinkMember 2024-04-01 2024-06-30 0001127248 country:CA 2024-12-31 0001127248 ema:IncrementalTaxBenefitsPayableToCustomersMember 2023-12-21 0001127248 ema:IncrementalTaxBenefitsPayableToCustomersMember 2024-12-31 0001127248 us-gaap:DomesticCountryMember ema:TaxCreditCarryForwardsMember 2024-12-31 0001127248 us-gaap:DomesticCountryMember ema:TaxCreditCarryForwardsMember 2024-01-01 2024-12-31 0001127248 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2023-12-31 0001127248 us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember 2023-12-31 0001127248 us-gaap:AociDerivativeQualifyingAsHedgeExcludedComponentParentMember 2023-12-31 0001127248 us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember 2023-12-31 0001127248 us-gaap:AccumulatedTranslationAdjustmentMember 2023-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2023-01-01 2023-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2024-01-01 2024-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2024-12-31 0001127248 us-gaap:TreasuryLockMember us-gaap:CashFlowHedgingMember 2023-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:DiscontinuedOperationsHeldforsaleMember 2024-01-01 2024-12-31 0001127248 us-gaap:CreditConcentrationRiskMember us-gaap:AccountsReceivableMember us-gaap:DiscontinuedOperationsHeldforsaleMember 2023-01-01 2023-12-31 0001127248 ema:NewMexicoGasCompanyMember 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember 2023-12-31 0001127248 ema:TampaElectricDivisionMember 2024-07-12 2024-07-12 0001127248 us-gaap:ConstructionContractsMember 2024-12-31 0001127248 us-gaap:OilAndGasServiceMember ema:NmgcMember 2024-12-31 0001127248 ema:FuelAndGasSupplyMember ema:NmgcMember 2024-12-31 0001127248 us-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember ema:NspMaritimeLinkIncMember ema:BondUnderFederalLoanGuaranteeMember 2024-12-31 0001127248 ema:TecCapitalCostRecoveryForRetiredPolkUnit1ComponentsMember 2024-12-31 0001127248 ema:TecCapitalCostRecoveryForRetiredPolkUnit1ComponentsMember 2023-12-31 0001127248 srt:MinimumMember ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 srt:MinimumMember ema:TampaElectricDivisionMember 2023-01-01 2023-12-31 0001127248 srt:MaximumMember ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:TampaElectricDivisionMember 2023-01-01 2023-12-31 0001127248 ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember ema:TampaElectricDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatoryClauseRevenuesUnderRecoveredMember ema:TampaElectricDivisionMember 2023-01-01 2023-12-31 0001127248 ema:TampaElectricDivisionMember ema:Year2025Member ema:PublicUtilitiesBaseRateMember 2024-12-03 2024-12-03 0001127248 ema:TampaElectricDivisionMember ema:Year2026Member ema:PublicUtilitiesBaseRateMember 2024-12-03 2024-12-03 0001127248 ema:TampaElectricDivisionMember ema:Year2027Member ema:PublicUtilitiesBaseRateMember 2024-12-03 2024-12-03 0001127248 ema:TampaElectricDivisionMember ema:Year2025Member 2024-12-03 2024-12-03 0001127248 ema:TampaElectricDivisionMember ema:Year2026Member 2024-12-03 2024-12-03 0001127248 ema:TampaElectricDivisionMember ema:Year2027Member 2024-12-03 2024-12-03 0001127248 srt:MinimumMember ema:TampaElectricDivisionMember ema:Year2025Member 2024-12-03 2024-12-03 0001127248 srt:MinimumMember ema:TampaElectricDivisionMember ema:Year2026Member 2024-12-03 2024-12-03 0001127248 srt:MinimumMember ema:TampaElectricDivisionMember ema:Year2027Member 2024-12-03 2024-12-03 0001127248 srt:MaximumMember ema:TampaElectricDivisionMember ema:Year2025Member 2024-12-03 2024-12-03 0001127248 srt:MaximumMember ema:TampaElectricDivisionMember ema:Year2026Member 2024-12-03 2024-12-03 0001127248 srt:MaximumMember ema:TampaElectricDivisionMember ema:Year2027Member 2024-12-03 2024-12-03 0001127248 srt:MedianMember ema:TampaElectricDivisionMember ema:Year2025Member 2024-12-03 2024-12-03 0001127248 srt:MedianMember ema:TampaElectricDivisionMember ema:Year2026Member 2024-12-03 2024-12-03 0001127248 srt:MedianMember ema:TampaElectricDivisionMember ema:Year2027Member 2024-12-03 2024-12-03 0001127248 srt:FuelMember ema:TampaElectricDivisionMember ema:June2024ToMay2025Member 2024-05-07 2024-05-07 0001127248 srt:FuelMember ema:TampaElectricDivisionMember ema:StartingApril12023Member 2023-03-07 2023-03-07 0001127248 srt:FuelMember ema:TampaElectricDivisionMember ema:Year2023Member 2023-03-07 2023-03-07 0001127248 ema:TampaElectricDivisionMember ema:HurricaneHeleneReserveMember 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:HurricaneMiltonMember 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:StormReserveMember 2024-12-31 0001127248 ema:TampaElectricDivisionMember ema:StormReserveMember 2024-01-01 2024-12-31 0001127248 ema:TampaElectricDivisionMember 2022-09-01 2022-09-30 0001127248 ema:TampaElectricDivisionMember ema:StormReserveMember 2023-01-23 0001127248 ema:TampaElectricDivisionMember ema:StormReserveMember 2023-08-16 0001127248 ema:TampaElectricDivisionMember ema:StormReserveMember 2023-01-01 2023-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:NovaScotiaPowerIncMember ema:NspMaritimeLinkIncMember ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 ema:FloridaElectricUtilityMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:FloridaElectricUtilityMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 ema:FloridaElectricUtilityMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 us-gaap:CommercialPaperMember ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:CommercialPaperMember ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2023-12-31 0001127248 us-gaap:CommercialPaperMember ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2023-12-31 0001127248 ema:PeoplesGasSystemDivisionMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 ema:PeoplesGasSystemDivisionMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 ema:PeoplesGasSystemDivisionMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:UnsecuredLoanNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:UnsecuredLoanNotesOneMember 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:UnsecuredLoanNotesOneMember 2023-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember ema:NewMexicoGasIntermediateMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember ema:NewMexicoGasIntermediateMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember ema:NewMexicoGasIntermediateMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember ema:GasUtilitiesAndInfrastructureMember ema:SecuredLoanNotesMember 2024-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember ema:GasUtilitiesAndInfrastructureMember ema:SecuredLoanNotesMember 2023-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember ema:GasUtilitiesAndInfrastructureMember ema:SecuredLoanNotesMember 2024-01-01 2024-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember 2024-12-31 0001127248 ema:GasUtilitiesAndInfrastructureMember 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesOneMember 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesOneMember 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesTwoMember 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesTwoMember 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:SecuredSeniorNotesAndDebenturesMember 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:SecuredSeniorNotesAndDebenturesMember 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesTwoMember 2024-01-01 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:SecuredSeniorNotesAndDebenturesMember 2024-01-01 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember 2024-12-31 0001127248 ema:OtherElectricUtilitiesMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:UnsecuredLoanNotesOneMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:UnsecuredLoanNotesOneMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesOneMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesOneMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesTwoMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesTwoMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:FixedToFloatingSubordinatedNotesMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:FixedToFloatingSubordinatedNotesMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:JuniorSubordinatedNotesMember 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:JuniorSubordinatedNotesMember 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:FixedToFloatingSubordinatedNotesMember 2024-01-01 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:JuniorSubordinatedNotesMember 2024-01-01 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:SeniorUnsecuredNotesTwoMember 2024-01-01 2024-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:UnsecuredLoanNotesOneMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredNonRevolvingCreditFacilityDueJune242025Member 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredNonRevolvingCreditFacilityDueJune242025Member 2024-06-24 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredNonRevolvingCreditFacilityDueJune242025Member 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredNonRevolvingCreditFacilityDueJune242025Member 2024-06-24 2024-06-24 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredNonRevolvingCreditFacilityDueJune242025Member 2024-12-16 2024-12-16 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2024-06-24 2024-06-24 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:NonRevolvingCreditFacilityDue2047Member 2024-06-13 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:NonRevolvingCreditFacilityDue2047Member 2024-06-24 2024-06-24 0001127248 ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember ema:NonRevolvingCreditFacilityDue2047Member 2024-01-01 2024-12-31 0001127248 ema:FixedRateNotesAndBondsMember ema:GasUtilitiesAndInfrastructureMember ema:NewMexicoGasIntermediateMember 2024-07-30 2024-07-30 0001127248 us-gaap:CorporateAndOtherMember ema:EmeraUsFinanceLpMember ema:UnsecuredSeniorNotesMember 2024-06-15 2024-06-15 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesDueJuly192028Member 2024-05-02 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesDueJuly192028Member 2023-01-01 2023-12-31 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesDueJuly192028Member 2024-05-02 2024-05-02 0001127248 ema:TampaElectricDivisionMember 2024-12-31 0001127248 ema:AllCreditFacilitiesMember 2024-12-31 0001127248 ema:AllCreditFacilitiesMember 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember 2024-01-01 2024-12-31 0001127248 ema:LabradorIslandLinkMember 2024-10-01 2024-12-31 0001127248 us-gaap:PublicUtilitiesInventoryCoalMember us-gaap:CommodityContractMember ema:DerivativeInstrumentSettlementPeriodOneMember 2024-01-01 2024-12-31 0001127248 us-gaap:PublicUtilitiesInventoryCoalMember us-gaap:CommodityContractMember ema:DerivativeInstrumentSettlementPeriodTwoMember 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember 2024-01-01 2024-12-31 0001127248 ema:TampaElectricDivisionMember 2023-11-17 2023-11-17 0001127248 us-gaap:CommonStockMember ema:AtTheMarketEquityProgramMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember srt:NaturalGasReservesMember 2023-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PhysicalNaturalGasPurchasesAndSalesMember 2024-01-01 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MinimumMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:MaximumMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember us-gaap:MeasurementInputOfferedPriceMember srt:WeightedAverageMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:NotDesignatedAsHedgingInstrumentTradingMember ema:PowerSwapsAndPhysicalContractsMember 2024-12-31 0001127248 country:BB 2024-01-01 2024-12-31 0001127248 ema:FloridaElectricUtilityMember 2024-12-31 0001127248 ema:CanadianElectricUtilitiesMember 2024-12-31 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember ema:FloridaElectricUtilityMember 2024-04-01 0001127248 us-gaap:RevolvingCreditFacilityMember ema:TampaElectricDivisionMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:AllOtherSegmentsMember us-gaap:RevolvingCreditFacilityMember ema:TecoFinanceIncMember 2024-04-01 0001127248 us-gaap:AllOtherSegmentsMember us-gaap:RevolvingCreditFacilityMember ema:TecoFinanceIncMember 2024-01-01 2024-12-31 0001127248 us-gaap:AllOtherSegmentsMember srt:ParentCompanyMember ema:RevolvingCreditFacilityIiMember 2024-06-17 0001127248 us-gaap:AllOtherSegmentsMember srt:ParentCompanyMember ema:RevolvingCreditFacilityIiMember 2024-12-31 0001127248 us-gaap:AllOtherSegmentsMember srt:ParentCompanyMember ema:RevolvingCreditFacilityIiMember 2024-06-17 2024-06-17 0001127248 us-gaap:AllOtherSegmentsMember srt:ParentCompanyMember ema:RevolvingCreditFacilityIiMember 2024-12-01 2024-12-31 0001127248 ema:MaritimeLinkProjectMember 2024-12-31 0001127248 us-gaap:SeriesFPreferredStockMember ema:FromFebruary152025Member 2024-01-01 2024-12-31 0001127248 ema:NmgcMember 2024-07-01 2024-09-30 0001127248 us-gaap:RegulatedOperationMember ema:NspiFamMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember ema:NspiFamMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2024-12-31 0001127248 us-gaap:UnregulatedOperationMember us-gaap:EnergyRelatedDerivativeMember us-gaap:ElectricityMember 2024-01-01 2024-12-31 0001127248 us-gaap:CommercialPaperMember ema:NovaScotiaPowerIncMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 ema:NewMexicoGasCompanyMember ema:GasUtilitiesAndInfrastructureMember ema:UnsecuredLoanNotesOneMember 2023-01-01 2023-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember ema:GasUtilitiesAndInfrastructureMember ema:SecuredLoanNotesMember 2023-01-01 2023-12-31 0001127248 ema:OtherElectricUtilitiesMember ema:UnsecuredLoanNotesTwoMember 2023-01-01 2023-12-31 0001127248 us-gaap:CorporateAndOtherMember ema:UnsecuredLoanNotesOneMember 2023-01-01 2023-12-31 0001127248 srt:MinimumMember ema:NovaScotiaPowerIncMember 2023-01-01 2023-12-31 0001127248 srt:MinimumMember ema:NovaScotiaPowerIncMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:NovaScotiaPowerIncMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:NovaScotiaPowerIncMember 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NspMaritimeLinkIncMember 2024-12-31 0001127248 us-gaap:RevenueSubjectToRefundMember ema:NovaScotiaPowerIncMember 2023-07-05 2023-07-05 0001127248 ema:NovaScotiaPowerIncMember ema:NovaScotiaCapAndTradeCapAndTradeProgramMember 2023-03-31 0001127248 ema:NovaScotiaPowerIncMember ema:NovaScotiaCapAndTradeCapAndTradeProgramMember 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NovaScotiaCapAndTradeCapAndTradeProgramMember 2022-01-01 2022-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2024-12-31 0001127248 srt:MinimumMember ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2021-08-15 2021-08-15 0001127248 ema:NovaScotiaPowerIncMember ema:UtilityAndReviewBoardMember 2024-06-27 0001127248 ema:NovaScotiaPowerIncMember ema:UtilityAndReviewBoardMember 2024-06-27 2024-06-27 0001127248 srt:FuelMember ema:NovaScotiaPowerIncMember 2024-04-17 2024-04-17 0001127248 srt:FuelMember ema:NovaScotiaPowerIncMember 2024-04-30 2024-04-30 0001127248 ema:NovaScotiaPowerIncMember ema:NspMaritimeLinkIncMember 2024-09-24 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2024-01-01 2024-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2023-01-01 2023-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember 2024-11-29 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:DebtAndFinancingCostsMember 2024-11-29 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2024-11-29 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember 2023-12-21 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember ema:UtilityAndReviewBoardMember 2022-01-01 2023-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember ema:UtilityAndReviewBoardMember 2022-01-01 2022-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember ema:UtilityAndReviewBoardMember 2023-01-01 2023-12-31 0001127248 ema:EmeraNewfoundlandAndLabradorHoldingsIncMember ema:NspMaritimeLinkIncMember ema:UtilityAndReviewBoardMember 2024-12-31 0001127248 ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 srt:MinimumMember ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 srt:MaximumMember ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 srt:MedianMember ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:ScenarioPlanMember ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:GasDistributionEquipmentMember us-gaap:ScenarioPlanMember ema:PeoplesGasSystemDivisionMember 2024-01-01 2024-12-31 0001127248 us-gaap:GasDistributionEquipmentMember us-gaap:ScenarioPlanMember srt:MedianMember ema:PeoplesGasSystemDivisionMember 2023-11-09 2023-11-09 0001127248 us-gaap:GasDistributionEquipmentMember us-gaap:ScenarioPlanMember ema:PeoplesGasSystemDivisionMember 2023-11-09 2023-11-09 0001127248 ema:NewMexicoGasCompanyMember 2024-01-01 2024-12-31 0001127248 ema:NewMexicoGasCompanyMember 2024-03-01 2024-03-01 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember 2024-01-01 2024-12-31 0001127248 ema:EmeraBrunswickPipelineCompanyLimitedMember 2024-12-31 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:FairTradingCommissionMember 2022-09-30 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:FairTradingCommissionMember 2022-09-01 2022-09-30 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:FairTradingCommissionMember 2024-05-06 2024-05-06 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:FairTradingCommissionMember 2024-01-01 2024-12-31 0001127248 ema:BarbadosLightAndPowerCompanyLimitedMember ema:FairTradingCommissionMember 2024-07-18 0001127248 us-gaap:ElectricTransmissionMember ema:GrandBahamaPowerCompanyLimitedMember 2024-01-01 2024-12-31 0001127248 us-gaap:ElectricTransmissionMember ema:GrandBahamaPowerCompanyLimitedMember 2023-01-01 2023-12-31 0001127248 ema:NovaScotiaPowerIncMember ema:NspMaritimeLinkIncMember ema:UtilityAndReviewBoardMember 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:FloridaElectricUtilityMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:OtherElectricUtilitiesMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember ema:GasUtilitiesAndInfrastructureMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember us-gaap:OperatingSegmentsMember us-gaap:CorporateAndOtherMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember srt:ConsolidationEliminationsMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember 2024-01-01 2024-12-31 0001127248 us-gaap:RegulatedOperationMember srt:ConsolidationEliminationsMember 2023-01-01 2023-12-31 0001127248 us-gaap:RegulatedOperationMember 2023-01-01 2023-12-31 0001127248 ema:TecCapitalCostRecoveryForEarlyRetiredAssetsMember 2024-12-31 0001127248 ema:TecCapitalCostRecoveryForEarlyRetiredAssetsMember 2023-12-31 0001127248 ema:RegulatoryFuelCostsDeferralAccountMember 2024-12-31 0001127248 ema:RegulatoryFuelCostsDeferralAccountMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel1Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel2Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2023-12-31 0001127248 us-gaap:FairValueMeasurementsRecurringMember us-gaap:EquityContractMember ema:OtherDerivativesMember 2023-12-31 0001127248 ema:NmgcMember 2024-09-30 0001127248 ema:January2023SettlementOfNmgcGasHedgesMember 2023-01-01 2023-12-31 0001127248 us-gaap:LineOfCreditMember srt:ParentCompanyMember 2024-12-31 0001127248 us-gaap:LineOfCreditMember srt:ParentCompanyMember 2023-12-31 0001127248 ema:TecoFinanceIncMember ema:AdvancesOnRevolvingCreditAndTermFacilitiesMember 2024-12-31 0001127248 ema:TecoFinanceIncMember ema:AdvancesOnRevolvingCreditAndTermFacilitiesMember 2023-12-31 0001127248 srt:ParentCompanyMember us-gaap:LineOfCreditMember 2024-01-01 2024-12-31 0001127248 srt:ParentCompanyMember us-gaap:LineOfCreditMember us-gaap:AllOtherSegmentsMember 2024-06-24 2024-06-24 0001127248 us-gaap:CorporateAndOtherMember ema:FixedToFixedResetRateJuniorSubordinatedNotesMember ema:EushiFinanceIncMember 2024-06-18 0001127248 us-gaap:CorporateAndOtherMember ema:FixedToFixedResetRateJuniorSubordinatedNotesMember ema:EushiFinanceIncMember 2024-06-18 2024-06-18 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredNonRevolvingFacilityDueFebruary192024Member 2023-01-01 2023-12-31 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredNonRevolvingFacilityDueFebruary192025Member 2024-02-16 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredNonRevolvingFacilityDueFebruary192025Member 2024-02-16 2024-02-16 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredNonRevolvingFacilityDueFebruary192025Member 2024-07-19 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2023-12-31 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2024-06-24 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2023-01-01 2023-12-31 0001127248 srt:ParentCompanyMember us-gaap:CorporateAndOtherMember ema:UnsecuredCommittedRevolvingCreditFacilityDueJune242029Member 2024-06-24 2024-06-24 0001127248 srt:MinimumMember us-gaap:DeferredCompensationShareBasedPaymentsMember srt:ManagementMember ema:AfterFirstYearOfProgramMember 2024-01-01 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2023-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-12-31 0001127248 us-gaap:PensionPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2023-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember 2024-12-31 0001127248 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember 2024-12-31 0001127248 us-gaap:OperatingSegmentsMember ema:CanadianElectricUtilitiesMember ema:NspMaritimeLinkIncProjectMember 2024-12-31 0001127248 srt:MinimumMember 2024-12-31 utr:MMBTU utr:mi utr:T iso4217:BBD iso4217:CAD iso4217:USD utr:MWh utr:km utr:MW xbrli:pure xbrli:shares iso4217:CAD xbrli:shares dummy:Customers dummy:Days iso4217:BSD xbrli:shares dummy:Item iso4217:CAD utr:M
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
40-F
☐
 
REGISTRATION STATEMENT
 
PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
 
☒
 
ANNUAL
REPORT
 
PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 2024
Commission File Number
000-54516
EMERA INCORPORATED
(Exact name of Registrant as specified in its charter)
Nova Scotia, Canada
(Province or other jurisdiction of incorporation or organization)
4911
(Primary Standard Industrial Classification Code Number (if applicable))
Not applicable
(I.R.S. Employer Identification Number (if applicable))
5151 Terminal Road
 
Halifax
,
Nova Scotia
,
Canada
B3J 1A1
Telephone: (
902
)
428-6096
(Address and telephone number of Registrant’s principal executive offices)
Emera US Finance LP
c/o Corporation Service Company
251 Little Falls Drive
Wilmington
,
Delaware
 
19808
 
Telephone: (
302
)
636-5401
 
(Name, address (including zip code) and telephone number (including area code)
 
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
 
Not applicable.
Securities registered or to be registered pursuant to Section 12(g) of the Act:
 
Not applicable.
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Not applicable.
For annual reports, indicate by check mark the information filed with this Form:
☒
 
Annual information form
☒
 
Audited annual financial statements
Number of outstanding shares of each of the issuer’s classes of
capital or common stock as of December 31, 2024:
295,935,686
 
Common Shares
4,866,814
 
Series A First Preferred Shares
1,133,186
 
Series B First Preferred Shares
10,000,000
 
Series C First Preferred Shares
5,000,000
 
Series E First Preferred Shares
8,000,000
 
Series F First Preferred Shares
12,000,000
 
Series H First Preferred Shares
8,000,000
 
Series J First Preferred Shares
9,000,000
 
Series L First Preferred Shares
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange
Act during
 
the preceding 12
 
months (or for
 
such shorter period
 
that the
 
Registrant was required
 
to file such
 
reports) and (2)
 
has
been subject to such filing requirements for the past 90 days.
Yes
 
☐
No
 
☒
Indicate by check mark whether the
 
registrant has submitted electronically every Interactive
 
Data File required to be submitted
 
and
posted pursuant
 
to Rule
 
405 of
 
Regulation S-T
 
(§232.405 of
 
this chapter)
 
during the
 
preceding 12
 
months (or
 
for such
 
shorter
period that the Registrant was required to submit and post such files).
Yes
 
☒
 
No
 
☐
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.
Emerging growth company
 
☐
If an emerging growth company that prepares is financial
 
statements in accordance with U.S. GAAP, indicate by check mark if the
registrant
 
has
 
elected
 
not
 
to
 
use
 
the
 
extended
 
transition
 
period
 
for
 
complying
 
with
 
any
 
new
 
or
 
revised
 
financial
 
accounting
standards
†
 
provided pursuant to Section 13(a) of the Exchange Act.
 
☐
†
 
The term “new
 
or revised financial accounting
 
standard” refers to
 
any update issued by
 
the Financial Accounting Standards
 
Board
to its Accounting Standards Codification after April 5, 2012.
Indicate
 
by
 
check
 
mark
 
whether
 
the
 
registrant
 
has
 
filed
 
a
 
report
 
on
 
and
 
attestation
 
to
 
its
 
management’s
 
assessment
 
of
 
the
effectiveness of its
 
internal control over financial
 
reporting under Section 404(b)
 
of the Sarbanes-Oxley Act
 
(15 U.S.C. 7262(b))
by the registered public accounting firm that prepared or issued its audit report.
☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements.
 
☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to
§ 240.10D-1(b).
 
☐
 
 
Certifications and Disclosure Regarding Controls
 
and Procedures.
(a)
 
Certifications regarding controls and procedures. See Exhibits 99.5
 
and 99.6.
(b)
 
Evaluation of disclosure controls and procedures. As of December 31, 2024,
 
an evaluation of the
effectiveness of the Registrant’s
 
“disclosure controls and procedures” (as such term is defined in Rules 13a-
15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934,
 
as amended (the “Exchange
Act”)), was carried out by the Registrant’s
 
Chief Executive Officer (“CEO”) and Chief
 
Financial Officer
(“CFO”). Based on that evaluation, the CEO and CFO have concluded that
 
as of such date the Registrant’s
disclosure controls and procedures are effective to provide
 
a reasonable level of assurance that information
required to be disclosed by the Registrant in reports that it files or submits under
 
the Exchange Act is
recorded, processed, summarized and reported within the time periods
 
specified in the United States
Securities and Exchange Commission’s
 
(the “Commission”) rules and forms.
It should be noted that while the CEO and CFO believe that the Registrant’s
 
disclosure controls and
procedures provide a reasonable level of assurance that they are effective,
 
they do not expect the disclosure
controls and procedures or internal control over financial reporting to be capable
 
of preventing all errors
and fraud. A control system, no matter how well conceived or operated,
 
can provide only reasonable, not
absolute, assurance that the objectives of the control system are met.
(c)
 
Management’s annual report
 
on internal control over financial reporting.
 
The Registrant's management is
responsible for establishing and maintaining adequate internal control
 
over financial reporting. The
Registrant's internal control framework is based on the criteria published
 
in the Internal Control –
Integrated Framework (2013), a report issued by the Committee of Sponsoring
 
Organizations (COSO) of
the Treadway Commission. The Registrant's management,
 
including the CEO and CFO, evaluated the
design and effectiveness of the Registrant's internal control over
 
financial reporting as at December 31,
2024 and concluded that the Registrant's internal control over financial
 
reporting is effective as at
December 31, 2024.
(d)
 
Attestation report of the registered public accounting firm.
 
This annual report does not include an
attestation report of the Registrant’s
 
registered public accounting firm regarding internal control over
financial reporting.
 
(e)
 
Changes in internal control over financial reporting. There were no changes
 
in the Registrant’s internal
control over financial reporting during the fiscal year ended December
 
31,
2024
, that have materially
affected, or are reasonably likely to materially affect,
 
the Registrant’s internal control
 
over financial
reporting.
Audit Committee Financial Expert.
 
The Registrant’s board of directors
 
(the “Board”) has determined that five
audit committee financial experts serve on its Audit Committee. The audit
 
committee financial experts are Paula Y.
Gold-Williams, Kent M. Harvey,
 
B. Lynn Loewen, Ian E. Robertson
 
and Carla M. Tully.
 
The Board has determined
that Paula Y.
 
Gold-Williams, Kent M. Harvey,
 
B. Lynn Loewen, Ian E. Robertson and
 
Carla M. Tully are
independent within the meaning of the listing standards of the New York
 
Stock Exchange. Information concerning
the relevant experience of Paula Y.
 
Gold-Williams, Kent M. Harvey,
 
B. Lynn Loewen, Ian E. Robertson and
 
Carla
M. Tully is included in their biographical information
 
contained in the Registrant’s Annual Information
 
Form for the
fiscal year ended December 31, 2024, filed as Exhibit 99.1 hereto (the “Annual
 
Information Form”). The
Commission has indicated that the designation of a person as an audit committee
 
financial expert does not make
such person an “expert” for any purpose, impose any duties, obligations
 
or liability on such person that are greater
than those imposed on members of the audit committee and board of directors
 
who do not carry this designation, or
affect the duties, obligations or liability of any other member of
 
the audit committee or board of directors.
Code of Ethics.
 
The Emera Code of Conduct was revised and became effective
 
on January 1, 2025 (the “Code”)
and applies to all directors, officers and employees of the Registrant, including
 
the CEO and CFO. Since the
adoption of the Code, there have not been any waivers, including implied waivers,
 
from any provision of the Code.
A copy of the Code can be found on Emera’s
 
internet website at the following address:
https://www.emera.com/about
 
-us/who-we-are/code-of-conduct.
 
 
 
 
The Code was furnished to the Commission on January 27, 2025 as Exhibit
 
99.1 to a report on Form 6-K and is
incorporated by reference herein as Exhibit 99.9.
Principal Accountant Fees and Services.
 
The information provided under the headings “Audit Committee—Audit
and Non-Audit Services Pre-Approval Process” and “Audit Committee—Auditors’
 
Fees” contained in the
Registrant’s Annual Information
 
Form. The Registrant’s Audit Committee approved
 
all of the Audit-Related and
Tax services provided
 
by Ernst & Young
 
LLP in
2024
 
and none were approved pursuant to the de minimis exception
provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
In connection with the Commission’s adoption
 
of amendments to finalize the implementation of disclosure and
submission requirements on December 2, 2021, pursuant to Release No. 34-93701,
 
the Registrant hereby affirms
that
 
Ernst & Young
 
LLP (PCAOB ID:
1263
) delivered an audit opinion relating to the Registrant’s
 
Financial
Statements (as defined below) contained in the Annual Information Form,
 
and such audit opinion was issued in
Halifax, Nova Scotia, Canada.
Liquidity and Capital Resources
The information provided under the headings (a) “Off-Balance Sheet
 
Arrangements” and (b) “Contractual
Obligations” contained in the Registrant’s
 
Management’s Discussion and
 
Analysis dated February 21, 2025 for the
year ended December 31, 2024, filed as Exhibit 99.2 hereto (the “MD&A”) and with
 
respect to clause (a) the
information provided at note 28 (“D. Guarantees and Letters of Credit”) and
 
note 33 (“Variable
 
Interest Entities”),
and with respect to clause (b) note 28 (“A. Commitments”) and note
 
26 (“Long-Term Debt”),
 
to the Audited
Consolidated Financial Statements as at and for the years ended December 31, 2024
 
and December 31, 2023, filed
as Exhibit 99.3 hereto (the “Financial Statements”), are incorporated by reference
 
herein.
Identification of the Audit Committee.
 
The information provided under the heading “Audit Committee” contained
in the Annual Information Form is incorporated by reference herein.
Mine Safety Disclosure.
 
Neither the Registrant nor any of its subsidiaries is the “operator” of
 
any “coal or other
mine”, as those terms are defined in section 3 of the Federal Mine Safety and Health Act of 1977
 
(30 U.S.C. 802),
that is subject to the provisions of such Act (30 U.S.C. 801 et seq.). Therefore, the
 
provisions of Section 1503(a) of
the Dodd-Frank Wall
 
Street Reform and Consumer Protection Act and Item 16 of General Instruction
 
B to Form 40-
F requiring disclosure concerning mine safety violations and other
 
regulatory matters do not apply to the Registrant
or any of its subsidiaries.
Disclosure Regarding Foreign Jurisdictions that
 
Prevent Inspections.
Not applicable.
Recovery of Erroneously Awarded
 
Compensation
. Not applicable.
EXHIBIT INDEX
Exhibit
Number
Description
99.1
99.2
99.3
99.4
99.5
UNDERTAKING
 
AND CONSENT TO SERVICE OF PROCESS
The Registrant undertakes to make available, in person or by telephone, representatives
 
to respond to inquiries made
by the Commission staff, and to furnish promptly,
 
when requested to do so by the Commission staff, information
relating to the securities in relation to which the obligation to file an annual report on
 
Form 40-F arises or
transactions in said securities.
The Registrant has previously filed a Form F-X in connection with the class of
 
securities in relation to which the
obligation to file this report arises.
Any change to the name or address of a Registrant’s
 
agent for service shall be communicated promptly to the
Commission by amendment to Form F-X referencing the file number of
 
the Registrant.
 
 
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of
 
the requirements for
filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned,
 
thereto
duly authorized.
DATED
 
this 21
th
day of February, 2025.
EMERA
INCORPORATED
By:
 
/s/ Scott C. Balfour
Name:
 
Scott C. Balfour
Title:
 
President & Chief
Executive Officer

Exhibit 99.1

 

LOGO

Emera Incorporated

Annual Information Form

For the year ended December 31, 2024

February 21, 2025


ANNUAL INFORMATION FORM

For the year ended December 31, 2024

Dated: February 21, 2025

TABLE OF CONTENTS

 

PRESENTATION OF INFORMATION

     4  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

     4  

CORPORATE STRUCTURE

     5  

Name and Incorporation

     5  

Intercorporate Relationships

     6  

INTRODUCTION

     6  

DESCRIPTION OF THE BUSINESS

     7  

Business Segments

     7  

Florida Electric Utility

     7  

Canadian Electric Utilities

     10  

Gas Utilities and Infrastructure

     13  

Other Electric Utilities

     16  

Other

     17  

GENERAL DEVELOPMENT OF THE BUSINESS

     18  

Florida Electric Utility

     18  

Canadian Electric Utilities

     20  

Gas Utilities and Infrastructure

     24  

Other Electric Utilities

     25  

Other

     27  

Financing Activity

     28  

RISK FACTORS

     29  

CAPITAL STRUCTURE

     29  

Common Shares

     29  

Emera First Preferred Shares

     30  

Emera Second Preferred Shares

     30  

Share Ownership Restrictions

     30  

CREDIT RATINGS

     31  

DIVIDENDS

     32  

MARKET FOR SECURITIES

     33  

Trading Price and Volume

     33  

ATM Program

     33  

DIRECTORS AND OFFICERS

     33  

Directors

     33  

Officers

     36  

AUDIT COMMITTEE

     37  

Audit and Non-Audit Services Pre-Approval Process

     39  

Auditors’ Fees

     39  

 

Emera Incorporated – 2024 Annual Information Form    2


CERTAIN PROCEEDINGS

     39  

CONFLICTS OF INTEREST

     40  

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

     40  

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

     40  

MATERIAL CONTRACTS

     40  

TRANSFER AGENT AND REGISTRAR

     40  

EXPERTS

     41  

ADDITIONAL INFORMATION

     41  

APPENDIX “A” – DEFINITIONS OF CERTAIN TERMS

     42  

APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES

     46  

APPENDIX “C” – MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2024

     49  

APPENDIX “D” – EMERA INCORPORATED AUDIT COMMITTEE CHARTER

     50  

 

Emera Incorporated – 2024 Annual Information Form    3


PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2024. All financial information is expressed CAD, rounded to the nearest million, and is presented in accordance with USGAAP, unless otherwise stated. Emera uses adjusted net income as a financial performance measure, which is not a defined financial measure under USGAAP and does not have standardized meanings prescribed by USGAAP. For further information on the non-GAAP financial measure, adjusted net income, including a full description of the measure and a reconciliation to the nearest USGAAP measure, please refer to the Company’s MD&A section entitled “Non-GAAP Financial Measures and Ratios”, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Certain capitalized terms used herein, and not otherwise defined herein, are defined under “Definitions of Certain Terms”, attached to this AIF as Appendix “A”. References to “including”, “include”, or “includes” means “including (or includes) but is not limited to” and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.

This AIF provides material information about the business and operations of Emera. The “Enterprise Risk and Risk Management” section of the Company’s MD&A is incorporated herein by reference and can be found under Emera’s profile on SEDAR+ at www.sedarplus.ca.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to Emera’s objectives, plans, financial and operating performance, the expected timing and outcome of the pending sale of NMGC, business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emera’s revenue, earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual net income and dividend growth; expansion of Emera’s business; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital investments; the nature, timing and costs associated with certain capital projects; the expected impact on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities, repayments and renewals; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions expected in the near term; the successful development of relationships with various stakeholders, the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

 

Emera Incorporated – 2024 Annual Information Form    4


The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather or global climate change, other acts of nature or other major events; seasonal weather patterns remaining stable; no significant cyber or physical attacks or disruptions to Emera’s systems; the continued ability to maintain transmission and distribution systems to ensure their continued performance; continued investment in solar, wind and hydro generation; continued natural gas activity; no severe and/or prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; expectations regarding the nature, timing and costs of capital investments of Emera and its subsidiaries; expectations regarding rate base growth; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws and regulations that may materially affect Emera’s operations and cash flows; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute Emera’s capital investment plan.

Forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include, but are not limited to: regulatory and political risk; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; climate change risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this AIF and in the documents incorporated herein by reference is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

CORPORATE STRUCTURE

Name and Incorporation

Emera was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). The Reorganization Act and the Privatization Act require the Company’s Articles of Association (the “Articles”) to contain provisions specifying that the head office and the principal executive offices of the Company are to be situated in the Province of Nova Scotia. The current address of the Company’s registered office, head office and principal executive offices is Emera Place, 5151 Terminal Road, Halifax, Nova Scotia, Canada, B3J 1A1.

 

Emera Incorporated – 2024 Annual Information Form    5


Intercorporate Relationships

The following table sets forth the relationships among the Company and its principal subsidiaries, the percentage of votes attaching to all voting securities of its respective subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by the Company, as well as their respective jurisdictions of incorporation, continuance, formation or organization. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10 per cent, or in the aggregate exceed 20 per cent, of the total consolidated assets or total consolidated revenues of the Company as at December 31, 2024.

 

 Subsidiaries   Percentage Ownership (%)   Jurisdiction
 Tampa Electric Company   100   Florida

 Nova Scotia Power

  100   Nova Scotia

 Peoples Gas System

  100   Florida

INTRODUCTION

Emera (TSX: EMA) is a North American provider of energy services owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico and the Caribbean. Emera is headquartered in Halifax, Nova Scotia.

Emera’s business strategy is centered on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow and dividends for shareholders.

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure and the targeted ROE, all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65 per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, the Caribbean and New Mexico at 4 per cent each.

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment plan will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.

Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through the issuance of preferred equity, and the issuance of common equity through Emera’s DRIP and its ATM Program. Maintaining investment-grade credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 18 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera’s anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

Emera Incorporated – 2024 Annual Information Form    6


DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

 

  •  

Florida Electric Utility, which consists of TEC;

 

  •  

Canadian Electric Utilities, which includes NSPI and an equity interest in NSPML (100 per cent);

 

  •  

Gas Utilities and Infrastructure, which includes PGS, NMGC, Emera Brunswick Pipeline Company, SeaCoast and an equity interest in M&NP (12.9 per cent);

 

  •  

Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which include BLPC, GBPC and an equity interest in Lucelec (19.5 per cent); and

 

  •  

Other, which includes Emera Energy, corporate holding, financing companies and certain other investments.

Emera and its subsidiaries had 7,605 employees as at December 31, 2024, approximately 30 per cent of whom are unionized.

Operations by Segment

Florida Electric Utility

The Florida Electric Utility segment consists of TEC, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC has $13 billion USD of assets, approximately 855,000 customers and 2,587 employees as at December 31, 2024.

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

Beginning in 2025, TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent (2024 - 9.25 per cent to 11.25 per cent), based on an allowed equity capital structure of 54 per cent (2024 – 54 per cent). An ROE of 10.50 per cent (2024 - 10.20 per cent) is used for the calculation of the return on investments for clauses.

For further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Market and Sales

 

TEC Revenue and Sales Volumes by Customer Class
      Electric Revenues (%)    GWh Electric Sales Volumes (%)

For the year ended December 31

   2024    2023    2024    2023

Residential

   59.7    64.9    48.8    49.0

Commercial

   27.1    30.4    30.8    30.7

Industrial

   6.4    7.7    9.6    9.9

Other (1)

   6.8    (3.0)    10.8    10.4

Total

   100.0    100.0    100.0    100.0

 

(1)

Other includes regulatory deferrals related to clauses, sales to public authorities, and off-system sales to other utilities.

 

Emera Incorporated – 2024 Annual Information Form    7


Energy Sources and Generation

As at December 31, 2024, TEC owns 6,620 MW of generating capacity, of which 73 per cent is natural gas fired, 20 per cent is solar and 7 per cent is coal. TEC also owns 2,192 kilometres of transmission facilities and 20,693 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

System Operations

TEC’s Energy Control Center co-ordinates and controls the electric generation, transmission and distribution facilities. The Energy Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system assets.

Through interconnection agreements with neighboring electric utilities within the Florida Region, TEC’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. As a member of the Florida Reserve Sharing Group, TEC has immediate access to reserve generating capacity from all other group members.

Contribution to Consolidated Net Income and Consolidated Adjusted Net Income

Florida Electric Utility’s contribution to consolidated net income was $468 million USD in 2024 (2023 – $466 million USD). Florida Electric Utility’s contribution to consolidated adjusted net income was $470 million in 2024 (2023 - $466 million). For a reconciliation of Florida Electric Utility’s adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Florida Electric Utility” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Seasonal Nature

Electric sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand.

Capital Investments

In 2024, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.4 billion USD (2023 – $1.3 billion USD). In 2025, capital investment is expected to be approximately $1.7 billion USD, including AFUDC. Capital projects include solar investments, grid modernization, storm hardening investments, building resilience and energy storage.

Environmental Considerations

TEC has significant environmental considerations. TEC operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.

Carbon Reductions and GHG

TEC has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at TEC’s facilities. Since 2000, TEC has reduced its system-wide emissions of CO2 by more than 50 per cent, bringing emissions to below 1990 levels, where they continue to remain. Since 2005, TEC has continued to optimize its existing coal units to operate on natural gas, during which time the number of retail customers and retail energy sales have risen. TEC has also substantially reduced CO2 emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine,

 

Emera Incorporated – 2024 Annual Information Form    8


and retiring Big Bend Unit 2 and Unit 3. The Big Bend Unit 1 modernization project is capable of producing 1,090 megawatts of power and will continue to lead to lower system-wide emissions.

On April 24, 2024, the EPA issued its final power plant rules for electric generating units, including (i) new GHG standards; and (ii) Mercury and Air Toxics Standards (“MATS”). The new MATS will not have a material impact on TEC. The new GHG standard applies only to existing coal-fired and new natural gas electric generating units and will therefore have limited impact on TEC generating units. Big Bend Unit 4 is the only unit affected. As written, the rule would require Big Bend Unit 4 to retire in 2039 without major enhancements to the unit, instead of the current planned retirement date of 2040.

CCR Recycling and Regulation

TEC produces ash and other by-products, collectively known as coal combustion residuals (“CCRs”) at Big Bend Power Station. Greater than 90 per cent of all CCRs produced at this facility are marketed to customers for beneficial use in commercial and industrial products. The EPA’s final CCR rule became effective on October 19, 2015 and regulates CCRs as non-hazardous solid waste. In 2016 and 2017, the FPSC approved Environmental Cost Recovery for capital and O&M expenses associated with various projects proposed as part of TEC’s CCR compliance program. Subsequently, a closure by removal and liner retrofit project for the West Slag Dewatering Pond was completed in 2020 and closure by removal of all CCRs from the Economizer Ash and Pyrite Ponds was completed in October 2021. The final project required for compliance with the CCR Rule at Big Bend is the North Gypsum Stackout Area Drainage Improvements Project, which is scheduled for completion in 2025. FDEP has revised the existing state solid waste regulation to incorporate Florida CCR permit requirements for regulated units and these new requirements will operate in lieu of the Federal permitting program. However, TEC is largely exempt from the state permitting requirements because it completed its mandatory closure projects prior to the state rule’s passage. On May 18, 2023, the EPA proposed new rules requiring identification and regulation of Legacy CCR Management Units. TEC is a member of the Utility Solid Waste Activities Group, who filed comments on behalf of its members in July 2023 contesting many of the proposed rule’s provisions.

The new CCR rule finalized in April 2024 covers any landfill or impoundment in existence at an inactive power facility but not receiving CCRs as of 2015, any CCR placed into the environment for beneficial uses, or CCR units (landfills and impoundments) previously closed under state programs. TEC is currently evaluating the impact of the new CCR rule at Unit 4 of the Big Bend Power Station and will likely require site evaluations beginning in 2025 to determine the presence or absence of CCR management units. If found, additional evaluations would be required in 2026 and based on those findings, modifications to the site groundwater monitoring could be required beginning in 2027 to determine the need for additional corrective action.

TEC expects that the costs to comply with the new environmental regulations would be eligible for recovery. If approved as prudent, the costs would be reflected in customers’ bills, recovered through either the environmental cost recovery clause or base rates.

Water Supply and Quality

The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to TEC’s Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on “waters of the United States”. TEC has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. Compliance includes the completion of the biological, technical, and financial study elements required by the rule. These study elements have been completed and submitted for Bayside and were used by the Florida Department of Environmental Protection (“FDEP”) to determine the necessity of cooling water system retrofits. FDEP agreed with TEC’s proposed plan for Bayside and TEC began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. TEC is negotiating an alternative schedule for Big Bend (as allowed by the rule) but completed a portion of the compliance requirements with the Big Bend modernization project with the installation of fish-friendly modified traveling screens and a fish return on modernized Unit 1. The remainder of the compliance

 

Emera Incorporated – 2024 Annual Information Form    9


requirements are to be determined and completed at a later date. The full impact of the new regulations on TEC will depend on the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.

The final EPA rule for existing steam electric effluent limit guidelines (“ELGs”) became effective January 4, 2016 and establishes limits for certain wastewater discharges. The new ELGs will not have a material impact on TEC. Big Bend completed construction of a deep injection well system in December 2023 for disposal of various types of wastewater. This change will be made to the final National Pollutant Discharge Elimination System (“NPDES”) permit, anticipated in 2025. Since Polk Power Station also uses a deep injection well rather than discharging it to surface water, the effluent limitations will no longer apply to either power station. The referenced wastewater at each power station will be regulated under the Underground Injection Control program rather than the NPDES program.

EPA Waters of the US

In 2023, the EPA and Department of the Army issued a final rule amending the definition of “waters of the United States”. The final rule is expected to have environmental permitting implications for new Tampa Electric solar sites and permitting renewals for existing facilities requiring approved jurisdictional determinations.

Ozone

On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in TEC’s service territory. The impact of this potential new standard on the operations of TEC will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, PGS is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 28, Commitments and Contingencies – Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Canadian Electric Utilities

The Canadian Electric Utilities segment includes NSPI and NSPML. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. NSPML is a 100 per cent equity interest in the Maritime Link Project (“Maritime Link”), a transmission project between the island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

Emera Incorporated – 2024 Annual Information Form    10


NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 557,000 customers with $7.1 billion in assets and 2,344 employees, as at December 31, 2024.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods.

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent of approved rate base.

For further details on NSPI’s regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Market and Sales

 

NSPI Revenue and Electricity Sales Volumes by Customer Class
      Electric Revenues (%)    GWh Electric Sales Volumes (%)

For the year ended December 31

   2024    2023    2024    2023

Residential

   55.0    55.7    48.2    47.8

Commercial

   27.5    28.4    28.8    29.2

Industrial

   15.2    13.4    21.0    20.7

Other

   2.3    2.5    2.0    2.3

Total

   100.0    100.0    100.0    100.0

Energy Sources and Generation

NSPI owns 2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro, wind, or solar, 7 per cent is petroleum coke (“petcoke”) and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 533 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing NLH’s NS Block delivery obligations, as discussed below.

NLH is obligated to provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NLH is obligated to provide approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from NLH through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from NLH for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

System Operations

NSPI’s Control Center Operations co-ordinates and controls the electric generation, transmission and distribution facilities with the goal of providing safe, reliable and efficient electricity supply while adhering to applicable environmental requirements and regulations. The Control Center is linked to the generating

 

Emera Incorporated – 2024 Annual Information Form    11


stations and other key facilities through the Supervisory Control and Data Acquisition system, a software application used by system operators for remote monitoring and control of the power system assets via the company’s telecommunication networks.

Through interconnection agreements with NB Power and with NLH, NSPI’s system has access to other regional power systems and the interconnected North American bulk electric system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. The interconnection agreements also provide participating utilities with a source of reserve power, subject to availability, transmission line capacity and the requirements of the supplier.

NSPI is a member of the NPCC, a body whose primary role is promoting the reliability of the interconnected power systems throughout the Northeastern United States and Eastern Canada (Nova Scotia, New Brunswick, Quebec, Ontario) under the regulatory authority of NERC. NERC and NPCC reliability standards and criteria are approved for enforcement in Nova Scotia by the UARB. NSPI complies with NPCC criteria and NERC standards for the design, planning and operation of NSPI’s portion of the interconnected bulk electric system.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 28,000 km of distribution facilities, which includes distribution supply substations.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project agreements.

Contribution to Consolidated Net Income

Canadian Electric Utilities’ contribution to consolidated net income was $232 million in 2024 (2023 – $247 million).

Seasonal Nature

Electric sales volumes are primarily driven by weather, number of customers, general economic conditions, and demand side management activities. Residential and commercial electricity sales are seasonal in Nova Scotia, with Q1 historically generating the highest sales, reflecting colder weather and fewer daylight hours in the winter season.

Capital Investment

NSPI

NSPI’s capital investments in 2024 were $487 million (2023 – $451 million), including AFUDC. In 2025, NSPI expects to invest $480 million, including AFUDC, primarily in capital projects to support power system reliability and reliable service for customers.

 

Emera Incorporated – 2024 Annual Information Form    12


NSPML

NSPML does not anticipate any significant capital investment in 2025.

Environmental Considerations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Other Environmental Legislation and Regulations

There have been several recent environmental developments at both the federal and provincial levels, as described below in the “General Development of the Business – Canadian Electric Utilities - NSPI” section. For additional information on environmental regulations affecting NSPI, see also NSPI’s 2024 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR+ at www.sedarplus.ca.

Gas Utilities and Infrastructure

The Gas Utilities and Infrastructure segment includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the Northeastern United States.

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to customers.

Market and sales

 

PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class
      Gas Revenues (%)    Therms Gas Sales Volumes (%)

For the year ended December 31

   2024    2023    2024    2023

Residential

   46.7    50.3    13.1    13.2

Commercial

   32.5    29.5    26.3    26.8

Industrial

   6.2    6.5    51.7    51.5

Other

   14.6    13.7    8.9    8.5

Total

   100.0    100.0    100.0    100.0

 

Emera Incorporated – 2024 Annual Information Form    13


PGS

As at December 31, 2024, PGS serves approximately 508,000 customers with $3.1 billion USD in assets and 814 employees. The PGS system includes approximately 25,240 kilometres of natural gas mains and 14,530 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2024.

PGS is regulated by the FPSC. Rates are set at a level that allows the utilities to collect total revenues or revenue requirements equal to their cost to provide service, plus an appropriate return on invested capital.

The approved ROE range for PGS is 9.15 per cent to 11.15 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 10.15 per cent is used for the calculation of return on investments recovered through cost recovery clauses.

For further details on PGS’ regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

NMGC

As at December 31, 2024, NMGC serves approximately 550,000 customers with $1.5 billion USD in assets and 750 employees. NMGC’s system includes 2,405 km of transmission lines and 17,810 km of distribution lines. Annual natural gas throughput was 1 billion therms in 2024.

NMGC is subject to regulation by the NMPRC. Rates are set at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.

NMGC’s approved ROE is 9.375 per cent on an allowed equity capital structure of 52 per cent.

For further details on NMGC’s regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Matters, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. For more information on the pending transaction, refer to the “General Development of the Business – Gas Utilities and Infrastructure” section below and the “Other Developments” section of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

EBPC

EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified liquefied natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/U.S. border near Baileyville, Maine.

Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RENAC under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement with RENAC, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

 

Emera Incorporated – 2024 Annual Information Form    14


Economic Dependence

Brunswick Pipeline has a 25-year firm service agreement with RENAC, which expires in 2034. The risk of non-payment is mitigated as Repsol, the parent company of RENAC, has provided EBPC with a guarantee for all RENAC’s payment obligations under the firm service agreement.

M&NP

Emera owns a 12.9 per cent interest in M&NP, which is a 1,400 km pipeline that transports natural gas throughout markets in Atlantic Canada and the Northeastern United States.

Contribution to Consolidated Net Income and Consolidated Adjusted Net Income

Gas Utilities and Infrastructure’s contribution to consolidated net income was $188 million USD in 2024 (2023 – $158 million USD). Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income was $194 million USD in 2024 (2023 – $158 million USD). For a reconciliation of Gas Utilities and Infrastructure’s adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Gas Utilities and Infrastructure” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Seasonal Nature

Gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial gas sales are seasonal. In Florida and New Mexico, Q1 is the strongest period for gas sales due to colder weather and heating demand.

Capital Investment

Capital investments, including AFUDC, in PGS in 2024 were $323 million USD (2023 – $495 million USD in the Gas Utilities and Infrastructure segment). In 2025, capital investment at PGS is expected to be approximately $360 million USD, including AFUDC. PGS will make investments to maintain the reliability of its system and support customer growth.

Environmental Considerations

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 28, Commitments and Contingencies – Legal Proceedings – Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Brunswick Pipeline is subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an integrated management system to ensure compliance and continuous improvement of its integrity, safety and environmental programs. Brunswick Pipeline also conducts regularly scheduled physical inspections of the pipeline and its right-of-way.

 

Emera Incorporated – 2024 Annual Information Form    15


Other Electric Utilities

Other Electric Utilities includes ECI, a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island and an equity investment in Lucelec on the island of St. Lucia.

Market and Sales

Other Electric Utilities operating revenues for 2024 were $413 million USD (2023 – $390 million USD) and electric sales volumes for 2024 were 1,307 GWh (2023 – 1,260 GWh).

BLPC

As at December 31, 2024, BLPC serves approximately 135,000 customers with $538 million USD of assets and a workforce of 432 employees. BLPC owns 243 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPC’s transmission system consists of 188 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 3,989 km of distribution lines which includes distribution supply substations.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted.

BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base is 10 per cent.

For further information and developments regarding BLPC, refer to the “General Development of the Business – Other Electric Utilities” section below.

GBPC

As at December 31, 2024, GBPC serves approximately 19,500 customers, with $340 million USD of assets and a workforce of 206 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 kilometers of distribution facilities.

GBPC has historically been regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulatory return on rate base is 8.52 per cent.

For further information and developments regarding GBPC, refer to the “General Development of the Business – Other Electric Utilities” section below.

For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

System Operation

BLPC and GBPC have system control centres that co-ordinate and control their electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining

 

Emera Incorporated – 2024 Annual Information Form    16


economy of operations. The generation and transmission system control centres are linked to their generating stations and other key parts of their systems by the “Supervisory Control and Data Acquisition” systems, with fibre optic, voice and data communications networks.

Transmission and Distribution

BLPC and GBPC transmit and distribute electricity from their generating stations to their customers.

Contribution to Consolidated Net Income and Adjusted Net Income

Other Electric Utilities’ contribution to consolidated net income was $35 million USD in 2024 (2023 – $28 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $35 million USD in 2024 (2023 – $26 million USD). For a reconciliation of Other Electric Utilities adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Other Electric Utilities” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Seasonal Nature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather. Grand Bahama is also particularly prone to tropical storm and hurricane impacts during Q3.

Capital Investment

Other Electric Utilities capital investments (including AFUDC) for 2024 were $59 million USD (2023 – $47 million USD). In 2025, capital investment is expected to be approximately $140 million USD, including AFUDC, primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

Environmental Considerations

Emera’s Caribbean utilities have implemented formal health & safety and environmental and management systems to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.

Other

The Other segment includes business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Business operations in the Other segment include Corporate; Emera Energy Services (EES), physical energy marketing and trading business; a 50 per cent joint venture interest in Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts; and Block Energy. In Q4 2024, Block Energy initiated the process to wind-up operations.

Corporate items included are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the U.S. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

 

Emera Incorporated – 2024 Annual Information Form    17


Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the company’s risk tolerances, including those related to value-at-risk and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related energy asset management services. The primary market area for the natural gas and power marketing and trading business is northeastern North America, including the Marcellus and Utica shale supply areas. EES also participates in the US Southeast, Gulf Coast and Midwest, and Central Canadian and Alberta natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region’s energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income of $15 to $30 million USD.

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $686 million in 2024 (2023 – loss of $147 million). Other’s contribution to consolidated adjusted net income was a loss of $342 million in 2024 (2023 – loss of $314 million). For further information on the non-GAAP measure adjusted net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Other” sections of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Capital Investment

In 2025, capital investment in the Other segment is not expected to be significant.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2025

The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years and changes that are expected to occur during the current financial year.

Florida Electric Utility

Base Rates

On August 16, 2022, the FPSC approved TEC’s request to increase revenue and ROE due to increases in the 30-year United States Treasury bond yield rate pursuant to the terms of a settlement agreement reached and approved in 2021. Effective July 1, 2022, the mid-point ROE was 10.20 per cent, and the range was 9.25 per cent to 11.25 per cent.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $22 million USD was approved by the FPSC on November 17, 2023.

 

Emera Incorporated – 2024 Annual Information Form    18


On April 2, 2024, TEC filed a rate case with the FPSC for new base rates. On December 3, 2024, the FPSC rendered a decision which includes annual base rate increases of $185 million USD in 2025 and adjustments of $87 million USD and $9 million USD in 2026 and 2027, respectively. The rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital and the allowed regulatory ROE range is 9.50 per cent to 11.50 per cent with a 10.50 per cent midpoint. On February 3, 2025, the FPSC issued the final order approving the decision, effective January 1, 2025. On February 18, 2025, a motion for reconsideration on certain aspects of the rate case order was filed with the FPSC. TEC will respond to this motion in February 2025. TEC expects the FPSC to reach a final decision on the motion in Q2 2025.

Fuel Recovery

The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was spread over customer bills from April 1, 2022 through December 2022.

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction was due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the FPSC approved the mid-course adjustment.

Big Bend Modernization Project

TEC invested $876 million USD, including $91 million USD of AFUDC, between 2018 and 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, TEC retired the Unit 1 components that would not be used in the modernized plant Big Bend Unit 2 and Big Bend Unit 3 in 2020, 2021 and 2023, respectively.

TEC’s 2021 settlement agreement provides recovery for the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years, effective January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Storm Reserve

In September 2022, TEC was impacted by Hurricane Ian with $119 million USD of restoration costs charged against TEC’s FPSC approved storm reserve. On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million USD, for a total of $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $134 million USD. The remaining balance of $29 million USD as of December 31, 2023, was collected over 12 months in 2024.

 

Emera Incorporated – 2024 Annual Information Form    19


In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in minimal impact to earnings.

On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of December 31, 2024, TEC deferred $49 million USD to the storm reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3 hurricane had a significant impact on TEC’s service territory which resulted in a peak number of customers out of 600,000. As of December 31, 2024, TEC deferred $340 million USD to the storm reserve for future recovery.

As at December 31, 2024, total restoration costs charged to the storm reserve account have exceeded the storm reserve balance and therefore $377 million USD has been deferred as a regulatory asset for future recovery. On February 4. 2025, the FPSC approved TEC’s petition filed on December 27, 2024 for the recovery of $466 million USD for costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton and the associated interest to replenish the storm reserve over an 18-month recovery period beginning in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC.

Storm Protection Cost Recovery Clause and Settlement Agreement

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. The current approved plan addressed the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

For more information, refer to the “Regulatory Environments and Updates – Florida Electric Utility” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca

Canadian Electric Utilities

NSPI

General Rate Application and Settlement Agreement

On February 2, 2023, the UARB approved the General Rate Application Settlement Agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increase of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. On March 27, 2023 the UARB issued a final order approving the electricity rates effective on February 2, 2023.

The settlement agreement established a storm rider for each of 2023, 2024 and 2025, which gives NSPI the ability to apply to the UARB for deferral and recovery of expenses if major storm restoration expense exceeds approximately $10 million in any given year. The storm rider was effective as of February 2, 2023, the GRA decision date. The application for deferral and recovery of the storm rider is made in the year following the year of the incurred costs, with recovery beginning in the year after the application. On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and

 

Emera Incorporated – 2024 Annual Information Form    20


incremental financing costs deferred to NSPI’s storm rider in 2023 to be recovered over a 12-month period beginning on January 1, 2025.

The settlement agreement also established a DSM rider, allowing NSPI to recover costs associated with DSM programs developed and delivered by EfficiencyOne, a third-party entity that currently holds the franchise for the provision of energy efficiency and conservation in the Province, regulated by the UARB.]. The DSM rider was effective as of February 2, 2023, the GRA decision date. Differences between DSM program costs and amounts recovered from customers through electricity rates are deferred to a DSM regulatory asset or liability and recovered from or returned to customers in subsequent periods.

Fuel Recovery

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period which began in Q2 2024 and is remitting those amounts to Invest Nova Scotia quarterly.

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province on terms and conditions for a federal loan guarantee (“FLG”) of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. On November 29, 2024, the UARB approved NSPML’s application to issue the debt, transfer the proceeds to NSPI as a refund of a portion of previous NSPML assessment payments, and to increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On December 16, 2024, the net proceeds of the NSPML debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance. On February 18, 2025, the UARB approved NSPI’s application to increase 2025 fuel rates to service the incremental NSPML debt.

Hurricane Fiona

On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Consolidated Balance Sheets. NSPI began amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.

Regulatory Matters – General

For more information, refer to the “Regulatory Environments and Updates – Canadian Electric Utilities – NSPI” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Battery Energy Storage System (“BESS”) Project

On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the BESS Project. The project is comprised of three 50 MW, four-hour battery facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.

 

Emera Incorporated – 2024 Annual Information Form    21


Environmental Legislation and Regulations

Nova Scotia Energy Reform Act

On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. This legislation implements certain recommendations made by the Clean Electricity Solutions Task Force, which was established by the Province to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. The legislation enacted the Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act, which provides for the establishment of and phased transition to the Nova Scotia Independent Energy System Operator (“NSIESO”). The Province previously had announced that the NSEISO’s responsibilities will include managing the operations of the electricity system, the connection of renewable energy projects to the grid and system planning and procuring new energy sources. NSPI is fully engaged in supporting the Province on these initiatives.

Clean Electricity Regulations (“CER”)

On December 17, 2024, Environment and Climate Change Canada released a finalized version of the CER. The CER establish performance standards to further limit GHG emissions from fossil fuel generated electricity starting in 2035 and help facilitate the Government of Canada’s intention of achieving a net-zero electricity grid by 2050. Compliance with the finalized version of the CER is not anticipated to require significant capital investment incremental to achieve the 2030 targets as NSPI’s planned capital investment during this period is driven by the Province’s goals to transition off coal and reach 80 per cent renewable electricity sales by 2030.

Nova Scotia Renewable Electricity Regulations (“RER”)

Under the provincially legislated RER, starting in 2020, 40 per cent of electric sales must be generated from renewable sources. NSPI met this target in 2024 and 2023, with 42 per cent and 43 per cent, respectively, of NSPI’s electric sales coming from renewable sources. NSPI’s 2024 renewable sales are subject to an annual compliance filing.

Due to the delay of NSPI receiving energy from the NS Block, the Province had provided NSPI with an alternative compliance plan that required NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan.

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Consolidated Statements of Income.

On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing for the matter is currently scheduled for June 2025.

Carbon Pricing Regulations

NSPI is a mandatory participant in Nova Scotia’s output-based pricing system (“OBPS”) carbon pricing program, which was effective January 1, 2023. Nova Scotia’s OBPS implements GHG emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards are subject to a carbon price that starts at $65 per tonne in 2023 and increases by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework

 

Emera Incorporated – 2024 Annual Information Form    22


provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.

Nova Scotia Cap-and-Trade Program Regulations

NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances and was permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall required the purchase of reserve credits directly from the Province. Lower than forecast Muskrat Falls energy received during the compliance period resulted in the increased deployment of higher carbon-emitting generation sources. On March 16, 2023, the Province provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance with the Nova Scotia Cap-and-Trade Program.

Other Legislation

Electricity Act Amendments

In April 2023, the Province enacted amendments to the Electricity Act which will allow the Province to issue requests for proposals for energy-storage in Nova Scotia, similar to the existing procurement process for renewable energy. In addition, the amendments to the Electricity Act allow the Governor in Council to approve unique or innovative energy storage projects that provide benefits to the electric system and reduce costs for customers.

In November 2023, the Province enacted amendments in the Electricity Act which permit the Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase agreements with renewable generation facilities by further empowering the Province to require NSPI to enter into an agreement for the sale of the electricity to specified customers. This allows specified customers to buy renewable electricity from specified producers, with NSPI managing the transmission and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated assets of NSPI. In 2024, the UARB approved the BESS project. For further details refer to “Regulatory Matters – General” section above.

Performance Standards Penalty Amendment

On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.

NSPML

Maritime Link Project

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.

 

Emera Incorporated – 2024 Annual Information Form    23


In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a monthly holdback of up to $2 million, which increased to $4 million beginning December 2023, as discussed below.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments”. The UARB also confirmed that the holdback mechanism would cease once 90 per cent of NS Block deliveries were achieved for 12 consecutive months (subject to potential relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.

On December 21, 2023, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2024, subject to a holdback of $4 million per month.

On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. On December 16, 2024, the net proceeds of the NSPML debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance as a refund of a portion of previous NSPML assessment payments. For further details, refer to the “Fuel Recovery” section above.

On November 29, 2024, NSPML received approval from the UARB to collect up to $197 million in 2025 from NSPI; which includes $158 million for the recovery of costs associated with the Maritime Link, and $39 million associated with the additional FLG debt and financing costs discussed in the “NSPI” section above. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded for the year ended December 31, 2024. NSPML expects to file an application to terminate the holdback mechanism in early 2025.

LIL

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. For more information, see the “Other Developments” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Gas Utilities and Infrastructure

General - Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is currently expected to close in October 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities are classified as held for sale as of Q3 2024. For more information on the pending transaction, refer to the “Other Developments” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

Emera Incorporated – 2024 Annual Information Form    24


PGS

Base Rates

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on December 27, 2023, with the new rates effective January 2024.

On January 30, 2025, PGS notified the FPSC of its intent to seek a base rate increase effective January 2026, reflecting a revenue requirement of approximately $90 to $110 million USD and subsequent year adjustment for 2027 of approximately $25 to $40 million USD. PGS’ proposed rates support on-going growth in Florida and a continued commitment to delivering safe and reliable service to PGS customers. The filing range amounts are estimates until PGS files its detailed case in March 2025. The FPSC is scheduled to hear the case in Q3 2025 with a decision expected by the end of 2025.

NMGC

Base Rates

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New rates became effective October 1, 2024.

For more information, refer to the “Regulatory Environments and Updates – Gas Utilities and Infrastructure” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Other Electric Utilities

BLPC

General Rate Review

In 2021 BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month.

On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and

 

Emera Incorporated – 2024 Annual Information Form    25


Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in 2025.

Clean Energy Transition Rider (“CETR”)

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETR (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETR. On May 6, 2024, the FTC approved the recovery of a 15 MW battery storage system through the CETR.

Tax Legislation

On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the FTC during a future rate setting process.

GBPC

Base Rates

On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The rates include a regulatory ROE of 12.84 per cent.

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. Review of the rate application is expected to be completed in 2025.

Fuel Recovery

Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 and 2024 the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew

Restoration costs associated with Hurricane Matthew in 2016 were recovered through an approved fuel charge, approved in 2016 by the GBPA. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three-year period ending December 31, 2024. As of November 2024, the Hurricane Matthew regulatory asset has been fully recovered.

 

Emera Incorporated – 2024 Annual Information Form    26


For more information, refer to the “Regulatory Environments and Updates – Other Electric Utilities” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Electricity Act, 2024

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. The GBPA has opposed the legislated removal of its regulatory authority over GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian government that provided for the development and administration of the Freeport area. Management expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however, does not foresee that the legislation or the outcome of such proceedings will have a material impact to Emera.

Other

Canadian Tax Legislation Changes

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. During 2024, the Company incurred $185 million of interest and financing expenses in connection with a specific financing structure. The interest and financing expenses related to the financing structure as well as $88 million of other interest and financing expenses are expected to be denied under the EIFEL regime. It was determined that the Company is more likely than not to realize the tax benefit of the denied interest and financing expenses in future periods and therefore a $79 million deferred income tax asset was recorded as at December 31, 2024.

USGAAP – Exemptive Relief

On January 28, 2021, the International Accounting Standards Board (“IASB”) published an Exposure Draft: Regulatory Assets and Regulatory Liabilities, which proposes the accounting model under which a company subject to rate regulation that meets the scope criteria would recognize regulatory assets and liabilities. The proposed effective date is annual reporting periods beginning on or after a date 18-24 months from the date of publication of the standard. Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Company’s financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that commences on or following the later of: (a) the effective date prescribed by the IASB for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.

The Company will continue to monitor the development of the Mandatory Rate-regulated Standard and assess the impact on the existing Exemptive Relief.

 

Emera Incorporated – 2024 Annual Information Form    27


Financing Activity

ATM Program

During 2022, approximately 4.07 million common shares were issued under the ATM Program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million, net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit of $207 million remained available for issuance under the ATM Program, which expired on September 5, 2023.

On November 14, 2023, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025.

During 2023, approximately 8.29 million common shares were issued under the ATM Program at an average price of $48.27 per share for gross proceeds of $400 million ($397 million, net of after-tax issuance costs) and an aggregate gross sales limit of $200 million remained available for issuance under the ATM Program.

On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up to $1 billion of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was increased by an amendment dated November 18, 2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13, 2024 to its short form base shelf prospectus dated October 3, 2023.

During 2024, approximately 5.12 million common shares were issued under the ATM Program at an average price of $51.52 per share for gross proceeds of $264 million ($261 million, net of after-tax issuance costs) and an aggregate gross sales limit of $336 million remained available for issuance under the ATM Program.

During 2025, up to and including February 21, 2025, 187,600 common shares were issued under the ATM Program and an aggregate gross sales limit of $326 million remains available for issuance under the ATM Program.

Preferred Share Issuances

On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Series C First Preferred Shares. The holders of the Series C First Preferred Shares had the right, at their option, to convert all or any of their Series C First Preferred Shares, on a one-for-one basis, into Series D First Preferred Shares on August 15, 2023 or to continue to hold their Series C First Preferred Shares. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series C First Preferred Shares would be converted into Series D First Preferred Shares on August 15, 2023.

On July 6, 2023, Emera announced it would not redeem the 12 million outstanding Series H First Preferred Shares. The holders of the Series H First Preferred Shares had the right, at their option, to convert all or any of their Series H First Preferred Shares, on a one-for-one basis, into Series I First Preferred Shares on August 15, 2023 or to continue to hold their Series H First Preferred Shares. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series H First Preferred Shares would be converted into Series I First Preferred Shares on August 15, 2023.

On January 8, 2025, Emera announced it would not redeem the 8 million outstanding Series F First Preferred Shares. The holders of the Series F First Preferred Shares had the right, at their option, to convert all or any of their Series F First Preferred Shares, on a one-for-one basis, into Series G First Preferred Shares on February 15, 2025 or to continue to hold their Series F First Preferred Shares. On February 6, 2025, Emera announced after having taken into account all conversion notices received from holders, no

 

Emera Incorporated – 2024 Annual Information Form    28


Series F First Preferred Shares would be converted into Series G First Preferred Shares on February 15, 2025.

Senior Notes

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured fixed rate notes, which matured in June 2023.

Subordinated Notes

On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes (the “Subordinated Notes”). The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.

Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US Finance LP $300 million USD senior note upon maturity in June 2024, and to repay a New Mexico Gas Intermediate, Inc. $150 million USD fixed rate note upon maturity in July 2024. The remaining proceeds were used for general corporate purposes.

For more information on financing activities for Emera and its subsidiaries, please refer to the “Liquidity and Capital Resources” section of Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

RISK FACTORS

For Emera’s risk factors, refer to the “Enterprise Risk and Risk Management” section of the MD&A and the “Principal Financial Risks and Uncertainties” section of Note 28, Commitments and Contingencies, to the Audited Financial Statements, which are each incorporated herein by reference, copies of which are available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

CAPITAL STRUCTURE

The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares is issuable in series.

As at December 31, 2024, 295,935,686 common shares, 4,866,814 Series A First Preferred Shares, 1,133,186 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares, 12,000,000 Series H First Preferred Shares, 8,000,000 Series J First Preferred Shares, 9,000,000 Series L First Preferred Shares, 2,200,525 Barbados DRs and 1,814,135 Bahamas DRs were issued and outstanding.

Common Shares

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings.

 

Emera Incorporated – 2024 Annual Information Form    29


The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares. The foregoing description is subject to the “Share Ownership Restrictions” section below.

Emera First Preferred Shares

The first preferred shares of each series rank on 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 will be entitled, for only as long as the dividends remain in arrears, 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.

The first preferred shares of each series are not redeemable at the option of their holders. For a summary of the terms and conditions of the Company’s authorized First Preferred Shares as of December 31, 2024, refer to Appendix “B” of this AIF.

Emera Second Preferred Shares

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2024, Emera had not issued any second preferred shares.

Share Ownership Restrictions

As required by the Reorganization Act and pursuant to the Privatization Act, the Articles of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15 per cent of the votes attached to all outstanding voting shares of Emera.

The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The

 

Emera Incorporated – 2024 Annual Information Form    30


Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:

 

      Moody’s    S&P    Fitch

Corporate

   Baa3    BBB    BBB

Outlook

   Negative    Stable (1)    Negative

Senior unsecured debt program

   Baa3    BBB-    BBB

Hybrid Notes

   Ba2    BB+    BB+

First Preferred Shares

   N/A    P-3 (high)    BB+

 

(1)

On January 22, 2025, S&P revised its outlook on Emera to stable from negative with no change to existing ratings.

Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.

Moody’s

Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from highest to lowest quality of such rated securities. The rating of Baa3 obtained from Moody’s in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the obligations are subject to moderate credit risk. As such, they are considered medium-grade and may possess speculative characteristics. The rating of Ba2 from Moody’s in respect of the Hybrid Notes is characterized as having speculative elements and being subject to substantial credit risk. It is the fifth highest of nine available rating categories. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

S&P

S&P’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The issuer rating of BBB obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments. The issue rating of BBB- from S&P in respect of the senior unsecured debt indicates that the obligations exhibit adequate protection parameters. The issue rating of BB+ from S&P in respect of the Hybrid Notes indicates that the obligations exhibit adequate projection parameters in the near term however the obligor may not have the capacity to meet its obligations in the long term. The issue and issuer ratings of BBB and BB are the fourth and fifth highest, respectively, of ten available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

A P-3 (high) rating with respect to Emera’s issued and outstanding First Preferred Shares is the third highest of the eight standard categories of ratings utilized by S&P for preferred shares.

 

Emera Incorporated – 2024 Annual Information Form    31


Fitch

Fitch’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB obtained from Fitch in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the issuer has adequate capacity to meet its financial commitments. The rating of BB from Fitch in respect of the Hybrid Notes is characterized as having elevated default risk however business or financial flexibility exists that support servicing the financial commitments. The BB rating from Fitch is the fifth highest of nine available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

Emera has made, or will make, payments in the ordinary course to the Rating Agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the Rating Agencies during the last two years.

For further information on the credit ratings of Emera and its subsidiaries, refer to the “Credit Ratings” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On June 28, 2024 Emera adjusted its annual dividend growth rate to one to two per cent.

Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2024.

The Board approved the payment of the following dividends during the last three completed fiscal years, as summarized in the following table:

 

       
Class of Shares       2024       2023       2022 
       

Common Shares(1), (2), (3)

     $2.8775        $2.7875        $2.6775  
       

Series A First Preferred Shares(4)

     $0.5456       $0.5456       $0.5456  
       

Series B First Preferred Shares

     $1.6966       $1.5583       $0.6869  
       

Series C First Preferred Shares(5)

     $1.6085       $1.2873       $1.1802  
       

Series E First Preferred Shares

     $1.1250       $1.1250       $1.1250  
       

Series F First Preferred Shares(6)

     $1.0505       $1.0505       $1.0505  
       

Series H First Preferred Shares(7)

     $1.5810       $1.3140       $1.2250  
       

Series J First Preferred Shares(8)

     $1.0625       $1.0625       $1.0625  
       

Series L First Preferred Shares(9)

     $1.1500       $1.1500       $1.1500  

 

(1)

On September 22, 2022, Emera approved an increase in the annual common share dividend rate from $2.65 to $2.76. The first payment was effective November 15, 2022.

 

Emera Incorporated – 2024 Annual Information Form    32


(2)

On September 20, 2023, Emera approved an increase in the annual common share dividend rate from $2.76 to $2.87. The first payment was effective November 15, 2023.

(3)

On September 18, 2024, Emera approved an increase in the annual common share dividend rate from $2.87 to $2.90. The first payment was effective November 15, 2024.

(4)

The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year period commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025.

(5)

The Series C First Preferred Shares annual dividend rate was reset from $1.18024 to $1.60852 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.

(6)

The Series F First Preferred Shares annual dividend rate was reset from $1.0505 to $1.43724 for the five year period commencing February 15, 2025 and ending on (and inclusive of) February 14, 2030.

(7)

The Series H First Preferred Shares annual dividend rate was reset from $1.2250 to $1.5810 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.

(8)

The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued April 6, 2021.

(9)

The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued September 24, 2021.

Pursuant to the Income Tax Act (Canada) and corresponding provincial legislation, all dividends paid on Emera’s common shares and first preferred shares qualify as eligible dividends.

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F”, “EMA.PR.H”, “EMA.PR.J” and “EMA.PR.L”, respectively. The Barbados DRs are listed on the BSE under the symbol EMABDR. The Bahamas DRs are listed on the BISX under the symbol EMAB. The trading volume and high and low price for Emera’s securities for each month of 2024 are set out In Appendix “C” of this AIF.

ATM Program

On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up to $1 billion of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was increased by an amendment dated November 18, 2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13, 2024 to its short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025, unless terminated prior to such date by the Company or otherwise in accordance with the terms of the equity distribution agreement. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – ATM Program” section above.

DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2024:

 

Name, Residence, Principal Occupations During the Past Five Years    Director
Since (2)
   Committees (3)

M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada

Chair of the Board since May 2014.(1) Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Former Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of

   2009    (4)

 

Emera Incorporated – 2024 Annual Information Form    33


Name, Residence, Principal Occupations During the Past Five Years    Director
Since (2)
   Committees (3)

Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company, as well as former director of the general partner of Pacific Northwest LNG LP and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014.

         

Scott C. Balfour, Halifax, Nova Scotia, Canada

A Director and President and Chief Executive Officer of Emera since March 2018. Mr. Balfour is a Director of many Emera subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the Ontario Energy Association.

   2018    (5)

James V, Bertram Calgary, Alberta, Canada

Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from 1998 until 2015, when he became Executive Chair. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international markets.

   2018   

Chair of HSEC

and Member of

MRCC

Henry E. Demone, Lunenburg, Nova Scotia, Canada

Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. Former Director of Saputo Inc. from June 2012 to September 2024.

   2014   

Chair of MRCC

and Member of

NCGC

Paula Y. Gold-Williams, San Antonio, Texas, U.S.

Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Co-Chair of the Keystone Policy Center. Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. A Director of ReNew Energy Global Plc, a renewable energy company based in India. Member of the Nasdaq’s Center for Board Excellence.

   2022   

Member of AC

and HSEC

Kent M. Harvey, New York, New York, U.S.

Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States.

   2017    Chair of AC and Member of HSEC

B. Lynn Loewen, FCPA, FCA, Montreal, Quebec, Canada

Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Risk Management and Technology Committees. Member of the Board of Directors of Kinaxis Inc., a Canadian company that has been revolutionizing supply chain management for more than three decades. She is a Member of Kinaxis’ Audit Committee. Chancellor of Mount Allison University, Chair of its Nominating and Governance Committee and a member of the Executive Committee since 2018. She is the former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment Former member of the Board of Directors of Gildan Activewear Inc. a Canadian apparel manufacture, from April 2024 to May 2024 and former member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023.

   2013    Member of AC, HSEC and RSC

Brian J. Porter, Toronto, Ontario, Canada

Former President and CEO of The Bank of Nova Scotia, operating as Scotiabank, a global bank operating in Canada and the Americas, from November 2013 until his

   2024(6)    Member of AC and RSC

 

Emera Incorporated – 2024 Annual Information Form    34


Name, Residence, Principal Occupations During the Past Five Years    Director
Since (2)
   Committees (3)

retirement in January 2023. Chair of the Board of Governors of Huron University College at Western University, Chair of the Building Ontario Fund and Chair of the Atlantic Salmon Federation (Canada). Director of Fairfax Financial Holdings Ltd. Previously served as Chair of the University Health Network Board of Trustees.

         

Ian E. Robertson, Oakville, Ontario, Canada

A principal of the Northern Genesis Capital Group, an investment group focused on identifying and investing in energy transition businesses. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power). Former member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III. Former Director of Embark Technology, Inc., an autonomous vehicle company, Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc.

   2022   

Member of AC

and RSC

Karen H. Sheriff, Picton, Ontario, Canada

Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to 2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd.

   2021   

Chair of NCGC

and Member of MRCC and RSC

Jochen E. Tilk, Toronto, Ontario, Canada

Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Mr. Tilk is Chair of the Board of AngloGold Ashanti Limited, a publicly listed international gold mining company, based in London, U.K. He is also Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization.

   2018   

Chair of RSC

and Member of MRCC and NCGC

Carla M. Tully, Arlington, Virginia, U.S.

Former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company. Currently, serves on the boards of the Nikola Corporation, Pattern Energy and the Citizens for Responsible Energy Solutions Forum. She is also a Senior Advisor for the Canadian Pension Plan Investment Board (CPPIB) and an advisor to several energy transition startups.

   2024(7)   

Member of

NCGC and AC

 

(1)

It was announced by the Company on November 14, 2024 that Karen Sheriff would succeed Jackie Sheppard as next chair of Board of Directors, effective February 21, 2025.

(2)

Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emera’s annual general meeting.

(3)

Board Committees as of December 31, 2024: Audit Committee (AC), Health, Safety and Environment Committee (HSEC), Management Resources and Compensation Committee (MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC).

(4)

Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board.

(5)

Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the Company but attends all committee meetings.

(6)

Effective March 6, 2024, Brian J. Porter became a Director of Emera.

(7)

Effective June 26, 2024, Carla M. Tully became a Director of Emera.

 

Emera Incorporated – 2024 Annual Information Form    35


Officers

The Officers of Emera as at December 31, 2024 were as follows:

 

   
Name and Residence    Principal Occupations During the Past Five Years

Scott C. Balfour

President and Chief Executive Officer

Halifax, Nova Scotia, Canada

  

A Director and President and Chief Executive Officer of Emera since March 2018. (1)

Gregory W. Blunden, FCPA

Chief Financial Officer

Halifax, Nova Scotia, Canada

  

Chief Financial Officer of Emera since March 2016.

Archibald Collins

President and Chief Executive Officer,

Tampa Electric Company (2)

Tampa, Florida, U.S.

  

President and CEO of Tampa Electric since May 2021. Prior to this, has served as President and Chief Operating Officer of Emera Caribbean, President and CEO of Grand Bahama Power, Executive Vice President Commercial Operations with Emera Energy, and Chief Operating Officer of Tampa Electric.

Karen E. Hutt

Executive Vice-President,

Business Development and Strategy

Halifax, Nova Scotia, Canada

  

Executive Vice-President, Business Development and Strategy of Emera since October 2019. Previously, President and Chief Executive Officer of NSPI since August 2016.

R. Michael Roberts

Chief Human Resources Officer

Halifax, Nova Scotia, Canada

  

Chief Human Resources Officer of Emera and NSPI since December 2014. Director of EBPC since March 2024.

Daniel P. Muldoon

Executive Vice-President Project

Development and Operations Support

Halifax, Nova Scotia, Canada

  

Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of EBPC, Emera Technologies LLC and NMGC and Block Energy, LLC. Former Director of Emera Maine from August 2013 until March 2020. Director of TEC and NSPML. Formerly Executive Vice-President, Major Renewables and Alternative Energy since May 2014.

Michael R. Barrett

Executive Vice-President and General Counsel

Halifax, Nova Scotia, Canada

  

Executive Vice-President and General Counsel of Emera since July 2022. Prior to this, General Counsel of Emera since November 2017. Prior to joining Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto.

Brian C. Curry

Corporate Secretary

Halifax, Nova Scotia, Canada

  

Corporate Secretary of Emera since November 2023 and prior to that Associate Corporate Secretary, Emera. Former Senior Director Regulatory and Corporate Secretary, NSPI from February 2021 to February 2023, Senior Regulatory Counsel and Corporate Secretary, NSPI from January 2020 to February 2021 and Regulatory Counsel from January 2015 to January 2020.

 

(1)

Mr. Balfour’s principal occupations during the past five years are described above in the Directors table.

 

(2)

Mr. Collins is included in Emera’s list of Officers in his capacity as the President and CEO of Tampa Electric Company, which comprises the Florida Electric Utility segment, a principal business unit of Emera.

As at December 31, 2024, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 239,479 common shares or less than 1 per cent of the issued and outstanding common shares of Emera.

 

Emera Incorporated – 2024 Annual Information Form    36


AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Brian J. Porter, Ian E. Robertson and Carla M. Tully. The responsibilities and duties of the Audit Committee are set out in the Audit Committee’s Charter, a copy of which is attached as Appendix “D” to this AIF.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “financially literate” as such term is defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:

Kent M. Harvey, Committee Chair

Former Chief Financial Officer for PG&E Corporation, an energy-based holding company headquartered in San Francisco. PG&E Corporation is the parent company of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. In over 33 years with PG&E Corporation, Mr. Harvey held progressively senior roles before he retired in 2016, including Senior Vice President and Chief Financial Officer 2009 to 2015, Senior Vice President, Chief Risk and Audit Officer 2005 to 2009. He was Senior Vice President, Chief Financial Officer and Treasurer with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, from 2000 to 2005. He holds a Bachelor’s degree in Economics and a Master’s degree in Engineering, both from Stanford University.

Paula Y. Gold-Williams

She is the former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Ms. Gold-Williams served in positions of increasing responsibility at CPS Energy before becoming CEO in 2015. She held multiple other positions during her 17-year career at CPS Energy, including Group EVP – Financial & Administrative Services, CFO and Treasurer. She was Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. She serves as an Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. She is also a member of the board of directors of ReNew Energy Global Plc, a renewable energy company based in India. She is also a member of the Nasdaq’s Center for Board Excellence, a community of like-minded board members, leaders, and innovators committed to advancing corporate governance best practices and effectiveness. Previously, Ms. Gold-Williams held other board positions, including serving on the United States’ Secretary of Energy’s Advisory Board; being a First Vice Chair of the Electric Power Resource Institute (EPRI); a member and designated Chair Pro Tem of the Federal Reserve Bank of Dallas’ San Antonio Branch; and a past-Chair of the San Antonio Chamber of Commerce. She holds an Associate Degree in Fine Arts from San Antonio College and a BBA in accounting from St. Mary’s University. She earned a Finance and Accounting MBA from Regis University in Denver, Colorado. She is a Certified Public Accountant and a Chartered Global Management Accountant.

B. Lynn Loewen, FCPA, FCA

Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. From 2008 to 2011, President of Expertech Network Installation Inc., a Canadian network infrastructure service provider. Ms. Loewen also held key positions with Bell Canada Enterprises, as Vice President of Finance Operations from 2005 to 2008, and as Vice President of Financial Controls from 2003 to 2005. Earlier in her career, she was with Air Canada Jazz where she held positions of increasing responsibility, including Chief Financial Officer and Vice President of Corporate Services. Ms. Loewen is a member of the Board of Directors of National Bank of Canada, serving as Chair of the Audit Committee and as a member of the Risk Management and Technology Committees. She is also a member of the Board of Directors of Kinaxis Inc., a Canadian company that has been revolutionizing supply chain management for more than three decades. She serves on Kinaxis’ Audit Committee. Chancellor of Mount

 

Emera Incorporated – 2024 Annual Information Form    37


Allison University, Chair of its Nominating and Governance Committee and a member of its Executive Committee since 2018. A member of its Board of Regents from 1998 to 2008, serving as Chair from 2007–2008. Ms. Loewen was a member of the Board of Directors of Gildan Activewear Inc., a Canadian apparel manufacturer from April 2024 to May 2024. She was a member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. She is also a former member of the Public Sector Pension Investment Board from 2001 to 2007, where she served on the Audit and Conflicts Committee from 2003 to 2007 and as Audit and Conflicts Committee Chair from 2006 to 2007. She was also Chair of its Governance Committee from 2003 to 2006. She holds a Bachelor of Commerce from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Directors Designation from the Institute of Corporate Directors.

Brian J. Porter

He joined the Emera Board on March 6, 2024. Mr. Porter was the President and CEO of The Bank of Nova Scotia, operating as Scotiabank, a global bank operating in Canada and the Americas, from November 2013 until his retirement in January 2023. Mr. Porter is Chair of the Board of Governors of Huron University College, Chair of the Building Ontario Fund and Chair of the Atlantic Salmon Federation (Canada). He is a Director of Fairfax Financial Holdings Ltd. He previously served as Chair of the University Health Network Board of Trustees. Mr. Porter received a Bachelor of Commerce from Dalhousie University, and was awarded an Honorary Doctor of Laws from Dalhousie University in 2008 and from Ryerson University in 2018. He is a graduate of the Advanced Management Program of the Harvard Business School. Mr. Porter has extensive experience in banking and capital markets and led one of Canada’s largest chartered banks through a period of significant growth and expansion.

Ian E. Robertson

He is a principal of the Northern Genesis Capital Group, an investment group focused on identifying and investing in energy transition businesses. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power), a publicly traded, diversified international generation, transmission, and distribution utility. Founder and principal of Algonquin Power Corporation Inc., a private independent power developer formed in 1988 and predecessor organization to Algonquin Power. Over 30 years of experience in the development of electric power generating projects and the operation of diversified regulated utilities. Former Member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III and a former Director of Embark Technology, Inc., an autonomous vehicle company, Largo Resources Ltd., and Algonquin Power and Atlantica Sustainable Infrastructure plc. Mr. Robertson is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science degree awarded by the University of Waterloo. He earned a Master of Business Administration degree from York University’s Schulich School of Business. He holds a Chartered Financial Analyst designation, as well as a global professional Master of Laws degree from the University of Toronto. He received a Chartered Director designation from the Directors College of McMaster University. Mr. Robertson is a former member of the board of directors of the American Gas Association.

Carla M. Tully

She joined the Emera Board of Directors in June 2024. She is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company she co-developed from concept and grew to a successful 1.7 gigawatts (GW) independent power producer, with an additional 2.0 GW of renewable energy under development. She previously served as Executive Vice President and Managing Director of Renewable Energy at MAP Energy, a $2.4 billion energy investment firm where she scaled the company’s renewable energy development business and raised its first all-renewable energy fund. At The AES Corporation, a global Fortune 500 utility and energy generation company, Ms. Tully held key senior leadership roles, including President of AES UK and Ireland. Currently, Ms. Tully serves on the boards of the Nikola Corporation, Pattern Energy and the Citizens for Responsible Energy Solutions Forum. She is also a Senior Advisor for the Canadian Pension Plan Investment Board (CPPIB) and an advisor to several energy transition startups. She holds a Master of Business Administration from Columbia Business School,

 

Emera Incorporated – 2024 Annual Information Form    38


a Master of Arts in Law and Diplomacy from the Fletcher School at Tufts University, and a bachelor’s degree in international relations and economics from the University of Southern California.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors’ independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.

Unless a type of service has received the pre-approval of the Audit Committee, it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels will also require specific approval by the Audit Committee.

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2024 and 2023 respectively, were as follows:

 

Service Fee    2024 ($)       2023 ($)   

Audit Fees

     $5,689,398         $3,910,266   

Audit-Related Fees (1)

     240,080         174,410   

Tax Fees (2)

     323,252         39,450   

All Other Fees

     -         75,000   

Total

           $6,252,730               $4,199,126   

 

(1)

Audit-related fees for Emera relate to fees associated with agreed upon procedures over rate-case filings and the audit of pension plans.

(2)

Tax fees for Emera relate to tax compliance services and general tax consulting advice on various matters.

CERTAIN PROCEEDINGS

To the knowledge of Emera, none of the Directors or Officers of the Company:

 

(1)

are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

 

  (a)

was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief executive officer or chief financial officer; or

 

  (b)

was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;

 

(2)

with the exception of Ms. Tully as set forth below, are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

 

(3)

have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any

 

Emera Incorporated – 2024 Annual Information Form    39


  proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee; or

 

(4)

have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

As of the date of this AIF, Carla M. Tully is a director of Nikola Corporation (“Nikola”). On February 19, 2025, Nikola announced that it and certain of its subsidiaries had filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware and that Nikola had also filed a motion seeking authorization to pursue an auction and sale process under Section 363 of the U.S. Bankruptcy Code.

CONFLICTS OF INTEREST

There are no existing or potential material conflicts of interest between Emera or any of its subsidiaries and any Director or Officer of Emera or any of its subsidiaries.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10 per cent or more of the current assets of Emera, exclusive of interest and costs.

During Emera’s most recently completed financial year, there have been no (a) penalties or sanctions imposed against Emera by a court relating to securities legislation or by a securities regulatory authority, (b) other penalties or sanctions imposed by a court or regulatory body against Emera that would likely be considered important to a reasonable investor in making an investment decision, and (c) settlement agreements entered into by Emera before a court relating to securities legislation or with a securities regulatory authority.

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10 per cent of any class or series of Emera’s outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emera’s last three completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Emera.

MATERIAL CONTRACTS

Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2024, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2024 that are still in effect as at the date of this AIF.

TRANSFER AGENT AND REGISTRAR

TSX Trust Company acts as Emera’s transfer agent and registrar for Emera’s common shares and first preferred shares. Registers for the registration and transfer of these securities of Emera are kept at TSX Trust Company’s principal offices in Halifax, Montreal and Toronto.

 

Emera Incorporated – 2024 Annual Information Form    40


EXPERTS

Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent in the context of the CPA Code of Professional Conduct of the Chartered Professional Accountants of Nova Scotia and are in compliance with Rule 3520 of the Public Company Accounting Oversight Board (United States).

ADDITIONAL INFORMATION

Additional information relating to Emera may be found under Emera’s profile on SEDAR+ at www.sedarplus.ca or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s Audited Financial Statements and MD&A.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Code of Conduct. Alternatively, a copy of the Emera Code of Conduct is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on its corporate website at www.emera.com.

 

Emera Incorporated – 2024 Annual Information Form    41


APPENDIX “A” - Definitions of Certain Terms

 

For convenience, certain terms used throughout this AIF shall have the following meanings:

“adjusted net income” has the meaning ascribed to it in the “Non-GAAP Financial Measures and Ratios” section of the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator;

“AIF” or “Annual Information Form” means this 2024 Annual Information Form of Emera;

“Atlantic Canada” means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island;

“ATM Program” means an at-the-market distribution program allowing Emera to issue common shares from treasury at the prevailing market price.

“Audited Financial Statements” means the audited consolidated financial statements of Emera as at and for the years ended December 31, 2024 and December 31, 2023, together with the auditors’ report thereon, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

“Bahamas DRs” means the DRs listed on BISX;

“Barbados DRs” means the DRs listed on the BSE;

“BBD” means Barbadian dollars;

“BISX” means The Bahamas International Securities Exchange;

“Bear Swamp” means Bear Swamp Power Company, LLC, a 633 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50 per cent interest;

“Block Energy” means Block Energy LLC, formerly Emera Technologies LLC, a wholly-owned subsidiary of Emera existing under the laws of the State of Florida.

“BLPC” means Barbados Light & Power Company Limited, a vertically integrated electric utility company incorporated under the laws of Barbados and a wholly-owned, direct subsidiary of ECI;

“Board” means the Board of Directors of Emera;

“Brooklyn Energy” means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Saint John LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC;

“BSD” means Bahamian dollars;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

“CAIR” means the Clean Air Interstate Rule;

“CER” or “Canada Energy Regulator”, the independent regulator of EBPC.

“COMFIT” means the Nova Scotia Community Feed in Tariff program which is offered by the Province of Nova Scotia and enables community organizations to be involved in renewable electricity generation;

“Company” means Emera;

“Consolidated Balance Sheets” means the consolidated balance sheets contained within the Audited Financial Statements;

“Directors” mean the directors of Emera and “Director” means any one of them;

“Dividend Reinvestment Plan” or “DRIP” means the Company’s Common Shareholders’ Dividend Reinvestment and Share Purchase Plan;

“DR” means a depositary receipt representing common shares of Emera;

“EBPC” or “Emera Brunswick Pipeline Company” means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly-owned, indirect subsidiary of Emera;

“ECI” means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and an indirect subsidiary of Emera and the parent company of BLPC and GBPC;

“ECRC” means the environmental cost recovery clause;

 

 

Emera Incorporated – 2024 Annual Information Form    42


“EfficiencyOne” mean a federally incorporated not-for-profit third-party entity that currently holds the franchise for the provision of energy efficiency and conservation in the Province, which is deemed to be a utility under the Public Utilities Act and regulated by the UARB.

“EIFEL” means excessive interest and financing expenses limitation;

“Electricity Act” means the Electricity Act, 2004, c. 25, s. 1. (Nova Scotia);

“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol “EMA”;

“Emera Energy” means the businesses of Emera Energy Services, Brooklyn Energy and Bear Swamp;

“Emera Energy LP” means a wholly-owned subsidiary of Emera formed under the laws of the Province of Nova Scotia;

“Emera Energy Services” or “EES” means Emera Energy LP and Emera Energy Services, Inc., a natural gas and electricity marketing and trading company and a wholly-owned, indirect subsidiary of Emera incorporated under the laws of the State of Delaware, which together form a natural gas and electricity marketing and trading business;

“Emera US Finance LP” means a wholly owned indirect financing limited partnership of Emera, formed under the laws of the State of Delaware;

“EPA” means the U.S. Environmental Protection Agency;

“EUSHI Finance, Inc.” means a wholly owned indirect financing subsidiary of Emera, incorporated under the laws of the State of Delaware;

“Fair Trading Commission, Barbados” or “FTC” means the regulator of BLPC;

“FAM” means the fuel adjustment mechanism established by the UARB;

“FCM” means forward capacity market;

“FERC” means the United States Federal Energy Regulatory Commission;

“Fitch” means the credit rating agency Fitch Ratings Inc;

“First Preferred Shares” means each series of Emera’s authorized first preferred shares, namely its Series 2016-A Conversion, First Preferred Shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series D First Preferred Shares, Series E First

Preferred Shares, Series F First Preferred Shares, Series G First Preferred Shares Series H First Preferred Shares, Series I First Preferred Shares Series J First Preferred Shares and Series L First Preferred Shares;

“FPSC” means the Florida Public Service Commission, the regulator of Tampa Electric and PGS;

“GBPA” means The Grand Bahama Port Authority, the regulator of GBPC;

“GBPC” or “Grand Bahama Power Company” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and an indirect subsidiary of ECI;

“Government of Canada Bond Yield” on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100 per cent of its principal amount on such date with a term to maturity of five years;

“Government of Canada T-Bill Rate” means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;

“GHG” means greenhouse gas;

“GWh” means the amount of electricity measured in gigawatt hours;

“Hybrid Notes” means the $1.2 billion USD unsecured, fixed-to-floating subordinated notes of Emera due 2076;

“IFRS” means International Financial Reporting Standards;

“IMP” means integrity management programs;

“IPPs” means independent power producers;

“km” means kilometre(s);

 

 

Emera Incorporated – 2024 Annual Information Form    43


“Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and Labrador developed by NLH (formerly, Nalcor Energy), which enables the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland;

“LNG” means liquefied natural gas;

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 19.5 per cent interest through ECI;

“M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas between the Maritime Provinces and New England, in which Emera holds an indirect 12.9 per cent interest;

“Maritime Link” means the transmission project which includes two 170-km sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, developed by NSP Maritime Link Inc.;

“Maritime Provinces” means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick and Prince Edward Island;

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2024, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

“Moody’s” means the credit rating agency Moody’s Investor Services, Inc. a subsidiary of Moody’s Corporation;

“MW” means the amount of power measured in megawatts;

“NB Power” means New Brunswick Power Corporation, a provincial Crown corporation formed under the laws of the Province of New Brunswick, responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;

“NERC” means North American Electric Reliability Corporation;

“New England” means the region of the United States consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont;

“NLH” means Newfoundland and Labrador Hydro, a company that is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador as a Crown corporation, and formerly Nalcor Energy;

“NMGC” means New Mexico Gas Company, Inc., a regulated gas distribution utility incorporated under the laws of Delaware and serving customers across New Mexico;

“NMPRC” means the New Mexico Public Regulation Commission, the regulator of NMGC;

“NPCC” means Northeast Power Coordinating Council, Inc.;

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;

“NS Block” means the electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project;

“NSEB” means Nova Scotia Energy Board;

“NSP Maritime Link Inc.” or “NSPML” means NSP Maritime Link Incorporated, a wholly-owned indirect subsidiary of Emera, incorporated under the laws of the Province of Newfoundland and Labrador, that developed the Maritime Link;

“NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct and indirect subsidiary of Emera;

“Officers” mean the executive officers of Emera and “Officer” means any one of them;

“O&M expenses” means operations and maintenance expenses;

“OM&G” means operating, maintenance and general;

“OBPS” means output-based pricing system;

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that is in effect for a period of more than 30 consecutive days;

“PGS” or “Peoples Gas System” means Peoples Gas System, Inc., formerly the Peoples Gas System Division of TEC, operating as a regulated gas distribution utility serving customers across Florida, and a wholly-owned indirect subsidiary of Emera existing under the laws of the State of Florida;

“PP&E” means property, plant and equipment;

“Privatization Act” means the Nova Scotia Power Privatization Act, S.N.S., 1992, c.8 - and all amendments thereto;

“Province” means the Province of Nova Scotia, Canada and includes, when the context requires, the

 

 

Emera Incorporated – 2024 Annual Information Form    44


provincial government of Nova Scotia, and “provincial” refers to Nova Scotia;

“Public Utilities Act” means the Public Utilities Act (Nova Scotia);

“Rating Agencies” means collectively Fitch, Moody’s and S&P, and “Rating Agency” means any one of the Rating Agencies;

“RENAC” means Repsol Energy North America Canada Partnership;

“Reorganization Act” means the Nova Scotia Power Reorganization (1998) Act, S.N.S., 1998, c.19 - and all amendments thereto;

“Repsol” means Repsol S.A, the parent company of RENAC;

“RER” means the Nova Scotia Renewable Electricity Regulations;

“ROE” means return on equity;

“S&P” means the credit rating agency S&P Global Ratings, a division of S&P Global Inc.;

“SeaCoast” means SeaCoast Gas Transmission, LLC, a company incorporated under the laws of the State of Delaware and a wholly-owned indirect subsidiary of Emera;

“Securities Act” means the United States Securities Act of 1933, as amended;

“SEDAR+” means the System for Electronic Document Analysis and Retrieval+ of the Canadian Securities Administrators, at www.sedarplus.ca;

“Series 2016-A Conversion, First Preferred Shares” means the cumulative preferential first preferred shares, Series 2016-A of Emera;

“Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares, Series A of Emera;

“Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera;

“Series C First Preferred Shares” means the cumulative rate reset first preferred shares, Series C of Emera;

“Series D First Preferred Shares” means the cumulative floating rate first preferred shares, Series D of Emera;

“Series E First Preferred Shares” means the cumulative redeemable first preferred shares, Series E of Emera;

“Series F First Preferred Shares” means the cumulative rate reset first preferred shares, Series F of Emera;

“Series G First Preferred Shares” means the cumulative floating rate first preferred shares, Series G of Emera;

“Series H First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series H of Emera;

“Series I First Preferred Shares” means the cumulative floating rate first preferred shares, Series I of Emera;

“Series J First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series J of Emera;

“Series K First Preferred Shares” means the cumulative floating rate first preferred shares, Series K of Emera;

“Series L First Preferred Shares” means the cumulative redeemable first preferred shares, Series L of Emera;

“SO2” means sulphur dioxide;

“SoBRA” means solar base rate adjustment;

“Subordinated Notes” means the $500 million USD 7.625% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2054;

“TEC” means Tampa Electric Company, an integrated regulated electric utility, serving customers in West Central Florida, a wholly-owned indirect subsidiary of Emera, incorporated under the laws of the State of Florida;

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, the independent regulator of NSPI;

“USD” means U.S. dollars; and

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute.

 

 

Emera Incorporated – 2024 Annual Information Form    45


APPENDIX “B” – Summary of Terms and Conditions of Authorized Series of First

Preferred Shares

As of December 31, 2024, the following series of First Preferred Shares have been authorized:

Series A, B, C, D, E, F, G, H, I, J, K and L First Preferred Shares

Holders of the First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the First Preferred Shares.

In any instance where the holders of First Preferred Shares are entitled to vote, each holder shall have one vote for each Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of Series A, C, F, H and J First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada Bond Yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, (i) in the case of the Series H preferred shares, to a fixed minimum reset of 4.90 per cent and (ii) in the case of the Series J preferred shares, to a fixed minimum reset of 4.25 per cent). Holders of the Series A, C, F, H and J First Preferred Shares have the right to convert their shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below.

Holders of Series B, D, G, I and K First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate , recalculated quarterly, on the applicable reset date plus a spread as set forth in the table below.

The Series A, C, F, H and J First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances by the payment of cash on the dates set forth in the table below at a price of $25.00 per share plus any accrued and unpaid dividends.

The Series B, D, G, I and K First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances after their respective initial redemption dates by payment in cash as set forth in the table below at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions as set out in the table below or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date.

Subject to certain conditions including the right of Emera to redeem, holders of the Series A, C, F, H and J First Preferred Shares, have the right to convert any or all of their Series A, C, F, H and J First Preferred Shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively. In addition, the Series A, C, F, H and J First Preferred Shares may be automatically converted by Emera into Series B, D, G, I and K First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series A, C, F, H and J First Preferred Shares outstanding, respectively.

Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, I and K First Preferred Shares, the holders of Series B, D, G, I and K First Preferred Shares have the right to convert any or all of their Series B, D, G, I and K First Preferred Shares into an equal number of Series A, C, F, H and J First Preferred Shares respectively. In addition, Series B, D, G, I and K First Preferred Shares may be automatically converted by Emera into Series A, C, F, H and J First Preferred Shares, respectively

 

Emera Incorporated – 2024 Annual Information Form    46


if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B, D, G, I and K First Preferred Shares outstanding.

Holders of Series E First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.125 per share per annum in perpetuity, subject to certain redemption rights. The Series E First Preferred Shares were not redeemable by the Company prior to August 18, 2018. The Series E First Preferred Shares are redeemable on or after August 18, 2018 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before August 15, 2019; $25.75 per share if redeemed on or after August 15, 2019 but before August 15, 2020; $25.50 per share if redeemed on or after August 15, 2020 but before August 15, 2021; $25.25 per share if redeemed on or after August 15, 2021 but before August 15, 2022; and $25.00 per share if redeemed on or after August 15, 2022; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Holders of Series L First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.150 per share per annum in perpetuity, subject to certain redemption rights. The Series L First Preferred Shares are not redeemable by the Company prior to November 15, 2026. The Series L First Preferred Shares are redeemable on or after November 15, 2026 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before November 15, 2027; $25.75 per share if redeemed on or after November 15, 2027 but before November 15, 2028; $25.50 per share if redeemed on or after November 15, 2028 but before November 15, 2029; $25.25 per share if redeemed on or after November 15, 2029 but before November 15, 2030; and $25.00 per share if redeemed on or after November 15, 2030; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Applicable redemption, conversion, interest and reset dates and spreads are listed in the following table:

 

       
Series of First
Preferred Shares
   Initial Redemption /
Interest Reset Date
 

Subsequent Redemption / Conversion / Interest

Reset Dates

   Spreads
       

Series A

   August 15, 2015   August 15, 2020 and every fifth year thereafter    1.84%
       

Series B

   August 15, 2020   August 15, 2025 and every fifth year thereafter    1.84%
       

Series C

   August 15, 2018   August 15, 2023 and every fifth year thereafter    2.65%
       

Series D

   –   August 15, 2023 and every fifth year thereafter    2.65%
       

Series E

   August 15, 2018   –    –
       

Series F

   February 15, 2020   February 15, 2025 and every fifth year thereafter    2.63%
       

Series G

   –   February 15, 2025 and every fifth year thereafter    2.63%
       

Series H

   August 15, 2023   August 15, 2028 and every fifth year thereafter    2.54%
       

Series I

   –   August 15, 2028 and every fifth year thereafter    2.54%
       

Series J

   May 15, 2026   May 15, 2031 and every fifth year thereafter    3.28%
       

Series K

   –   May 15, 2031 and every fifth year thereafter    3.28%
       

Series L

   November 15, 2026   –    –

Series 2016-A Conversion, First Preferred Shares

The Series 2016-A Conversion, First Preferred Shares were authorized pursuant to the Hybrid Notes offering in June 2016. As at December 31, 2024, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.

Holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of

 

Emera Incorporated – 2024 Annual Information Form    47


the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.

In any instance where the holders of Series 2016-A Conversion, First Preferred Shares are entitled to vote, each holder shall have one vote for each Series 2016-A Conversion, First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of each series of Series 2016-A Conversion, First Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board, at the same rate as would have accrued on the related series of Hybrid Notes (had such Hybrid Notes remained outstanding). The Series 2016-A Conversion, First Preferred Shares do not have a fixed maturity date.

The Series 2016-A Conversion, First Preferred Shares are redeemable by Emera on June 15, 2026. After that date, Emera may redeem at any time all, or from time to time any part, of the outstanding Series 2016-A Conversion, First Preferred Shares, without the consent of the holders, by the payment of an amount in cash for each such share so redeemed of USD$1,000 per share together with an amount equal to all accrued and unpaid dividends thereon.

 

Emera Incorporated – 2024 Annual Information Form    48


APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR

EMERA’S SECURITIES IN 2024

 

      Common
Shares
     Depositary Receipts      Series of First Preferred Shares  
  

 

Barbados
BBD
(1)

    

 

Bahamas

BSD (2)

     A      B      C      E      F      H      J      L  

December

                                            

High ($)

     56.20        20.06        8.52        16.85        16.94        23.56        19.00        21.43        24.50        22.74        19.19  

Low ($)

     52.71        18.41        8.52        16.00        16.01        22.66        18.31        19.95        23.17        21.80        18.34  

Volume

     23,295,397        82        15,247        45,696        24,662        74,824        41,102        90,137        143,287        185,594        138,818  

November

                                            

High ($)

     53.75        20.00        9.43        16.00        16.99        23.01        18.78        20.37        23.47        22.28        18.85  

Low ($)

     49.46        17.57        9.43        15.26        16.55        21.87        18.01        19.28        22.55        20.65        18.58  

Volume

     32,478,281        54        953        101,485        51,304        169,123        35,600        205,903        387,791        56,328        60,962  

October

                                            

High ($)

     54.19        23.00        9.79        16.52        17.19        23.00        19.40        19.91        23.71        21.45        19.53  

Low ($)

     49.06        17.93        8.98        15.03        16.02        22.30        18.69        19.06        23.15        20.95        18.66  

Volume

     34,184,085        1,280        0        66,359        22,322        115,923        38,135        300,184        97,443        110,039        140,356  

September

                                            

High ($)

     53.83        23.00        9.50        15.40        17.00        22.94        19.46        19.59        23.75        21.60        19.60  

Low ($)

     50.64        18.56        9.50        14.95        15.25        22.04        18.95        18.93        22.81        20.95        19.05  

Volume

     21,527,984        32        913        92,918        28,520        143,633        28,147        31,230        148,702        65,786        82,297  

August

                                            

High ($)

     50.91        23.00        9.06        15.26        16.88        22.92        19.07        19.39        23.90        22.15        19.38  

Low ($)

     48.53        17.43        9.06        14.40        16.40        21.52        18.35        18.07        23.05        19.92        18.70  

Volume

     26,567,189        25        365        28,208        10,062        160,812        31,014        262,878        182,558        89,727        31,289  

July

                                            

High ($)

     50.56        18.31        8.55        15.75        17.75        22.43        18.60        19.39        24.01        22.80        19.00  

Low ($)

     44.13        16.11        8.55        15.00        16.49        21.55        17.37        18.57        23.00        20.30        17.79  

Volume

     29,603,191        0        1,826        20,749        35,993        169,967        62,491        147,804        243,084        133,891        73,003  

June

                                            

High ($)

     48.19        23.00        8.80        15.35        17.10        21.80        17.70        19.93        23.24        21.14        18.01  

Low ($)

     44.40        16.06        8.10        14.24        16.25        20.23        17.06        17.53        21.85        20.01        17.26  

Volume

     20,606,470        5        0        49,361        64,972        144,182        43,696        169,210        118,740        93,825        95,191  

May

                                            

High ($)

     50.69        23.00        9.29        15.50        17.40        21.77        17.84        19.80        23.30        21.49        18.10  

Low ($)

     46.07        16.75        8.37        14.85        16.76        21.20        16.81        18.55        21.00        20.27        17.32  

Volume

     28,099,615        35        0        356,028        52,925        504,710        17,355        202,799        108,480        82,250        31,871  

April

                                            

High ($)

     47.99        23.00        8.52        15.11        17.74        21.74        17.44        18.85        22.46        20.49        17.95  

Low ($)

     45.56        16.62        8.24        14.37        16.38        21.00        16.75        18.51        20.90        19.94        16.96  

Volume

     37,216,196        49        6,106        174,528        42,988        78,041        32,482        339,208        191,149        49,423        160,921  

March

                                            

High ($)

     49.14        23.00        9.12        14.60        16.44        21.55        17.65        18.89        22.27        20.32        17.98  

Low ($)

     47.04        17.12        8.66        14.15        16.05        20.90        16.89        18.22        21.15        19.26        17.30  

Volume

     16,223,256        16        0        90,523        14,951        62,190        18,200        54,278        55,243        97,184        33,448  

February

                                            

High ($)

     48.83        18.09        9.60        14.55        17.08        22.00        17.96        19.39        22.49        21.32        17.82  

Low ($)

     46.23        17.05        9.60        13.97        16.25        20.99        17.10        18.40        21.24        20.02        17.21  

Volume

     23,857,187        0        150        10,410        14,510        59,971        35,530        166,299        54,054        55,580        56,528  

January

                                            

High ($)

     51.81        23.00        9.68        15.18        17.00        22.00        17.98        19.90        22.49        21.02        17.95  

Low ($)

     47.41        17.63        8.85        13.49        15.00        20.25        16.79        17.09        21.40        18.00        16.95  

Volume

     25,400,512        235        0        220,670        45,357        108,412        40,908        319,541        119,158        92,010        124,913  

 

(1)

The Barbados DRs trade on the BSE. During those months in 2024 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Barbados DRs relative to those of Emera’s common shares on the TSX.

(2)

The Bahamas DRs trade on the BISX. During those months in 2024 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Bahamas DRs relative to those of Emera’s common shares on the TSX.

 

Emera Incorporated – 2024 Annual Information Form    49


February 2025    LOGO

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

There shall be a committee of the Board of Directors (the “Board”) of Emera Inc. (“Emera”) which shall be known as the Audit Committee (the “Committee”). The Committee shall assist the Board in discharging its oversight responsibilities concerning:

 

-

the quality and integrity of Emera’s financial statements;

 

-

the effectiveness of Emera’s internal control systems over financial reporting;

 

-

the internal audit and assurance process;

 

-

the qualifications, independence and performance of the external auditors;

 

-

major financial risk exposures;

 

-

Emera’s compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and

 

-

any other duties set out in this Charter or delegated to the Committee by the Board.

 

1.

Financial Reporting

 

  (a)

The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in, and recommending to the Board for approval:

 

  (i)

the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and earnings press releases;

 

  (ii)

any documents containing Emera’s audited financial statements; and,

 

  (iii)

the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases.

 

  (b)

The Board may delegate the approval of the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases to the Committee.

 

  (c)

The Committee shall oversee and assess that adequate procedures are in place for the review of public disclosure of financial information.

 

2.

External Auditors

 

  (a)

The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.

 

  (b)

Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or

 

Emera Incorporated – 2024 Annual Information Form    50


  issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.

 

  (c)

The Committee shall be responsible for resolving disagreements between management and the external auditor concerning financial reporting.

 

  (d)

At least annually, the Committee shall obtain and review a report by the external auditors describing: (i) the firm’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess the auditors’ independence).

 

  (e)

The Committee shall annually evaluate the auditors’, including the lead audit partner’s, qualifications, performance, professional skepticism and independence.

 

  (f)

The Committee shall determine that the external audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under prescribed independence rules.

 

  (g)

Every five (5) years, the Committee shall perform a comprehensive review of the performance of the external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.

 

  (h)

The Committee will review differences that were noted or proposed by the external auditors, but that were considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.

 

3.

Non-Audit Services

 

  (a)

The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor.

 

  (b)

The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.

 

  (c)

In accordance with policies and procedures established by the Committee, and applicable legislation and regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.

 

4.

Oversight and Monitoring of Audits

 

  (a)

The Committee shall meet with the external auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.

 

Emera Incorporated – 2024 Annual Information Form    51


  (b)

The Committee shall discuss with the external auditor any issues that arise with Management or the internal auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.

 

  (c)

The Committee shall regularly review with the external auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the external auditors’ activities or access to requested information, and Management’s response.

 

  (d)

The Committee shall review with Management the results of internal and external audits.

 

  (e)

The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.

 

5.

Oversight and Review of Accounting Principles and Practices

The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

 

  (a)

the quality, appropriateness and acceptability of Emera’s accounting principles and practices used in its financial reporting, changes in Emera’s accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events;

 

  (b)

all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any “other opinions” sought by Management from an independent auditor, other than the Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;

 

  (c)

disagreements between Management and the external auditor or the internal auditors regarding the application of any accounting principles or practices;

 

  (d)

any material change to Emera’s auditing and accounting principles and practices as recommended by Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;

 

  (e)

the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial disclosures;

 

  (f)

any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect asset and liability carrying values and the timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera;

 

  (g)

the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;

 

Emera Incorporated – 2024 Annual Information Form    52


  (h)

any legal matter, claim or contingency that could have a significant impact on the financial statements, Emera’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emera’s financial statements;

 

  (i)

the treatment for financial reporting purposes of any significant transactions which are not a normal part of Emera’s operations.

 

6.

Hiring Policies

The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

 

7.

Pension Plans

The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.

 

8.

Oversight of Finance Matters

 

  (a)

The Committee shall review the appointments of key financial executives involved in the financial reporting process of Emera, including the Chief Financial Officer.

 

  (b)

The Committee may request for review, and shall receive when requested, material tax policies and tax planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emera’s compliance with tax and financial reporting laws and regulations.

 

  (c)

The Committee shall meet at least annually with Management to review and discuss Emera’s major financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks.

 

  (d)

The Committee may review any investments or transactions that the Committee wishes to review, or which the internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.

 

  (e)

The Committee shall review financial information of material subsidiaries of Emera and any auditor recommendations concerning such subsidiaries.

 

  (f)

The Committee may request for review, and shall receive when requested, all related party transactions required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made.

 

Emera Incorporated – 2024 Annual Information Form    53


9.

Internal Controls

The Committee shall oversee:

 

  (a)

the adequacy and effectiveness of the Company’s internal accounting and financial controls and the recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and

 

  (b)

management’s compliance with the Company’s processes, procedures and internal controls.

In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.

The Committee will carry out the following specific duties:

 

  (c)

Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.

 

  (d)

Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their certification process for the annual and interim filing with applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record, process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls.

 

  (e)

Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies.

 

10.

Internal Auditor

 

  (a)

The lead internal auditor shall report directly to the Committee. The Committee shall approve the appointment, removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment.

 

  (b)

The Committee shall review and approve the internal audit plan, including activities, organizational structure, staffing, qualifications and budget, and shall review all major changes to the plan. The Committee shall review and discuss with the internal auditor the scope, progress, and results of executing the internal audit plan. The Committee shall receive reports on the status of significant findings, recommendations, and management’s responses.

 

  (c)

The Committee shall meet periodically with the internal auditor to discuss the progress of their activities, any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Management’s responses in addressing audit-related deficiencies.

 

Emera Incorporated – 2024 Annual Information Form    54


  (d)

The Committee shall obtain from the internal auditor and review summaries of the significant reports to Management prepared by the internal auditor, and the actual reports if requested by the Committee, and Management’s responses to such reports.

 

  (e)

The Committee shall annually receive and review a report on the Chief Executive Officers’ expense accounts.

 

  (f)

The Committee may communicate with the internal auditor with respect to their reports and recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.

 

  (g)

The Committee shall, at least annually, approve the internal audit charter. The internal auditor shall confirm to the Committee annually that the function adheres to applicable professional standards. The Committee may provide feedback on the performance of the lead internal auditor as deemed necessary.

 

  (h)

The Committee shall, at least annually, review the independence of the internal audit function and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal audit function.

 

  (i)

The Committee shall review the results of an external assessment, performed every five years by a qualified independent assessor or assessment team, of the internal audit function in conformance with Global Internal Audit Standards.

 

11.

Complaints

The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters. Without limiting the foregoing, the Committee shall receive periodic ethics updates under Emera’s Code of Conduct which relate to matters within the scope of responsibility of the Committee as defined in this Charter, and the Committee shall review the related activities within that scope under Emera’s Ethics Program, such as financial reporting, accounting and auditing, business integrity, and corporate assets and infrastructure.

 

12.

Other Responsibilities

The Committee shall:

 

  (a)

Periodically review Management’s process for identifying non-compliance with legal and regulatory requirements;

 

  (b)

Annually receive and review a report on executive officers’ compliance with the Company’s Code of Conduct;

 

  (c)

Annually provide feedback on the performance of the Chief Financial Officer;

 

Emera Incorporated – 2024 Annual Information Form    55


  (d)

Review actions taken by the Company to identify and manage risks related to the Audit Committee mandate, including Primary Enterprise Risks, which may have the potential to adversely impact the Company’s operations, strategy or reputation; and

 

  (e)

Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board.

 

13.

Limitation on Authority

Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

PART II

COMPOSITION

 

14.

Composition

 

  (a)

Emera’s Articles of Association require that the Committee shall be comprised of no less than three directors none of whom may be officers or employees of Emera nor may they be an officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation.

 

  (b)

The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements.

 

  (c)

Committee members shall be appointed at the Board meeting following the election of Directors at Emera’s annual shareholders’ meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.

 

  (d)

Pursuant to Emera’s Articles of Association, the Board may appoint, remove, or replace any member of the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the Committee.

 

  (e)

The Secretary of the Committee shall advise Emera’s internal and external auditors of the names of the members of the Committee promptly following their election.

 

Emera Incorporated – 2024 Annual Information Form    56


PART III

COMMITTEE PROCEDURE

 

15.

Meetings

 

  (a)

Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall meet at least quarterly.

 

  (b)

The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting, shall be determined from time to time by the Committee.

 

  (c)

Emera’s internal and external auditors shall be notified of all meetings of the Committee and shall have the right to appear before and be heard by the Committee.

 

  (d)

Emera’s internal or external auditors may request the Chair of the Committee to consider any matters which the internal or external auditors believe should be brought to the attention of the Committee or the Board.

 

16.

Separate Sessions

 

  (a)

The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.

 

  (b)

The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the Committee to bring forward matters requiring its attention.

 

  (c)

The Committee shall meet periodically without Management present.

 

17.

Quorum

A majority of the members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.

 

18.

Chair

Pursuant to Emera’s Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.’s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.

 

19.

Secretary and Minutes

Pursuant to Emera’s Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emera’s Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emera’s records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.

 

Emera Incorporated – 2024 Annual Information Form    57


20.

Board Relationships and Reporting

The Committee shall:

 

  (a)

Review annually the Committee’s Charter;

 

  (b)

Oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emera’s Annual Information Form and any other applicable disclosure documents;

 

  (c)

Report to the Board at the next following board meeting on any meeting held by the Committee, and as required, regularly report to the Board on Committee activities, issues, and related recommendations; and

 

  (d)

Maintain free and open communication between the Committee, the external auditors, internal auditors, and Management, and determine that all parties are aware of their responsibilities.

 

21.

Powers

The Committee shall:

 

  (a)

examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;

 

  (b)

have the authority to communicate directly with the internal and external auditors; and

 

  (c)

have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates.

 

22.

Experts and Advisors

The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.

 

Emera Incorporated – 2024 Annual Information Form    58
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
exhibit992p1i0
Exhibit 99.2
1
Management’s Discussion & Analysis
As at February 21, 2025
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera
Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the
“Company”) during the fourth quarter of, and for the full year of, 2024 relative to the same periods in 2023
and selected financial information for 2022; and its financial position as at December 31, 2024 relative to
December 31, 2023. The Company’s activities are carried out through five reportable segments: Florida
Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
 
This MD&A should be read in conjunction with the Emera annual audited consolidated financial
statements and supporting notes as at and for the year ended December 31, 2024.
 
Emera follows United
States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related
to Emera, including the Company’s Annual Information Form, can be found on Sedar+ at
www.sedarplus.ca.
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s
non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities,
revenues and expenses. At December 31, 2024, Emera’s rate-regulated subsidiaries and investments
include:
 
Rate-Regulated Subsidiary or Equity Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric Company (“TEC”)
Florida Public Service Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. ("NSPI")
Nova Scotia Utility and Review Board (“UARB”)
 
Peoples Gas System, Inc. (“PGS”)
FPSC
New Mexico Gas Company, Inc. (“NMGC”)
New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC ("SeaCoast")
FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick
Pipeline”)
 
Canadian Energy Regulator ("CER")
Barbados Light & Power Company Limited (“BLPC”)
 
Fair Trading Commission, Barbados ("FTC")
Grand Bahama Power Company Limited (“GBPC”)
 
The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)
UARB
Maritimes & Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)
National Utility Regulatory Commission
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and
Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States
dollars (“USD”) unless otherwise stated.
2
TABLE
 
OF CONTENTS
Forward-looking Information……………………......
2
Introduction and Strategic Overview………….……
3
Non-GAAP Financial Measures and Ratios….…...
4
Consolidated Financial Review……….……………
6
 
Significant Items Affecting Earnings………........
6
 
Consolidated Financial Highlights………………
 
7
 
Consolidated Income Statement Highlights……
9
Business Overview and Outlook…………….……..
12
 
Florida Electric Utility ………………...............…
12
 
Canadian Electric Utilities …..………….……….
13
 
Gas Utilities and Infrastructure..…….…….…….
16
 
Other Electric Utilities ……………………………
17
 
Other……………………………………………….
18
Consolidated Balance Sheet Highlights…………..
19
Other Developments…………………………………
21
Financial Highlights……………………………..…..
22
 
Florida Electric Utility …………..........................
22
 
Canadian Electric Utilities ……..…………..……
24
 
Gas Utilities and Infrastructure……………...…..
27
 
Other Electric Utilities …………………………....
29
 
Other…………………………………………….….
30
Liquidity and Capital Resources………..…………..
33
 
Consolidated Cash Flow Highlights…..…………
34
 
Working Capital……………………………………
35
 
Contractual Obligations…………………………..
36
 
Forecasted Consolidated Capital Investments…
37
 
Debt Management………………………………..
37
 
Credit Ratings……………………………………..
39
 
Guaranteed Debt………………………………….
39
 
Outstanding Stock Data………………………….
40
Pension Funding……………………………………..
41
Off-Balance Sheet Arrangements………………….
42
Dividend Payout Ratio……………………………….
43
Transactions with Related Parties….……………...
43
Enterprise Risk and Risk Management……………
43
Risk Management including Financial
 
Instruments…………………………………………
54
Disclosure and Internal Controls……………………
55
Critical Accounting Estimates….……………………
56
Changes in Accounting Policies and Practices…...
61
 
Future Accounting Pronouncements……………
61
Summary of Quarterly Results……........................
62
FORWARD
 
-LOOKING INFORMATION
This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view
with respect to the Company’s expectations regarding future growth, results of operations, performance,
the expected timing and outcome of the pending sale of NMGC, business prospects and opportunities,
and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws.
All such information and statements are made pursuant to safe harbour provisions contained in applicable
securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”,
“forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and
similar expressions are often intended to identify FLI, although not all FLI contains these identifying
words. The FLI reflects management’s current beliefs and is based on information currently available to
Emera’s management and should not be read as guarantees of future events, performance or results,
and will not necessarily be accurate indications of whether, or the time at which, such events,
performance or results will be achieved.
 
FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could
cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that
could cause results or events to differ from current expectations include, without limitation: regulatory and
political risk; change in law risk; operating and maintenance risks; changes in economic conditions;
commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future
dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and
costs associated with certain capital investments; expected impacts on Emera of challenges in the global
economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes
in customer energy usage patterns; developments in technology that could reduce demand for electricity;
climate change risk; weather risk, including higher frequency and severity of weather events; risk of
wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk;
derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption
of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory
and government decisions, including changes to environmental legislation, financial reporting and tax
legislation; risks associated with pension plan performance and funding requirements; loss of service
area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties
associated with infectious diseases, pandemics and similar public health threats; market energy sales
prices; labour relations; and availability of labour and management resources.
 
 
 
 
 
 
 
 
 
 
3
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from
the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A
is qualified in its entirety by the above cautionary statements and, except as required by law, Emera
undertakes no obligation to revise or update any FLI as a result of new information, future events or
otherwise.
INTRODUCTION AND STRATEGIC
 
OVERVIEW
Emera (TSX: EMA) is a North American provider of energy services, owning and operating a portfolio of
cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional
operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova
Scotia.
Emera’s business strategy is centered on continued investment in its regulated utilities, combined with a
focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million
customers. Effective execution of these priorities supports predictable and growing earnings, cash flow
and dividends for shareholders.
Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility
(known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity
(“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes
and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65
per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, and the
Caribbean and New Mexico at 4 per cent each.
Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and
is focused on delivering value for customers through prudent investments in reliability and system
resiliency, infrastructure modernization,
 
expansion to address customer growth, integration of
renewables, and technological innovations to deliver better customer experiences. It is anticipated that
approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated
by customer growth and system requirements at both TEC and PGS.
As at
millions of dollars
2025
2026
2027
2028
2029
Total
Capital investment plan
$
 
3,420
$
 
3,990
$
 
4,050
$
 
4,380
$
 
4,590
$
 
20,430
Average consolidated rate base
 
US operations
$
 
21,520
$
 
23,340
$
 
25,140
$
 
27,050
$
 
29,400
 
Canadian operations
 
7,630
 
8,000
 
8,370
 
8,590
 
8,870
 
Total
$
 
29,150
$
 
31,340
$
 
33,510
$
 
35,640
$
 
38,270
*Capital investment plan and average consolidated rate base exclude NMGC. Refer to “Other Developments” for more information
on the pending sale of NMGC
Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt
raised at the operating company level consistent with regulated capital structures, equity issuances, and
the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through
the issuance of preferred equity, and the issuance of common equity through Emera’s dividend
reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade
credit ratings is a core strategic priority of the Company.
Emera has increased dividends per common share paid for 18 consecutive years and has provided
forward annual dividend growth guidance of one to two per cent. Emera’s anticipates adjusted EPS
average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend
payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and
“Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios”
section.
4
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and
are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to
similar measures presented by other entities. These measures and ratios are discussed and reconciled
below.
Adjusted Net Income, Adjusted EPS – Basic, and Dividend Payout Ratio of
Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”)
measure by excluding items below from net income attributable to common shareholders. Management
believes excluding these items better distinguishes ongoing operations of the business and allows
investors to better understand and evaluate the business.
 
Emera calculates adjusted net income for the Florida Electric Utility, Canadian Electric Utilities, Gas
Utilities and Infrastructure, Other Electric Utilities, and Other segments. Reconciliation to the nearest
GAAP measure is included in each segment. For more information refer to the Financial Highlights
section for each of Florida Electric Utility, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are
calculated using adjusted net income, as described above. For further details on dividend payout ratio of
adjusted net income, refer to the “Dividend Payout Ratio” section.
Adjusting item impacting all periods:
Mark-to-market (“MTM”) Adjustments:
Management believes excluding from net income the effect of MTM valuations and changes thereto, until
settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows,
and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The
MTM adjustments are related to the following:
●
 
held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the
price differential between the point where natural gas is sourced and where it is delivered, and
the related amortization of transportation capacity recognized as a result of certain Emera Energy
marketing and trading transactions;
●
 
the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s
equity income;
●
 
equity securities held in BLPC and Emera Energy; and
 
FX hedges entered into to hedge USD denominated operating unit earnings exposure.
Adjusting items impacting 2024:
Gain on Sale of Emera’s Indirect Minority Interest in the LIL (“Gain on sale of LIL”):
In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of LIL. In
Q4 2024, Emera recognized a $22 million tax benefit related to the reversal of a prior year valuation
allowance. A portion of the taxable capital gain on sale of LIL was offset by prior year loss carryforwards,
of which the tax benefit was subject to a valuation allowance as at December 31, 2023.
 
For further
details refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
Financing Structure Wind-Up:
In Q4 2024, Emera recognized a $58 million tax benefit related to denied interest and financing expenses
and the wind-up of a specific financing structure. For further details refer to the “Significant Items Affecting
Earnings” and “Other Developments” sections.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5
Charges Related to Wind-Down Costs and Certain Asset Impairments:
In Q4 2024, the Company recognized $26 million, after-tax, in wind-down costs and certain asset
impairments, primarily at Block Energy LLC (“Block Energy”). For further details, refer to the “Significant
Items Affecting Earnings” section.
Charges Related to the Pending Sale of NMGC:
On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q3 2024, the Company
recognized $206 million in non-cash goodwill and other impairment charges, after-tax, and an additional
loss of $19 million in estimated transaction costs, after-tax, related to the pending sale. For further details,
refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
Adjusting items impacting 2022:
GBPC Impairment Charge:
In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to
GBPC due to a decline in the fair value (“FV”) of the reporting unit.
 
NSPML Unrecoverable Costs:
In Q1 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-tax)
included in NSPML’s final capital cost application.
 
Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except per share amounts)
2024
2023
2024
2023
2022
Net income attributable to common shareholders
$
 
154
$
 
289
$
 
494
$
 
978
$
 
945
Gain on sale of LIL, after-tax
(1)
 
22
 
-
 
 
129
 
-
 
 
-
 
Financing structure wind-up
 
58
 
-
 
 
58
 
-
 
 
-
 
Charges related to wind-down costs and certain asset
impairments, after-tax
(2)
 
(26)
 
-
 
 
(26)
 
-
 
 
-
 
Charges related to the pending sale of NMGC, after-tax
(3)(4)
 
-
 
 
-
 
 
(225)
 
-
 
 
-
 
MTM (loss) gain, after-tax
(5)
 
(146)
 
114
 
(291)
 
169
 
175
GBPC impairment charge
 
 
-
 
 
-
 
 
-
 
 
-
 
 
(73)
NSPML unrecoverable costs
 
-
 
 
-
 
 
-
 
 
-
 
 
(7)
Adjusted net income
$
 
246
$
 
175
$
 
849
$
 
809
$
 
850
EPS – basic
$
 
0.52
$
 
1.04
$
 
1.71
$
 
3.57
$
 
3.56
Adjusted EPS – basic
$
 
0.84
$
 
0.63
$
 
2.94
$
 
2.96
$
 
3.20
(1) Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net of income tax
 
expense of
$53 million for the year ended December 31, 2024 (2023 – nil).
(2) Net of income tax recovery of $6 million for the three months and year ended December 31, 2024 (2023 – nil).
(3) Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million
 
in transaction costs,
after-tax for the year ended December 31, 2024 (2023 – nil).
(4) Net of income tax recovery of $21 million for the year ended December 31, 2024 (2023 – nil).
(5) Net of income tax recovery of $57 million for the three months ended December 31, 2024 (2023 – $44 million
 
expense) and $117
million recovery for the year ended December 31, 2024 (2023 – $68 million expense) (2022 – $73 million expense).
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA
are non-GAAP financial measures used by Emera. These financial measures are used by numerous
investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess
Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in
capital, and finance working capital requirements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
Adjusted EBITDA represents EBITDA excluding the income effect of the gain on sale of LIL, charges
related to wind-down costs and certain asset impairments, charges related to the pending sale of NMGC,
MTM adjustments, the 2022 GBPC impairment charge, and the 2022 NSPML unrecoverable costs.
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2024
2023
2024
2023
2022
Net income
(1)
$
 
173
$
 
307
$
 
568
$
 
1,045
$
 
1,009
Interest expense, net
 
248
 
241
 
973
 
925
 
709
Income tax (recovery) expense
 
(199)
 
51
 
(159)
 
128
 
185
Depreciation and amortization
 
296
 
264
 
1,162
 
1,049
 
952
EBITDA
$
 
518
$
 
863
$
 
2,544
$
 
3,147
$
 
2,855
Gain on sale of LIL, excluding income tax
 
-
 
 
-
 
 
182
 
-
 
 
-
 
Charges related to wind-down costs and certain asset
impairments, excluding income tax
 
(32)
 
-
 
 
(32)
 
-
 
 
-
 
Charges related to the pending sale of NMGC,
excluding income tax
 
-
 
 
-
 
 
(246)
 
-
 
 
-
 
MTM (loss) gain, excluding income tax
 
(203)
 
158
 
(408)
 
237
 
248
GBPC impairment charge
 
-
 
 
-
 
 
-
 
 
-
 
 
(73)
NSPML unrecoverable costs
 
-
 
 
-
 
 
-
 
 
-
 
 
(7)
Adjusted EBITDA
$
 
753
$
 
705
$
 
3,048
$
 
2,910
$
 
2,687
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.
CONSOLIDATED
 
FINANCIAL REVIEW
Significant Items Affecting Earnings
The items detailed below have had a significant impact on Net Income Attributable to Common
Shareholders but have been excluded from Adjusted Net Income as described in the section entitled
“Non-GAAP Financial Measures and Ratios”.
 
Financing Structure Wind-Up
During 2024, the Company incurred $185 million of interest and financing expenses in connection with a
specific financing structure. The current and future interest and financing expenses are expected to be
denied under the recently enacted Excessive Interest and Financing Expenses Limitation (“EIFEL”)
legislation and, as a result, the financing structure has been wound up. It was determined that Emera is
more likely than not to realize the benefit of the current denied interest and financing expenses in future
periods and therefore a $54 million deferred income tax asset and related income tax benefit ($0.19 per
common share) was recorded during Q4 2024. In addition, Emera recognized a $4 million income tax
benefit ($0.01 per common share) related to the reversal of a deferred income tax liability on the wind-up
of the financing structure. The total tax benefit of $58 million was recorded in “Income Tax (Recovery)
Expense” on the Consolidated Statements of Income and included in the Other segment. For further
details on the EIFEL legislation, refer to the “Other Developments” section.
Charges Related to Wind-Down Costs and Certain Asset Impairments
In Q4 2024, Emera recognized $32 million ($26 million after-tax, or $0.09 per common share) in wind-
down costs and certain asset impairments, primarily at Block Energy. These were recorded in “Other
Income, net” and “Impairment Charges” on the Consolidated Statements of Income and included mainly
in the Other segment.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7
Gain on Sale of LIL
On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after
transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was
recognized in “Other Income, net” on the Consolidated Statements of Income in Q2 2024 and included in
the Other segment. In Q4 2024, Emera recognized a $22 million ($0.08 per common share) tax benefit
related to the reversal of a prior year valuation allowance. A portion of the taxable capital gain on the sale
of the LIL equity interest was offset by prior year loss carryforwards, of which the tax benefit had been
subject to a valuation allowance as at December 31, 2023. This tax benefit was recorded in “Income Tax
(Recovery) Expense” on the Consolidated Statements of Income in Q4 2024 and included in the Other
segment. For further details on the transaction, refer to the “Other Developments” section.
Charges Related to the Pending Sale of NMGC
In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206
after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded
in “Impairment charges” on the Consolidated Statements of Income and included in the Other and Gas
Utilities and Infrastructure segments, respectively. For further details on the pending sale of NMGC, refer
to the “Other Developments” section. For further details on the non-cash goodwill impairment charge,
refer to note 23 in the consolidated financial statements.
Additionally, in Q3 2024, Emera recorded a loss of $25 million ($19 million after-tax, or $0.06 per common
share) in estimated transaction costs related to the pending sale of NMGC. These transaction costs were
recorded in “Other Income, net” on the Consolidated Statement of Income and included in the Other
segment. For further details, refer to the “Other Developments” section.
 
Earnings Impact of MTM Loss, After-Tax
Quarter-to-date the 2023 MTM gain, after-tax, of $114 million decreased $260 million to a $146 million
MTM loss, after-tax, for the same period in 2024. For the year ended, the 2023 MTM gain, after-tax, of
$169 million decreased $460 million to a $291 million MTM loss, after-tax, for the same period in 2024.
These decreases were primarily due to changes in existing positions, partially offset by lower amortization
of gas transportation at Emera Energy Services (“EES”).
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of dollars
 
December 31
December 31
Adjusted net income
2024
2023
2024
2023
2022
Florida Electric Utility
$
 
120
$
 
115
$
 
644
$
 
627
$
 
596
Canadian Electric Utilities
 
77
 
68
 
232
 
247
 
222
Gas Utilities and Infrastructure
 
87
 
59
 
267
 
214
 
221
Other Electric Utilities
 
21
 
4
 
48
 
35
 
29
Other
 
(59)
 
(71)
 
(342)
 
(314)
 
(218)
Adjusted net income
$
 
246
$
 
175
$
 
849
$
 
809
$
 
850
Gain on sale of LIL, after-tax
 
22
 
-
 
 
129
 
-
 
 
-
 
Financing structure wind-up
 
58
 
-
 
 
58
 
-
 
 
-
 
Charges related to wind-down costs and
 
certain asset impairments, after-tax
 
(26)
 
-
 
 
(26)
 
-
 
 
-
 
Charges related to the pending sale of NMGC, after-tax
 
-
 
 
-
 
 
(225)
 
-
 
 
-
 
MTM (loss) gain, after-tax
 
(146)
 
114
 
(291)
 
169
 
175
GBPC impairment charge
 
-
 
 
-
 
 
-
 
 
-
 
 
(73)
NSPML unrecoverable costs
 
-
 
 
-
 
 
-
 
 
-
 
 
(7)
Net income attributable to common shareholders
$
 
154
$
 
289
$
 
494
$
 
978
$
 
945
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8
The following table highlights significant changes in adjusted net income from 2023 to 2024:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net income – 2023
$
 
175
$
 
809
Operating Unit Performance
Increased earnings at NSPI due to increased income tax recovery,
partially offset by higher operating, maintenance and general expenses
(“OM&G”) due primarily to a lower storm cost deferral
 
31
 
19
Increased earnings quarter-over-quarter at Other Electric Utilities
primarily due to the timing of recovery of fuel costs and lower OM&G.
Year-over-year increased primarily due to higher sales volumes, partially
offset by higher OM&G
 
17
 
13
Increased earnings quarter-over-quarter at NMGC due to higher
revenue from new base rates, partially offset by higher income tax
expense. Decreased earnings year-over-year due to lower asset
optimization revenue, partially offset by higher revenue from new base
rates
 
14
 
(4)
Increased earnings at PGS due to higher revenue from new base rates
and customer growth, partially offset by increased interest expense,
depreciation, OM&G, and income tax expense
 
11
 
58
Increased earnings at TEC due to higher revenues from customer
growth and new base rates, and the impact of a weaker CAD, partially
offset by higher OM&G, and depreciation. Year-over-year increased
earnings also due to lower income tax expense and lower interest
expense, partially offset by unfavourable weather
 
5
 
17
Decreased earnings year-over-year at EES due to favourable hedging
opportunities in Q1 2023 and less favourable market conditions in 2024
 
(3)
 
(16)
Decreased earnings at Bear Swamp primarily due to the recognition of
investment tax credits in 2023
 
(13)
 
(20)
Decreased income from equity investments due to the sale of LIL equity
interest
 
(16)
 
(32)
Corporate
Decreased deferred income tax asset valuation allowance due to
utilization of tax loss carryforwards
 
36
 
39
Increased income tax recovery due to increased loss before provision
for income taxes
 
15
 
20
Increased interest expense due to the impact of a weaker CAD on USD
interest expense, increased total Corporate debt and increased interest
rates
 
(9)
 
(38)
Increased OM&G quarter-over-quarter primarily due to the timing
difference in the valuation of long-term incentive expense and related
hedges
 
(16)
 
(1)
Other Variances
 
(1)
 
(15)
Adjusted net income – 2024
$
 
246
$
 
849
For the
Year ended December 31
millions of dollars
2024
2023
2022
Operating cash flow before changes in working capital
$
 
2,194
$
 
2,336
$
 
1,147
Change in working capital
 
452
 
(95)
 
(234)
Operating cash flow
$
 
2,646
$
 
2,241
$
 
913
Investing cash flow
$
 
(2,218)
$
 
(2,917)
$
 
(2,569)
Financing cash flow
$
 
(818)
$
 
939
$
 
1,555
For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
As at
 
December 31
millions of dollars
2024
2023
2022
Total assets
$
 
42,951
$
 
39,480
$
 
39,742
Total long-term
 
debt (including current portion)
 
(1)
$
 
18,407
$
 
18,365
$
 
16,318
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at December 31, 2024, NMGC's assets and liabilities
were classified as held for sale and are excluded from this table. For further details, refer to the 'Other Developments' section
 
and
note 4 in the consolidated financial statements.
Consolidated Income Statement Highlights
For the
 
Three months ended
Year ended
Year ended
millions of dollars
December 31
December 31
December 31
(except per share amounts)
2024
2023
Variance
2024
2023
Variance
2022
Operating revenues
$
 
1,763
$
 
1,972
$
 
(209)
$
 
7,200
$
 
7,563
$
 
(363)
$
 
7,588
Operating expenses
 
1,524
 
1,467
 
(57)
 
6,120
 
5,769
 
(351)
 
5,959
Income from operations
$
 
239
$
 
505
$
 
(266)
$
 
1,080
$
 
1,794
$
 
(714)
$
 
1,629
Other (expense) income, net
$
 
(29)
$
 
51
$
 
(80)
$
 
203
$
 
158
$
 
45
$
 
145
Interest expense, net
$
 
248
$
 
241
$
 
(7)
$
 
973
$
 
925
$
 
(48)
$
 
709
Income tax (recovery) expense
$
 
(199)
$
 
51
$
 
250
$
 
(159)
$
 
128
$
 
287
$
 
185
Net income attributable to
common shareholders
$
 
154
$
 
289
$
 
(135)
$
 
494
$
 
978
$
 
(484)
$
 
945
Adjusted net income
$
 
246
$
 
175
$
 
71
$
 
849
$
 
809
$
 
40
$
 
850
Weighted average shares of
common stock outstanding
 
(in millions)
 
294.1
 
277.7
 
16.4
 
289.1
 
273.6
 
15.5
 
265.5
EPS – basic
$
 
0.52
$
 
1.04
$
(0.52)
$
 
1.71
$
 
3.57
$
(1.86)
$
 
3.56
EPS – diluted
$
 
0.52
$
 
1.04
$
(0.52)
$
 
1.71
$
 
3.57
$
(1.86)
$
 
3.55
Adjusted EPS – basic
$
 
0.84
$
 
0.63
$
0.21
$
 
2.94
$
 
2.96
$
(0.02)
$
 
3.20
Adjusted EBITDA
$
 
753
$
 
705
$
 
48
$
 
3,048
$
 
2,910
$
 
138
$
 
2,687
Dividends per common share
declared
$
 
0.7250
$
 
0.7175
$
 
0.0075
$
 
2.8775
$
 
2.7875
$
 
0.0900
$
 
2.6775
Dividends per first preferred shares declared:
 
Series A
$
 
0.5456
$
 
0.5456
$
 
-
 
$
 
0.5456
 
Series B
$
 
1.6966
$
 
1.5583
$
 
0.1383
$
 
0.6869
 
Series C
$
 
1.6085
$
 
1.2873
$
 
0.3212
$
 
1.1802
 
Series E
$
 
1.1250
$
 
1.1250
$
 
-
 
$
 
1.1250
 
Series F
$
 
1.0505
$
 
1.0505
$
 
-
 
$
 
1.0505
 
Series H
$
 
1.5810
$
 
1.3140
$
 
0.2670
$
 
1.2250
 
Series J
$
 
1.0625
$
 
1.0625
$
 
-
 
$
 
1.0625
 
Series L
$
 
1.1500
$
 
1.1500
$
 
-
 
$
 
1.1500
Operating Revenues
For Q4 2024, operating revenues decreased $209 million compared to Q4 2023 and, excluding
decreased MTM gain of $291 million, increased $82 million. For the year ended December 31, 2024,
operating revenues decreased $363 million compared to 2023 and, excluding decreased MTM gain of
$559 million, increased $196 million. The increases were due to new rates at PGS, NSPI, TEC and
NMGC; the impact of a weaker CAD; and increased customer growth at TEC and PGS. The increases
were partially offset by lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC;
and lower fuel revenue at NMGC. Year-over-year increase was also due to a change in the fuel cost
recovery methodology for an industrial customer in 2023 at NSPI (offset in fuel for generation and
purchased power).
10
Operating Expenses
For Q4 2024, operating expenses increased $57 million compared to Q4 2023, and, excluding charges
related to wind-down costs and certain asset impairments of $4 million, increased $53 million. For the
year ended December 31, 2024, operating expenses increased $351 million compared to 2023, and
excluding the goodwill and other impairment charges primarily related to the pending sale of NMGC of
$225 million, increased $126 million due to higher depreciation at TEC and PGS; the impact of a weaker
CAD; higher OM&G due to timing of deferred clause recoveries at PGS and TEC; lower storm cost
deferral and higher demand side management program costs at NSPI; and higher labour costs at PGS.
This was partially offset by lower natural gas prices at NMGC, PGS and TEC and lower storm cost
recognition at TEC (offset in revenue). Year-over-year increase was also due to a change in fuel cost
recovery for an industrial customer in 2023 at NSPI (offset in revenue).
Other Income, Net
For Q4 2024, other income, net decreased $80 million compared to Q4 2024 due to charges related to
wind-down costs and certain asset impairments and higher FX losses.
For the year ended December 31, 2024, other income, net increased $45 million compared to the same
period in 2023 due to the gain on sale of LIL, after transaction costs, partially offset by higher FX losses,
charges related wind-down costs and certain asset impairments, transaction costs related to the pending
sale of NMGC, and lower interest income.
Interest Expense, Net
For Q4 2024, interest expense, net increased $7 million and for the year ended December 31,2024,
increased $48 million compared to the same periods in 2023 due to the impact of a weaker CAD on USD
interest expense, increased borrowings to support ongoing operations and higher interest rates.
Income Tax (Recovery) Expense
For Q4 2024, income tax recovery increased $250 million compared to Q4 2023 due to decreased
income before provision for income taxes, decreased deferred income tax asset valuation allowance and
recognition of tax benefits associated with denied interest and financing expenses.
For the year ended December 31, 2024, income tax recovery increased $287 million compared to 2023
due to decreased income before provision for income taxes (excluding the gain on sale of LIL and
charges related to the pending sale of NMGC), decreased deferred income tax asset valuation allowance
and recognition of tax benefits associated with denied interest and financing expenses. This increased
recovery was partially offset by the net tax impact of the gain on sale of LIL and charges related to the
pending sale of NMGC.
Net Income and Adjusted Net Income
 
For Q4 2024, net income attributable to common shareholders compared to Q4 2023, was favourably
impacted by the $58 million tax benefit related to a specific financing structure and its wind-up and the
$22 million valuation allowance reversal related to the gain on sale of LIL, and unfavourably impacted by
the $26 million charges related to wind-down costs and certain asset impairments, and the $260 million
decrease in MTM gains. Excluding these impacts, adjusted net income increased $71 million, primarily
due to increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC, and increased
Corporate income tax recovery. This was partially offset by lower equity earnings from LIL; increased
Corporate OM&G due to timing of long-term incentive expenses and related hedges; increased Corporate
interest expense; and decreased earnings at Emera Energy.
For the year ended December 31, 2024, net income attributable to common shareholders,
 
compared to
the same period in 2023, was favourably impacted by the $129 million gain on sale of LIL, and the $58
million tax benefit related to a specific financing structure and its wind-up and unfavourably impacted by
the $26 million in charges related to wind-down costs and certain asset impairments, $225 million in
charges related to the pending sale of NMGC, and the $460 million decrease in MTM gains. Excluding
these changes, adjusted net income increased $40 million. The increase was primarily due to increased
earnings at PGS, NSPI, TEC, and Other Electric Utilities, and increased Corporate income tax recovery.
This was partially offset by increased Corporate interest expense; lower equity earnings from LIL; and
decreased earnings at Emera Energy.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
EPS – Basic and Adjusted EPS – Basic
For Q4 2024, EPS – basic was lower than in Q4 2023 due to the impact of decreased earnings, as
discussed above, and an increase in weighted average shares outstanding. Adjusted EPS – basic was
higher in Q4 2024, compared to Q4 2023, due to increased adjusted earnings as discussed above,
partially offset by an increase in weighted average shares outstanding.
For the year ended December 31, 2024, EPS – basic was lower than in 2023 due to the impact of an
increase in weighted average shares outstanding and decreased earnings, as discussed above. Adjusted
EPS – basic was lower in 2024, compared to 2023, due to the impact of an increase in weighted average
shares outstanding, partially offset by increased adjusted earnings, as discussed above.
Effect of Foreign Currency Translation
Emera operates in the United States (“US”), Canada and various Caribbean countries and, as such,
generates revenues and incurs expenses denominated in local currencies which are translated into CAD
for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD,
can positively or adversely affect results.
Results of foreign operations are translated at the weighted average rate of exchange, and assets and
liabilities of foreign operations are translated at period end rates.
The relevant CAD/USD exchange rates
on net income attributable to common shareholders for 2024 and 2023 are as follows:
Three months ended
 
Year ended
December 31
December 31
2024
2023
2024
2023
Weighted average CAD/USD
 
$
1.37
$
1.36
$
1.36
$
1.35
Period end CAD/USD exchange rate
$
1.44
$
1.32
$
1.44
$
1.32
The table below includes Emera’s significant segments whose contributions to adjusted net income are
recorded in USD currency:
Three months ended
Year ended
For the
 
December 31
December 31
millions of USD
2024
2023
2024
2023
Florida Electric Utility
(1)
$
85
$
85
$
470
$
466
Gas Utilities and Infrastructure
 
(2)(3)
56
41
178
142
Other Electric Utilities
15
3
35
26
Other segment
(4)(5)
(33)
(18)
(131)
(95)
Total
(1)(3)(5)
$
123
$
111
$
552
$
539
(1) Excludes $2 million USD, after-tax, in other impairment charges for the three months and year ended December 31, 2024.
 
(2) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(3) Excludes $6 million USD, after-tax, in other impairment charges associated with the pending sale of NMGC for the year ended
December 31, 2024.
 
(4) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD
denominated debt.
(5) Excludes $84 million USD in MTM losses, after-tax, for the three months ended December 31, 2024 (2023 – $73 million
 
USD
MTM gain, after-tax) and $189 million in USD MTM losses, after-tax, for the year ended December 31, 2024 (2023 – $116
 
million
USD MTM gain, after-tax).
Weakening of the CAD increased adjusted net income by $2 million in Q4 2024 and $5 million for the
year ended December 31, 2024, compared to the same periods in 2023. Impacts of the changes in the
translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of
USD earnings in the Other segment.
The translation impact of a weaker CAD on USD earnings was more than offset by the realized and
unrealized losses on FX hedges used to mitigate translation risk of USD earnings, resulting in a $29
million decrease to net income in Q4 2024 and $35 million decrease to net income for the year ended
December 31, 2024, compared to the same periods in 2023.
 
12
BUSINESS OVERVIEW AND OUTLOOK
Florida Electric Utility
The Florida Electric Utility segment consists of TEC, a vertically integrated regulated electric utility
engaged in the generation, transmission and distribution of electricity, serving customers in West Central
Florida. TEC has $13 billion USD of assets and approximately 855,000 customers at December 31, 2024.
TEC owns 6,620 megawatts (“MW”) of generating capacity, of which 73 per cent is natural gas fired, 20
per cent is solar and 7 per cent is coal. TEC also owns 2,192 kilometres of transmission facilities and
20,693 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity
established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.
Beginning in 2025, TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent (2024 – 9.25
per cent to 11.25 per cent) based on an allowed equity capital structure of 54 per cent (2024 – 54 per
cent). An ROE of 10.50 per cent (2024 – 10.20 per cent) is used for the calculation of the return on
investments for clauses.
TEC anticipates earning within its ROE range in 2025. As a result of new base rates effective January 1,
2025, TEC's 2025 USD earnings are expected to be higher than in 2024. Normalizing 2024 for weather,
TEC’s sales volumes in 2025 are projected to be higher than in 2024 due to customer growth. TEC
expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic
growth in Florida.
On April 2, 2024, TEC filed a rate case with the FPSC for new base rates. On December 3, 2024, the
FPSC rendered a decision which includes annual base rate increases of $185 million USD in 2025 and
adjustments of $87 million USD and $9 million USD in 2026 and 2027, respectively. The rates include
recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy
control center, and other resiliency and reliability projects. The allowed equity in the capital structure will
continue to be 54 per cent from investor sources of capital and the allowed regulatory ROE range is 9.50
per cent to 11.50 per cent with a 10.50 per cent midpoint. On February 3, 2025, the FPSC issued the final
order approving the decision, effective January 1, 2025. On February 18, 2025, a motion for
reconsideration on certain aspects of the rate case order was filed with the FPSC. TEC will respond to
this motion in February 2025. TEC expects the FPSC to reach a final decision on the motion in Q2 2025.
 
On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall
approximately 200 miles north of Tampa, in Taylor
 
County, as a Category 4 hurricane. TEC’s service
territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number
of customers out of 100,000. As of December 31, 2024, TEC deferred $49 million USD to the storm
reserve for future recovery.
 
On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near
Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3
hurricane had a significant impact on TEC’s service territory which resulted in a peak number of
customers out of 600,000. As of December 31, 2024, TEC deferred $340 million USD to the storm
reserve for future recovery.
As at December 31, 2024, total restoration costs charged to the storm reserve account have exceeded
the storm reserve balance (for additional details on the storm reserve, refer to note 7 in Emera’s
consolidated financial statements) and therefore $377 million USD has been deferred as a regulatory
asset for future recovery. On February 4, 2025, the FPSC approved TEC’s petition filed on December 27,
2024 for the recovery of $466 million USD for costs associated with Hurricane Idalia, Hurricane Debby,
Hurricane Helene and Hurricane Milton and the associated interest to replenish the storm reserve over an
18-month recovery period beginning in March 2025. The amount of cost-recovery is subject to a true-up
mechanism with the FPSC.
 
13
On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a
$138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction
was due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected
2024 costs in the fall of 2023. On May 7, 2024, the FPSC approved the mid-course adjustment.
In 2025, capital investment in the Florida Electric Utility segment is expected to be $1.7 billion USD (2024
– $1.4 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects
include solar investments,
 
grid modernization, storm hardening investments, building resilience and
energy storage.
 
Canadian Electric Utilities
The Canadian Electric Utilities segment includes NSPI and NSPML. NSPI is a vertically integrated
regulated electric utility engaged in the generation, transmission and distribution of electricity and the
primary electricity supplier to customers in Nova Scotia. NSPML is a 100 per cent equity interest in the
Maritime Link Project (“Maritime Link”), a transmission project between the island of Newfoundland and
Nova Scotia.
 
On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the
“Significant Items Affecting Earnings” and “Other Developments” sections.
 
NSPI
With $7.1 billion of assets and approximately 557,000 customers at December 31, 2024, NSPI owns
2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas
and/or oil; 19 per cent is hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is
biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from
independent power producers (“IPPs”) and community feed-in tariff (“COMFIT") participants, which own
533 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity,
 
representing
Newfoundland and Labrador Hydro’s (“NLH”) Nova Scotia Block (“NS Block”) delivery obligations,
 
as
discussed below. NSPI owns approximately 5,000 kilometres of transmission facilities and 28,000
kilometres of distribution facilities.
NLH is obligated to provide NSPI with approximately 900 Gigawatt hours (“GWh”) of energy annually over
35 years. In addition, for the first five years of the NS Block, NLH is obligated to provide approximately
240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime
Link. NSPI has the option of purchasing additional market-priced energy from NLH through the Energy
Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from
NLH for up to 1.8 Terawatt
 
hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of
energy per year through August 31, 2041.
 
NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up to 40 per cent of approved rate base.
 
NSPI anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be
consistent with 2024. Sales volumes are expected to be higher in 2025 than 2024.
14
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the
Province of Nova Scotia (the “Province”) on terms and conditions for a federal loan guarantee (“FLG”) of
$500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of
the replacement energy that was required during the several years of delay in the Muskrat Falls
hydroelectricity project. On September 25, 2024, NSPI and NSPML filed applications with the UARB
related to the FLG. On November 29, 2024, the UARB approved NSPML’s application to issue the debt,
transfer the proceeds to NSPI as a refund of a portion of previous NSPML assessment payments
(“NSPML Refund”), and to increase its annual assessment charge to NSPI to recover the refund and
related financing costs over a 28-year period. On December 16, 2024, the net proceeds of the NSPML
debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance. On
February 18, 2025, the UARB approved NSPI's application to increase 2025 fuel rates to service the
incremental NSPML debt
.
On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and
incremental financing costs deferred to NSPI’s storm rider in 2023 to be recovered over a 12-month
period beginning on January 1, 2025.
On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating
costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB
approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The
UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired
because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Consolidated Balance Sheets.
NSPI began amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.
On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the
Battery Energy Storage System Project. The project is comprised of three 50 MW, four-hour battery
facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.
 
On April 17, 2024, the UARB approved the sale of $117 million of the FAM
 
regulatory asset to Invest
Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117
million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset.
NSPI is collecting the amortization and financing costs related to the $117 million from customers on
behalf of Invest Nova Scotia over a 10-year period, which began in Q2 2024, and is remitting those
amounts to Invest Nova Scotia quarterly.
 
In 2025, capital investment, including AFUDC, is expected to be $480 million (2024 – $487 million). NSPI
is primarily investing in capital projects required to support power system reliability and reliable service for
customers.
 
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the
Province. NSPI continues to work with both levels of government to comply with these laws and
regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI
anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under
NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and
environmental legislative requirements, including the risk of non-compliance, which could adversely affect
NSPI’s operations and financial performance. For further discussion on these risks and environmental
legislation and regulations, refer to the “Enterprise Risk and Risk Management” section. Recent
developments related to provincial and federal environmental laws and regulations are outlined below.
15
Clean Electricity Regulations (“CER”):
On December 17, 2024, Environment and Climate Change Canada released a finalized version of the
CER. The CER establish performance standards to further limit greenhouse gas (“GHG”) emissions from
fossil fuel-generated electricity starting in 2035 and help facilitate the Government of Canada’s intention
of achieving a net-zero electricity grid by 2050. Compliance with the finalized version of the CER is not
anticipated to require significant capital investment incremental to achieve the 2030 targets as NSPI’s
planned capital investment during this period is driven by the Province’s goals to transition off coal and
reach 80 per cent renewable electricity sales by 2030.
Nova Scotia Energy Reform Act:
On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. The legislation enacted the
Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB
is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased
focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act,
which provides for the establishment of and phased transition to the Nova Scotia Independent Energy
System Operator. NSPI is fully engaged in supporting the Province on these initiatives.
RER:
On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million
penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in
2022. The hearing for the matter is currently scheduled for June 2025.
 
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,
based on an actual five-quarter average regulated common equity component of up to 30 per cent.
Equity earnings from NSPML in 2025 are expected to consistent with 2024. The NSPML investment is
recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy
between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the
efficiency and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on
August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project
agreements.
 
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the
Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further
information, refer to the NSPI section above.
 
On November 29, 2024, NSPML received approval from the UARB to collect up to $197 million in 2025
from NSPI; which includes $158 million for the recovery of costs associated with the Maritime Link, and
$39 million associated with the additional FLG debt and financing costs discussed in the NSPI section
above. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no
holdback recorded for the year ended December 31, 2024. NSPML expects to file an application to
terminate the holdback mechanism in early 2025.
NSPML does not anticipate any significant capital investment in 2025.
16
Gas Utilities and Infrastructure
The Gas Utilities and Infrastructure segment includes PGS, NMGC, SeaCoast, Brunswick Pipeline and
Emera’s equity investment in M&NP.
 
PGS is a regulated gas distribution utility engaged in the purchase,
distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas
distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving
customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering
services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified
liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern US.
On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close
in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending
sale, NMGC’s assets and liabilities were classified as held for sale as of Q3 2024. For more information
on the pending transaction, refer to the “Other Developments” section.
PGS
With $3.1 billion USD of assets and approximately 508,000 customers, the PGS system includes 25,240
kilometres of natural gas mains and 14,530 kilometres of service lines. Natural gas throughput (the
amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in
2024.
 
The approved ROE range for PGS is 9.15 per cent to 11.15 per cent based on an allowed equity capital
structure of 54.7 per cent. An ROE of 10.15 per cent is used for the calculation of return on investments
for clauses.
PGS anticipates earning near the bottom of its allowed ROE range in 2025 as a result of the continued
investments across Florida to maintain reliability and service new customers. Capital investments are
expected to outpace revenue growth. USD earnings for 2025 are expected to be consistent with 2024
primarily due to higher operating costs and depreciation driven by ongoing capital investments to support
customer demand and system needs.
On January 30, 2025, PGS notified the FPSC of its intent to seek a base rate increase effective January
2026, reflecting a revenue requirement of approximately $90 to $110 million USD and subsequent year
adjustment for 2027 of approximately $25 to $40 million USD. PGS' proposed rates support on-going
growth in Florida and a continued commitment to delivering safe and reliable service to PGS customers.
The filing range amounts are estimates until PGS files its detailed case in March 2025. The FPSC is
scheduled to hear the case in Q3 2025 with a decision expected by the end of 2025.
 
In 2025, capital investment, including AFUDC, is expected to be approximately $360 million USD (2024 –
$323 million USD). PGS will make investments to maintain the reliability of their systems and support
customer growth.
 
NMGC
With $1.5 billion USD of assets and approximately 550,000 customers, NMGC’s system includes
approximately 2,405 kilometres of transmission pipelines and 17,810 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 1 billion therms in 2024.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.
 
NMGC’s USD earnings contributions to Emera in 2025 are expected to be lower than in 2024 as a result
of the pending sale of NMGC that is currently expected to close in October 2025.
17
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. On March 1, 2024,
NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30
million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect
the recovery of increased operating costs and capital investments in pipeline projects and related
infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw,
and to not reassert in a future rate case application, its request for a regulatory asset for costs associated
with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas
storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New
rates became effective October 1, 2024.
Other Electric Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with
regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of
BLPC on the island of Barbados, GBPC on Grand Bahama Island, and an equity investment in Lucelec
on the island of St. Lucia.
Other Electric Utilities’ USD earnings in 2025 are expected to be consistent with the prior year.
In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $140
million USD, including AFUDC (2024 – $59 million USD), primarily in more efficient and cleaner sources
of generation, including renewables and battery storage.
 
BLPC
With $538 million USD of assets and approximately 135,000 customers, BLPC owns 243 MW of
generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPC owns approximately
188 kilometres of transmission facilities and 3,989 kilometres of distribution facilities. BLPC’s approved
regulated return on rate base is 10 per cent.
On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation)
 
Act
into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per
cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested
the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs
over a period to be approved by the FTC during a future rate setting process.
 
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC
granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per
month. On February 15, 2023, the FTC issued a decision on the application which included the following
significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent,
a directive to update the major components of rate base to September 16, 2022, and a directive to
establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a
Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was
subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion.
Interim rates continue to be in effect through to a date to be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,
2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and
requested that they be stayed. On December 11, 2023, the Court granted the stay.
 
BLPC’s position is
that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal
is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is
currently scheduled to be heard in 2025.
18
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation
requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types, subject to the passage of implementing
legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the
implementation of the licenses once enacted.
GBPC
With $340 million USD of assets and approximately 19,500 customers, GBPC owns 98 MW of oil-fired
generation, approximately 90 kilometres of transmission facilities and 994 kilometres of distribution
facilities. GBPC’s approved regulatory return on rate base is 8.52 per cent.
 
On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement,
GBPC filed a rate plan proposal. Review of the rate application is expected to be completed in 2025
.
On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of
the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian
regulator, regulate GBPC. The GBPA
 
has opposed the legislated removal of its regulatory authority over
GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian
government that provided for the development and administration of the Freeport area. Management
expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however,
does not foresee that the legislation or the outcome of such proceedings will have a material impact to
Emera.
Other
The Other segment includes business operations that in a normal year are below the required threshold
for reporting as separate segments; and corporate expense and revenue items that are not directly
allocated to the operations of Emera’s subsidiaries and investments.
Business operations in the Other segment include Corporate; Emera Energy Services (EES), a physical
energy marketing and trading business; a 50 per cent joint venture interest in Bear Swamp, a 660 MW
pumped storage hydroelectric facility in northwestern Massachusetts; and Block Energy. In Q4 2024,
Block Energy initiated the process to wind-up operations.
Corporate items included are certain corporate-wide functions including executive management, strategic
planning, treasury services, legal, financial reporting, tax planning, corporate business development,
corporate governance, investor relations, risk management, insurance, acquisition and disposition related
costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest
revenue on intercompany financings and interest expense on corporate debt in both Canada and the US.
It also includes costs associated with corporate activities that are not directly allocated to the operations
of Emera’s subsidiaries and investments.
 
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas
and electricity markets, which can be influenced by weather, local supply constraints and other supply
and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1
and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver
annual adjusted net income of $15 to $30 million USD.
The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due primarily to
the wind-up of Block Energy in 2024.
 
The Other segment does not anticipate any significant capital investment in 2025.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
19
CONSOLIDATED
 
BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2023 and December 31,
2024 include:
Increase
 
(Decrease)
Total
due to
Other
Increase
 
held for sale
Increase
millions of dollars
(Decrease)
classification (1)
(Decrease)
Explanation of Other Increase (Decrease)
Assets
Cash and cash equivalents
$
 
(371)
$
 
(8)
$
 
(363)
Decreased due to investment in PP&E, net
repayments on committed credit facilities at
Corporate and NSPI, repayment of short-term
debt at TEC, retirement of long-term debt at
Emera, TEC and New Mexico Gas
Intermediate, Inc (“NMGI”), and dividends paid
on Emera common stock. These were partially
offset by cash from operations, proceeds from
debt issuances at TEC and EUSHI Finance,
Inc. (“EUSHI Finance”), proceeds received on
the sale of the LIL equity interest and proceeds
from common shares issued
Derivative instruments
(current and long-term)
 
(74)
 
(1)
 
(73)
Decreased due to reversal of 2023 contracts at
EES, partially offset by higher commodity prices
at NSPI
Regulatory assets (current
and long-term)
 
322
 
(34)
 
356
Increased due to higher storm costs recovery
clause assets at TEC and NSPI, the effect of
FX translation of Emera’s non-Canadian
affiliates, and reclassification of early retired
plant from PP&E to a regulatory asset at TEC.
These were partially offset by decreased FAM
balance at NSPI due to the NSPML refund, and
decreased fuel clause recovery balance at TEC
due to higher over-recoveries
Receivables and other assets
(current and long-term)
 
70
 
(150)
 
220
Increased due to higher cash collateral
positions on derivative instruments and
increased trade receivables as a result of
higher commodity prices at EES, and the effect
of FX translation of Emera's non-Canadian
affiliates. These were partially offset by lower
gas transportation assets at EES and lower
trade receivables at TEC
Assets held for sale (current
and long-term), net of
liabilities
 
973
 
973
-
PP&E, net of accumulated
depreciation and amortization
 
1,792
 
(1,828)
 
3,620
Increased due to capital additions in excess of
depreciation and the effect of FX translation of
Emera's non-Canadian affiliates, partially offset
by a reclassification of early retired plant to TEC
capital cost recovery regulatory asset
Investments subject to
significant influence
 
(748)
 
-
 
 
(748)
Decreased primarily due to sale of LIL equity
interest
Goodwill
 
(13)
 
(303)
 
290
Increased due to the effect of FX translation of
Emera's non-Canadian affiliates, partially offset
by the non-cash impairment charge recognized
primarily related to NMGC
(1) On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 NMGC's assets and liabilities were
classified as held for sale. For further details, refer to the 'Other Developments' section and note 3 in the consolidated financial
statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20
Increase
 
(Decrease)
Total
due to
Other
Increase
 
held for sale
Increase
millions of dollars
(Decrease)
classification (1)
(Decrease)
Explanation of Other Increase (Decrease)
Liabilities and Equity
Short-term debt and long-
term debt (including current
portion)
$
 
9
$
 
(742)
$
 
751
Increased due the effect of FX translation of
Emera's non-Canadian affiliates, proceeds from
long-term debt issuance at TEC, and issuance
of junior subordinated notes at EUSHI Finance.
These were partially offset by repayment of
Emera’s committed credit facilities using the LIL
transaction proceeds, repayment of short-term
debt at TEC and NSPI, and retirement of long-
term debt at Corporate, TEC, and NMGI
Accounts payable
 
538
 
(131)
 
669
Increased due to storm cost payable at TEC,
the effect of FX translation of Emera’s non-
Canadian affiliates, and increased commodity
prices at EES
Deferred income tax
liabilities, net of deferred
income tax assets
 
 
(205)
 
(167)
 
(38)
No significant change after removing impact of
held for sale classification
Derivative instruments
(current and long-term)
 
113
 
(1)
 
114
Increased due to new contracts in 2024 and
changes in existing positions at EES, higher FX
forward liability at Corporate due to changes in
the FX hedges, partially offset by higher
commodity prices and settlements of derivative
instruments at NSPI
Regulatory liabilities (current
and long-term)
 
108
 
(284)
 
392
Increased due to effect of FX translation of
Emera’s non-Canadian affiliates and
recognition of fuel cost recovery liabilities at
TEC and NSPI due to over-recovery of fuel
costs
Other liabilities (current and
long-term)
 
152
 
(34)
 
186
Increased due the effect of FX translation of
Emera's non-Canadian affiliates and higher
accrued interest on long-term debt at NSPI
Common stock
 
580
 
-
 
 
580
Increased due to shares issued
Accumulated other
comprehensive income
 
956
 
-
 
 
956
Increased due to the effect of FX translation of
Emera's non-Canadian affiliates
Retained earnings
 
(335)
 
-
 
 
(335)
Decreased due to dividends paid in excess of
net income
(1) On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 NMGC's assets and liabilities were
classified as held for sale. For further details, refer to the 'Other Developments' section and note 3 in the consolidated financial
statements.
21
OTHER DEVELOPMENTS
Canadian Tax Legislation
 
Changes
On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled
in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March
28, 2023, was enacted.
 
Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL
applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of
EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be
carried forward indefinitely. During 2024, the Company incurred $185 million of interest and financing
expenses in connection with a specific financing structure. The interest and financing expenses related to
the financing structure as well as $88 million of other interest and financing expenses are expected to be
denied under the EIFEL regime. It was determined that the Company is more likely than not to realize the
tax benefit of the denied interest and financing expenses in future periods and therefore a $79 million
deferred income tax asset has been recorded as at December 31, 2024
.
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC
for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the
transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025,
subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s
assets and liabilities are classified as held for sale.
As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold,
Emera assessed the NMGC reporting unit for goodwill impairment by comparing the FV of expected
transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“NMGC
carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash
goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million
USD, after-tax) was recorded in “Impairment Charges” on the Consolidated Statements of Income in Q3
2024.
 
Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at
the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an
additional loss for the estimated future transaction costs of $16 million ($12 million after-tax), in addition to
incurred transaction costs of $9 million ($7 million after-tax) recorded in “Other Income, net” on the
Consolidated Statements of Income in Q3 2024.
The Company will continue to record depreciation on the NMGC assets through the transaction closing
date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover
basis of the assets when sold. Depreciation and amortization of $26 million ($19 million USD) was
recorded on these assets from August 5, 2024, the date they were classified as held for sale, through
December 31, 2024.
Increase in Common Dividend
On September 18, 2024, the Emera Board of Directors approved an increase in the annual common
share dividend rate to $2.90 from $2.87 per common share. The first payment was effective November
15, 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
22
Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction
value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s
contractual obligation to fund the remaining initial capital investment, which represents additional LIL
equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow
pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable
is held at FV and included in the gain on sale, after transaction costs. As of December 31, 2024, the
estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after tax and
transaction costs, of $107 million, was included in the Other segment (the gain on sale, net of transaction
costs of $182 million was recognized in “Other Income, net” on the Consolidated Statements of Income).
In Q4 2024, Emera recognized a $22 million tax benefit due to the reversal of a prior year valuation
allowance related to loss carryforwards applied against a portion of the taxable capital gain on the sale of
LIL. This tax benefit was recorded in “Income Tax (Recovery) Expense” on the Consolidated Statements
of Income in Q4 2024 and included in the Other segment. Proceeds from the sale were used to reduce
corporate debt and fund investment in the Company’s regulated utility businesses.
Appointments
Board of Directors
Effective February 21, 2025, Karen Sheriff was appointed Chair of the Emera Board of Directors,
succeeding Jackie Sheppard. Ms. Sheriff joined the Emera Board of Directors in February 2021 and since
that time has served as a member of the Management Resources and Compensation Committee, the
Risk and Sustainability Committee as well as Chair of the Nominating and Corporate Governance
Committee.
 
Effective June 26, 2024, Carla Tully joined the Emera Board of Directors. Ms. Tully is the former Chief
Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company.
 
She also
previously served as Executive Vice President and Managing Director of Renewable Energy at MAP
Energy and held various senior leadership roles with AES Corporation.
 
Effective March 6, 2024, Brian J. Porter joined the Emera Board of Directors. Mr. Porter is the former
President and Chief Executive Officer of The Bank of Nova Scotia (Scotiabank), a global bank operating
in Canada and the Americas.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2024
2023
2024
2023
Operating revenues – regulated electric
$
 
582
$
 
613
$
 
2,526
$
 
2,637
Regulated fuel for generation and purchased power
$
 
151
$
 
162
$
 
622
$
 
682
Contribution to consolidated adjusted net income
$
 
85
$
 
85
$
 
470
$
 
466
Contribution to consolidated adjusted net income - CAD
$
 
120
$
 
115
$
 
644
$
 
627
Charges related to wind-down costs and certain asset
impairments, after-tax
(1)
$
 
(2)
$
 
-
 
$
 
(2)
$
 
-
 
Contribution to consolidated net income
 
$
 
83
$
 
85
$
 
468
$
 
466
Contribution to consolidated net income – CAD
$
 
117
$
 
115
$
 
641
$
 
627
Average fuel costs in dollars per MWh
$
 
31
$
 
34
$
 
28
$
 
31
(1) Net of income tax recovery of $1 million for the three months and year ended December 31, 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
23
The impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three
months and year ended December 31, 2024, by $3 million and $10 million, respectively.
Net Income
Highlights of net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2023
$
85
$
 
466
Decreased operating revenues primarily due to decreased fuel
recovery clause revenue, lower storm surcharge revenue (offset in
OM&G), and the unfavourable load impact of Hurricane Milton, partially
offset by customer growth and new base rates. Revenues were also
impacted by favourable weather of $10 million quarter-over-quarter,
and unfavourable weather of $10 million year-over-year
 
(31)
 
(111)
Decreased fuel for generation and purchased power due to lower
natural gas prices
 
11
 
60
Decreased OM&G due to lower storm cost recognition (offset in
revenue), partially offset by the timing of deferred clause recoveries
and higher solar operations, labour, and software maintenance costs
 
16
 
47
Increased depreciation and amortization due to additions to facilities
and generation projects placed in service
 
(9)
 
(32)
Decreased interest expense year-over-year due to lower borrowings
 
 
-
 
 
7
Decreased state and municipal taxes due to lower retail sales tax,
partially offset by higher property taxes
 
4
 
14
Decreased income tax expense year-over-year due to increased
production tax credits related to solar facilities
 
-
 
 
18
Other
 
7
 
(1)
Contribution to consolidated net income – 2024
$
 
83
$
 
468
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following table by customer class:
Electric Revenues
Electric Sales Volumes
 
(millions of USD)
(Gigawatt hours ("GWh"))
 
2024
2023
2024
2023
Residential
$
 
1,507
$
 
1,711
 
10,269
 
10,307
Commercial
 
686
 
803
 
6,481
 
6,462
Industrial
 
162
 
203
 
2,019
 
2,082
Other
(1)
 
171
 
(80)
 
2,276
 
2,194
Total
$
 
2,526
$
 
2,637
 
21,045
 
21,045
(1) Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales to
 
other utilities.
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
2024
2023
Natural gas
 
 
18,027
 
17,843
Solar
 
2,250
 
1,748
Purchased power
 
 
1,569
 
1,443
Coal
 
 
32
 
744
Total
 
 
21,878
 
21,778
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24
TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on
economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy
from solar or battery storage), such that the incremental
 
cost of production increases as sales volumes
increase. Generation mix may also be affected by plant outages, plant performance, availability of lower
priced short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a
level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost
of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC
rate setting hearings which can occur at the initiative of TEC, the FPSC, or other interested parties.
 
For
further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 7 in
the consolidated financial statements.
Canadian Electric Utilities
On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the
transaction, refer to the “Other Developments” section.
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except as indicated)
2024
2023
2024
2023
Operating revenues – regulated electric
$
 
479
$
 
439
$
 
1,855
$
 
1,671
Regulated fuel for generation and purchased power
(1)
$
 
(216)
$
 
234
$
 
509
$
 
777
Contribution to consolidated net income
$
 
77
$
 
68
$
 
232
$
 
247
Average fuel costs in dollars per MWh
(2)
$
 
(73)
$
 
81
$
 
45
$
 
70
(1) Regulated fuel for generation and purchased power includes NSPI's FAM
 
deferral on the Consolidated Statements of Income,
however, it is excluded in the segment overview.
 
(2) 2024 Average fuel costs include the $486 million NSPML Refund which decreased average fuel costs
 
by $164 per MWh and $43
per MWh for the three months and year ended December 31, 2024, respectively.
 
Average fuel costs for the year ended December
31, 2023 include reversal of the $166 million of the Nova Scotia Cap-and-Trade Program
 
provision which decreased average fuel
costs by $15 per MWh. For more information the NSPML Refund and the Nova Scotia Cap-and-Trade
 
Program provision reversal,
refer to note 7 in the consolidated financial statements.
Canadian Electric Utilities' contribution to consolidated net income is summarized in the following table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2024
2023
2024
2023
NSPI
$
 
71
$
 
40
$
 
160
$
 
141
Equity investment in NSPML
 
6
 
12
 
44
 
46
Equity investment in LIL
 
-
 
 
16
 
28
 
60
Contribution to consolidated net income
 
$
 
77
$
 
68
$
 
232
$
 
247
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
Net Income
Highlights of net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income – 2023
$
 
68
$
 
247
Increased operating revenues at NSPI due to new rates. Year-over-year
also due to changes in fuel cost recovery methodology for an industrial
customer in 2023
(1)
 
40
 
184
Decreased regulated fuel for generation and purchased power at NSPI
due to the NSPML Refund
(1)
and decreased commodity prices, partially
offset by change in generation mix and increased sales volumes. Year-
over-year decrease was partially offset by the reversal of the Nova
Scotia Cap-and-Trade Program provision
(1)
 
in 2023
 
450
 
268
Increased FAM deferral at NSPI primarily due to the NSPML Refund
(1)
.
Year-over-year increase also due to changes in the fuel cost recovery
methodology for an industrial customer in 2023 and under-recovery of
fuel costs in 2023, partially offset by the reversal of the Nova Scotia
Cap-and-Trade Program provision
(1)
 
in 2023
 
(484)
 
(428)
Increased OM&G due to a lower storm cost deferral, and higher demand
side management program costs at NSPI
 
(8)
 
(24)
Decreased income from equity investments due to the sale of LIL
 
(16)
 
(34)
Increased income tax recovery at NSPI due to the utilization of tax loss
carryforwards offset to a regulatory deferred income tax liability, partially
offset by decreased tax deductions in excess of accounting depreciation
related to property, plant and equipment
 
40
 
32
Other
 
(13)
 
(13)
Contribution to consolidated net income – 2024
$
 
77
$
 
232
(1) For more information on the changes in fuel cost recovery methodology for an industrial customer in 2023, the $486 million
NSPML Refund, and the $166 million reversal of the Nova Scotia Cap-and-Trade Program provision,
 
refer to note 7 in the
consolidated financial statements.
NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Electric Revenues
Electric Sales Volumes
(millions of dollars)
(GWh)
 
2024
2023
2024
2023
Residential
$
 
997
$
 
910
 
5,096
 
4,986
Commercial
 
499
 
463
 
3,046
 
3,053
Industrial
 
276
 
219
 
2,217
 
2,164
Other
 
41
 
41
 
222
 
239
Total
$
 
1,813
$
 
1,633
 
10,581
 
10,442
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
 
2024
2023
Coal
 
 
3,347
 
3,086
Natural gas
 
2,317
 
1,946
Purchased power
 
620
 
881
Petcoke
 
374
 
553
Oil
 
132
 
145
Total non-renewables
 
6,790
 
6,611
Purchased power - IPP,
 
COMFIT and imports
 
3,464
 
3,251
Wind, hydro and solar
 
932
 
1,149
Biomass
 
 
140
 
128
Total renewables
 
4,536
 
4,528
Total production volumes
 
11,326
 
11,139
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on
economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase
agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which
carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the
use of the Maritime Link.
 
Generation mix may also be affected by plant outages, carbon pricing programs, including the Nova
Scotia Output-Based Pricing System, availability of renewable generation, availability of energy from the
NS Block, plant performance, and compliance with environmental regulations.
 
Regulatory Environment - NSPI
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public
Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s
operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI
is not subject to a general annual rate review process, but rather participates in hearings held from time to
time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery
mechanisms, refer to note 7 in the consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
27
Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close
in late 2025, subject to certain approvals, including regulatory approval by the NMPRC. For more
information on the pending transaction, refer to the “Other Developments” section.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2024
2023
2024
2023
Operating revenues – regulated gas
(1)
$
 
317
$
 
290
$
 
1,160
$
 
1,114
Operating revenues – non-regulated
 
3
 
3
 
15
 
15
Total operating revenue
$
 
320
$
 
293
$
 
1,175
$
 
1,129
Regulated cost of natural gas
$
 
81
$
 
99
$
 
289
$
 
391
Contribution to consolidated adjusted net income
 
$
 
61
$
 
43
$
 
194
$
 
158
Contribution to consolidated adjusted net income – CAD
$
 
87
$
 
59
$
 
267
$
 
214
Charges related to the pending sale of NMGC, after-tax
(2)
$
 
-
 
$
 
-
 
$
 
(6)
$
 
-
 
Contribution to consolidated net income
 
$
 
61
$
 
43
$
 
188
$
 
158
Contribution to consolidated net income – CAD
$
 
87
$
 
59
$
 
259
$
 
214
(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2023 – $11
 
million) for the
three months ended December 31, 2024 and $46 million (2023 – $46 million) for the year ended December 31 2024;
 
however, it is
excluded from the gas revenues and cost of natural gas analysis below.
(2) Includes an other impairment charge, net of income tax recovery of nil and $2 million for the three months and the year ended
December 31, 2024, respectively.
Gas Utilities and Infrastructure's contribution to consolidated adjusted net income is summarized in the
following table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2024
2023
2024
2023
PGS
$
 
28
$
 
21
$
 
120
$
 
79
NMGC
 
23
 
14
 
39
 
43
Other
 
10
 
8
 
35
 
36
Contribution to consolidated adjusted net income
 
$
 
61
$
 
43
$
 
194
$
 
158
Impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three months
and year ended December 31, 2024, by $3 million and $4 million respectively.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
28
Net Income
Highlights of net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2023
$
 
43
$
 
158
Increased gas revenues due to new base rates at PGS and NMGC,
and customer growth at PGS, partially offset by lower fuel revenues at
NMGC
 
27
 
54
Decreased asset optimization revenues at NMGC
 
 
-
 
 
(8)
Decreased cost of natural gas due to lower natural gas prices primarily
at NMGC
 
18
 
102
Increased OM&G primarily due to the timing of deferred clause
recoveries and higher labour cost at PGS
 
 
(5)
 
(31)
Increased depreciation primarily due to asset growth at PGS and the
effect of reversal of accumulated depreciation in 2023 as a result of the
2021 rate case settlement at PGS
 
(13)
 
(39)
Increased interest expense, net year-over-year, primarily due to higher
interest rates and increased borrowings to support ongoing operations
and capital investments primarily at PGS
 
1
 
(15)
Increased income tax expense primarily due to increased income
before provision for income taxes at PGS. Quarter-over-quarter
increase also due to increased income before provision for income
taxes at NMGC
 
 
(13)
 
(21)
Charges related to the pending sale of NMGC, after-tax
 
-
 
 
(6)
Other
 
3
 
(6)
Contribution to consolidated net income – 2024
$
 
61
$
 
188
Operating Revenues – Regulated Gas
Annual gas revenues and sales volumes are summarized in the following tables by customer class:
 
Gas Revenues
Gas Volumes
(millions of USD)
(millions of Therms)
 
2024
2023
2024
2023
Residential
$
 
520
$
 
537
 
410
 
414
Commercial
 
362
 
315
 
824
 
839
Industrial
(1)
 
69
 
69
 
1,620
 
1,615
Other
(2)
 
163
 
147
 
278
 
266
Total
(3)
$
 
1,114
$
 
1,068
 
3,132
 
3,134
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue
 
excludes $46 million of finance income from Brunswick Pipeline (2023 – $46 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In
Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has
firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on
major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to
customers.
 
In Florida, natural gas service is unbundled for non-residential customers and residential customers who
use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if
requested, to provide transportation-only services for all customer classes. The commodity portion of
bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore
no net earnings effect when a customer shifts to transportation-only sales.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29
Annual gas sales by type are summarized in the following table:
Gas Volumes by Type
 
(millions of Therms)
2024
2023
Transportation
 
2,434
 
2,461
System supply
 
698
 
673
Total
 
3,132
 
3,134
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
 
For further information on PGS’s and NMGC’s regulatory environment and recovery mechanisms, refer to
note 7 in the consolidated financial statements.
Other Electric Utilities
.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2024
2023
2024
2023
Operating revenues – regulated electric
$
 
107
$
 
104
$
 
413
$
 
390
Regulated fuel for generation and purchased power
$
 
55
$
 
57
$
 
215
$
 
204
Contribution to consolidated adjusted net income
$
 
15
$
 
3
$
 
35
$
 
26
Contribution to consolidated adjusted net income – CAD
$
 
21
$
 
4
$
 
48
$
 
35
Equity securities MTM (loss) gain
 
$
 
(1)
$
 
2
$
 
-
 
$
 
2
Contribution to consolidated net income
$
 
14
$
 
5
$
 
35
$
 
28
Contribution to consolidated net income
 
– CAD
$
 
19
$
 
6
$
 
48
$
 
37
Electric sales volumes (GWh)
 
323
 
323
 
1,307
 
1,260
Electric production volumes (GWh)
 
347
 
345
 
1,403
 
1,362
Average fuel cost in dollars per MWh
$
 
159
$
 
165
$
 
153
$
 
150
The impact of the change in the FX rate increased CAD earnings and adjusted earnings by $1 million for
the three months and year ended December 31, 2024.
Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2024
2023
2024
2023
BLPC
$
 
13
$
 
4
$
 
27
$
 
18
GBPC
 
3
 
-
 
 
11
 
11
Other
 
(1)
 
(1)
 
(3)
 
(3)
Contribution to consolidated adjusted net income
 
$
 
15
$
 
3
$
 
35
$
 
26
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30
Net Income
Highlights of net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2023
$
 
5
$
 
28
Increased operating revenues quarter-over-quarter due to the timing of
recovery of fuels costs. Year-over-year increased primarily due to
higher sales volumes.
 
3
 
23
Increased fuel for generation and purchased power year-over-year due
to higher sales volumes at BLPC.
 
 
2
 
(11)
Increased OM&G, year-over-year due to higher insurance premiums
and increased generation maintenance costs at GBPC and BLPC.
 
 
1
 
(8)
Other
 
3
 
3
Contribution to consolidated net income – 2024
$
 
14
$
 
35
Regulatory Environments
BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on capital invested.
 
GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate base.
 
For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note
7 in the consolidated financial statements.
Other
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2024
2023
2024
2023
Marketing and trading margin
(1) (2)
$
 
35
$
 
35
$
 
77
$
 
96
Other non-regulated operating revenue
 
10
 
5
 
32
 
27
Total operating revenues – non-regulated
$
 
45
$
 
40
$
 
109
$
 
123
Contribution to consolidated adjusted net (loss) income
 
$
 
(59)
$
 
(71)
$
 
(342)
$
 
(314)
Gain on sale of LIL, after-tax (3)(4)
 
22
 
-
 
 
129
 
-
 
Financing structure wind-up
 
58
 
-
 
 
58
 
-
 
Charges related to wind-down costs and certain asset
impairments, after-tax
(5)
 
(23)
 
-
 
 
(23)
 
-
 
Charges related to the pending sale of NMGC, after-tax (6)
 
-
 
 
-
 
 
(217)
 
-
 
MTM (loss) gain, after-tax
(7)
 
(144)
 
112
 
(291)
 
167
Contribution to consolidated net (loss) income
$
 
(146)
$
 
41
$
 
(686)
$
 
(147)
(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity,
 
pipeline and storage
capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a MTM loss, pre-tax of $159 million in Q4 2024 (2023 – $131 million gain) and a MTM
loss, pre-tax of $357 million for the year ended December 31, 2024 (2023 – $216 million gain).
 
(3) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the
“Significant Items Affecting Earnings” and “Other Developments” sections.
(4) Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net income tax expense
 
of
$53 million for the year ended December 31, 2024 (2023 – nil).
(5) Primarily relates to Block Energy, net of income
 
tax recovery of $6 million for the year ended December 31, 2024 (2023 – nil).
(6) Includes a goodwill impairment charge of $210 million ($198 million after-tax) and transaction costs of $25 million ($19 million
after-tax) for the year ended December 31, 2024 (2023 – nil).
(7) Net of income tax recovery of $57 million for the three months ended December 31, 2024 (2023 – $44 million
 
expense) and
$117 million recovery for the year ended December
 
31, 2024 (2023 – $68 million expense).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31
Other's contribution to consolidated adjusted net (loss) income is summarized in the following table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2024
2023
2024
2023
Emera Energy:
 
EES
$
 
16
$
 
19
$
 
30
$
 
46
 
Other
 
(2)
 
6
 
2
 
18
Corporate – see breakdown of adjusted contribution below
 
(73)
 
(91)
 
(360)
 
(356)
Block Energy
 
-
 
 
(4)
 
(13)
 
(18)
Other
 
-
 
 
(1)
 
(1)
 
(4)
Contribution to consolidated adjusted net (loss) income
 
$
 
(59)
$
 
(71)
$
 
(342)
$
 
(314)
Net Income
Highlights of net income changes are summarized in the following table:
For the
Three months ended
 
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net (loss) income – 2023
$
 
41
$
 
(147)
Decreased marketing and trading margin year-over-year due to
favourable hedging opportunities in Q1 2023 and less favourable
market conditions in 2024, specifically lower natural gas prices and
volatility
 
-
 
 
(19)
Increased OM&G quarter-over-quarter primarily due to the timing
difference in the valuation of long-term incentive expense and related
hedges
 
(18)
 
(2)
Increased interest expense due to the impact of a weaker CAD on USD
interest expense, increased total debt and increased interest rates
 
(9)
 
(38)
Corporate FX losses on the translation of USD short-term debt
balances
 
(5)
 
(9)
Decreased deferred income tax asset valuation allowance due to the
utilization of tax loss carryforwards
 
36
 
39
Increased income tax recovery due to increased loss before provision
for income taxes, partially offset by the recognition of investment tax
credits related to Bear Swamp facility upgrades in 2023
 
3
 
4
Gain on sale of LIL, after-tax
 
22
 
129
Financing structure wind-up
 
58
 
58
Charges related to wind-down costs and certain asset impairments,
after-tax
 
(23)
 
(23)
Charges related to the pending sale of NMGC, after-tax
 
-
 
 
(217)
The 2023 MTM gain, after-tax, decreased to a loss for the same
periods in 2024 due to changes in existing positions, partially offset by
lower amortization of gas transportation assets at EES
 
(254)
 
(457)
Other
 
 
3
 
(4)
Contribution to consolidated net (loss) income – 2024
$
 
(146)
$
 
(686)
32
Emera Energy
 
EES derives revenue and earnings from wholesale marketing and trading of natural gas and electricity
within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure.
EES purchases and sells physical natural gas and electricity, the related transportation and transmission
capacity rights, and provides energy asset management services. The primary market area for the natural
gas and power marketing and trading business is northeastern North America, including the Marcellus
and Utica shale supply areas. EES also participates in the US Southeast, Gulf Coast and Midwest, and
Central Canadian and Alberta natural gas markets. Its counterparties include electric and gas utilities,
natural gas producers, electricity generators and other marketing and trading entities. EES operates in a
competitive environment, and the business relies on knowledge of the region’s energy markets,
understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a
focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial
products to hedge purchases and sales, and investing in transportation capacity rights to enable
movement across its portfolio.
EES’ contribution to consolidated adjusted net income was $16 million in Q4 2024, compared to $19
million in Q4 2023; and $30 million ($21 million USD) for the year ended December 31, 2024, compared
to $46 million ($33 million USD) for the same period in 2023. Market conditions in 2024 were less
favourable compared to 2023 due to lower natural gas prices and volatility.
MTM Adjustments
Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased
power”, “Income from equity investments” and “Income tax (recovery) expense” are affected by MTM
adjustments. Variance explanations of the MTM changes for this quarter and for the year are explained in
the table above.
 
Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including
local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs
involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the
counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs
arise on the price differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,
which is amortized over the term of the AMA contract.
 
Subsequent changes in gas price differentials, to the extent they are not offset by the accounting
amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM
adjustments may be substantial during the term of the contract, especially in the winter months of a
contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,
and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and
the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA
volumes increase, MTM volatility resulting in gains and losses may also increase.
Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.
Fluctuations in the FX rate result in MTM gains or losses are recorded in “Other income, net” on the
Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
33
Corporate
Corporate's adjusted loss is summarized in the following table:
 
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2024
2023
2024
2023
Operating expenses
 
(1)
 
$
 
(23)
$
 
(7)
$
 
(74)
$
 
(73)
Interest expense
 
(97)
 
(88)
 
(367)
 
(329)
Income tax recovery
 
76
 
25
 
170
 
111
Preferred dividends
 
(19)
 
(18)
 
(73)
 
(66)
Other
 
(2)(3)
 
(10)
 
(3)
 
(16)
 
1
Corporate adjusted net loss
 
(4)(5)(6)(7)
$
 
(73)
$
 
(91)
$
 
(360)
$
 
(356)
(1) Operating expenses include OM&G and depreciation.
 
(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings
exposure.
(3) Includes a realized net loss, pre-tax of $5 million ($4 million after-tax) for the three months ended December 31, 2024
 
(2023 – $4
million net loss, pre-tax and $3 million loss, after-tax) and a $12 million net loss, pre-tax ($9 million after-tax) for the year
 
ended
December 31, 2024 (2023 – $11 million
 
net loss, pre-tax and $8 million loss after-tax) on FX hedges, as discussed above.
(4) Excludes a MTM loss, after-tax of $25 million for the three months ended December 31, 2024 (2023 – $15 million gain, after-tax)
and a MTM loss, after-tax of $31 million for the year ended December 31, 2024 (2023 – $20 million gain, after-tax).
(5) Excludes a gain on sale of LIL, after-tax, of $107 million for the year ended December 31, 2024 (2023 – nil).
(6) Excludes certain charges related to the pending sale of NMGC of $234 million ($217 million after-tax) for the year ended
December 31, 2024 (2023 – nil).
(7) Excludes the tax recovery of $58 million related to a specific financing structure and its wind-up and $22 million
 
on reversal of a
prior year valuation allowance related to the sale of LIL for the three months and year ended December 31, 2024 (2023
 
– nil).
LIQUIDITY AND CAPITAL
 
RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy
investments. Utility customer bases are diversified by both sales volumes and revenues among customer
classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the
business. Circumstances that could affect the Company’s ability to generate cash include changes to
global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity
price changes on collateral requirements and timely recoveries of fuel and storm costs from customers,
the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery
of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a
financial position to contribute cash dividends to Emera provided they do not breach their debt covenants,
where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing
rate base investment, business acquisitions, greenfield development, dividends and debt servicing.
Emera has an approximate $20 billion capital investment plan over the 2025 through 2029 period and
supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory
approval.
Emera currently has a strong liquidity position and ability to service debt obligations as they come due to
meet any near-term capital investment requirements as currently planned. Emera plans to use cash from
operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC to
support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of
the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity
requirements in support of the Company’s capital investment plan are expected to be funded through
issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
34
Emera has total committed credit facilities with varying maturities that cumulatively provide $2.3 billion
CAD and $1.6 billion USD of credit, with approximately $1.1 billion CAD and $593 million USD undrawn
and available at December 31, 2024. The Company was holding a cash balance of $204 million, which
includes $8 million classified as assets held for sale, related to the pending sale of NMGC, at December
31, 2024. For further discussion, refer to the “Debt Management” section below.
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash Flows between the years ended December
31, 2024 and 2023 include:
millions of dollars
2024
2023
$ Change
Cash, cash equivalents and restricted cash, beginning of period
$
 
588
$
 
332
$
 
256
Provided by (used in):
 
Operating cash flow before changes in working capital
 
2,194
 
2,336
 
(142)
 
Change in working capital
 
452
 
(95)
 
547
Operating activities
$
 
2,646
$
 
2,241
$
 
405
Investing activities
 
(2,218)
 
(2,917)
 
699
Financing activities
 
(818)
 
939
 
(1,757)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and
cash associated with assets held for sale
 
23
 
(7)
 
30
Cash, cash equivalents, restricted cash, and cash associated with assets held
for sale, end of period
$
 
221
$
 
588
$
 
(367)
Cash Flow from Operating Activities
Net cash provided by operating activities increased
$405 million to $2,646 million for the year ended
December 31, 2024, compared to $2,241 million in 2023.
Cash from operations before changes in working capital decreased
$142 million for the year ended
December 31, 2024. This decrease was due to increased storm cost recovery regulatory asset related to
Hurricane Helene and Hurricane Milton at TEC, lower fuel clause recoveries at TEC, and the reversal of
the Nova Scotia Cap-and-Trade Program provision in Q1 2023 at NSPI. These were partially offset by the
NSPML Refund, favourable change in regulatory liabilities due to the 2023 gas hedge settlements at
NMGC, increased electric revenue at NSPI, proceeds from the FAM asset sale to Invest Nova Scotia at
NSPI, and increased earnings and the recovery of the conservation clause expense at PGS.
Changes in working capital increased operating cash flows by $547 million for the year ended December
31, 2024. This increase was due to increased accounts payable at TEC due to Hurricane Helene and
Hurricane Milton storm cost accruals, favourable changes in cash collateral positions at NSPI, lower
accounts receivable at TEC, reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023 at
NSPI, favourable changes in fuel inventory at NSPI and TEC, and favourable changes in accounts
payable at NSPI, NMGC, and PGS. These were partially offset by unfavourable changes in cash
collateral positions at EES, unfavourable changes in accounts receivable at NMGC due to the receipt of
the 2023 gas hedge settlement, unfavourable changes in natural gas inventory at EES, and unfavourable
changes in accounts receivable at NSPI.
Cash Flow used in Investing Activities
Net cash used in investing activities decreased $699 million to $2,218 million for the year ended
December 31, 2024, compared to $2,917 million in 2023. The decrease was primarily due to the
proceeds of $927 million received on the sale of Emera’s LIL equity interest, partially offset by higher
capital investment in 2024.
35
Capital expenditures for the year ended December 31, 2024, including AFUDC, were $3,206 million
compared to $2,976 million in 2023. Details of 2024 capital spending by segment are shown below:
 
●
 
$1,998 million – Florida Electric Utility (2023 – $1,771 million);
●
 
$494 million – Canadian Electric Utilities (2023 – $461 million);
●
 
$626 million – Gas Utilities and Infrastructure (2023 – $673 million);
 
●
 
$81 million – Other Electric Utilities (2023 – $63 million); and
●
 
$7 million – Other (2023 – $8 million).
Cash Flow from Financing Activities
Net cash used in financing activities decreased $1,757 million to $818 million for the year ended
December 31, 2024, compared to net cash provided by financing activities of $939 million in 2023. This
decrease was due to lower issuance of long-term debt at PGS, NSPI, and NMGC, higher repayment of
Emera's committed credit facilities using the LIL transaction proceeds, retirement of long-term debt at
Emera, TEC and NMGC, and higher net repayments under committed credit facilities at NSPI. These
were partially offset by proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by
EUSHI Finance Inc., lower short-term debt repayments at TEC, and issuance of long-term debt at TEC.
Working Capital
As at December 31, 2024, Emera’s cash and cash equivalents were $196 million (2023 – $567 million)
and Emera’s investment in non-cash working capital was $224 million (2023 – $831 million). Of the cash
and cash equivalents held at December 31, 2024, $185 million was held by Emera’s foreign subsidiaries
(2023 – $482 million). A portion of these funds are invested in countries that have certain exchange
controls, approvals, and processes for repatriation. Such funds are available to fund local operating and
capital requirements unless repatriated.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36
Contractual Obligations
As at December 31, 2024, contractual commitments for each of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Long-term debt principal
 
(1)
$
 
234
$
 
3,279
$
 
120
$
 
651
$
 
1,764
$
 
13,192
$
 
19,240
Interest payment obligations
(2)(3)
 
884
 
799
 
712
 
705
 
636
 
8,210
 
11,946
Purchased power
(4)
 
307
 
277
 
368
 
368
 
369
 
4,487
 
6,176
Transportation
(5)(6)
 
742
 
545
 
544
 
454
 
412
 
3,228
 
5,925
Capital projects
 
604
 
287
 
24
 
-
 
 
-
 
 
-
 
 
915
Fuel, gas supply and storage
(7)
 
591
 
94
 
21
 
5
 
-
 
 
-
 
 
711
Pension and post-retirement
obligations
(8)
 
31
 
32
 
68
 
72
 
73
 
224
 
500
Asset retirement obligations
 
9
 
1
 
1
 
2
 
1
 
422
 
436
Other
 
160
 
95
 
80
 
59
 
59
 
264
 
717
$
 
3,562
$
 
5,409
$
 
1,938
$
 
2,316
$
 
3,314
$
 
30,027
$
 
46,566
As detailed below, contractual obligations at December 31, 2024 includes
 
those related to NMGC. On completion of the sale of
NMGC, all remaining future contractual obligations will be transferred to the buyer.
 
For further details on the pending transaction,
refer to the "Other Developments" section.
(1) Includes $696 million related to NMGC (2026: $100 million, and $576 million thereafter).
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.
 
For debt instruments
with variable rates, interest is calculated for all future periods using the rates in effect at December 31,
 
2024, including any expected
required payment under associated swap agreements.
(3) Includes $353 million related to NMGC (2025: $26 million, 2026: $26 million, 2027: $23 million, 2028: $23 million,
 
2029: $23
million, and $232 million thereafter).
(4) Annual requirement to purchase electricity from IPPs or other utilities over varying contract lengths.
(5) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$135 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(6) Includes $86 million related to NMGC (2025: $30 million, 2026: $24 million, 2027: $16 million, 2028: $12 million,
 
and 2029: $4
million).
(7) Includes $177 million related to NMGC (2025: $109 million, 2026: $52 million, 2027: $13 million, and 2028: $3 million).
(8) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions
 
to the
registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI's Collective
 
Bargaining
Agreement and estimated benefit payments related to other unfunded benefit plans.
 
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years
from its January 15, 2018 in-service date. In November 2024, the UARB approved the collection of up to
$197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable
to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods
(April through October, inclusive) for NLH's use, if requested, effective August 15, 2021 and continuing for
50 years. As transmission rights are contracted, the obligations are included within “Other” in the above
table.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
37
Forecasted Consolidated Capital Investments
The 2025 forecasted consolidated capital investments, including AFUDC, are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
 
358
$
 
117
$
 
-
 
$
 
32
$
 
-
 
$
 
507
New renewable generation
 
567
 
-
 
 
-
 
 
81
 
-
 
 
648
Electric transmission
 
169
 
188
 
-
 
 
53
 
-
 
 
410
Electric distribution
 
614
 
140
 
-
 
 
-
 
 
-
 
 
754
Gas transmission and distribution
 
-
 
 
-
 
 
481
 
-
 
 
-
 
 
481
Facilities, equipment, vehicles, and other
 
547
 
40
 
5
 
23
 
5
 
620
$
 
2,255
$
 
485
$
 
486
$
 
189
$
 
5
$
 
3,420
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to
unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD
per the table below.
Undrawn
Credit
and
millions of dollars in currency as noted below
Maturity
Facilities
Utilized
Available
In CAD:
 
Emera – committed revolving credit facility
June 2029
$
 
1,300
$
 
792
$
 
508
 
NSPI – committed revolving credit facility
June 2029
 
800
 
189
 
611
 
Emera – non-revolving facility
 
February 2026
 
200
 
200
 
-
 
In USD:
 
TEC – committed revolving credit facility
December 2028
 
800
 
637
 
163
 
TECO Finance – committed revolving credit facility
December 2028
 
400
 
184
 
216
 
PGS – revolving facility
December 2028
 
250
 
138
 
112
 
NMGC – revolving credit facility
December 2026
 
125
 
34
 
91
 
Other – committed revolving credit facilities
Various
 
24
 
13
 
11
Emera and its subsidiaries have certain financial and other covenants associated with their debt and
credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant
requirements as at December 31, 2024.
 
Emera’s significant covenant is 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 to 1
0.55 : 1
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with
proceeds from commercial paper.
On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to
extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in
commercial terms from the prior agreement.
38
On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 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 credit facility to extend the maturity date
from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. On
December 16, 2024, NSPI repaid the $300 million unsecured non-revolving credit facility using the net
proceeds from the NSPML debt issuance transferred to NSPI as approved by the UARB. For more
information on the FLG, refer to the “Business Overview and Outlook – Canadian Electric Utilities”
section.
On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity
date from December 16, 2027 to 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 facility to finance the Battery Energy Storage
Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs
up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project
costs over the term of the agreement. The facility will be available until 6 months after completion of the
project, not to exceed May 21, 2027, and matures 20 years following the end of the period. As at
December 31, 2024, NSPI had utilized $19 million from the facility, which bears interest at 2.51 per cent.
Gas Utilities and Infrastructure
On December 10, 2024, Brunswick Pipeline amended its non-revolving loan agreement. The maturity
date was extended to December 2028 and now includes annual principal repayments.
On July 30, 2024, NMGI repaid its $150 million USD fixed rate notes upon maturity.
Other Electric Utilities
On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend
the maturity date from February 19, 2025 to 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 revolving credit facility increasing the facility
from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June
24, 2029. There were no other material changes in commercial terms from the prior agreement.
On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in
August 2024.
On June 18, 2024, EUSHI Finance completed an issuance of $500 million USD fixed-to-fixed reset rate
junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on
December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S.
treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, at its option,
may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-
annual interest payment date thereafter, at a redemption price equal to the principal amount.
 
 
 
 
 
 
 
 
 
 
 
 
39
Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US
Finance LP $300 million USD senior note upon maturity in June 2024, and to repay an NMGI $150 million
USD fixed rate notes upon maturity in July 2024. The remaining proceeds were used for general
corporate purposes.
On June 17, 2024, Emera repaid $200 million on the December 2024 unsecured non-revolving facility,
decreasing the facility from $400 million to $200 million. In December 2024, Emera repaid the $200
million upon maturity.
On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit
facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other
changes in commercial terms from the prior agreement.
On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the
maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial
terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400
million to $200 million. On February 20, 2025, Emera extended the agreement for an additional year to
February 2026 with no other changes in terms. This facility was classified as long-term debt at December
31, 2024.
Credit Ratings
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch
S&P
Moody's
DBRS
Emera
 
(1)
BBB (Negative)
BBB- (Stable)
Baa3 (Negative)
N/A
TEC
(1)
A (Negative)
BBB+ (Stable)
A3 (Negative)
N/A
PGS
A (Negative)
N/A
N/A
N/A
NMGC
(2)
BBB+ (Stable)
N/A
N/A
N/A
NSPI
 
(1)
N/A
BBB- (Stable)
N/A
BBB (high)(stable)
(1) On January 22, 2025, Standard and Poor’s (“S&P") revised its outlook on Emera and its subsidiaries to stable from negative with
no change to existing ratings.
(2) On May 30, 2024, Fitch Ratings (“Fitch”) revised NMGC’s outlook to stable from negative.
Guaranteed Debt
As of December 31, 2024, the Company had $2.95 billion USD (2023 – $2.75 billion USD) senior
unsecured notes and junior subordinated notes (collectively referred to as the "US Notes”) outstanding.
The US Notes are fully and unconditionally guaranteed, on a joint and several basis, and in the case of
the fixed-to-fixed reset rate junior subordinated notes due 2054 only, on a joint, several and subordinated
basis, by Emera and Emera US Holdings Inc. (“EUSHI”) (in such capacity, the “Guarantor Subsidiaries”).
Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US
Finance LP.
 
EUSHI Finance is owned indirectly by Emera through EUSHI.
Other subsidiaries of the Company do not guarantee the US Notes (such subsidiaries are referred to as
the "Non-Guarantor Subsidiaries"); however, Emera has unrestricted access to the assets of consolidated
entities.
In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial
information for Emera, EUSHI, Emera US Finance LP and EUSHI Finance (together, the "Obligor
Group"), on a combined basis after transactions and balances between the combined entities have been
eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded
from the summarized financial information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40
The Obligor Group was not determined using geographic, service line or other similar criteria and, as a
result, the summarized financial information includes portions of Emera’s domestic and international
operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition
or results of operations for any purpose other than to comply with the specific requirements for guarantor
reporting.
Summarized Statement of Income (Loss)
 
The Company recognized income related to guaranteed debt under the following categories:
For the
Year ended December 31
millions of dollars
2024
2023
Loss from operations
$
 
(279)
$
 
(62)
Net gains
(1)
$
 
442
$
 
394
(1) Includes $1,352 million (2023 – $962 million) in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
December 31
millions of dollars
2024
2023
Current assets
 
(1)
$
 
391
$
 
272
Goodwill
 
5,858
 
5,871
Other assets
(2)
 
6,474
 
6,263
Total assets
 
(3)
$
 
12,723
$
 
12,406
Current liabilities
(4)
$
 
611
$
 
1,264
Long-term liabilities
(5)
 
13,129
 
11,956
Total liabilities
$
 
13,740
$
 
13,220
(1) Includes $217 million (2023 – $178 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $5,937 million (2023 – $5,906 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $42,951 million
 
(2023 – $39,480 million).
(4) Includes $184 million (2023 – $167 million) due to non-guarantor subsidiaries.
(5) Includes $5,980 million (2023 – $5,854 million) due to non-guarantor subsidiaries.
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2023
284.12
$
8,462
Issuance of common stock under ATM program
(1)
5.12
261
Issued under the DRIP,
 
net of discounts
6.10
291
Senior management stock options exercised and Employee Share Purchase Plan
0.60
28
Balance, December 31, 2024
295.94
$
9,042
(1) For the year ended December 31, 2024, a total of 5,117,273
 
common shares were issued under Emera's ATM program
 
at an
average price of $51.52 per share for gross proceeds of $264 million ($261 million, net of after-tax issuance costs). As at
December 31, 2024, an aggregate gross sales limit of $336 million remained available for issuance under the ATM
 
program.
As at February 14, 2025, the amount of issued and outstanding common shares was 297.7 million.
If all outstanding stock options were converted as at February 14, 2025, an additional 3.8 million common
shares would be issued and outstanding.
 
 
 
 
 
 
 
 
41
ATM Equity Program
On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up
to $1 billion of common shares from treasury to the public from time to time, at the Company's discretion,
at the prevailing market price. The ATM Program was increased by an amendment dated November 18,
2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13,
2024 to its short form base shelf prospectus dated October 3, 2023.
Preferred Stock
 
As at February 19, 2025, Emera had the following preferred shares issued and outstanding: Series A –
4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;
Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not
have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
On January 8, 2025, Emera announced that it would not redeem the outstanding Series F preferred
shares on February 15, 2025. During the conversion period between January 15, 2025 and January 31,
2025, subject to certain conditions, the holders of Series F shares had the right, at their option, to convert
all or any of their Series F shares, on a one-for-one basis into Cumulative Floating Rate First Preferred
Shares, Series G on February 15, 2025.
 
On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares will
be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.
 
On February 6, 2025, Emera announced after having taken into account all conversion notices received
from holders none of the Series F preferred shares were converted to Series G preferred shares.
PENSION FUNDING
For funding purposes, Emera determines required contributions to its largest defined benefit (“DB”)
pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement
as the impact of investment gains and losses are recognized over a multi-year period. Expected cash flow
for DB pension plans is $41 million in 2025 (2024 – $36 million). All pension plan contributions are tax
deductible and will be funded with cash from operations.
Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real
return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of
preserving capital with an acceptable level of risk for the pension fund investments.
 
To
 
achieve the overall long-term asset allocation, pension assets are managed by external investment
managers per each pension plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of domestic and global equities, domestic and global bonds and short-
term investments. The Company reviews investment manager performance on a regular basis and
adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $56 million for 2025 (2024 –
$51 million).
Defined Benefit Pension Plan Summary
in millions of dollars
Plans by region
TECO Holdings
NSPI
Caribbean
 
Total
Assets as at December 31, 2024
$
 
987
$
 
1,495
$
 
11
$
 
2,493
Accounting obligation at December 31, 2024
$
 
970
$
 
1,380
$
 
17
$
 
2,367
Accounting expense (income) during fiscal 2024
$
 
5
$
 
(11)
$
 
3
$
 
(3)
42
Off-Balance Sheet Arrangements
Defeasance
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities
that provide principal and interest streams to match the related defeased debt, which at December 31,
2024 totalled $200 million (2023 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with this portion of the portfolio.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit were not included within the Consolidated Balance Sheets as at
December 31, 2024:
TECO Holdings, Inc. (“TECO Holdings”) has a guarantee in connection with SeaCoast’s performance of
obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential
amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires
five years after the gas transportation precedent agreement termination date, which was terminated on
January 1, 2022. The counterparty has the right to require TECO Holdings to provide replacement credit
support either in the form of a substitute guarantee from an affiliate with an investment grade credit rating
or a letter of credit or cash deposit of $27 million USD.
TECO Holdings has a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires December 31, 2055, subject to two extension terms at the option of the
counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential
amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. The
counterparty has the right to require TECO Holdings to provide replacement credit support in the form of
either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or
cash deposit of $13 million USD.
Emera has a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will
automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount
of $104 million USD (2023 – $104 million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $105 million USD
(December 31, 2023 – $103 million USD) to third parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2025. The amount committed
as at December 31, 2024 was $58 million (December 31, 2023 – $56 million).
Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could
arise from specific future changes in Canadian federal law, subject to certain conditions and limitations.
No such changes in law have been proposed at this time. A reasonable estimate of the potential amount
of future payments that could result from future claims under this indemnity cannot be calculated, but the
risk of having to make any significant payments under this indemnity is considered to be remote.
43
DIVIDEND PAYOUT
 
RATIO
Emera has provided annual dividend growth guidance of one to two per cent per year. On September 18,
2024, the Board approved an increase in the annual common share dividend rate to $2.9000 from
$2.8700 per common share. The first quarterly dividend payment at the increased rate was paid on
November 15, 2024.
Emera’s common share dividends paid in 2024 were $2.8775 ($0.7175 in Q1, Q2, and Q3 and $0.7250 in
Q4) per common share and for 2023 were $2.7875 ($0.6900 in Q1, Q2, and Q3 and $0.7175 in Q4) per
common share. This represents a dividend payout ratio of net income of 168 per cent in 2024 (2023 – 78
per cent) and a dividend payout ratio of adjusted net income of 98 per cent in 2024 (2023 – 94 per cent).
 
TRANSACTIONS WITH RELATED
 
PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
Significant transactions between Emera and its associated companies are as follows:
●
 
Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling a recovery of $324 million for the year ended December 31, 2024 (2023 –
$163 million expense). NSPML is accounted for as an equity investment, and therefore corresponding
earnings related to this revenue are reflected in Income from equity investments.
 
For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities –
NSPML” and “Contractual Obligations” sections.
●
Natural gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,
totalled $
11
million for the year ended December 31, 2024 (2023
– $14 million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2024 and at December 31, 2023.
ENTERPRISE RISK AND RISK MANAGEMENT
Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board, to ensure risks are appropriately identified, assessed,
monitored and subject to appropriate controls. The Board has a Risk and Sustainability Committee
(“RSC”) to assist the Board in carrying out its risk and sustainability oversight responsibilities. The RSC’s
mandate includes oversight of the Company’s Enterprise Risk Management framework, including the
identification, assessment, monitoring and management of enterprise risks.
44
The significant business risks to Emera are described below, many of which are beyond the Company’s
control, and could have a material adverse effect on Emera or its subsidiaries, or their business
operations, liquidity or access to or cost of capital, financial position, prospects, and/or results of
operations (herein considered a “Material Adverse Effect”). The nature of risk is such that no such list is
comprehensive, and the actual effect of any of the risks discussed could be materially different from what
is described below. Additionally,
 
other risks not presently known may arise, risks not currently considered
material may become material in the future, or two or more risks which are not themselves material, could
together be material.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments are subject to complex legislative
and regulatory frameworks that cover material aspects of their businesses. These frameworks influence
key factors such as rates and cost structures, revenue requirements, allowed ROEs, capital structures,
rate base and capital investments, and the recovery of purchased electricity and fuel costs and other
costs. Regulators also review the prudency of costs and make other decisions that can impact customer
rates and the reliability of service. Emera’s cost-of-service utilities must obtain regulatory approvals for
material aspects of their businesses, including changing or adding rates and/or riders. Such approvals
often require public hearing proceedings involving numerous stakeholders, and there is no assurance in
the outcomes or impact of any regulatory process or decision.
If Emera is unable to recover in a timely manner a material amount of costs or a return on invested capital
through regulatory mechanisms or otherwise, is disallowed the recovery of certain costs, is subject to
regulatory penalties, is not permitted to make certain capital investments, or is not permitted to invest in or
divest certain utility assets, it could result in a Material Adverse Effect, including valuation impairments.
Regulatory lag, the time between the incurrence of costs and the granting of the rates to recover those
costs by regulators, may also result in a Material Adverse Effect.
Aspects of the acquisition, ownership, operations, siting, planning, construction, and decommissioning of
electric generation, storage, transmission and distribution facilities and natural gas transportation and
distribution systems are also subject to regulatory processes and approvals of regulators, government
departments and agencies, and other third parties. The failure to obtain, maintain, and renew such
approvals or significant changes in the terms and conditions thereof could have a Material Adverse Effect.
 
The regulatory framework, process and regulatory decisions may also be adversely affected by changes
in government, shifts in government or public policy, legislative changes, regulatory decisions, geopolitical
changes, changes in the economic environment, or other factors. Government interference in the
regulatory process or regulatory decisions can undermine regulatory stability, predictability,
 
and
independence. Any such changes could have a Material Adverse Effect.
 
Change in Law Risk
The Company is also exposed to changes in the political environment and leadership, changes in law or
regulations, changes to governmental policies, trade disputes, and the imposition of tariffs, any of which
may impact the Company’s businesses, the markets for energy and inputs thereto, or general economic
conditions, and which may result in a Material Adverse Effect. This may include initiatives regarding
deregulation or restructuring of the energy industry, which may result in increased competition, and
increased or unrecovered costs. State and local policies in some US jurisdictions have sought to prevent
or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions
policies have been adopted to prevent limitations on the use of natural gas.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or the resulting operating or compliance costs or other impacts. It may be difficult
for Emera to respond in an effective and timely manner to such future legislative, policy or regulatory
changes.
 
45
Environmental Legislation
:
Emera is subject to extensive regulation by federal, provincial, state, regional and local authorities
regarding environmental matters, primarily related to its utility operations. This includes laws, regulations
and policies relating to GHG emissions, renewable energy standards, climate change, air quality, water
quality and usage, waste management, wastewater discharges, soil quality, aquatic and terrestrial
habitats, hazardous waste, health, endangered species, and wildlife mortality.
 
In some jurisdictions where Emera operates, government legislation and policy has included timelines for
mandated shutdowns of coal-fired generating facilities, has required a certain percentage of electricity be
generated from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the
medium and long terms, these could potentially lead to a significant portion of hydrocarbon infrastructure
assets being subject to additional regulation and limitations in respect of GHG emissions and operations.
 
Both the Government of Nova Scotia and the Government of Canada have enacted or introduced
legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has
established targets with respect to the percentage of renewable energy in NSPI’s generation mix and
reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.
The Government of Canada has also enacted regulations imposing emissions standards on coal-fired
generation that would effectively require the decommissioning of such facilities. While Nova Scotia is
exempted from such regulations through 2029, there is no guarantee that such exemption will continue
into the future. Failure to meet such goals by 2030 or comply with applicable legislation or regulation
could result in a Material Adverse Effect.
 
Per- and polyfluoroalkyl substances (“PFAS”) are man-made chemicals that are widely used in consumer
products and can persist and bio-accumulate in the environment. The Company does not manufacture
PFAS but because these emerging contaminants of concern are so ubiquitous in products and the
environment, it may impact Emera’s operations. Changes in environmental laws and regulations related
to PFAS could result in new costs or obligations for investigation and cleanup and change the Company’s
strategy for land acquisition for projects such as solar generation and could result in a Material Adverse
Effect.
These and new or revised environmental laws, regulations, policies, or interpretations of those laws,
regulations or policies could result in a Material Adverse Effect by, among other things, preventing or
delaying the development of energy infrastructure projects, restricting the use or output of certain
facilities, requiring the early retirement of certain generation facilities that could result in stranded costs,
limiting the availability or use of certain fuels required for the production of electricity, requiring additional
pollution control equipment, curtailing sales of natural gas to new customers, which could reduce future
customer growth in Emera’s natural gas businesses, changing the nature and timing of capital
investments, requiring significant capital investments, imposing operating or other costs associated with
compliance including carbon taxes or emissions allowances, or by limiting or eliminating certain
operations or rendering such operations uneconomical.
 
Impacts could be more significant in the future as
the result of new or revised laws or requirements or stricter or more expansive application of existing
environmental laws, regulations and policies. Failure to recover environmental costs in a timely manner
through rates may also result in a Material Adverse Effect.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and
regulations authorizing the imposition of penalties for non-compliance, exposing Emera to legal or
regulatory proceedings, disputes, civil fines, injunctive relief, criminal penalties and other sanctions, which
could result in a Material Adverse Effect.
 
46
Weather Risk
A Material Adverse Effect may arise from weather seasonal variations impacting energy consumption, as
well as severe weather events, changing air temperatures, wildfires and other severe weather conditions
that are expected to become more frequent and intense as a result of climate change. Refer to “Climate
Change Risk”.
The temperature, seasonal variations, and other weather conditions significantly influence the availability
and demand for electricity and natural gas by customers, the price of energy commodities, such as fuel
used by the Company’s utilities, and the production of electricity at power generation facilities. For
example, NSPI could see lower sales in winter months if temperatures are warmer than expected.
 
Severe weather events or conditions such as hurricanes, floods, storm surge, tornadoes, droughts, fires,
extreme temperatures, snow or ice storms, and other natural disasters create a risk of physical damage to
the Company’s assets and a risk of extended service outages or fuel supply disruptions.
 
For example,
high winds can cause widespread damage to transmission and distribution infrastructure, solar
generation, and wind-powered generation. Substantially all of the Company’s fossil fueled generation
assets are located at or near coastal sites and, as such, are exposed to the separate and combined
effects of rising sea levels and increasing storm intensity, including storm surges and flooding.
 
Severe weather events or conditions could reduce revenues and require the Company to incur additional
costs, such as repair and replacement costs, costs of replacement power and fuel, increased insurance
costs, and the need to access additional financing sources. These could result in a Material Adverse
Effect if not resolved or mitigated in a timely and efficient manner through insurance or regulatory cost
recovery. This risk to transmission and distribution facilities is typically not insured, and as such the
restoration cost is generally recovered through regulatory processes, either in advance through reserves,
or after the fact through the establishment of regulatory assets. Recovery is not assured, is subject to
prudency review, and may be subject to delay resulting in increased debt and debt servicing costs.
Severe weather events or other catastrophic natural disasters could also result in long-term reductions in
demand for electricity or natural gas or the slowing of customer growth in one or more of the Company’s
service territories, which could have a Material Adverse Effect. The impact of extreme weather events
would be amplified if the same events affect multiple utilities in the Company’s portfolio.
High winds and lack of precipitation also increase the risk of wildfires resulting from the Company’s
infrastructure or for which the Company may otherwise have responsibility. If it is found to be responsible
for such a fire, the Company could suffer material costs, losses and damages, all or some of which may
not be recoverable through insurance, legal, regulatory cost recovery or other processes. If not recovered
through these means or if recovery is delayed, they could result in a Material Adverse Effect. Resulting
costs could include fire suppression costs, regeneration, timber value, increased insurance costs and
costs arising from damages and losses incurred by third parties.
 
The Company purchases power from third-party owned hydroelectricity sources and operates
hydroelectric generation in certain of its markets. Such generation depends on availability of water and
the hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air
temperatures could adversely affect the availability of water and consequently the amount of electricity
that may be produced from such facilities.
 
47
Climate Change Risk
Physical Risk:
Climate change may negatively impact the Company’s operations as a result of increased frequency and
intensity of weather events and related physical risks, any of which could result in a Material Adverse
Effect (for more information refer to “Weather Risk” and “System Operating and Maintenance Risks”). An
increase in physical risk associated with climate change can also adversely impact the cost and
availability of insurance, insurance deductibles and self-retention, as well as credit ratings, which could
affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (refer to
“Liquidity and Capital Markets Risk”).
 
Transition Risk:
As government policy and the economy transition toward decarbonization in many jurisdictions, the
Company is exposed to risks arising from policy, legal, technology,
 
and market changes, which could
result in a Material Adverse Effect. The energy transition will require the Company to address changes to
environmental policies, laws and regulations which are being proposed and adopted in many jurisdictions
in response to concerns regarding the effects or impacts of climate change (refer to “Environmental
Legislation”). The pace of such new initiatives is expected to accelerate in some jurisdictions.
 
The Company will be required to manage the impacts of these changes on customer demand and rates,
while integrating increased amounts of intermittent renewable energy sources and new technologies,
implementing and making the investments required to meet new resiliency and security standards, and
adapting the Company’s infrastructure and generating capacity to meet changing customer demands and
usage patterns. The energy transition and the ability of the Company to achieve mandated climate related
targets and goals will require significant capital investment, effective engagement with policymakers,
regulators and stakeholders, and depend upon many factors which are outside of the Company’s direct
control. Depending on the regulatory response to government legislation and regulations, the Company
may be exposed to the risk of reduced recovery through rates in respect of the affected assets.
 
Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become
difficult or uneconomic to insure in commercial insurance markets. Some insurance companies have
begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-
term impacts of climate change which may result in less insurance capacity, more restrictive coverage
and increased premiums. The Company could also face litigation or regulatory action related to
environmental harms from GHG emissions or failure to substantiate certain environmental claims.
 
The failure to effectively respond to climate change transition risks could adversely affect the Company’s
ability to deliver safe, reliable, and cost-effective service, the Company’s reputation with stakeholders, its
ability to operate and grow, and the Company’s access to, and cost of, capital, each of which could result
in a Material Adverse Effect.
 
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks, data breaches, cyber-extortion, and
unauthorized access that could result in a Material Adverse Effect. The Company relies on IT systems,
cloud infrastructure, third-party service providers and the diligence of its team members to effectively
manage and safely operate its assets. This includes controls for interconnected systems of generation,
distribution and transmission as well as financial, billing and other enterprise systems. As the Company
operates critical energy infrastructure, it may be at greater risk of cyberattacks, which could include those
from nation-state cyber threat actors. Major emerging and ongoing global conflicts may also elevate this
risk, by increasing the sophistication, magnitude, and frequency of cyberattacks.
 
48
Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the
public internet and gain access to critical and non-critical infrastructures. Cyberattacks can also occur via
personnel with access to critical assets or trusted networks. Methods used to attack critical assets could
include generic or energy-sector-specific malware delivered via network transfer, removable media,
attachments, links in e-mails or other communications, or social engineering. The methods used by
attackers are continuously evolving and can be difficult to predict and detect and may become more
sophisticated, frequent, severe, and difficult to stop to the extent that attackers are able to leverage
evolving artificial intelligence models or tools.
Despite security measures in place, the Company’s systems, assets and information could experience
security breaches that could cause system failures, disrupt energy supply and delivery, business
operations, or adversely affect safety. Such breaches could compromise customer, employee-related or
other information systems and could result in loss of service to customers, unavailability of critical assets,
safety issues, compromise billing and customer-facing information, such as outage maps, disrupt internal
control and financial processes, or result in the release, loss, corruption, destruction, and/or misuse of
critical, sensitive, confidential or proprietary information, intellectual property, or personal information of
customers or employees. These breaches could also delay delivery or result in contamination or
degradation of hydrocarbon products the Company transports, stores or distributes.
 
Cyberattacks or unauthorized access may cause lost revenues, costs, losses, regulatory penalties and
third-party damages all, or some of which may not be recoverable through insurance, legal, regulatory
cost recovery or other processes. Resulting costs could include, amongst others, response, recovery and
remediation costs, increased protection or insurance costs and costs arising from damages and losses
incurred by third parties. This could result in a Material Adverse Effect and there is no assurance that
cyberattacks or other security breaches can be adequately addressed in a timely manner.
The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security
Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness
program, and employee communication and training. With respect to certain of its assets, the Company is
required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,
those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power
Coordinating Council, and the United States Department of Homeland Security. The status of key
elements of the Company’s cybersecurity program is reported to the RSC. The Board oversees risk and
mitigation plans in relation to cybersecurity risks and receives a quarterly update in a risk dashboard at
each regularly scheduled Board meeting.
Energy Consumption Risk
Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns
due to fluctuations in a number of factors including general economic conditions, weather events,
customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as
rooftop solar, electric vehicles, data centers, and battery storage. Government policies promoting energy
efficiency, distributed generation, and new technology developments that enable those policies, have the
potential to impact how electricity enters the system and how it is bought and sold. In addition, increases
in distributed generation may impact demand resulting in lower load and revenues. These changes could
negatively impact Emera’s operations, rate base, net earnings, and cash flows and result in a Material
Adverse Effect.
 
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with a significant amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
 
49
Emera manages currency risks through matching US denominated debt to finance its US operations and
may use foreign currency derivative instruments to hedge specific transactions and earnings exposure.
The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency
transactions such as fuel purchases, revenue streams and capital expenditures, and on net income
earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries
permits the recovery of prudently incurred costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated
Other Comprehensive Income (Loss) ("AOCI”).
Liquidity and Capital Markets Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera’s access to capital and cost of borrowing is subject to several risk factors, including
financial market conditions, market disruptions and ratings assigned by various market analysts, including
credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or
cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth
plan requires significant capital investments in PP&E and the risk associated with changes in interest
rates could have an adverse effect on the cost of financing. The Company’s future access to capital and
cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective
capital could have a material impact on Emera’s ability to fund its growth plan.
 
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,
the full value of the net liability of these positions could be required to be posted as collateral.
 
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could have a Material Adverse Effect. This may also result in
higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased
risk to full and timely recovery of costs and regulatory assets.
Interest Rate Risk:
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk.
 
50
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity
and Capital Markets Risk”.
 
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk:
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates.
Public Health Crisis Risk
An outbreak of infectious disease, a pandemic or other public health threats, or a fear of any of the
foregoing, could result in a Material Adverse Effect to Emera and its subsidiaries. This could include
causing operating, supply chain and project development delays and disruptions, labour shortages and
shutdowns (including as a result of government regulation and prevention measures), which could have a
negative impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health
threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing
and extent of capital investments, capital market activities, and counterparty risk; which could result in a
Material Adverse Effect.
Health and Safety
 
The Company’s operations inherently involve risk to the health and safety of employees, contractors and
members of the public. Personal injury or loss of life resulting from failure to implement or observe
appropriate health and safety procedures or comply with health and safety laws and regulations could
result in adverse operational, reputational, legal, regulatory, or financial impacts, any of which could have
a Material Adverse Effect.
 
Project Development and Land Use Rights Risk
The Company’s capital plan includes significant investment in generation, infrastructure modernization,
and customer-focused technologies. Any projects planned or currently in construction, particularly
significant capital projects, may be subject to risks that could result in a Material Adverse Effect including,
but not limited to, impact on costs from schedule delays, increased demand for renewable energy inputs,
risk of cost overruns, ensuring compliance with operating and environmental requirements and other
events within or beyond the Company’s control. The Company’s projects may also require approvals and
permits at the federal, provincial, state, regional and local levels. There is no assurance that Emera will
be able to obtain the necessary project approvals or applicable permits or receive regulatory approval to
recover the costs in rates.
51
Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,
and may be subject to land claims. Present or future assets may be located on lands that have been used
for traditional purposes and therefore subject to specific consultations, consents, or conditions for
development or operation. If the Company’s rights to locate and operate its assets on any such lands are
subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If
reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to
remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be
uneconomical to proceed with.
Counterparty Risk
Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of
which may endure financial challenges resulting from commodity price and market volatility, economic
instability or adversity, adverse political or regulatory changes and other causes which may cause or
contribute to such parties’ insolvency, bankruptcy,
 
restructuring or default on their contractual obligations
to Emera.
 
Emera is also exposed to potential losses related to amounts receivable from customers,
energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance
under an agreement.
There is no assurance that management strategies will be effective, and significant counterparty defaults
could result in a Material Adverse Effect.
Supply Chain Risk
Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute
on the capital investment program in a cost-effective and timely manner are dependent on maintaining an
efficient supply chain. Domestic and global supply chain issues may delay the delivery, increase the cost,
or result in shortages of certain materials, fuel, equipment and other resources that are critical to the
Company’s operations. These disruptions may be further exacerbated by inflationary pressures, labour
shortages, more frequent and severe weather events, government incentives increasing demand for
clean energy projects, changes in carbon-related costs, policies and regulations, and the impact of
international conflicts. In addition, global supply chains and the financial condition and results of the
business could be Materially Adversely Affected by the imposition of custom duties or other tariffs, or an
increase in trade restrictions in the future. Failure to eliminate or manage supply chain constraints may
impact the availability and cost of items and labour that are necessary to support operations and capital
investment and could have a Material Adverse Effect.
 
Fuel Supply Disruptions:
Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both
within and outside their service territories, which may be caused by severe weather or natural disasters.
This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party
fuel production, storage, pipeline, and distribution facilities. Significant unanticipated fuel supply
disruptions could result in increased exposure to commodity price risk for Emera’s regulated electric and
gas utilities and Emera Energy, and these could have a Material Adverse Effect.
 
Commodity Price Risk
The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts
and arrangements.
52
Regulated Utilities:
The Company’s utility fuel supply is exposed to broader global market conditions, which may include
impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel
markets can be affected by a wide range of factors which are difficult to predict and may change rapidly,
including but not limited to, currency fluctuations, changes in global economic conditions, natural
disasters, transportation or production disruptions, and geo-political risks, such as political instability,
conflicts, changes to international trade agreements, tariffs, trade sanctions or embargos.
 
Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased
risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns
and sales, any of which could result in a Material Adverse Effect.
Emera Energy Marketing and Trading:
The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in
particular, its natural gas asset management arrangements, are contracted on a back-to-back basis,
avoiding any material long or short commodity positions. However, the portfolio is subject to commodity
price risk, particularly with respect to basis point differentials between relevant markets in the event of an
operational issue, imposition of tariffs, or counterparty default. Changes in commodity prices can also
result in increased collateral requirements associated with physical contracts and financial hedges,
resulting in higher liquidity requirements and increased costs to the business.
Future Employee Benefit Plan Performance and Funding Risk
Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover
employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO
Holdings Group Retirement Plan and the Grand Bahama Power Company Limited Union Employees’
Pension Plan. The cost of providing these benefit plans varies depending on plan provisions, interest
rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial
assumptions include earnings on plan assets, discount rates (interest rates used to determine funding
levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around
future salary growth, inflation and mortality. The three largest drivers of cost are investment performance,
interest rates and inflation, which are affected by global financial and capital markets. Depending on
future interest rates and future inflation and actual versus expected investment performance, Emera could
be required to make larger contributions in the future to fund these plans, which could have a Material
Adverse Effect.
Labour Risk
Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,
developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to
trades, technical staff and engineers with an increasing number of employees expected to retire over the
next several years. Failure to attract, develop and retain an appropriately qualified workforce could have a
Material Adverse Effect.
 
Approximately 30 per cent of Emera’s labour force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could
result in higher labour costs and work disruptions, which could adversely affect service to customers and
have a Material Adverse Effect.
 
53
IT Risk
Emera relies on various IT systems to manage operations, including increasing reliance on IT solutions
operated by third parties, such as software as a service and third-party cloud hosting. This subjects
Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these
systems. This includes impairment of its IT, potential disruption of internal control systems, substantial
capital expenditures, demands on management time and other risks of delays, difficulties in upgrading
existing systems, transitioning to new systems or integrating new systems into its current systems.
Emera’s digital transformation strategy, including investment in infrastructure modernization and customer
focused technologies, is driving increased investment in IT solutions, resulting in increased project risks
associated with the implementation of these solutions.
 
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the US and the Caribbean and any such changes could have a Material Adverse Effect. The
value of Emera’s existing deferred income tax assets and liabilities are determined by existing tax laws
and could be negatively impacted by changes in laws.
 
System Operating and Maintenance Risks
The safe and reliable operation of electric generation and electric and natural gas transmission and
distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks
inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric
generation, transmission and distribution operations can be impacted by risks such as mechanical
failures, supply chain issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, human error, damage to facilities, and infrastructure caused by hurricanes,
storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline
operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third
parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by
hurricanes, storms, floods, fires and other natural disasters. Electric utility and natural gas transmission
and distribution pipeline operation interruption could negatively affect customer and public confidence,
and public safety and have a Material Adverse Effect.
Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all these losses,
which could have a Material Adverse Effect.
 
Uninsured Risk
Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to
provide indemnity in the event of liability to third parties. A significant portion of Emera’s electric utilities’
transmission and distribution assets and its gas utilities’ distribution assets are not insured, as is
customary in the industry, as the cost of coverage is prohibitive. In addition, Emera accepts deductibles
and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as
well as time sensitive claims discovery and reporting provisions and there can be no assurance that the
types of liabilities or losses that may be incurred will be covered by insurance.
The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits, or
claims that fall within a significant self-insured retention could have a Material Adverse Effect, if regulatory
recovery is not available.
54
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
 
The Company manages exposure to normal operating and market risks relating to commodity prices, FX,
interest rates and share prices through contractual protections with counterparties where practicable, and
by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as HFT. Collectively,
 
these contracts and financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption if the criteria are no longer met.
 
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in
income in the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at FV with any changes in FV value recognized
in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Management believes any gains or losses resulting
from settlement of these derivatives related to fuel for generation and purchased power will be refunded
to or collected from customers in future rates. TEC and PGS have no derivatives related to hedging.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55
Derivative Assets and Liabilities Recognized on the Balance Sheet
As at
December 31
December 31
millions of dollars
2024
2023
Regulatory Deferral:
Derivative instrument assets
(1)
$
 
45
$
 
16
Derivative instrument liabilities
(2)
 
(40)
 
(76)
Regulatory assets
(1)
 
53
 
88
Regulatory liabilities
 
(2)
 
(44)
 
(17)
Net asset
$
 
14
$
 
11
HFT Derivatives:
 
Derivative instrument assets
 
(1)
$
 
122
$
 
202
Derivatives instruments liabilities
(2)
 
(542)
 
(421)
Net liability
$
 
(420)
$
 
(219)
Other Derivatives:
Derivative instrument assets
(1)
$
 
-
 
$
 
22
Derivatives instruments liabilities
 
(2)
 
(36)
 
(7)
Net asset (liability)
$
 
(36)
$
 
15
(1) Current, other and assets held for sale.
(2) Current, long-term and liabilities associated with assets held for sale.
Realized and Unrealized Gains (Losses) Recognized in Net Income
For the
Year ended December 31
millions of dollars
2024
2023
Regulatory Deferral:
Regulated fuel for generation and purchased power
(1)
$
 
(44)
$
 
62
HFT Derivatives:
Non-regulated operating revenues
$
 
207
$
 
1,037
Other Derivatives:
OM&G
$
 
14
$
 
(9)
Other income, net
 
(56)
 
17
Net gains (losses)
$
 
(42)
$
 
8
Total net gains
$
 
121
$
 
1,107
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have
 
been
terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized
 
in
“Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of December 31, 2024, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2023 –
$14 million, after-tax). For the year ended December 31, 2024, unrealized gains of $2 million (2023 – $2
million) have been reclassified from AOCI into interest expense.
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and
procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on criteria published in the Internal Control Integrated
Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the
Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer,
evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2024 to
provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed.
Control systems determined to be appropriately designed can only provide reasonable assurance with
respect to the reliability of financial reporting and may not prevent or detect all misstatements.
56
There were no changes in the Company’s ICFR, during the year ended December 31, 2024, that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Rate Regulation
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity
investments are subject to examination and approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies. Differences occur when regulators render their
decisions on rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is based on expectations of the future actions of
the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on
recovery of costs, rates earned on invested capital, and the timing and amount of assets to be recovered.
Application of regulatory accounting guidance is a critical accounting policy as a change in these
assumptions may result in a material impact on reported assets, liabilities and the results of operations.
As at December 31, 2024, the Company had recorded $3,427 million (2023 – $3,105 million) of regulatory
assets and $1,880 million (2023 – $1,772 million) of regulatory liabilities.
Accumulated Reserve – Cost of Removal
TEC, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The
non-ARO COR represent estimated funds received from customers through depreciation rates to cover
future COR of PP&E upon retirement that are not legally required. The companies accrue for COR over
the life of the related assets based on depreciation studies approved by their respective regulators. Costs
are estimated based on historical experience and future expectations, including expected timing and
estimated future cash outlays. As at December 31, 2024, the balance of the Accumulated reserve – COR
within regulatory liabilities was $733 million (2023 – $849 million).
Pension and Other Post-Retirement Employee Benefits
The Company provides post-retirement benefits to employees, including defined benefit pension plans.
The cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future expectations.
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by employee demographics - including age, compensation
levels, employment periods, contribution levels and earnings - could have a material impact on reported
assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in
determining the accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s annual earnings and cash requirements.
 
 
 
 
 
 
 
 
 
 
57
Pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in
actual equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of
the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan members’ average remaining service period. For
the largest plans this is currently 8.2 years (8.4 years for 2024 benefit cost) for Canadian plans and a
weighted average of 11.6 years for US plans. The Company’s use of smoothed asset values reduces
volatility related to amortization of actuarial investment experience. As a result, the main cause of volatility
in reported pension cost is the discount rate used to determine the PBO.
 
The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate
bonds in each operating entity’s country and is determined with reference to bonds which have the same
duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for
benefit cost purposes and the expected return on plan assets for each plan:
2024
2023
Discount rate for
benefit cost
purposes
Expected
return on
 
plan assets
Discount rate for
benefit cost
 
purposes
Expected
 
return on
 
plan assets
TECO Holdings Group Retirement Plan
5.27%
7.05%
5.55%
7.05%
TECO Holdings Group Supplemental
Executive Retirement Plan
(1)
5.15%
N/A
5.45%/5.31%
N/A
TECO Holdings Group Benefit
Restoration Plan (1)
5.18%
N/A
5.48/5.30/5.49%
N/A
TECO Holdings Post-retirement Health
and Welfare Plan
5.28%
N/A
5.53%/6.14%
N/A
NMGC Retiree Medical Plan
5.28%
4.25%
5.55%
2.50%
NSPI
 
4.63%, 4.62%
6.00%
5.17%, 5.19%
6.25%
GBPC Salaried
5.75%
 
6.00%
5.75%
 
6.00%
GBPC Union
5.75%
 
5.35%
5.75%
 
5.35%
(1) The discount rate for benefit cost purposes is updated throughout the year as special events occur,
 
such as settlements and
curtailments
Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution
plans was $56 million in 2024 (2023 – $43 million). The reported benefit cost is impacted by numerous
assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the
discount rate and asset return assumptions would have had +/- impact on the 2024 benefit cost of $0.5
million and $3.0 million, respectively (2023 – $0.5 million and $2.5 million).
 
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end of each month, the Company must make an
estimate of energy delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including
current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in
determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2024,
unbilled revenues totalled $342 million (2023 – $363 million) on total regulated operating revenues of
$7,447 million (2023 – $7,235 million).
58
PP&E
PP&E represents 61 per cent of total assets on the Company’s balance sheet and includes generation,
transmission and distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
depreciable assets in each category. The service lives of regulated PP&E are determined based on
depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $1,135 million for the year ended December 31, 2024 (2023 – $1,019 million).
Goodwill Impairment Assessments
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of
identifiable assets acquired, and liabilities assumed at the acquisition date.
 
Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting unit may be below its carrying value.
Application of the goodwill impairment test requires management judgment on significant assumptions
and estimates. When assessing goodwill for impairment, the Company has the option of first performing a
qualitative assessment to determine whether a quantitative assessment is necessary. In performing a
qualitative assessment, management considers, among other factors, macroeconomic conditions,
industry and market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss
is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and
growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net
operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these
assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting
units.
As of December 31, 2024, Emera’s goodwill represents the excess of the acquisition purchase price for
TECO Energy, Inc. (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets
acquired and liabilities assumed. In Q3 2024, Emera entered into an agreement to sell NMGC. As a
result, a quantitative goodwill impairment assessment was performed on the NMGC reporting unit and the
Company recorded a goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million
USD ($146 million USD, after-tax). The reduced NMGC goodwill balance of $303 million is included in the
NMGC disposal unit classified as held for sale. For further details, refer to note 23 in the consolidated
financial statements.
In Q4 2024, a qualitative assessment was performed for TEC, given the significant excess of FV over
carrying amounts calculated during the last quantitative test in Q4 2023. Management concluded it was
more likely than not that the FV of this reporting unit exceeded its carrying amount, including goodwill. As
such, no quantitative testing was required. Given the length of time passed since the last quantitative
impairment test for the PGS reporting unit, Emera elected to bypass a qualitative assessment and
performed a quantitative impairment assessment in Q4 2024 using a combination of the income and
market approach. This assessment estimated that the FV of the PGS reporting unit exceeded its carrying
amount, including goodwill, and as a result no impairment charges were recognized.
59
As of December 31, 2024, the Company had goodwill with a total carrying amount of $5,858 million
(December 31, 2023 – $5,871 million). The change in the carrying value of goodwill from 2023 to 2024
was primarily a result of the impairment of the goodwill assigned to the NMGC reporting unit and NMGC
goodwill included in disposal units classified as held for sale, partially offset by the effect of the FX
translation of Emera’s foreign affiliates.
Long-Lived Assets Impairment Assessments
The Company assesses whether there has been an impairment of long-lived assets and intangibles when
a triggering event occurs, such as a significant market disruption or the sale of a business. The
assessment involves comparing undiscounted expected future cash flows, to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-
lived asset over its estimated FV.
The Company believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment on reported assets and earnings could
be material. Management is required to make assumptions based on expectations regarding results of
operations for significant/indefinite future periods and current and expected market conditions in such
periods. Markets can experience significant uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other recoverable amounts are based on a
combination of historical experience, fundamental economic analysis, observable market activity and
independent market studies. The Company’s expectations regarding uses and holding periods of assets
are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
In 2024, impairment charges of $19 million ($14 million after-tax) were recognized on certain assets, $8
million of which was included in “Other income, net” with $11 million included in “Impairment Charges” on
the Consolidated Income Statement. No impairment charges related to long-lived assets were recognized
in 2023.
Income Taxes
 
Income taxes are determined based on expected tax treatment of transactions recorded in the
consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred income tax assets will be recovered from future taxable income is
assessed, and assumptions are made about expected timing of reversal of deferred income tax assets
and liabilities. Uncertainty associated with application of tax statutes and regulations and outcomes of tax
audits and appeals, requires that judgments and estimates be made in the accrual process and in
calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold
may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and
changes are recorded based on new information, including issuance of relevant guidance by the courts or
tax authorities and developments occurring in examinations of the Company’s tax returns.
The Company believes accounting estimates related to income taxes are critical estimates. Realization of
deferred income tax assets depends on the generation of sufficient taxable income, both operating and
capital, in future periods. A change in estimated valuation allowance could have a material impact on
reported assets and results of operations. Administrative actions of tax authorities, changes in tax law or
regulation, and uncertainty associated with the application of tax statutes and regulations, could change
the Company’s estimate of income taxes, including the potential for elimination or reduction of the
Company’s ability to realize tax benefits and to utilize deferred income tax assets.
 
60
Asset Retirement Obligations
Measurement of the FV of AROs requires the Company to make reasonable estimates concerning the
method and timing of settlement associated with legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential events, such as changing legislation or
regulations, and advances in remediation technologies. Emera has AROs associated with remediation of
generation, transmission, distribution and pipeline assets.
 
An ARO represents the FV of estimated cash flows necessary to discharge the future obligation using the
Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed depreciation studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of
“Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is
recorded in “PP&E” and included in the next depreciation study. Accordingly,
 
changes to the ARO or cost
recognition attributable to changes in the factors discussed above, should not impact the results of
operations of the Company.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not
recognized in the consolidated financial statements as the FV of these obligations could not be
reasonably estimated given insufficient information to do so. A conditional ARO refers to a legal obligation
to perform an asset retirement activity in which the timing and/or method of settlement are conditional on
a future event that may or may not be within the control of the entity. Management monitors these
obligations and a liability is recognized at FV when an amount can be determined.
As at December 31, 2024, AROs recorded on the balance sheet were $217 million (2023 – $192 million).
The Company estimates the undiscounted amount of cash flow required to settle the obligations is
approximately $453 million (2023 – $426 million), which will be incurred between 2025 and 2061. The
majority of these costs will be incurred between 2028 and 2050.
Financial Instruments
The Company is required to determine the FV of all derivatives except those that qualify for the NPNS
exception. FV is the price that would be received for the sale of an asset or paid to transfer a liability in an
orderly arms-length transaction between market participants at the measurement date. FV measurements
are required to reflect assumptions that market participants would use in pricing an asset or liability based
on the best available information, including the risks inherent in a particular valuation technique, such as
a pricing model, and the risks inherent in the inputs to the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the FV hierarchy. The FV measurement of a
financial instrument is included in only one of the three levels and is based on the lowest level input
significant to the derivation of the FV. FV is determined, directly or indirectly,
 
using inputs that are
observable for the asset or liability. Only in limited circumstances does the Company enter into
commodity transactions involving non-standard features where market observable data is not available or
have contract terms that extend beyond five years.
61
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2024, is
described as follows:
 
Improvements to Reportable Segment Disclosures
The Company adopted Accounting Standard Update (“ASU”) 2023-07, Segment Reporting (Topic 280),
Improvements to Reportable Segment Disclosures. The change in the standard improves reportable
segment disclosure requirements, primarily through enhanced disclosures about significant segment
expenses. The changes improve financial reporting by requiring disclosure of incremental segment
information on an annual and interim basis for all public entities to enable investors to develop more
decision-useful financial analyses. The guidance was effective for annual reporting periods beginning
after December 15, 2023, and for interim periods beginning after December 15, 2024. Adoption of the
standard resulted in additional qualitative disclosures provided in note 5.
Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have
not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be
either not applicable to the Company or to have an insignificant impact on the consolidated financial
statements.
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive
 
Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement
 
Expenses. The standard update improves the disclosures about a public business entity’s expenses by
 
requiring more detailed information about the types of expenses (including purchases of inventory,
 
employee compensation, depreciation and amortization) included within income statement expense
 
captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026,
 
and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The
standard updates are to be applied prospectively with the option for retrospective application. The
 
Company is currently evaluating the impact of adoption of the standard update on its consolidated
 
financial statements disclosures.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes
 
(Topic
 
740): Improvements to Income
Tax
 
Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of
income tax disclosures by requiring consistent categories and greater disaggregation of information in the
reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income
tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)
by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes
and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:
Income Tax
 
Expense, and the removal of disclosures no longer considered cost beneficial or relevant.
The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early
adoption is permitted. The standard will be applied on a prospective basis, with retrospective application
permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated
financial statements disclosures.
 
 
 
 
 
 
 
 
 
 
 
62
SUMMARY OF QUARTERLY
 
RESULTS
For the quarter ended
millions of dollars
 
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
(except per share amounts)
2024
2024
2024
2024
2023
2023
2023
2023
Operating revenues
$
 
1,763
$
 
1,802
$
 
1,617
$
 
2,018
$
 
1,972
$
 
1,740
$
 
1,418
$
 
2,433
Net income attributable to common
shareholders
$
 
154
$
 
4
$
 
129
$
 
207
$
 
289
$
 
101
$
 
28
$
 
560
EPS – basic
$
0.52
$
 
0.01
$
 
0.45
$
 
0.73
$
 
1.04
$
 
0.37
$
 
0.10
$
 
2.07
EPS – diluted
$
0.52
$
 
0.01
$
 
0.45
$
 
0.73
$
 
1.04
$
 
0.37
$
 
0.10
$
 
2.07
Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter
provides strong earnings contributions due to a significant portion of the Company’s operations being in
northeastern North America, where winter is the peak electricity usage season. The third quarter provides
strong earnings contributions due to summer being the heaviest electric consumption season in Florida.
Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand
for energy and the cost of service. Quarterly results could also be affected by items outlined in the
“Significant Items Affecting Earnings” section. Quarter-over-quarter variances are discussed further
below.
Q4 2024 compared to Q4 2023
For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.
Q3 2024 compared to Q3 2023
Q3 2024 net income attributable to common shareholders decreased by $97 million and EPS – basic and
diluted decreased by $0.36 compared to Q3 2023. The decreases were primarily due to charges related
to the pending sale of NMGC; decreased earnings at Emera Energy; lower equity earnings from LIL;
lower Corporate income tax recovery due to decreased losses before provision for income taxes;
increased Corporate interest expense due to increased interest rates and increased total debt; and
increased Corporate preferred share dividends. These changes were partially offset by decreased MTM
losses; increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing
difference in the valuation of long-term incentive expense and related hedges. The change in EPS was
also impacted by an increase in weighted average shares outstanding.
Q2 2024 compared to Q2 2023
Q2 2024 net income attributable to common shareholders increased by $101 million and EPS – basic and
diluted increased by $0.35 compared to Q2 2023. The increases were primarily due to the gain on sale of
LIL, after transaction costs; increased earnings at PGS and TEC; increased Corporate income tax
recovery due to increased losses before provision for income taxes; and decreased MTM losses. These
changes were partially offset by decreased earnings at NMGC and NSPI; higher Corporate interest
expense due to increased interest rates and increased total average debt; and FX losses on the
translation of USD short-term debt balances in Corporate. The change in EPS was also impacted by an
increase in weighted average shares outstanding.
Q1 2024 compared to Q1 2023
Q1 2024 net income attributable to common shareholders decreased by $353 million and EPS – basic
and diluted decreased by $1.34 compared to Q1 2023. The decreases were primarily due to increased
MTM losses; lower earnings at TEC, NMGC, NSPI and EES; increased Corporate OM&G due to the
timing difference in the valuation of long-term incentive expense and related hedges; and increased
Corporate interest expense due to increased total debt. These changes were partially offset by higher
earnings at PGS and NSPML; and higher income tax recovery at Corporate. The change in EPS was also
impacted by an increase in weighted average shares outstanding.
EX-99.3
1.2 25.5 25 25 25.5 http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet August 15, 2025 August 15, 2028 February 15, 2025 August 15, 2025 August 15, 2028 five P3Y P3Y P3Y P3Y
Exhibit 99.3
1
EMERA INCORPORATED
Consolidated
Financial Statements
December 31,
2024
 
and 2023
2
MANAGEMENT REPORT
Management's Responsibility for Financial Reporting
The accompanying consolidated financial statements of Emera
 
Incorporated and the information in this
annual report are the responsibility of management and have
 
been approved by the Board of Directors
(“Board”).
The consolidated financial statements have been prepared
 
by management in accordance with United
States Generally Accepted Accounting Principles. When alternative
 
accounting methods exist,
management has chosen those it considers most appropriate
 
in the circumstances. In preparation of
these consolidated financial statements, estimates are sometimes
 
necessary when transactions affecting
the current accounting period cannot be finalized with
 
certainty until future periods. Management
represents that such estimates, which have been properly reflected
 
in the accompanying consolidated
financial statements, are based on careful judgments and
 
are within reasonable limits of materiality.
Management has determined such amounts on a reasonable
 
basis in order to ensure that the
consolidated financial statements are presented fairly in
 
all material respects. Management has prepared
the financial information presented elsewhere in the annual report
 
and has ensured that it is consistent
with that in the consolidated financial statements.
Emera Incorporated maintains effective systems
 
of internal accounting and administrative controls,
consistent with reasonable cost. Such systems are designed to
 
provide reasonable assurance that the
financial information is reliable and accurate, and that
 
Emera Incorporated's assets are appropriately
accounted for and adequately safeguarded.
 
The Board is responsible for ensuring that management
 
fulfils its responsibilities for financial reporting
and is ultimately responsible for reviewing and approving
 
the consolidated financial statements. The
Board carries out this responsibility principally through its
 
Audit Committee.
The Audit Committee is appointed by the Board, and its
 
members are directors who are not officers or
employees of Emera Incorporated. The Audit Committee meets
 
periodically with management, as well as
with the internal auditors and with the external auditors, to discuss
 
internal controls over the financial
reporting process, auditing matters and financial reporting
 
issues, to satisfy itself that each party is
properly discharging its responsibilities, and to review the annual
 
report, the consolidated financial
statements and the external auditors' report. The Audit
 
Committee reports its findings to the Board for
consideration when approving the consolidated financial statements
 
for issuance to the shareholders.
 
The Audit Committee also considers, for review by the Board
 
and approval by the shareholders, the
appointment of the external auditors.
 
The consolidated financial statements have been audited
 
by Ernst & Young
 
LLP,
 
the external auditors, in
accordance with Canadian Generally Accepted Auditing Standards
 
and with the standards of the Public
Company Accounting Oversight Board. Ernst & Young
 
LLP has full and free access to the Audit
Committee.
February 21, 2025
“Scott Balfour”
“Gregory Blunden”
President and Chief Executive Officer
 
President and Chief Executive Officer
 
Chief Financial Officer
 
3
Report of Independent Registered Public Accounting Firm
To
the Shareholders and the Board of Directors of Emera
 
Incorporated
Opinion on the Consolidated Financial Statements
 
We have audited the accompanying Consolidated
 
Balance Sheets of Emera Incorporated (the
“Company“) as of December 31, 2024 and 2023, the related Consolidated
 
Statements of Income,
Consolidated Statements of Comprehensive Income,
 
Consolidated Statements of Changes in Equity and
Consolidated Statements of Cash Flows for the years
 
then ended, and the related notes (collectively
referred to as the “consolidated financial statements“).
 
In our opinion, the consolidated financial
statements present fairly,
 
in all material respects, the consolidated financial position
 
of the Company as of
December 31, 2024 and 2023, and the consolidated results
 
of its operations and its consolidated cash
flows for each of the two years in the period ended December
 
31, 2024, in conformity with United States
generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility
 
of the Company‘s management. Our
responsibility is to express an opinion on the Company‘s
 
consolidated financial statements based on our
audits. We are a public accounting firm registered
 
with the Public Company Accounting Oversight Board
(United States) (“PCAOB”) and are required to be independent
 
with respect to the Company in
accordance with the U.S. federal securities laws and the
 
applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
 
We conducted our audits in accordance with
 
the standards of the PCAOB. Those standards require
 
that
we plan and perform the audits to obtain reasonable
 
assurance about whether the consolidated financial
statements are free of material misstatement, whether
 
due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its
 
internal control over financial reporting. As part
of our audits we are required to obtain an understanding
 
of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness
 
of the Company's internal control over
financial reporting. Accordingly,
 
we express no such opinion.
 
Our audits included performing procedures to assess
 
the risks of material misstatement of the
consolidated financial statements, whether due to error
 
or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test
 
basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our
 
audits also included evaluating the accounting
principles used and significant estimates made by management,
 
as well as evaluating the overall
presentation of the consolidated financial statements. We
 
believe that our audits provide a reasonable
basis for our opinion.
 
Critical Audit Matters
The critical audit matters communicated below are matters
 
arising from the current period audit of the
financial statements that were communicated or required
 
to be communicated to the audit committee and
that: (1) relate to accounts or disclosures that are material
 
to the financial statements and (2) involved our
especially challenging, subjective or complex judgments.
 
The communication of critical audit matters
does not alter in any way our opinion on the consolidated financial
 
statements, taken as a whole, and we
are not, by communicating the critical audit matters
 
below, providing separate opinions
 
on the critical
audit matters or on the accounts or disclosures to which
 
they relate.
4
Accounting for the effects of rate regulation
Description
of the Matter
As disclosed in note 7 of the consolidated financial statements,
 
the Company has $3.4
billion in regulatory assets and $1.9 billion in regulatory
 
liabilities. The Company’s rate-
regulated subsidiaries are subject to regulation by various
 
federal, state and provincial
regulatory authorities in the geographic regions in which
 
they operate. The regulatory
rates are designed to recover the prudently incurred costs
 
of providing the regulated
products or services and provide a reasonable return on
 
the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities,
 
rate regulation impacts multiple
financial statement line items, including, but not limited to,
 
property, plant
 
and equipment
(“PP&E”), operating revenues and expenses, income taxes,
 
and depreciation expense.
Auditing the impact of rate regulation on the Company’s
 
financial statements is complex
and highly judgmental due to the significant judgments
 
made by the Company to support
its accounting and disclosure for regulatory matters when
 
final regulatory decisions or
orders have not yet been obtained or when regulatory
 
formulas are complex. There is
also subjectivity involved in assessing the potential
 
impact of future regulatory decisions
on the financial statements. Although the Company
 
expects to recover costs from
customers through rates, there is a risk that the regulator
 
will not approve full recovery of
the costs incurred. The Company’s judgments
 
include making an assessment of the
probability of recovery of and return on costs incurred, of the
 
potential disallowance of
part of the cost incurred, or of the probable refund of
 
gains or amounts previously
collected from customers through future rates.
How We
Addressed
the Matter in
Our Audit
We performed audit procedures that included,
 
amongst others, assessing the Company’s
evaluation of the probability of future recovery for regulatory
 
assets, PP&E, and refund of
regulatory liabilities by obtaining and reviewing relevant
 
regulatory orders, filings,
testimony, hearings
 
and correspondence, and other publicly available
 
information. For
regulatory matters for which regulatory decisions or orders
 
have not yet been obtained,
we inspected the rate-regulated subsidiaries’ filings for
 
any evidence that might contradict
the Company’s assertions, and reviewed other regulatory
 
orders, filings and
correspondence for other entities within the same or similar
 
jurisdictions to assess the
likelihood of recovery or refund in future rates based on
 
the regulator’s treatment of
similar costs under similar circumstances. We obtained
 
and evaluated an analysis from
the Company and corroborated that analysis with letters
 
from legal counsel, when
appropriate, regarding cost recoveries, gains or amounts
 
previously collected from
customers or future changes in rates. We also assessed
 
the methodology,
 
accuracy and
completeness of the Company’s calculations of regulatory
 
asset and liability balances
based on provisions and formulas outlined in rate orders
 
and other correspondence with
the regulators. We evaluated the Company's
 
disclosures related to the impacts of rate
regulation.
Fair Value (“FV”) measurement of derivative
 
financial instruments
Description
of the Matter
Held-for-trading (“HFT”) derivative assets of $270 million
 
and liabilities of $690 million,
disclosed in note 16 to the consolidated financial statements,
 
are measured at FV.
 
The
Company recognized $207 million in realized and unrealized
 
gains during the year with
respect to HFT derivatives.
Auditing the Company’s valuation of HFT derivatives
 
is complex and highly judgmental
due to the complexity of the contract terms and valuation models,
 
and the significant
estimation required in determining the FV of the contracts.
 
In determining the FV of HFT
derivatives, significant assumptions about future economic
 
and market assumptions with
uncertain outcomes are used, including third-party sourced
 
forward commodity pricing
curves based on illiquid markets, internally developed correlation
 
factors and basis
differentials. These assumptions have a significant
 
impact on the FV of the HFT
derivatives.
 
5
How We
Addressed
the Matter in
Our Audit
We performed audit procedures that included,
 
amongst others, reviewing executed
contracts and agreements for the identification of inputs
 
and assumptions impacting the
valuation of derivatives. With the support of our valuation
 
specialists, we assessed the
methodology and mathematical accuracy of the Company’s
 
valuation models and
compared the commodity pricing curves used by the Company
 
to current market and
economic data. For the forward commodity pricing curves,
 
we compared the Company’s
pricing curves to independently sourced pricing curves.
 
We also assessed the
methodology and mathematical accuracy of the Company’s
 
calculations to develop
correlation factors and basis differentials. In
 
addition, we assessed whether the FV
hierarchy disclosures in note 17 to the consolidated financial
 
statements were consistent
with the source of the significant inputs and assumptions
 
used in determining the FV of
derivatives.
 
/s/
Ernst & Young LLP
Chartered Professional Accountants
We have served as the Company‘s auditor since
 
1998.
Halifax, Canada
February 21, 2025
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
Emera Incorporated
Consolidated Statements of Income
 
For the
Year ended December 31
millions of dollars (except per share amounts)
2024
2023
Operating revenues
 
Regulated electric
$
 
5,872
$
 
5,746
 
Regulated gas
 
1,575
 
1,489
 
Non-regulated
(247)
 
328
 
Total
 
operating revenues (note 6)
 
7,200
 
7,563
Operating expenses
 
Regulated fuel for generation and purchased power
 
1,992
 
1,881
 
Regulated cost of natural gas
 
396
 
527
 
Operating, maintenance and general expenses ("OM&G")
 
1,918
 
1,879
 
Provincial, state, and municipal taxes
 
 
427
 
433
 
Depreciation and amortization
 
1,162
 
1,049
 
Impairment charges (note 23)
 
225
-
 
 
Total
 
operating expenses
 
6,120
 
5,769
Income from operations
 
1,080
 
1,794
Income from equity investments (note 8)
 
99
 
146
Other income, net (note 9)
 
203
 
158
Interest expense, net (note 10)
 
973
 
925
Income before provision for income taxes
 
409
 
1,173
Income tax (recovery) expense (note 11)
(159)
 
128
Net income
 
 
568
 
1,045
Non-controlling interest in subsidiaries ("NCI")
 
1
 
1
Preferred stock dividends
 
73
 
66
Net income attributable to common shareholders
$
 
494
$
 
978
Weighted average shares of common stock outstanding (in millions) (note 13)
 
Basic
 
289
 
274
 
Diluted
 
289
 
274
Earnings per common share (note 13)
 
Basic
$
 
1.71
$
 
3.57
 
Diluted
$
 
1.71
$
 
3.57
Dividends per common share declared
$
 
2.8775
$
 
2.7875
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7
Emera Incorporated
Consolidated Statements of Comprehensive Income
 
For the
Year ended December 31
millions of dollars
2024
2023
Net income
 
$
 
568
$
 
1,045
Other comprehensive income (loss) ("OCI"), net of tax
Foreign currency translation adjustment
(1)
 
1,027
(270)
Unrealized (losses) gains on net investment hedges
(2)
(139)
 
38
Cash flow hedges – reclassification adjustment for gains included in income
(2)
(2)
Unrealized gains on available-for-sale investment
 
2
-
 
Net change in unrecognized pension and post-retirement benefit obligation
(3)
 
 
68
(39)
OCI
(4)
 
 
956
(273)
Comprehensive income
 
1,524
 
772
Comprehensive income attributable to NCI
 
1
 
1
Comprehensive Income of Emera Incorporated
$
 
1,523
$
 
771
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax expense of $
10
 
million for the year ended December 31, 2024 (2023
 
– $
7
 
million recovery).
2) The Company has designated $
1.2
 
billion United States dollar (USD) denominated
 
Hybrid Notes as a hedge of the foreign
currency exposure of its net investment in USD
 
denominated operations.
 
3) Net of tax expense of
nil
 
for the year ended December 31, 2024 (2023 – $
1
 
million expense).
4) Net of tax expense of $
10
 
million for the year ended December 31, 2024 (2023
 
– $
6
 
million recovery).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of dollars
2024
2023
Assets
Current assets
 
Cash and cash equivalents
$
 
196
$
 
567
 
Restricted cash
 
 
17
 
21
 
Inventory (note 15)
 
781
 
790
 
Derivative instruments (notes 16 and 17)
 
115
 
174
 
Regulatory assets (note 7)
 
595
 
339
 
Receivables and other current assets (note 19)
 
1,811
 
1,817
 
Assets held for sale (note 4)
 
173
-
 
 
3,688
 
3,708
Property, plant and equipment ("PP&E"),
net of accumulated depreciation
and amortization of $
10,442
 
and $
9,994
, respectively (note 21)
 
26,168
 
24,376
Other assets
 
Deferred income taxes (note 11)
 
392
 
208
 
Derivative instruments (notes 16 and 17)
 
51
 
66
 
Regulatory assets (note 7)
 
2,832
 
2,766
 
Net investment in direct finance and sales type leases (note 20)
 
610
 
621
 
Investments subject to significant influence (note 8)
 
654
 
1,402
 
Goodwill (note 23)
 
5,858
 
5,871
 
Other long-term assets (note 33)
 
538
 
462
 
Assets held for sale (note 4)
 
2,160
-
 
 
13,095
 
11,396
Total assets
$
 
42,951
$
 
39,480
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
Emera Incorporated
Consolidated Balance Sheets – Continued
As at
 
December 31
December 31
millions of dollars
2024
2023
Liabilities and Equity
Current liabilities
 
Short-term debt (note 24)
$
 
1,400
$
 
1,433
 
Current portion of long-term debt (note 26)
 
234
 
676
 
Accounts payable
 
 
1,992
 
1,454
 
Derivative instruments (notes 16 and 17)
 
526
 
386
 
Regulatory liabilities (note 7)
 
262
 
168
 
Other current liabilities (note 25)
 
489
 
427
 
Liabilities associated with assets held for sale (note 4)
 
212
-
 
 
5,115
 
4,544
Long-term liabilities
 
Long-term debt (note 26)
 
18,173
 
17,689
 
Deferred income taxes (note 11)
 
2,331
 
2,352
 
Derivative instruments (notes 16 and 17)
 
91
 
118
 
Regulatory liabilities (note 7)
 
1,618
 
1,604
 
Pension and post-retirement liabilities (note 22)
 
274
 
265
 
Other long-term liabilities (note 8 and 27)
 
910
 
820
 
Liabilities associated with assets held for sale (note 4)
 
1,148
-
 
 
24,545
 
22,848
Equity
 
Common stock (note 12)
 
9,042
 
8,462
 
Cumulative preferred stock (note 29)
 
1,422
 
1,422
 
Contributed surplus
 
84
 
82
 
Accumulated other comprehensive income ("AOCI') (note 14)
 
1,261
 
305
 
Retained earnings
 
 
1,468
 
1,803
 
Total
 
Emera Incorporated equity
 
13,277
 
12,074
 
NCI (note 30)
 
14
 
14
 
Total
 
equity
 
13,291
 
12,088
Total liabilities and equity
$
 
42,951
$
 
39,480
Commitments and contingencies
(note 28)
nil
nil
The accompanying notes are an integral part of these consolidated financial statements.
Approved on behalf of the Board of Directors
“Karen Sheriff”
 
“Scott Balfour”
Chair of the Board
 
President and Chief Executive Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
Emera Incorporated
Consolidated Statements of Cash Flows
For the
Year ended December 31
millions of dollars
2024
2023
Operating activities
Net income
 
$
 
568
$
 
1,045
Adjustments to reconcile net income to net cash provided by operating activities:
 
Depreciation and amortization
 
1,165
 
1,060
 
Income from equity investments, net of dividends
(8)
(22)
 
Allowance for funds used during construction ("AFUDC") – equity
(53)
(38)
 
Deferred income taxes, net
(191)
 
97
 
Net change in pension and post-retirement liabilities
(46)
(68)
 
NSPI fuel adjustment mechanism ("FAM")
 
451
(88)
 
Net change in fair value ("FV") of derivative instruments
 
228
(666)
 
Net change in regulatory assets and liabilities
 
(226)
 
554
 
Net change in capitalized transportation capacity
 
175
 
434
 
Goodwill impairment charge
 
214
-
 
 
Gain on sale of LIL, excluding transaction costs
(191)
-
 
 
Other operating activities, net
 
108
 
28
Changes in non-cash working capital (note 31)
 
452
(95)
Net cash provided by operating activities
 
2,646
 
2,241
Investing activities
 
Additions to PP&E
(3,151)
(2,937)
 
Proceeds from disposal of investment subject to significant influence
 
927
-
 
 
Other investing activities
 
6
 
20
Net cash used in investing activities
(2,218)
(2,917)
Financing activities
 
Change in short-term debt, net
 
56
(66)
 
Proceeds from short-term debt with maturities greater than 90 days
-
 
 
548
 
Repayment of short-term debt with maturities greater than 90 days
-
 
(1,086)
 
Proceeds from long-term debt, net of issuance costs
 
1,361
 
1,932
 
Retirement of long-term debt
(1,086)
(151)
 
Net repayments under committed credit facilities
(825)
(96)
 
Issuance of common stock, net of issuance costs
 
284
 
424
 
Dividends on common stock
(538)
(488)
 
Dividends on preferred stock
(73)
(66)
 
Other financing activities
 
 
3
(12)
Net cash (used in) provided by financing activities
(818)
 
939
Effect of exchange rate changes on cash, cash equivalents, restricted cash and
cash associated with assets held for sale
 
23
(7)
Net (decrease) increase in cash, cash equivalents, restricted cash and cash
associated with assets held for sale
(367)
 
256
Cash, cash equivalents, and restricted cash, beginning of year
 
588
 
332
Cash, cash equivalents, restricted cash, and cash associated with assets held for
sale, end of year
$
 
221
$
 
588
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
-
 
Cash, cash equivalents, restricted cash and cash associated with assets held for
sale
$
 
221
$
 
588
Supplementary Information to Consolidated Statements of Cash Flows (note 31)
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
Emera Incorporated
Consolidated Statements of Changes in Equity
Common
Preferred
Contributed
Retained
Total
 
Stock
Stock
Surplus
AOCI
Earnings
NCI
Equity
millions of dollars
Balance, December 31, 2023
$
 
8,462
$
 
1,422
$
 
82
$
 
305
$
 
1,803
$
 
14
$
 
12,088
Net income of Emera Inc.
-
 
-
 
-
 
-
 
 
567
 
1
 
568
Other comprehensive income, net of
tax expense of $
10
 
million
-
 
-
 
-
 
 
956
-
 
-
 
 
956
Dividends declared on preferred stock
(note 29)
-
 
-
 
-
 
-
 
(73)
-
 
(73)
Dividends declared on common stock
($
2.8775
/share)
-
 
-
 
-
 
-
 
(829)
-
 
(829)
Issued under the at-the-market
program ("ATM"), net of after-tax
issuance costs
 
261
-
 
-
 
-
 
-
 
-
 
 
261
Issued under the Dividend
Reinvestment Program ("DRIP"), net of
discount
 
291
-
 
-
 
-
 
-
 
-
 
 
291
Senior management stock options
exercised and Employee Common
Share Purchase Plan ("ECSPP")
 
28
-
 
 
2
-
 
-
 
-
 
 
30
Other
-
 
-
 
-
 
-
 
-
 
(1)
(1)
Balance, December 31, 2024
$
 
9,042
$
 
1,422
$
 
84
$
 
1,261
$
 
1,468
$
 
14
$
 
13,291
Balance, December 31, 2022
$
 
7,762
$
 
1,422
$
 
81
$
 
578
$
 
1,584
$
 
14
$
 
11,441
Net income of Emera Inc.
-
 
-
 
-
 
-
 
 
1,044
 
1
 
1,045
Other comprehensive loss, net of tax
recovery of $
6
 
million
-
 
-
 
-
 
(273)
-
 
-
 
(273)
Dividends declared on preferred stock
(note 29)
-
 
-
 
-
 
-
 
(66)
-
 
(66)
Dividends declared on common stock
($
2.7875
/share)
-
 
-
 
-
 
-
 
(759)
-
 
(759)
Issued under the ATM, net of after-tax
issuance costs
 
397
-
 
-
 
-
 
-
 
-
 
 
397
Issued under the DRIP, net of discount
 
272
-
 
-
 
-
 
-
 
-
 
 
272
Senior management stock options
exercised and ECSPP
 
31
-
 
 
1
-
 
-
 
-
 
 
32
Other
-
 
-
 
-
 
-
 
-
 
(1)
(1)
Balance, December 31, 2023
$
 
8,462
$
 
1,422
$
 
82
$
 
305
$
 
1,803
$
 
14
$
 
12,088
The accompanying notes are an integral part of these consolidated financial statements.
12
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2024 and 2023
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an
 
energy and services company that invests in
electricity generation, transmission and distribution, and
 
gas transmission and distribution.
 
At December 31, 2024, Emera’s reportable segments
 
include the following:
 
●
 
Florida Electric Utility,
 
which consists of Tampa
 
Electric (“TEC”), a vertically integrated regulated
electric utility, serving
 
approximately
855,000
 
customers in West Central Florida;
●
 
Canadian Electric Utilities, which includes:
●
 
Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated
 
electric utility and the
primary electricity supplier in Nova Scotia, serving approximately
557,000
 
customers; and
●
 
a
100
 
per cent equity interest in NSP Maritime Link Inc. (“NSPML”),
 
which developed the
Maritime Link Project, a $
1.8
 
billion, including AFUDC, transmission project between the
island of Newfoundland and Nova Scotia.
On June 4, 2024, Emera completed the sale of its
31.1
 
per cent indirect minority equity interest in the
Labrador Island Link Partnership (“LIL”), which was previously
 
included in the Canadian Electric
Utilities segment. For further details, refer to note 4.
●
 
Gas Utilities and Infrastructure, which includes:
●
 
Peoples Gas System Inc. (“PGS”), a regulated gas distribution
 
utility, serving
 
approximately
508,000
 
customers across Florida;
●
 
New Mexico Gas Company,
 
Inc. (“NMGC”), a regulated gas distribution utility,
 
serving
approximately
550,000
 
customers in New Mexico. On August 5, 2024,
 
Emera announced an
agreement to sell NMGC. The transaction is expected to
 
close in late 2025, subject to certain
approvals, including approval by the New Mexico Public
 
Regulation Commission (“NMPRC”).
For further details, refer to note 4.
●
 
Emera Brunswick Pipeline Company Limited (“Brunswick
 
Pipeline”), a
145
-kilometre pipeline
delivering re-gasified liquefied natural gas from Saint John,
 
New Brunswick to the United
States (“US”) border under a
25
-year firm service agreement with Repsol Energy
 
North
America Canada Partnership (“Repsol Energy Canada”),
 
which expires in 2034;
 
●
 
SeaCoast Gas Transmission, LLC (“SeaCoast”),
 
a regulated intrastate natural gas
transmission company offering services in Florida;
 
and
●
 
a
12.9
 
per cent equity interest in Maritimes & Northeast
 
Pipeline (“M&NP”), a
1,400
-kilometre
pipeline that transports natural gas throughout markets
 
in Atlantic Canada and the
northeastern US.
 
●
 
Other Electric Utilities, which includes Emera (Caribbean)
 
Incorporated (“ECI”), a holding company
with regulated electric utilities that include:
●
 
The Barbados Light & Power Company Limited (“BLPC”),
 
a vertically integrated regulated
electric utility on the island of Barbados, serving approximately
135,000
 
customers;
 
●
 
Grand Bahama Power Company Limited (“GBPC”), a vertically
 
integrated regulated electric
utility on Grand Bahama Island, serving approximately
19,500
 
customers; and
●
 
a
19.5
 
per cent equity interest in St. Lucia Electricity Services
 
Limited (“Lucelec”), a vertically
integrated regulated electric utility on the island of St.
 
Lucia.
13
●
 
Emera’s other segment includes investments in
 
energy-related non-regulated companies that are
below the required threshold for reporting as separate
 
segments and corporate expense and revenue
items that are not directly allocated to the operations of Emera’s
 
subsidiaries and investments. This
includes:
●
 
Emera Energy, which
 
consists of:
●
 
Emera Energy Services (“EES”), a physical energy business
 
that purchases and sells
natural gas and electricity and provides related energy
 
asset management services;
 
●
 
Brooklyn Power Corporation (“Brooklyn Energy”), a
30
 
MW biomass co-generation
electricity facility in Brooklyn, Nova Scotia; and
●
 
a
50.0
 
per cent joint venture interest in Bear Swamp Power
 
Company LLC (“Bear
Swamp”), a
660
 
MW pumped storage hydroelectric facility in northwestern
Massachusetts.
 
●
 
Emera US Finance LP (“Emera Finance”), EUSHI Finance, Inc.
 
and TECO Finance, Inc.
(“TECO Finance”), financing subsidiaries of Emera;
●
 
Emera US Holdings Inc., a wholly owned holding company
 
for certain of Emera’s assets
located in the US; and
●
 
Other investments.
Basis of Presentation
These consolidated financial statements are prepared
 
and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”)
 
and, in the opinion of management, include all
adjustments that are of a recurring nature and necessary
 
to fairly state the financial position of Emera.
 
 
All dollar amounts are presented in Canadian dollars (“CAD”),
 
unless otherwise indicated.
Principles of Consolidation
These consolidated financial statements include the accounts
 
of Emera Incorporated, its majority-owned
subsidiaries, and a variable interest entity (“VIE”) in which
 
Emera is the primary beneficiary.
 
Emera uses
the equity method of accounting to record investments
 
in which the Company has the ability to exercise
significant influence, and for VIEs in which Emera is not
 
the primary beneficiary.
The Company performs ongoing analysis to assess whether
 
it holds any VIEs or whether any
reconsideration events have arisen with respect to existing
 
VIEs.
To
identify potential VIEs, management
reviews contractual and ownership arrangements such
 
as leases, long-term purchase power agreements,
tolling contracts, guarantees, jointly owned facilities and
 
equity investments. VIEs of which the Company
is deemed the primary beneficiary must be consolidated.
 
The primary beneficiary of a VIE has both the
power to direct the activities of the VIE that most significantly
 
impacts its economic performance and the
obligation to absorb losses or the right to receive benefits
 
of the VIE that could potentially be significant to
the VIE. In circumstances where Emera has an investment
 
in a VIE but is not deemed the primary
beneficiary, the VIE
 
is accounted for using the equity method. For further
 
details on VIEs, refer to note 33.
Intercompany balances and transactions have been
 
eliminated on consolidation, except for the net profit
on certain transactions between certain non-regulated and regulated
 
entities in accordance with
accounting standards for rate-regulated entities. The net profit
 
on these transactions, which would be
eliminated in the absence of the accounting standards
 
for rate-regulated entities, is recorded in non-
regulated operating revenues. An offset is recorded
 
to PP&E, regulatory assets, regulated fuel for
generation and purchased power,
 
or OM&G, depending on the nature of the transaction.
 
14
Use of Management Estimates
 
The preparation of consolidated financial statements
 
in accordance with USGAAP requires management
to make estimates and assumptions. These may affect
 
reported amounts of assets and liabilities at the
date of the financial statements and reported amounts
 
of revenues and expenses during the reporting
periods. Significant areas requiring use of management
 
estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension
 
and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived
 
assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and
 
valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing
 
basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable
 
at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Regulatory Matters
Regulatory accounting applies where rates are established
 
by, or subject to
 
approval by, an
 
independent
third-party regulator. Rates
 
are designed to recover prudently incurred costs of providing
 
regulated
products or services and provide an opportunity for a reasonable
 
rate of return on invested capital, as
applicable. For further detail, refer to note 7.
Foreign Currency Translation
 
Monetary assets and liabilities denominated in foreign
 
currencies are converted to CAD at the rates of
exchange prevailing at the balance sheet date. The resulting differences
 
between the translation at the
original transaction date and the balance sheet date are
 
included in income.
Assets and liabilities of foreign operations whose functional
 
currency is not the Canadian dollar are
translated using exchange rates in effect at the balance
 
sheet date and the results of operations at the
average exchange rate in effect for the period. The
 
resulting exchange gains and losses on the assets
and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt
 
held in CAD functional currency companies as
hedges of net investments in USD denominated foreign
 
operations. The change in the carrying amount of
these investments, measured at exchange rates in effect
 
at the balance sheet date, is recorded in OCI.
Revenue Recognition
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand
 
charges, basic facilities charges and
clauses and riders, are recognized when obligations under the
 
terms of a contract are satisfied, which is
when electricity and gas are delivered to customers over
 
time as the customer simultaneously receives
and consumes the benefits. Electric and gas revenues
 
are recognized on an accrual basis and include
billed and unbilled revenues. Revenues related to the
 
sale of electricity and gas are recognized at rates
approved by the respective regulators and recorded
 
based on metered usage, which occurs on a
periodic, systematic basis, generally monthly or bi-monthly.
 
At the end of each reporting period, electricity
and gas delivered to customers, but not billed, is estimated
 
and corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled
 
revenue at the end of the reporting period
 
is calculated
by estimating the megawatt hours (“MWh”) or therms delivered
 
to customers at the established rates
expected to prevail in the upcoming billing cycle. This
 
estimate includes assumptions as to the pattern of
energy demand, weather, line
 
losses and inter-period changes to customer classes.
15
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera
 
Energy’s corresponding purchases and sales
 
of
natural gas and electricity,
 
pipeline capacity costs and energy asset management
 
revenues. Revenues
are recorded when obligations under terms of the contract
 
are satisfied and are presented on a net basis
reflecting the nature of contractual relationships with customers
 
and suppliers.
Energy sales are recognized when obligations under the
 
terms of the contracts are satisfied, which is
when electricity is delivered to customers over time.
 
Other non-regulated revenues are recorded when obligations
 
under the terms of the contract are
satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts
 
taxes discussed below,
 
collected by the
Company concurrent with revenue-producing activities
 
are excluded from revenue.
Franchise Fees and Gross Receipts
TEC and PGS recover from customers certain costs incurred,
 
on a dollar-for-dollar basis, through prices
approved by the Florida Public Service Commission (“FPSC”).
 
The amounts included in customers’ bills
for franchise fees and gross receipt taxes are included
 
as “Regulated electric” and “Regulated gas”
revenues in the Consolidated Statements of Income.
 
Franchise fees and gross receipt taxes payable by
TEC and PGS are included as an expense on the Consolidated
 
Statements of Income in “Provincial, state
and municipal taxes”.
NMGC is an agent in the collection and payment of franchise
 
fees and gross receipt taxes and is not
required by a tariff to present the amounts on
 
a gross basis. Therefore, NMGC’s franchise
 
fees and gross
receipt taxes are presented net with no line item impact
 
on the Consolidated Statements of Income.
PP&E
 
PP&E is recorded at original cost, including AFUDC or
 
capitalized interest, net of contributions received in
aid of construction.
The cost of additions, including betterments and replacements
 
of units, are included in “PP&E” on the
Consolidated Balance Sheets. When units of regulated PP&E
 
are replaced, renewed or retired, their cost,
plus removal or disposal costs, less salvage proceeds,
 
is charged to accumulated depreciation, with no
gain or loss reflected in income. Where a disposition of
 
non-regulated PP&E occurs, gains and losses are
included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials,
 
contracted services, direct labour,
 
AFUDC for
regulated property or interest for non-regulated property,
 
ARO, and overhead attributable to the capital
project. Overhead includes corporate costs such as finance,
 
information technology and labour costs,
along with other costs related to support functions, employee
 
benefits, insurance, procurement, and fleet
operating and maintenance. Expenditures for project development
 
are capitalized if they are expected to
have a future economic benefit.
Normal maintenance projects and major maintenance
 
projects that do not increase overall life of the
related assets are expensed as incurred. When a major
 
maintenance project increases the life or value of
the underlying asset, the cost is capitalized.
 
Depreciation is determined by the straight-line method, based
 
on the estimated remaining service lives of
the depreciable assets in each functional class of depreciable
 
property. For some
 
of Emera’s rate-
regulated subsidiaries, depreciation is calculated using
 
the group remaining life method, which is applied
to the average investment, adjusted for anticipated costs
 
of removal less salvage, in functional classes of
depreciable property.
 
The service lives of regulated assets require
 
regulatory approval.
16
Intangible assets, which are included in “PP&E” on the Consolidated
 
Balance Sheets, consist primarily of
computer software and land rights. Amortization is determined
 
by the straight-line method, based on the
estimated remaining service lives of the asset in each category.
 
For some of Emera’s rate-regulated
subsidiaries, amortization is calculated using the amortizable
 
life method which is applied to the net book
value to date over the remaining life of those assets. The
 
service lives of regulated intangible assets
require regulatory approval.
Goodwill
Goodwill is calculated as the excess of the purchase price
 
of an acquired entity over the estimated FV of
identifiable assets acquired and liabilities assumed at the
 
acquisition date. Goodwill is carried at initial
cost less any write-down for impairment and is adjusted
 
for the impact of foreign exchange (“FX”).
Goodwill is subject to assessment for impairment at the
 
reporting unit level annually,
 
or if an event or
change in circumstances indicates that the FV of a reporting
 
unit may be below its carrying value. When
assessing goodwill for impairment, the Company has the option
 
of first performing a qualitative
assessment to determine whether a quantitative assessment
 
is necessary. In
 
performing a qualitative
assessment management considers, among other factors,
 
macroeconomic conditions, industry and
market considerations and overall financial performance.
If the Company performs a qualitative assessment and
 
determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses
 
to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares
 
the FV of the reporting unit to its carrying
value, including goodwill (“carrying amount”). If the carrying
 
amount of the reporting unit exceeds its FV,
an impairment loss is recorded. Management estimates
 
the FV of the reporting unit by using the income
approach, or a combination of the income and market
 
approach. The income approach uses a discounted
cash flow analysis which relies on management’s
 
best estimate of the reporting unit’s projected
 
cash
flows. The analysis includes an estimate of terminal values
 
based on these expected cash flows using a
methodology which derives a valuation using an assumed
 
perpetual annuity based on the reporting unit’s
residual cash flows. The discount rate used is a market participant
 
rate based on a peer group of publicly
traded comparable companies and represents the weighted
 
average cost of capital of comparable
companies. For the market approach, management estimates
 
FV based on comparable companies and
transactions within comparable industries, or in the case
 
of the NMGC quantitative assessment in 2024,
transactions involving the reporting unit. Significant assumptions
 
used in estimating the FV of a reporting
unit using an income approach include discount and growth
 
rates, rate case assumptions including future
cost of capital, valuation of the reporting unit’s net
 
operating loss (“NOL”) and projected operating
 
and
capital cash flows. Adverse changes in these assumptions
 
could result in a future material impairment of
the goodwill assigned to Emera’s reporting units.
As of December 31, 2024, Emera’s goodwill represented
 
the excess of the acquisition purchase price for
TECO Energy, Inc.
 
(TEC, PGS and NMGC reporting units) over the FV
 
assigned to identifiable assets
acquired and liabilities assumed. In Q3 2024, Emera entered
 
into an agreement to sell NMGC. As a
result, a quantitative goodwill impairment assessment
 
was performed on the NMGC reporting unit and the
Company recorded a goodwill impairment charge of $
210
 
million ($
198
 
million, after-tax) or $
155
 
million
USD ($
146
 
million USD, after-tax). The reduced NMGC goodwill
 
balance of $
303
 
million is included in the
NMGC disposal unit classified as held for sale. For further
 
details, refer to note 23.
In Q4 2024, a qualitative assessment was performed for
 
TEC given the significant excess of FV over
carrying amounts calculated during the last quantitative test
 
in Q4 2023. Management concluded it was
more likely than not that the FV of this reporting unit exceeded
 
its carrying amount, including goodwill. As
such, no quantitative testing was required. Given the length
 
of time passed since the last quantitative
impairment test for the PGS reporting unit, Emera elected
 
to bypass a qualitative assessment and
performed a quantitative impairment assessment in Q4
 
2024 using a combination of the income and
market approach. This assessment estimated that the
 
FV of the PGS reporting unit exceeded its carrying
amount, including goodwill, and as a result, no impairment
 
charges were recognized.
17
Income Taxes and
 
Investment Tax
 
Credits
Emera recognizes deferred income tax assets and liabilities
 
for the future tax consequences of events
that have been included in financial statements or income tax
 
returns. Deferred income tax assets and
liabilities are determined based on the difference
 
between the carrying value of assets and liabilities on
the Consolidated Balance Sheets, and their respective
 
tax bases using enacted tax rates in effect
 
for the
year in which the differences are expected to reverse.
 
The effect of a change in income tax rates on
deferred income tax assets and liabilities is recognized
 
in earnings in the period when the change is
enacted, unless required to be offset to a regulatory
 
asset or liability by law or by order of the regulator.
Emera recognizes the effect of income tax positions
 
only when it is more likely than not that they will be
realized. Management reviews all readily available current and
 
historical information, including forward-
looking information, and the likelihood that deferred income
 
tax assets will be recovered from future
taxable income is assessed and assumptions are made
 
about the expected timing of reversal of deferred
income tax assets and liabilities. If management subsequently
 
determines it is likely that some or all of a
deferred income tax asset will not be realized, a valuation
 
allowance is recorded to reflect the amount of
deferred income tax asset expected to be realized.
 
Generally, investment
 
tax credits are recorded as a reduction to income
 
tax expense in the current or
future periods to the extent that realization of such benefit
 
is more likely than not. Investment tax credits
earned on regulated assets by TEC, PGS and NMGC are
 
deferred and amortized as required by
regulatory practices.
TEC, PGS, NMGC and BLPC collect income taxes from
 
customers based on current and deferred income
taxes. NSPI, NSPML and Brunswick Pipeline collect income taxes
 
from customers based on income tax
that is currently payable, except for the deferred income taxes
 
on certain regulatory balances specifically
prescribed by regulators. For the balance of regulated
 
deferred income taxes, NSPI, NSPML and
Brunswick Pipeline recognize regulatory assets or liabilities
 
where the deferred income taxes are
expected to be recovered from or returned to customers
 
in future years. These regulated assets or
liabilities are grossed up using the respective income tax
 
rate to reflect the income tax associated with
future revenues that are required to fund these deferred
 
income tax liabilities, and the income tax benefits
associated with reduced revenues resulting from the realization
 
of deferred income tax assets. GBPC is
not subject to income taxes.
Emera classifies interest and penalties associated with
 
unrecognized tax benefits as interest and
operating expense, respectively.
 
For further detail, refer to note 11.
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and
 
market risks relating to commodity prices,
FX, interest rates and share prices through contractual
 
protections with counterparties where practicable,
and by using financial instruments consisting mainly of
 
FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures,
 
options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of
 
natural gas. These physical and financial
contracts are classified as HFT.
 
Collectively, these contracts
 
and financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on
 
its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales
 
(“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance
 
sheet; these contracts are recognized in
income when they settle. A physical contract generally
 
qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business
 
needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery,
 
the Company intends to receive physical delivery of the
commodity, and the
 
Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue
 
the treatment of these contracts
under this exemption if the criteria are no longer met.
 
18
Derivatives qualify for hedge accounting if they meet stringent
 
documentation requirements and can be
proven to effectively hedge identified risk both at
 
the inception and over the term of the instrument.
Specifically, for cash
 
flow hedges, change in the FV of derivatives is deferred
 
to AOCI and recognized in
income in the same period the related hedged item is realized.
 
Where documentation or effectiveness
requirements are not met, the derivatives are recognized
 
at FV with any changes in FV recognized in net
income in the reporting period, unless deferred as a result
 
of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that
 
are documented as economic hedges or for
which the NPNS exception has not been taken, are subject
 
to regulatory accounting treatment. The
change in FV of the derivatives is deferred to a regulatory
 
asset or liability. The
 
gain or loss is recognized
in the hedged item when the hedged item is settled. Management
 
believes any gains or losses resulting
from settlement of these derivatives related to fuel for
 
generation and purchased power will be refunded
to or collected from customers in future rates. TEC and PGS
 
have no derivatives related to hedging.
Derivatives that do not meet any of the above criteria are
 
designated as HFT,
 
with changes in FV
normally recorded in net income of the period. The Company
 
has not elected to designate any derivatives
to be included in the HFT category where another accounting
 
treatment would apply.
Emera classifies gains and losses on derivatives as a component
 
of non-regulated operating revenues,
fuel for generation and purchased power,
 
other expenses, inventory,
 
and OM&G, depending on the
nature of the item being economically hedged. Transportation
 
capacity arising as a result of marketing
and trading derivative transactions is recognized as an asset
 
in “Receivables and other current assets”
and amortized over the period of the transportation contract
 
term. Cash flows from derivative activities are
presented in the same category as the item being hedged within
 
operating activities on the Consolidated
Statements of Cash Flows. Non-hedged derivatives are included
 
in operating cash flows on the
Consolidated Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance
 
Sheets, are not offset by the FV amounts of cash
collateral with the same counterparty.
 
Rights to reclaim cash collateral are recognized
 
in “Receivables
and other current assets” and obligations to return cash
 
collateral are recognized in “Accounts payable”.
Leases
The Company determines whether a contract contains
 
a lease at inception by evaluating whether the
contract conveys the right to control the use of an identified
 
asset for a period of time in exchange for
consideration.
 
Emera has leases with independent power producers (“IPP”)
 
and other utilities for annual requirements to
purchase wind and hydro energy over varying contract
 
lengths which are classified as finance leases.
These finance leases are not recorded on the Company’s
 
Consolidated Balance Sheets as payments
associated with the leases are variable in nature and there
 
are no minimum fixed lease payments. Lease
expense associated with these leases is recorded as “Regulated
 
fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized
 
on the Consolidated Balance Sheets
based on the present value of the future minimum lease payments
 
over the lease term at commencement
date. As most of Emera’s leases do not provide
 
an implicit rate, the incremental borrowing rate
 
at
commencement of the lease is used in determining
 
the present value of future lease payments. Lease
expense is recognized on a straight-line basis over the
 
lease term and is recorded as “OM&G” on the
Consolidated Statements of Income.
Where the Company is the lessor,
 
a lease is a sales-type lease if certain criteria are met
 
and the
arrangement transfers control of the underlying asset
 
to the lessee. For arrangements where the criteria
are met due to the presence of a third-party residual value
 
guarantee, the lease is a direct financing
lease.
 
19
For direct finance leases, a net investment in the lease
 
is recorded that consists of the sum of the
minimum lease payments and residual value, net of estimated
 
executory costs and unearned income.
The difference between the gross investment
 
and the cost of the leased item is recorded as unearned
income at the inception of the lease. Unearned income
 
is recognized in income over the life of the lease
using a constant rate of interest equal to the internal
 
rate of return on the lease.
 
For sales-type leases, the accounting is similar to the accounting
 
for direct finance leases however,
 
the
difference between the FV and the carrying value
 
of the leased item is recorded at lease commencement
rather than deferred over the term of the lease.
 
Emera has certain contractual agreements that include lease and non-lease components, which
management has elected to account for as a single lease component.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of highly liquid short-term investments
 
with original maturities of three months or
less at acquisition.
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced
 
amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately
 
30 days. A late payment fee may be
assessed on account balances after the due date. The
 
Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to
 
be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical
 
loss experience, customer deposits,
current events, the characteristics of existing accounts
 
and reasonable and supportable forecasts that
affect the collectability of the reported amount.
 
Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate
 
to cover expected losses. Receivables are
written off against the allowance when they are
 
deemed uncollectible.
Inventory
Fuel and materials inventories are valued at the lower
 
of weighted-average cost or net realizable value,
unless evidence indicates the weighted-average cost
 
will be recovered in future customer rates.
 
Asset Impairment
Long-Lived Assets:
Emera assesses whether there has been an impairment
 
of long-lived assets and intangibles when a
triggering event occurs, such as a significant market disruption
 
or sale of a business.
 
The assessment involves comparing undiscounted expected
 
future cash flows to the carrying value of the
asset. When the undiscounted cash flow analysis indicates
 
a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring
 
the excess of the carrying amount of the long-
lived asset over its estimated FV.
 
The Company’s assumptions relating to future
 
results of operations or
other recoverable amounts, are based on a combination
 
of historical experience, fundamental economic
analysis, observable market activity and independent market
 
studies. The Company’s expectations
regarding uses and holding periods of assets are based
 
on internal long-term budgets and projections,
which consider external factors and market forces, as
 
of the end of each reporting period. The
assumptions made are consistent with generally accepted
 
industry approaches and assumptions used for
valuation and pricing activities.
In 2024, impairment charges of $
19
 
million ($
14
 
million after-tax) were recognized on certain assets,
 
$
8
million of which was included in Other income, net with $
11
 
million included in Impairment charges on the
Consolidated Income Statement.
No
 
impairment charges related to long-lived assets were recognized
 
in
2023.
 
20
Equity Method Investments:
The carrying value of investments accounted for under
 
the equity method are assessed for impairment by
comparing the FV of these investments to their carrying values,
 
if a FV assessment was completed, or by
reviewing for the presence of impairment indicators. If
 
an impairment exists, and it is determined to be
other-than-temporary,
 
a charge is recognized in earnings equal to the
 
amount the carrying value exceeds
the investment’s FV.
No
 
impairment of equity method investments was required
 
in either 2024 or 2023.
Financial Assets:
Equity investments, other than those accounted for under
 
the equity method, are measured at FV,
 
with
changes in FV recognized in the Consolidated Statements of Income.
 
Equity investments that do not
have readily determinable FV are recorded at cost minus
 
impairment, if any,
 
plus or minus changes
resulting from observable price changes in orderly transactions
 
for the identical or similar investments.
No
impairment of financial assets was required in either
 
2024 or 2023.
 
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection
 
with the future disposal or removal costs
resulting from the permanent retirement, abandonment
 
or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute,
 
written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
An ARO represents the FV of estimated cash flows necessary
 
to discharge the future obligation, using
the Company’s credit adjusted risk-free rate. The
 
amounts are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed depreciation
 
studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory
 
requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived
 
asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same
 
manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value.
 
AROs are included in “Other long-term
liabilities” and accretion expense is included as part of
 
“Depreciation and amortization”. Any regulated
accretion expense not yet approved by the regulator is
 
recorded in “PP&E” and included in the next
depreciation study.
Some of the Company’s transmission and distribution
 
assets may have conditional AROs that are not
recognized in the consolidated financial statements, as
 
the FV of these obligations could not be
reasonably estimated, given insufficient information
 
to do so. A conditional ARO refers to a legal
obligation to perform an asset retirement activity in which
 
the timing and/or method of settlement are
conditional on a future event that may or may not be
 
within the control of the entity.
 
Management
monitors these obligations and a liability is recognized at FV
 
in the period in which an amount can be
determined.
Cost of Removal (“COR”)
TEC, PGS, NMGC and NSPI recognize non-ARO COR
 
as regulatory liabilities or regulatory assets. The
non-ARO COR represent funds received from customers
 
through depreciation rates to cover estimated
future non-legally required COR of PP&E upon retirement. The
 
companies accrue for COR over the life of
the related assets based on depreciation studies approved
 
by their respective regulators. The costs are
estimated based on historical experience and future
 
expectations, including expected timing and
estimated future cash outlays.
21
Stock-Based Compensation
The Company has several stock-based compensation
 
plans: a common share option plan for senior
management; an employee common share purchase plan;
 
a deferred share unit (“DSU”) plan; a
performance share unit (“PSU”) plan; and a restricted
 
share unit (“RSU”) plan. The Company accounts for
its plans in accordance with the FV-based method of
 
accounting for stock-based compensation. Stock-
based compensation cost is measured at the grant date,
 
based on the calculated FV of the award, and is
recognized as an expense over the employee’s or
 
director’s requisite service period using the graded
vesting method. Stock-based compensation plans recognized as
 
liabilities are initially measured at FV
and re-measured at FV at each reporting date, with the
 
change in liability recognized in income.
Employee Benefits
The costs of the Company’s pension and other
 
post-retirement benefit programs for employees are
expensed over the periods during which employees render service.
 
The Company recognizes the funded
status of its defined-benefit and other post-retirement plans on
 
the balance sheet and recognizes
changes in funded status in the year the change occurs.
 
The Company recognizes unamortized gains
and losses and past service costs in “AOCI” or “Regulatory
 
assets” on the Consolidated Balance Sheets.
The components of net periodic benefit cost other than
 
the service cost component are included in “Other
income, net” on the Consolidated Statements of Income.
 
For further detail, refer to note 22.
Government Grants
The Company accounts for government grants by applying
 
a grant accounting model by analogy to
International Accounting Standards (“IAS”) 20, Accounting
 
for Government Grants and Disclosure of
Government Assistance. A grant relating to an asset is
 
reflected in the determination of the carrying
amount of the asset. A grant relating to income is presented
 
as a deduction from the related expense it is
intended to compensate.
In 2024, the Company received an aggregate of $
47
 
million (2023 – $
7
 
million) of government grants from
various Canadian and US government agencies towards
 
capital projects included in
PP&E
. The capital
projects receiving grants primarily relate to the Company’s
 
decarbonization and environmental
compliance initiatives. Further details on significant grant programs
 
utilized in 2024 and 2023 are noted
below.
 
Natural Resources Canada (“NRCan”) Smart Renewables
 
& Electrification Pathways (“SREP”):
On March 27, 2024, NSPI was approved for a grant under the
 
NRCan SREPs to fund the construction of
three
 
50 MW battery storage systems in Nova Scotia.
 
NSPI can make claims under the grant for
33
 
per
cent of eligible project costs to a maximum $
109
 
million. Eligible costs can be incurred until March
 
31,
2027. For the year-end December 31, 2024, NSPI received
 
$
26
 
million (2023 –
nil
) in funding under the
grant, which has been recorded as a reduction to the carrying
 
amount of the project in
PP&E
.
2.
CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policy that is applicable
 
to, and adopted by the Company in 2024, is
described as follows:
 
Improvements to Reportable Segment Disclosures
The Company adopted Accounting Standard Update (“ASU”) 2023-07,
 
Segment Reporting (Topic
 
280),
Improvements to Reportable Segment Disclosures. The change
 
in the standard improves reportable
segment disclosure requirements, primarily through enhanced
 
disclosures about significant segment
expenses. The changes improve financial reporting by
 
requiring disclosure of incremental segment
information on an annual and interim basis for all public
 
entities to enable investors to develop more
decision-useful financial analyses. The guidance was
 
effective for annual reporting periods beginning
after December 15, 2023, and for interim periods beginning
 
after December 15, 2024. Adoption of the
standard resulted in additional qualitative disclosures provided
 
in note 5.
22
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of
 
all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The following
 
updates have been issued by the FASB,
 
but as allowed, have
not yet been adopted by Emera. Any ASUs not included below
 
were assessed and determined to be
either not applicable to the Company or to have an insignificant
 
impact on the consolidated financial
statements.
Disaggregation of Income Statement Expenses
In November 2024, the FASB
 
issued ASU 2024-03, Income Statement Reporting–Comprehensive
Income–Expense Disaggregation Disclosures (Subtopic
 
220-40): Disaggregation of Income Statement
Expenses. The standard update improves the disclosures about
 
a public business entity’s expenses by
requiring more detailed information about the types of
 
expenses (including purchases of inventory,
employee compensation, depreciation and amortization)
 
included within income statement expense
captions. The guidance will be effective for annual
 
reporting periods beginning after December 15, 2026,
and interim reporting periods beginning after December
 
15, 2027. Early adoption is permitted. The
standard updates are to be applied prospectively with the option
 
for retrospective application. The
Company is currently evaluating the impact of adoption
 
of the standard update on its consolidated
financial statements disclosures.
Improvements to Income Tax
 
Disclosures
In December 2023, the FASB
 
issued ASU 2023-09, Income Taxes
 
(Topic
 
740): Improvements to Income
Tax
 
Disclosures. The standard enhances the transparency,
 
decision usefulness and effectiveness of
income tax disclosures by requiring consistent categories
 
and greater disaggregation of information in the
reconciliation of income taxes computed using the enacted
 
statutory income tax rate to the actual income
tax provision and effective income tax rate, as well
 
as the disaggregation of income taxes paid (refunded)
by jurisdiction. The standard also requires disclosure of income
 
(loss) before provision for income taxes
and income tax expense (recovery) in accordance with
 
U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application
 
– General Notes to Financial Statements:
Income Tax
 
Expense, and the removal of disclosures no longer considered
 
cost beneficial or relevant.
The guidance will be effective for annual reporting periods
 
beginning after December 15, 2024. Early
adoption is permitted. The standard will be applied on
 
a prospective basis, with retrospective application
permitted. The Company is currently evaluating the impact of
 
adoption of the standard on its consolidated
financial statements disclosures.
4.
DISPOSITIONS
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement
 
to sell its indirect wholly owned subsidiary NMGC
for a total enterprise value of approximately $
1.3
 
billion USD, consisting of cash proceeds and the
transfer of debt and customary closing adjustments. The
 
transaction is expected to close in late 2025,
subject to certain approvals, including approval by the
 
NMPRC. As a result of the pending sale, NMGC’s
assets and liabilities are classified as held for sale.
As the transaction proceeds will be lower than the carrying amount
 
of the assets and liabilities being sold,
Emera assessed the NMGC reporting unit for goodwill impairment
 
by comparing the FV of expected
transaction proceeds to the carrying value of net assets,
 
including goodwill of $
366
 
million USD (“NMGC
carrying amount”). The goodwill of the reporting unit was
 
determined to be impaired and a non-cash
goodwill impairment charge of $
210
 
million ($
198
 
million, after-tax) or $
155
 
million USD ($
146
 
million
USD, after-tax) was recorded in “Impairment Charges” on the Consolidated
 
Statements of Income in Q3
2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
23
Following the goodwill impairment assessment, the held for
 
sale assets and liabilities were measured at
the lower of their carrying amount or fair value less costs
 
to sell. The measurement resulted in an
additional loss for the estimated future transaction costs
 
of $
16
 
million ($
12
 
million after-tax), in addition to
incurred transaction costs of $
9
 
million ($
7
 
million after-tax) recorded in “Other Income, net” on the
Consolidated Statements of Income in Q3 2024.
The Company will continue to record depreciation on the NMGC
 
assets through the transaction closing
date, as the depreciation continues to be reflected in
 
customer rates and will be reflected in the carryover
basis of the assets when sold. Depreciation and amortization
 
of $
26
 
million ($
19
 
million USD) was
recorded on these assets from August 5, 2024, the date
 
they were classified as held for sale, through
December 31, 2024.
Details of the assets and liabilities classified as held for
 
sale are as follows:
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
 
per cent indirect minority equity interest in the LIL
for a total transaction value of $
1.2
 
billion, including cash proceeds of $
957
 
million and $
235
 
million for
assuming Emera’s contractual obligation to fund the
 
remaining initial capital investment, which represents
additional LIL equity interest for the acquirer.
 
Cash proceeds from the sale in the amount of $
30
 
million is
held in escrow pending finalization of certain agreements
 
with the LIL general partner. The
 
escrow
proceeds receivable is held at FV and included in the gain
 
on sale, after transaction costs. As of
December 31, 2024, the estimated FV of the escrow proceeds
 
receivable is $
25
 
million. In Q2 2024, a
gain on sale, after transaction costs, of $
182
 
million, ($
107
million, after tax and transaction costs), was
recognized in “Other Income, net” on the Consolidated
 
Statements of Income and included in the Other
segment. In Q4 2024, Emera recognized a $
22
 
million tax benefit due to the reversal of a prior year
valuation allowance related to loss carryforwards applied against
 
a portion of the taxable capital gain on
the sale of LIL. This tax benefit was recorded in “Income Tax
 
(Recovery) Expense” on the Consolidated
Statements of Income in Q4 2024 and included in the
 
Other segment.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24
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)
 
-
 
 
Total operating revenues
 
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
 
have been eliminated on consolidation except
 
for certain transactions
between non-regulated and regulated entities. Management
 
believes elimination of these transactions would
 
understate PP&E,
OM&G, or regulated fuel for generation and purchased
 
power. Inter-company transactions that have not been eliminated
 
are
measured at the amount of consideration established
 
and agreed to by the related parties. Eliminated
 
transactions are included in
determining reportable segments.
(2) Segment net income is reported on a basis
 
that includes internally allocated financing
 
costs of $
29
 
million for the year ended
December 31, 2024, between the Gas Utilities
 
and Infrastructure and Other segments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
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)
 
-
 
 
Total operating revenues
 
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
 
have been eliminated on consolidation except
 
for certain transactions
between non-regulated and regulated entities. Management
 
believes elimination of these transactions would
 
understate PP&E,
OM&G, or regulated fuel for generation and purchased
 
power. Inter-company transactions that have not been eliminated
 
are
measured at the amount of consideration established
 
and agreed to by the related parties. Eliminated
 
transactions are included in
determining reportable segments.
(2) Segment net income is reported on a basis
 
that includes internally allocated financing
 
costs of $
95
 
million for the year ended
December 31, 2023, between the Florida Electric
 
Utility, Gas Utilities and Infrastructure and Other segments.
Geographical Information
Revenues (based on country of origin of the product or service sold)
For the
Year ended December 31
millions of dollars
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
 
NMGC. As at December 31, 2024, NMGC's assets
 
and liabilities were classified as held
for sale and excluded from the table above. For further
 
details on the pending transaction, refer to note 4.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26
6. REVENUE
The following disaggregates the Company’s revenue
 
by major source:
Electric
Gas
Other
Florida
Canadian
Other
 
Gas Utilities
Inter-
Electric
Electric
Electric
and
 
Segment
millions of dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 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
 
Regulated revenue
$
 
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)
 
Non-regulated revenue
$
-
 
$
-
 
$
-
 
$
 
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
 
Regulated revenue
$
 
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
 
Non-regulated revenue
$
-
 
$
-
 
$
-
 
$
 
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
 
represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline's service agreement
 
with Repsol Energy Canada.
(3) Revenue which does not represent revenues
 
from contracts with customers.
(4) Includes gains (losses) on settlement of energy
 
related derivatives, which do not represent
 
revenue from contracts with
customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent
 
gas transportation contracts, lighting contracts,
and long-term steam supply arrangements with fixed contract
 
terms. As of December 31, 2024, the
aggregate amount of the transaction price allocated to
 
remaining performance obligations was $
495
million (2023 – $
488
 
million), including $
3
 
million related to NMGC. This amount includes
 
$
135
 
million of
future performance obligations related to a gas transportation
 
contract between SeaCoast and PGS
through
2040
. This amount excludes contracts with an original
 
expected length of one year or less and
variable amounts for which Emera recognizes revenue at the
 
amount to which it has the right to invoice
for services performed. Emera expects to recognize revenue for
 
the remaining performance obligations
through
2044
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
27
7. REGULATORY
 
ASSETS AND LIABILITIES
 
Regulatory assets represent prudently incurred costs that have
 
been deferred because it is probable they
will be recovered through future rates or tolls collected from customers.
 
Management believes existing
regulatory assets are probable for recovery either because
 
the Company received specific approval from
the applicable regulator, or
 
due to regulatory precedent established for similar circumstances.
 
If
management no longer considers it probable that an asset
 
will be recovered, deferred costs are charged
to income.
 
Regulatory liabilities represent obligations to make refunds
 
to customers or to reduce future revenues for
previous collections. If management no longer considers
 
it probable that a liability will be settled, the
related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization
 
is as approved by the respective
regulator.
As at
December 31
December 31
millions of dollars
 
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
 
regulatory assets
 
$
 
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
 
regulatory liabilities
$
 
1,880
$
 
1,772
(1) On August 5, 2024, Emera announced an
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's assets and liabilities
were classified as held for sale and excluded from
 
the table above.
 
For further details on the pending transaction, refer
 
to note 4.
(2) Comprised of regulatory assets and liabilities
 
that are not individually significant.
Deferred Income Tax
 
Regulatory Assets and Liabilities
To
 
the extent deferred income taxes are expected to be recovered
 
from or returned to customers in future
years, a regulatory asset or liability is recognized as appropriate
 
.
 
28
TEC Capital Cost Recovery for Early Retired Assets
Represents the remaining net book value of Big Bend Power
 
Station Units 1 through 3 and smart meter
assets that were early retired. The balance earns a rate of return
 
as permitted by the FPSC and is
recovered as a separate line item on customer bills for
 
a period of
15
 
years, beginning in January 2022.
Storm Cost Recovery Clauses
TEC and PGS Storm Reserve:
The storm reserve is for hurricanes and other named storms
 
that cause significant damage to TEC and
PGS systems. As allowed by the FPSC, if charges to the
 
storm reserve exceed the storm reserve liability,
the excess is to be carried as a regulatory asset. TEC
 
and PGS can petition the FPSC to seek recovery
of restoration costs over a 12-month period or longer,
 
as determined by the FPSC, as well as replenish
the reserve.
NSPI Storm Rider:
NSPI has a UARB approved storm rider for each of 2023,
 
2024 and 2025, which gives NSPI the ability to
apply to the UARB for recovery of costs if major storm
 
restoration expenses exceed approximately $
10
million in a given year. The
 
storm rider was effective as of the General Rate
 
Application (“GRA”) decision
date. The application for deferral and recovery of the storm rider
 
is made in the year following the year of
the incurred cost, with recovery beginning in the year
 
after the application.
 
GBPC Storm Restoration:
This asset includes storm restoration costs incurred by
 
GBPC related to Hurricane Dorian in 2020 and
Hurricane Matthew in 2016.
 
Pension and Post-Retirement Medical Plan
 
This asset is primarily related to the deferred costs of pension and
 
post-retirement benefits at TEC, PGS
and, in 2023, NMGC. Deferred costs of postretirement
 
benefits that are included in expense are
recognized as cost of service for rate-making purposes
 
as permitted by the FPSC and New Mexico Public
Regulation Commission (“NMPRC”), as applicable and
 
amortized over the remaining service life of plan
participants.
TEC Capital Cost Recovery for Retired Polk Unit 1
 
Components
This regulatory asset relates to the remaining net book value
 
of certain components of Polk Unit 1 that
were early retired on December 31, 2024. The balance earns a
 
rate of return as permitted by the FPSC
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
 
of derivatives that are documented as
economic hedges or that do not qualify for NPNS exemption,
 
as a regulatory asset or liability as approved
by the UARB. The realized gain or loss is recognized
 
when the hedged item settles in regulated fuel for
generation and purchased power,
 
other income, inventory,
 
or OM&G, depending on the nature of the item
being economically hedged.
Cost Recovery Clauses
 
These assets and liabilities are clauses and riders related to
 
TEC, PGS and, in 2023, NMGC.
 
They are
recovered or refunded through cost-recovery mechanisms
 
approved by the FPSC or NMPRC, as
applicable, on a dollar-for-dollar basis in a subsequent
 
period.
29
Environmental Remediations
This asset is primarily related to PGS costs associated with environmental
 
remediation at Manufactured
Gas Plant sites. The balance is included in rate base, partially
 
offsetting the related liability,
 
and earns a
rate of return as permitted by the FPSC. The timing of recovery
 
is based on a settlement agreement
approved by the FPSC.
Stranded Cost Recovery
Due to decommissioning of a GBPC steam turbine in 2012,
 
the GBPA approved
 
recovery of a $
21
 
million
USD stranded cost through electricity rates; it is included in
 
rate base and expected to be included in
rates in future years.
 
NSPI FAM
NSPI has a FAM, approved
 
by the UARB, allowing NSPI to recover fluctuating fuel
 
and certain fuel-
related costs from customers through regularly scheduled
 
fuel rate adjustments. Differences between
prudently incurred fuel costs and amounts recovered from customers
 
through electricity rates in a year
are deferred to a FAM regulatory
 
asset or liability and recovered from or returned to
 
customers in
subsequent periods.
 
Accumulated Reserve – COR
This regulatory asset or liability represents the non-ARO
 
COR reserve in TEC, PGS, NSPI and in 2023,
NMGC. AROs represent the FV of estimated cash flows
 
associated with the Company’s legal obligation to
retire its PP&E.
 
Non-ARO COR represent estimated funds received
 
from customers through depreciation
rates to cover future COR of PP&E value upon retirement
 
that are not legally required. This reduces rate
base for ratemaking purposes. This liability is reduced
 
as COR are incurred and increased as
depreciation is recorded for existing assets and as new
 
assets are put into service.
Regulatory Environments and Updates
Florida Electric Utility
TEC is regulated by the FPSC and is also subject to regulation
 
by the Federal Energy Regulatory
Commission. The FPSC sets rates at a level that allows
 
utilities such as TEC to collect total revenues or
revenue requirements equal to their cost of providing service,
 
plus an appropriate return on invested
capital. Base rates are determined in FPSC rate setting
 
hearings which can occur at the initiative of TEC,
the FPSC or other interested parties.
TEC’s approved regulated return on equity (“ROE”)
 
range for 2024 and 2023 was
9.25
 
per cent to
11.25
per cent based on an allowed equity capital structure of
54
 
per cent. An ROE of
10.20
 
per cent (2023 –
10.20
 
per cent) is used for the calculation of the return
 
on investments for clauses.
Base Rates:
On April 2, 2024, TEC filed a rate case with the FPSC for
 
new base rates. On December 3, 2024, the
FPSC rendered a decision which includes annual base
 
rate increases of $
185
 
million USD in 2025 and
adjustments of $
87
 
million USD and $
9
 
million USD in 2026 and 2027, respectively.
 
The allowed equity in
the capital structure will continue to be
54
 
per cent from investor sources of capital and the allowed
regulatory ROE range is
9.50
 
per cent to
11.50
 
per cent with a
10.50
 
per cent midpoint. On February 3,
2025, the FPSC issued the final order approving the decision,
 
effective January 1, 2025. On February 18,
2025, a motion for reconsideration on certain aspects of the
 
rate case order was filed with the FPSC.
 
On August 16, 2023, TEC filed a petition to implement the
 
2024 Generation Base Rate Adjustment
provisions pursuant to the 2021 rate case settlement agreement.
 
Inclusive of TEC’s ROE adjustment, the
increase of $
22
 
million USD was approved by the FPSC on November
 
17, 2023.
30
Fuel Recovery and Other Cost Recovery Clauses:
TEC has a fuel recovery clause approved by the FPSC,
 
allowing the opportunity to recover fluctuating
fuel expenses from customers through annual fuel rate
 
adjustments. The FPSC annually approves cost-
recovery rates for purchased power,
 
capacity, environmental
 
and conservation costs, including a return
on capital invested. Differences between prudently
 
incurred fuel costs and the cost-recovery rates
 
and
amounts recovered from customers through electricity
 
rates in a year are deferred to a regulatory asset or
liability and recovered from or returned to customers
 
in subsequent periods.
 
On April 2, 2024, TEC requested a mid-course adjustment
 
to its fuel and capacity charges, reflecting a
$
138
 
million USD reduction over
12 months
, from June 2024 through May 2025. The requested
 
reduction
was due to a decrease in actual and projected 2024 natural
 
gas prices since TEC submitted its projected
2024 costs in the fall of 2023. On May 7, 2024, the FPSC
 
approved the mid-course adjustment.
On January 23, 2023, TEC requested an adjustment
 
to its fuel charges to recover the 2022 fuel under-
recovery of $
518
 
million USD over a period of
21 months
. The request also included an adjustment to
2023 projected fuel costs to reflect the reduction in natural gas
 
prices since September 2022 for a
projected reduction of $
170
 
million USD for the balance of 2023. The changes were
 
approved by the
FPSC on March 7, 2023, and were effective
 
beginning on April 1, 2023.
Storm Reserve:
On
September 26, 2024, Hurricane Helene passed 100 miles west
 
of Tampa
 
and made landfall
approximately 200 miles north of Tampa,
 
in Taylor
 
County, as a Category
 
4 hurricane. TEC’s service
territory was impacted by the tropical storm force winds
 
and storm surge which resulted in a peak number
of customers out of 100,000. As of December 31, 2024, TEC
 
deferred $
49
 
million USD to the storm
reserve for future recovery.
On October 9, 2024, Hurricane Milton made landfall approximately
 
50 miles south of Tampa,
 
near
Sarasota, and was the worst weather event to impact the
 
area in over 100 years. The Category 3
hurricane had a significant impact on TEC’s service
 
territory which resulted in a peak number of
customers out of 600,000. As of December 31, 2024, TEC deferred
 
$
340
 
million USD to the storm
reserve for future recovery
.
 
As at December 31, 2024, total restoration costs charged
 
to the storm reserve account have exceeded
the storm reserve balance, and therefore $
377
 
million USD has been deferred as a regulatory asset
 
for
future recovery. On February
 
4, 2025, the FPSC approved TEC’s petition, filed
 
on December 27, 2024,
for the recovery of $
466
 
million USD for costs associated with Hurricane Idalia, Hurricane
 
Debby,
Hurricane Helene and Hurricane Milton and the associated
 
interest which will replenish the storm reserve
over an 18-month recovery period beginning March 2025.
 
The amount of cost-recovery is subject to a
true-up mechanism with the FPSC.
In September 2022, TEC was impacted by Hurricane Ian, with
 
$
119
 
million USD of restoration costs
charged against TEC’s FPSC approved storm reserve.
 
On January 23, 2023, TEC petitioned the FPSC
for recovery of the storm reserve regulatory asset and the replenishment
 
of the balance in the storm
reserve to the approved storm reserve level of $
56
 
million USD, for a total of $
131
 
million USD. The storm
cost recovery surcharge was approved by the FPSC on March
 
7, 2023, and TEC began applying the
surcharge in April 2023. Subsequently,
 
on November 9, 2023, the FPSC approved TEC’s
 
petition, filed on
August 16, 2023, to update the total storm cost collection
 
to $
134
 
million USD. The remaining balance of
$
29
 
million USD as of December 31, 2023, was collected over
 
12 months in 2024.
 
31
Storm Protection Cost Recovery Clause and Settlement
 
Agreement:
The Storm Protection Plan Cost Recovery Clause provides
 
a process for Florida investor-owned utilities,
including TEC, to recover transmission and distribution
 
storm hardening costs for incremental activities
not already included in base rates. Differences between
 
prudently incurred clause-recoverable costs and
amounts recovered from customers through electricity
 
rates in a year are deferred and recovered from or
returned to customers in a subsequent year.
 
The current approved plan addressed the years 2023,
 
2024
and 2025 and was approved by the FPSC in October,
 
2022.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities
 
Act of Nova Scotia (“Public Utilities Act”) and is
subject to regulation under the Public Utilities Act by the UARB.
 
The Public Utilities Act gives the UARB
supervisory powers over NSPI’s operations and
 
expenditures. Electricity rates for NSPI’s customers
 
are
also subject to UARB approval. NSPI is not subject to
 
a general annual rate review process, but rather
participates in hearings held from time to time at NSPI’s
 
or the UARB’s request.
NSPI is regulated under a cost-of-service model, with rates
 
set to recover prudently incurred costs of
providing electricity service to customers and provide a
 
reasonable return to investors. NSPI’s approved
regulated ROE range for 2024 and 2023 was
8.75
 
per cent to
9.25
 
per cent based on an actual five
quarter average regulated common equity component
 
of up to
40
 
per cent of approved rate base.
GRA:
On February 2, 2023, the UARB approved the GRA settlement
 
agreement between NSPI, key customer
representatives and participating interest groups. This resulted
 
in average customer rate increases of
6.9
per cent effective on February 2, 2023, and further
 
average increases of
6.5
 
per cent on January 1, 2024,
with any under or over-recovery of fuel costs addressed through
 
the UARB’s established FAM
 
process. It
also established a storm rider and a demand-side management
 
rider. On March 27,
 
2023, the UARB
issued a final order approving the electricity rates effective
 
on February 2, 2023.
Fuel Recovery:
On April 17, 2024, the UARB approved the sale of $
117
 
million of the FAM regulatory
 
asset to Invest
Nova Scotia, a provincial Crown corporation. On April
 
30, 2024, the transaction closed and the $
117
million was remitted to NSPI, which resulted in a corresponding
 
decrease of the FAM regulatory
 
asset.
NSPI is collecting the amortization and financing costs
 
related to the $
117
 
million from customers on
behalf of Invest Nova Scotia over a
10
-year period, which began in Q2 2024, and is
 
remitting those
amounts to Invest Nova Scotia quarterly.
 
Federal Loan Guarantee (“FLG”):
On September 24, 2024, the Government of Canada finalized
 
an agreement with NSPI, NSPML and the
Province of Nova Scotia (the “Province”) on terms and
 
conditions for a FLG of $
500
 
million in debt to be
issued by NSPML to help Nova Scotia customers manage
 
unrecovered costs of the replacement energy
that was required during the several years of delay in the
 
Muskrat Falls hydroelectricity project. On
September 25, 2024, NSPI and NSPML filed applications
 
with the UARB related to the FLG. On
November 29, 2024, the UARB approved NSPML’s
 
application to issue the debt, transfer the proceeds
 
to
NSPI as a refund of a portion of previous NSPML assessment
 
payments, and to increase its annual
assessment charge to NSPI to recover the refund and
 
related financing costs over a
28
-year period. On
December 16, 2024, the net proceeds of the NSPML debt
 
issuance were transferred to NSPI and applied
against the FAM regulatory
 
asset balance. On February 18, 2025, the UARB approved
 
NSPI's application
to increase 2025 fuel rates to service the incremental
 
NSPML debt.
Storm Rider:
On December 2, 2024, the UARB approved the recovery
 
of $
24
 
million of major storm restoration and
incremental financing costs deferred to NSPI’s storm
 
rider in 2023 to be recovered over a
12
-month
period beginning on January 1, 2025.
32
Hurricane Fiona:
On June 27, 2024, the UARB approved the deferred recognition
 
of $
25
 
million in incremental operating
costs incurred during the Hurricane Fiona storm restoration
 
efforts in September 2022. Following UARB
approval, the $
25
 
million was reclassified to “Regulatory assets”
 
from “Other long-term assets”. The
UARB also directed NSPI to reclassify $
10
 
million of undepreciated costs related to assets retired
because of Hurricane Fiona to “Regulatory assets” from “PP&E”
 
on the Consolidated Balance Sheets.
NSPI began amortizing both of these regulatory assets
 
over a
10
-year period beginning July 1, 2024.
Nova Scotia Cap-and-Trade
 
(“Cap-and-Trade”)
 
Program:
On December 31, 2022, the FAM
 
included a cumulative $
166
 
million in fuel costs related to the accrued
purchase of emissions credits and $
6
 
million related to credits purchased from provincial auctions.
 
On
March 16, 2023, the Province provided NSPI with emissions
 
allowances sufficient to achieve compliance
for the 2019 through 2022 period. As such, compliance costs
 
accrued of $
166
 
million were reversed in Q1
2023. The credits NSPI purchased from provincial auctions
 
in the amount of $
6
 
million were not refunded
and no further costs were incurred to achieve compliance
 
with the Cap-and-Trade Program.
Extra Large Industrial Active Demand Tariff:
On July 5, 2023, NSPI received approval from the UARB to
 
change the methodology in which fuel cost
recovery from an industrial customer is calculated. Due to significant
 
volatility in commodity prices in
2022, the previous methodology did not result in a reasonable
 
determination of the fuel cost to serve this
customer. The change in methodology,
 
effective January 1, 2022, results in a shifting
 
of fuel costs from
this industrial customer to the FAM.
 
This adjustment was recorded in Q2 2023 resulting
 
in a $
51
 
million
increase to the FAM regulatory
 
asset and an offsetting decrease to unbilled revenue
 
within Receivables
and other current assets. This adjustment had minimal
 
impact on earnings.
NSPML
Equity earnings from the Maritime Link are dependent
 
on the approved ROE and operational
performance of NSPML. NSPML’s
 
approved regulated ROE range is
8.75
 
per cent to
9.25
 
per cent,
based on an actual five-quarter average regulated common
 
equity component of up to
30
 
per cent.
 
Newfoundland and Labrador Hydro’s (“NLH”) Nova
 
Scotia Block (“NS Block”) delivery obligations
commenced in 2021 and delivery will continue over the next
35 years
 
pursuant to the agreements.
 
On September 24, 2024, the Government of Canada finalized
 
an agreement with NSPI, NSPML, and the
Province on terms and conditions for a FLG of $
500
 
million in debt to be issued by NSPML. For further
information, refer to the NSPI section above.
 
On November 29, 2024, NSPML received approval from the
 
UARB to collect up to $
197
 
million in 2025
from NSPI; which includes $
158
 
million for the recovery of costs associated with the Maritime
 
Link, and
$
39
 
million associated with the additional FLG debt and financing costs
 
noted in the NSPI section above.
Payments from NSPI are subject to a holdback of up to $
4
 
million per month. There was
no
 
holdback
recorded for the year ended December 31, 2024.
 
On December 21, 2023, NSPML received approval from the
 
UARB to collect up to $
164
 
million in 2024
from NSPI for the recovery of costs associated with the
 
Maritime Link subject to a holdback of $
4
 
million
per month.
33
On October 4, 2023 and January 31, 2024, the UARB issued
 
decisions providing clarification on
remaining aspects of the Maritime Link holdback mechanism
 
primarily relating to release of past and
future holdback amounts and requirements to end the holdback
 
mechanism. In these decisions, the
UARB agreed with the Company’s submission that
 
$
12
 
million ($
8
 
million related to 2022 and $
4
 
million
related to 2023) of the previously recorded holdback remain
 
credited to NSPI’s FAM,
 
with the remainder
released to NSPML and recorded in Emera’s “Income
 
from equity investments”. The UARB also
confirmed that NSPML can apply for termination of the
 
holdback mechanism upon
90
 
per cent of NS
Block deliveries being achieved for 12 consecutive months (subject
 
to potential relief for planned outages
or exceptional circumstances) and the net outstanding
 
balance of previously underdelivered NS Block
energy is less than
10
 
per cent of the contracted annual amount. In addition,
 
the UARB increased the
monthly holdback amount from $
2
 
million to $
4
 
million beginning December 1, 2023.
Gas Utilities and Infrastructure
PGS
PGS is regulated by the FPSC. The FPSC sets rates at
 
a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their
 
cost of providing service, plus an appropriate return
on invested capital.
PGS’s approved ROE range for 2024 and 2023
 
was
9.15
 
per cent to
11.15
 
per cent with a
10.15
 
per cent
midpoint, based on an allowed equity capital structure
 
of
54.7
 
per cent.
 
Base Rates:
On April 4, 2023, PGS filed a rate case with the FPSC
 
and a hearing for the matter was held in
September 2023. On November 9, 2023, the FPSC approved
 
a $
118
 
million USD increase to base
revenues which includes $
11
 
million USD transferred from the cast iron and bare
 
steel replacement rider,
for a net incremental increase to base revenues of $
107
 
million USD. This reflects a
10.15
 
per cent
midpoint ROE with an allowed equity capital structure of
54.7
 
per cent. A final order was issued on
December 27, 2023, with the new rates effective January
 
2024.
Fuel Recovery:
PGS recovers the costs it pays for gas supply and
 
interstate transportation for system supply through its
Purchased Gas Adjustment Clause (“PGAC”). This clause is designed
 
to recover actual costs incurred by
PGS for purchased gas, gas storage services, interstate pipeline
 
capacity, and
 
other related items
associated with the purchase, distribution, and sale of
 
natural gas to its customers.
 
These charges may
be adjusted monthly based on a cap approved annually
 
by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement
 
Programs:
The FPSC annually approves a conservation charge that
 
is intended to permit PGS to recover prudently
incurred expenditures in developing and implementing
 
cost effective energy conservation programs
 
which
are required by Florida law and approved and monitored
 
by the FPSC. PGS also has a Cast Iron/Bare
Steel Pipe Replacement clause to recover the cost of accelerating
 
the replacement of cast iron and bare
steel distribution lines in the PGS system. In February 2017,
 
the FPSC approved expansion of the Cast
Iron/Bare Steel clause to allow recovery of accelerated
 
replacement of certain obsolete plastic pipe. The
majority of cast iron and bare steel pipe has been removed
 
from its system, with replacement of obsolete
plastic pipe continuing until 2028 under the rider.
 
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC
 
sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service,
 
plus an appropriate return on invested capital.
 
NMGC’s approved ROE for 2024 and 2023
 
was
9.375
 
per cent on an allowed equity capital structure of
52
 
per cent.
34
Base Rates:
On September 14, 2023, NMGC filed a rate case with
 
the NMPRC for new base rates.
 
On March 1, 2024,
NMGC filed with the NMPRC a settlement with the support
 
of all parties in the case for an increase of $
30
million USD in annual base revenues and maintaining
 
NMGC’s ROE at
9.375
 
per cent. The rates reflect
the recovery of increased operating costs and capital investments
 
in pipeline projects and related
infrastructure, as well as a new customer information and
 
billing system. NMGC also agreed to withdraw,
and to not reassert in a future rate case application,
 
its request for a regulatory asset for costs associated
with its 2022 application for a certificate of public convenience
 
and necessity for a liquefied natural gas
storage facility in New Mexico. The NMPRC approved
 
the rate case settlement on July 25, 2024. New
rates became effective October 1, 2024.
Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This
 
clause recovers actual costs for purchased gas,
gas storage services, interstate pipeline capacity,
 
and other related items associated with the purchase,
transmission, distribution, and sale of natural gas to its
 
customers. On a monthly basis, NMGC can adjust
charges based on the next month’s expected cost
 
of gas and any prior month under-recovery or over-
recovery. The NMPRC
 
requires that NMGC annually file a reconciliation
 
of the PGAC period costs and
recoveries. NMGC must file a PGAC Continuation Filing
 
with the NMPRC every four years to establish
that the continued use of the PGAC is reasonable and
 
necessary. NMGC
 
received approval of its PGAC
Continuation in December 2024, for the four-year period
 
ending December 2028.
Brunswick Pipeline
 
Brunswick Pipeline is a
145
-kilometre pipeline delivering natural gas from the Saint
 
John LNG import
terminal near Saint John, New Brunswick to markets in
 
the northeastern US. Brunswick Pipeline entered
into a
25
-year firm service agreement commencing in July
 
2009 with Repsol Energy Canada. The
agreement provides for a predetermined toll increase
 
in the fifth and fifteenth year of the contract. The
pipeline is considered a Group II pipeline regulated by
 
the Canada Energy Regulator (“CER”). The CER
Gas Transportation Tariff
 
is filed by Brunswick Pipeline in compliance with the
 
requirements of the CER
Act and sets forth the terms and conditions of the transportation
 
rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
BLPC is regulated by the Fair Trading
 
Commission (“FTC”), under the Utilities Regulation (Procedural)
Rules 2003. BLPC is regulated under a cost-of-service model,
 
with rates set to recover prudently incurred
costs of providing electricity service to customers plus
 
an appropriate return on capital invested. BLPC’s
approved regulated return on rate base was
10
 
per cent for 2024 and 2023.
Licenses:
BLPC currently operates pursuant to a single integrated license
 
to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the Government
 
of Barbados passed legislation
requiring multiple licenses for the supply of electricity.
 
In 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types,
 
subject to the passage of implementing
legislation. The timing of the final enactment is unknown at
 
this time, but BLPC will work towards the
implementation of the licenses once enacted.
35
Base Rates:
In 2021, BLPC submitted a general rate review application
 
to the FTC. In September 2022, the FTC
granted BLPC interim rate relief, allowing an increase in base rates
 
of approximately $
1
 
million USD per
month. On February 15, 2023, the FTC issued a decision
 
on the application which included the following
significant items: an allowed regulatory ROE of
11.75
 
per cent, an equity capital structure of
55
 
per cent,
a directive to update the major components of rate base
 
to September 16, 2022, and a directive to
establish regulatory liabilities totalling approximately $
71
 
million USD. On March 7, 2023, BLPC filed a
Motion for Review and Variation
 
(the “Motion”) and applied for a stay of the FTC’s
 
decision, which was
subsequently granted. On November 20, 2023, the FTC
 
issued their decision dismissing the Motion.
Interim rates continue to be in effect through to
 
a date to be determined in a final decision and order.
 
On December 1, 2023, BLPC appealed certain aspects
 
of the FTC’s February 15 and November 20,
2023, decisions to the Supreme Court of Barbados in the
 
High Court of Justice (the “Court”) and
requested that they be stayed. On December 11,
 
2023, the Court granted the stay.
 
BLPC’s position is
that the FTC made errors of law and jurisdiction in their
 
decisions and believes the success of the appeal
is probable, and as a result, the adjustments to BLPC’s
 
final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been
 
recorded at this time. The appeal is
currently scheduled to be heard in 2025.
 
Fuel Recovery:
BLPC’s fuel costs flow through a fuel pass-through
 
mechanism which provides opportunity to recover
 
all
prudently incurred fuel costs from customers in a timely
 
manner. The calculation of the fuel
 
charge is
adjusted on a monthly basis and reported to the FTC for
 
approval.
Clean Energy Transition
 
Rider (“CETR”):
On May 31, 2023, the FTC approved BLPC’s
 
application to establish an alternative cost recovery
mechanism to recover prudently incurred costs associated
 
with its CETR (the “Decision”). The
mechanism is intended to facilitate the timely recovery between
 
rate cases of costs associated with
approved renewable energy assets. BLPC will be required
 
to submit an individual application for the
recovery of costs of each asset through the cost recovery
 
mechanism, meeting the minimum criteria as
set out in the Decision. On October 5, 2023, BLPC applied
 
to the FTC to recover the costs of a battery
storage system through the CETR. On May 6, 2024, the
 
FTC approved the recovery of a
15
 
MW battery
storage system through the CETR.
Barbados Domestic Tax
 
Rate Change:
On May 24, 2024, the Government of Barbados signed
 
the Income Tax
 
(Amendment and Validation)
 
Act
into law. The legislation, effective
 
January 1, 2024, implemented a corporate income
 
tax rate of
9
 
per
cent, requiring BLPC to remeasure its deferred income
 
tax liabilities. On July 18, 2024, BLPC requested
the deferred recovery of the $
5
 
million USD remeasurement. BLPC is seeking amortization
 
of the costs
over a period to be approved by the FTC during a future
 
rate setting process.
 
GBPC
GBPC is regulated by the GBPA.
 
The GBPA
 
has granted GBPC a licensed, regulated and exclusive
franchise to produce, transmit and distribute electricity
 
on the island until 2054. Rates are set to recover
prudently incurred costs of providing electricity service
 
to customers plus an appropriate return on rate
base. GBPC’s approved regulated return on rate base
 
was
8.52
 
per cent for 2024 (2023 –
8.32
 
per cent).
Electricity Act, 2024:
On June 1, 2024, the Electricity Act, 2024 took effect.
 
The legislation purports to remove the jurisdiction of
the GBPA over GBPC
 
and to have the Utilities Regulation and Competition
 
Authority, another
 
Bahamian
regulator, regulate GBPC.
 
Base Rates:
There is a fuel pass-through mechanism and tariff review
 
policy with new rates submitted every three
years. On August 1, 2024, as required by the GBPA
 
Operating Protocol and Regulatory Framework
Agreement, GBPC filed a rate plan proposal and is awaiting
 
regulatory review.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36
Fuel Recovery:
GBPC’s fuel costs flow through a fuel pass-through
 
mechanism which provides the opportunity to recover
all prudently incurred fuel costs from customers in a timely
 
manner. In 2023 and 2024,
 
the fuel pass
through charge was adjusted monthly,
 
in-line with actual fuel costs.
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
 
(1)
 
124
 
118
 
20
 
21
 
12.9
Lucelec
(1)
 
55
 
48
 
4
 
4
 
19.5
LIL
(2)
-
 
 
747
 
29
 
63
-
 
Bear Swamp
 
(3)
-
 
-
 
 
2
 
12
 
50.0
$
 
654
$
 
1,402
$
 
99
$
 
146
(1) Emera has significant influence over the operating
 
and financial decisions of these companies through
 
Board representation
and therefore, records its investment in these
 
entities using the equity method.
 
(2) On June 4, 2024, Emera completed the sale
 
of its equity interest in the LIL. For further
 
details, refer to note 4.
(3) The investment balance in Bear Swamp is
 
in a credit position primarily as a result
 
of a $
179
 
million distribution received in 2015.
Bear Swamp's credit investment balance of $
92
 
million (2023 – $
81
 
million) is recorded in Other long-term liabilities
 
on the
Consolidated Balance Sheets.
 
Equity investments include a $
9
 
million difference between the cost and the
 
underlying FV of the
investees' assets as at the date of acquisition. The excess
 
is attributable to goodwill.
Emera accounts for its variable interest investment in
 
NSPML as an equity investment (note 33).
NSPML's consolidated summarized balance sheets are illustrated
 
as follows:
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
 
(1)
 
778
 
272
Non-current assets
 
27
 
29
Total
 
assets
$
 
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
 
liabilities and equity
$
 
2,267
$
 
1,795
(1) On November 29, 2024, the UARB approved
 
the creation of a $
500
 
million regulatory asset for debt issued as a
 
result of the
FLG. For further details, refer to note 7.
(2) On December 16, 2024, NSPML issued a
 
$
500
 
million bond under the FLG. For further details
 
refer to note 7.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
37
9. OTHER INCOME, NET
For the
Year ended December 31
millions of dollars
2024
2023
Gain on sale of LIL, net of transaction costs
 
(1)
$
 
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
 
(1)
(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
 
on sale, after transaction costs, of Emera's indirect
 
minority interest in the LIL and the
pending sale of NMGC, refer to note 4.
(2) Primarily related to the wind-down of Block
 
Energy LLC
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
11. INCOME TAXES
The income tax provision, for the years ended December
 
31, differs from that computed using the
enacted combined Canadian federal and provincial statutory
 
income tax rate for the following reasons:
millions of dollars
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
 
credits
(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
 
effect of equity earnings
(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
 
-up Tax
 
Act (“Domestic Top
 
-up Tax
 
Act”):
On November 28, 2024, the Domestic Top
 
-up Tax
 
Act was enacted with an effective date of January
 
1,
2024.The Domestic Top
 
-up Tax
 
Act did not have an impact on the Company.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38
Excessive Interest and Financing Expenses Limitation
 
(“EIFEL”) Regime:
On June 20, 2024, Bill C-59, an Act to implement certain provisions
 
of the fall economic statement tabled
in Parliament on November 21, 2023, and certain provisions
 
of the budget tabled in Parliament on March
28, 2023, was enacted.
 
Bill C-59 includes the EIFEL regime, which is effective
 
January 1, 2024. EIFEL
applies to limit a company’s net interest and financing
 
expense deduction to no more than 30 per cent of
earnings before interest, income taxes, depreciation, and amortization
 
for tax purposes. Any denied
interest and financing expenses under the EIFEL regime can
 
be carried forward indefinitely.
During 2024, the Company incurred $
185
 
million of interest and financing expenses in connection with
 
a
specific financing structure. The interest and financing expenses
 
related to the financing structure as well
as $
88
 
million of other interest and financing expenses are expected
 
to be denied under the EIFEL
regime. It was determined that the Company is more likely
 
than not to realize the tax benefit of the denied
interest and financing expenses in future periods and therefore
 
a $
79
 
million deferred income tax asset
has been recorded as at December 31, 2024. In Q4 2024, the
 
Company recognized a $
58
 
million tax
benefit related to the denied interest and financing expenses
 
and the reversal of the related deferred
income tax liability in connection with the financing structure
 
and its wind-up.
Canadian Global Minimum Tax
 
Act (“GMTA”):
On June 20, 2024, the GMTA
 
was enacted with an effective date of January
 
1, 2024. The GMTA
 
did not
have an impact on the Company.
Barbados Domestic Tax
 
Rate Change:
 
On May 24, 2024, the Government of Barbados signed the
 
Income Tax
 
(Amendment and Validation)
 
Act
 
into law. The legislation, effective
 
January 1, 2024, implemented a corporate income tax
 
rate of
9
 
per
 
cent, requiring BLPC to remeasure its deferred income
 
tax liabilities.
 
Barbados Corporation Top
 
-up Tax
 
(Amendment) Act (“Top
 
-up Tax
 
Act”):
On May 24, 2024, the Top
 
-up Tax
 
Act was enacted with an effective date of January
 
1, 2024. The Top
 
-up
Tax
 
Act did not have an impact on the Company
.
 
United States Inflation Reduction Act (“IRA”):
On August 16, 2022, the IRA was signed into legislation.
 
The IRA includes numerous tax incentives for
clean energy, such
 
as the extension and modification of existing investment
 
and production tax credits for
projects placed in service through 2024, and introduces
 
new technology-neutral clean energy related tax
credits beginning in 2025. As of December 31, 2024, the
 
Company has recorded a $
82
 
million (December
31, 2023 – $
30
 
million) regulatory liability on the Consolidated Balance
 
Sheets in recognition of its
obligation to pass the incremental tax benefits realized
 
to customers.
The following table reflects the composition of taxes on
 
income from continuing operations presented in
the Consolidated Statements of Income for the years ended
 
December 31:
millions of dollars
2024
2023
Current income taxes
 
Canada
$
 
29
$
 
26
 
United States
 
4
 
5
Deferred income taxes
 
Canada
(200)
 
93
 
United States
 
155
 
128
Adjustments to beginning of the year valuation allowance
 
Canada
(61)
-
Investment tax credits
 
United States
(6)
(29)
Operating loss carryforwards
 
Canada
(4)
(93)
 
United States
(76)
(2)
Income tax (recovery) expense
$
(159)
$
 
128
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
39
The following table reflects the composition of income
 
before provision for income taxes presented in the
Consolidated Statements of Income for the years ended
 
December 31:
millions of dollars
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
 
the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of dollars
2024
2023
Deferred income tax assets:
Tax
 
loss carryforwards
$
 
1,118
$
 
1,195
Tax
 
credit carryforwards
 
534
 
454
Regulatory liabilities
 
 
225
 
175
Derivative instruments
 
144
 
205
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
(198)
(196)
Derivative instruments
(105)
(235)
Investments subject to significant influence
(46)
(216)
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)
Considering all evidence regarding the utilization of the Company’s
 
deferred income tax assets, it has
been determined that Emera is more likely than not to realize
 
all recorded deferred income tax assets,
except for certain loss carryforwards and unrealized capital
 
losses on long-term debt and investments. A
valuation allowance of $
322
 
million has been recorded as at December 31, 2024 (2023
 
– $
363
 
million)
related to the loss carryforwards, long-term debt and investments.
 
During 2024, the Company recognized
a $
58
 
million tax benefit primarily due to the utilization of certain
 
loss carryforwards, which were subject to
a valuation allowance as at December 31, 2023.
The Company intends to indefinitely reinvest earnings
 
from certain foreign operations. Accordingly,
 
$
4.7
billion as at December 31, 2024 (2023 – $
4.7
 
billion) in cumulative temporary differences for which
deferred taxes might otherwise be required, have not
 
been recognized. It is impractical to estimate the
amount of income and withholding tax that might be payable
 
if a reversal of temporary differences
occurred.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40
Emera’s NOL, capital loss and tax credit carryforwards
 
and their expiration periods as at December 31,
2024 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
 
NOL
$
 
2,420
$
(967)
$
 
1,453
2026 - 2044
 
Capital loss
 
55
(55)
-
 
Indefinite
 
Tax Credit
2
(1)
1
2028 - 2042
 
United States
 
Federal NOL
$
 
1,587
$
(1)
$
 
1,586
2036 - Indefinite
 
State NOL
 
1,351
(1)
 
1,350
2026 - Indefinite
 
Tax credit
 
533
(3)
 
530
2025 - 2044
Other
 
NOL
$
 
91
$
(23)
$
 
68
2025 - 2031
The following table provides details of the change in unrecognized
 
tax benefits for the years ended
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
 
tax deductions at NSPI and research and
development tax credits primarily at TEC. The total amount
 
of unrecognized tax benefits as at December
31, 2024 was $
42
 
million (2023 – $
37
 
million), which would affect the effective
 
tax rate if recognized. The
total amount of accrued interest with respect to unrecognized tax
 
benefits was $
10
 
million (2023 – $
9
million) with $
1
 
million interest expense recognized in the Consolidated
 
Statements of Income (2023 – $
2
million).
No
 
penalties have been accrued. The balance of unrecognized
 
tax benefits could change in the
next 12 months as a result of resolving Canada Revenue
 
Agency (“CRA”) and Internal Revenue Service
audits. A reasonable estimate of any change cannot be made
 
at this time.
NSPI and the CRA are currently in a dispute with respect
 
to the timing of certain tax deductions for
its 2006 through 2010 and 2013 through 2016 taxation
 
years. The ultimate permissibility of the tax
deductions is not in dispute; rather,
 
it is the timing of those deductions. The cumulative net
 
amount in
dispute to date is $
126
 
million (2023 – $
126
 
million), including interest. NSPI has prepaid $
55
 
million
(2023 – $
55
 
million) of the amount in dispute, as required by
 
CRA.
On November 29, 2019, NSPI filed a Notice of Appeal
 
with the Tax
 
Court of Canada with respect to its
dispute of the 2006 through 2010 taxation years. Should
 
NSPI be successful in defending its position, all
payments including applicable interest will be refunded.
 
If NSPI is unsuccessful in defending any portion
of its position, the resulting taxes and applicable interest
 
will be deducted from amounts previously paid,
with the difference, if any,
 
either owed to, or refunded from, the CRA. The related
 
tax deductions will be
available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years
 
not currently in dispute, further payments will
be required; however, the
 
ultimate permissibility of these deductions would be
 
similarly not in dispute.
NSPI and its advisors believe that NSPI has reported
 
its tax position appropriately.
 
NSPI continues to
assess its options to resolving the dispute; however,
 
the outcome of the Notice of Appeal process is not
determinable at this time.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41
Emera files a Canadian federal income tax return, which
 
includes its Nova Scotia provincial income tax.
Emera’s subsidiaries file Canadian, US, Barbados,
 
and St. Lucia income tax returns. As at December
 
31,
2024, the Company’s tax years still open to examination
 
by taxing authorities include 2006 and
subsequent years.
 
12. COMMON STOCK
Authorized
: Unlimited number of non-par value common shares.
2024
2023
Issued and outstanding:
millions
of shares
 
millions of
dollars
millions of
shares
 
millions of
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,
 
net of discounts
 
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
 
total of
8,287,037
 
common shares were issued under Emera's ATM program at an
average price of $
48.27
 
per share for gross proceeds of $
400
 
million ($
397
 
million net of after-tax issuance costs).
(2) For the year ended December 31, 2024, a
 
total of
5,117,273
 
common shares were issued under Emera's ATM program at an
average price of $
51.52
 
per share for gross proceeds of $
264
 
million ($
261
 
million net of after-tax issuance costs). As at December
31, 2024, an aggregate gross sales limit of $
336
 
million remained available for issuance under the
 
ATM program.
As at December 31, 2024, the following common shares
 
were reserved for issuance:
6
 
million (2023 –
6
million) under the senior management stock option plan,
2
 
million (2023 –
2
 
million) under the employee
common share purchase plan and
12
 
million (2023 –
18
 
million) under the DRIP.
 
The issuance of common shares under the common share compensation
 
arrangements does not allow
the plans to exceed
10
 
per cent of Emera's outstanding common shares. As at
 
December 31, 2024,
Emera was in compliance with this requirement.
 
ATM Equity Program
On November 18, 2024, Emera increased the size of
 
the ATM Program to
 
allow the Company to issue up
to $
1
 
billion of common shares from treasury to the public from
 
time to time, at the Company's discretion,
at the prevailing market price. The ATM
 
Program was increased by an amendment dated November 18,
2024 to its prospectus supplement dated November 14, 2023 and
 
an amendment dated November 13,
2024 to its short form base shelf prospectus dated October 3,
 
2023.
13. EARNINGS PER SHARE
Basic earnings per share is determined by dividing net income
 
attributable to common shareholders by
the weighted average number of common shares outstanding
 
during the period. Diluted EPS is computed
by dividing net income attributable to common shareholders
 
by the weighted average number of common
shares outstanding during the period, adjusted for the exercise
 
and/or conversion of all potentially dilutive
securities. Such dilutive items include Company contributions
 
to the senior management stock option
plan, convertible debentures and shares issued under the DRIP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42
The following table reconciles the computation of basic
 
and diluted earnings per share:
For the
Year ended December 31
millions of dollars (except per share amounts)
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
14. 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
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 rate hedge
Interest expense, net
$
(2)
$
(2)
Net change in unrecognized pension and post-retirement benefit costs
 
Actuarial losses
Other income, net
$
 
2
$
-
 
 
Past service (gains) costs
Other income, net
(2)
 
2
 
Amounts reclassified into obligations
Pension and post-retirement benefits
 
68
(40)
Total
 
before tax
 
68
(38)
Income tax expense
-
 
(1)
Total
 
net of tax
$
 
68
$
(39)
Total reclassifications out of AOCI, net of tax, for the period
$
 
66
$
(41)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43
15. INVENTORY
As at
December 31
December 31
millions of dollars
 
2024
2023
Materials
 
$
 
453
$
 
408
Fuel
 
 
328
 
382
Total
$
 
781
$
 
790
16. DERIVATIVE
 
INSTRUMENTS
Derivative assets and liabilities relating to the foregoing categories
 
consisted of the following:
Derivative Assets
Derivative Liabilities
As at
December 31
December 31
December 31
December 31
millions of dollars
2024
2023
2024
2023
Regulatory deferral:
 
Commodity swaps and forwards
$
 
25
$
 
16
$
 
44
$
 
76
 
FX forwards
 
27
 
3
 
3
 
3
 
52
 
19
 
47
 
79
HFT derivatives:
 
Power swaps and physical contracts
 
34
 
29
 
30
 
36
 
Natural gas swaps, futures, forwards, physical
 
 
contracts
 
236
 
319
 
660
 
531
 
270
 
348
 
690
 
567
Other derivatives:
 
Equity derivatives
 
-
 
 
4
 
2
-
 
 
FX forwards
-
 
 
18
 
34
 
7
-
 
 
22
 
36
 
7
Total
 
gross current derivatives
 
322
 
389
 
773
 
653
Impact of master netting agreements:
 
Regulatory deferral
(7)
(3)
(7)
(3)
 
HFT derivatives
(148)
(146)
(148)
(146)
Total
 
impact of master netting agreements
(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
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
 
on the pending transaction, refer to note 4.
(2) Derivative assets and liabilities are classified
 
as current or long-term based upon the maturities
 
of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a
 
gain of $
19
 
million that is being amortized through
interest expense over
10 years
 
as the underlying hedged item settles. As of December 31,
 
2024, the
unrealized gain in AOCI was $
12
 
million, after-tax (December 31, 2023 – $
14
 
million, after-tax). For the
year ended December 31, 2024, unrealized gains of $
2
 
million (2023 – $
2
 
million) have been reclassified
from AOCI into interest expense, net. The Company expects
 
$
2
 
million of unrealized gains currently in
AOCI to be reclassified into net income within the next
 
twelve months.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
44
Regulatory Deferral
The Company has recorded the following changes with
 
respect to derivatives receiving regulatory
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
 
change in derivative instruments
$
 
41
$
 
24
$
(52)
$
(204)
$
(17)
(1) Realized (gains) losses will be recognized in
 
fuel for generation and purchased power when
 
the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments
 
settled and consumed in the period and hedging relationships
 
that have been
terminated or the hedged transaction is no longer
 
probable.
As at December 31, 2024, the Company had the following
 
notional volumes designated for regulatory
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
 
unrealized gains (losses) with respect to HFT
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
 
gains in net income
$
 
207
$
 
1,037
As at December 31, 2024, the Company had the following
 
notional volumes of outstanding HFT
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
-
 
-
 
-
 
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45
Other Derivatives
As at December 31, 2024, the Company had equity
 
derivatives in place to manage cash flow risk
associated with forecasted future cash settlements of deferred
 
compensation obligations and FX forwards
in place to manage cash flow risk associated with forecasted
 
USD cash inflows.
The equity derivatives
hedge the return on
2.9
 
million shares and extends until December 2025. The
 
FX forwards have a
combined notional amount of $
520
 
million USD and expire in 2025 through 2026.
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
 
gains (losses) in net income
$
(56)
$
 
14
$
 
17
$
(9)
Credit Risk
The Company is exposed to credit risk with respect to
 
amounts receivable from customers, energy
marketing collateral deposits and derivative assets. Credit risk
 
is the potential loss from a counterparty’s
non-performance under an agreement. The Company manages
 
credit risk with policies and procedures
for counterparty analysis, exposure measurement, and
 
exposure monitoring and mitigation. Credit
assessments are conducted on all new customers and
 
counterparties, and deposits or collateral are
requested on any high-risk accounts.
 
The Company assesses the potential for credit losses
 
on a regular basis and, where appropriate,
maintains provisions. With respect to counterparties, the Company
 
has implemented procedures to
monitor the creditworthiness and credit exposure of counterparties
 
and to consider default probability in
valuing the counterparty positions. The Company monitors
 
counterparties’ credit standing, including those
that are experiencing financial problems, have significant swings
 
in default probability rates, have credit
rating changes by external rating agencies, or have changes
 
in ownership. Net liability positions are
adjusted based on the Company’s current default probability.
 
Net asset positions are adjusted based on
the counterparty’s current default probability.
 
The Company assesses credit risk internally for
counterparties that are not rated.
As at December 31, 2024, the maximum exposure the
 
Company had to credit risk was $
1.3
 
billion (2023
– $
1.2
 
billion), which included accounts receivable net
 
of collateral/deposits and assets related to
derivatives.
 
It is possible that volatility in commodity prices could cause
 
the Company to have material credit risk
exposures with one or more counterparties. If such counterparties
 
fail to perform their obligations under
one or more agreements, the Company could suffer
 
a material financial loss. The Company transacts with
counterparties as part of its risk management strategy for managing
 
commodity price, FX and interest
rate risk. Counterparties that exceed established credit
 
limits can provide a cash deposit or letter of credit
to the Company for the value in excess of the credit limit where
 
contractually required. The total cash
deposits/collateral on hand as at December 31, 2024 was
 
$
303
 
million (2023 – $
310
 
million), which
mitigated the Company’s maximum credit risk
 
exposure. The Company uses the cash as payment for the
amount receivable or returns the deposit/collateral to the
 
customer/counterparty where it is no longer
required by the Company.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46
The Company enters into commodity master arrangements
 
with its counterparties to manage certain
risks, including credit risk to these counterparties. The
 
Company generally enters into International Swaps
and Derivatives Association agreements, North American Energy
 
Standards Board agreements and, or
Edison Electric Institute agreements. The Company believes
 
entering into such agreements offers
protection by creating contractual rights relating to creditworthiness,
 
collateral, non-performance and
default.
As at December 31, 2024, the Company had $
140
 
million (2023 – $
142
 
million) in financial assets,
considered to be past due, which have been outstanding for
 
an average
61
 
days. The FV of these
financial assets was $
128
 
million (2023 – $
127
 
million), the difference of which was included
 
in the
allowance for credit losses. These assets primarily relate
 
to accounts receivable from electric and gas
revenue.
 
Concentration Risk
The Company's concentrations of risk consisted of the
 
following:
As at
December 31, 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
 
(1)
 
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
 
sale of NMGC. As at December 31, 2024
 
NMGC's assets and liabilities were
classified as held for sale. For further details, refer
 
to note 4.
Cash Collateral
The Company’s cash collateral positions consisted
 
of the following:
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
47
Collateral is posted in the normal course of business based
 
on the Company’s creditworthiness, including
its senior unsecured credit rating as determined by certain
 
major credit rating agencies. Certain
derivatives contain financial assurance provisions that require
 
collateral to be posted if a material adverse
credit-related event occurs. If a material adverse event resulted
 
in the senior unsecured debt falling below
investment grade, the counterparties to such derivatives
 
could request ongoing full collateralization.
As at December 31, 2024, the total FV of derivatives
 
in a liability position was $
617
 
million (December 31,
2023
–
 
$
504
 
million). If the credit ratings of the Company
 
were reduced below investment grade, the full
value of the net liability position could be required to be
 
posted as collateral for these derivatives.
17. FV MEASUREMENTS
The Company is required to determine the FV of all derivatives
 
except those which qualify for the NPNS
exemption (see note 1) and uses a market approach
 
to do so. The three levels of the FV hierarchy are
defined as follows:
Level 1 – Where possible, the Company bases the fair valuation
 
of its financial assets and liabilities on
quoted prices in active markets (“quoted prices”) for identical
 
assets and liabilities.
Level 2 – Where quoted prices for identical assets and
 
liabilities are not available, the valuation of certain
contracts must be based on quoted prices for similar assets
 
and liabilities with an adjustment related to
location differences. Also, certain derivatives are valued
 
using quotes from over-the-counter clearing
houses.
Level 3 – Where the information required for a Level 1
 
or Level 2 valuation is not available, derivatives
must be valued using unobservable or internally developed inputs.
 
The primary reasons for a Level 3
classification are as follows:
●
 
While valuations were based on quoted prices, significant assumptions
 
were necessary to reflect
seasonal or monthly shaping and locational basis differentials.
●
 
The term of certain transactions extends beyond the period when
 
quoted prices are available and,
accordingly, assumptions
 
were made to extrapolate prices from the last quoted
 
period through the
end of the transaction term.
●
 
The valuations of certain transactions were based on internal
 
models, although quoted prices were
utilized in the valuations.
Derivative assets and liabilities are classified in their entirety,
 
based on the lowest level of input that is
significant to the FV measurement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48
The following tables set out the classification of the methodology
 
used by the Company to FV its
derivatives:
As at
December 31, 2024
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
 
Commodity swaps and forwards
$
 
15
$
 
3
$
-
 
$
 
18
 
FX forwards
-
 
 
27
-
 
 
27
 
15
 
30
-
 
 
45
HFT derivatives:
 
Power swaps and physical contracts
 
2
 
23
 
5
 
30
 
Natural gas swaps, futures, forwards, physical
 
 
contracts and related transportation
 
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:
 
Commodity swaps and forwards
$
 
18
$
 
19
$
-
 
$
 
37
 
FX forwards
-
 
 
3
-
 
 
3
 
18
 
22
-
 
 
40
HFT derivatives:
 
Power swaps and physical contracts
 
2
 
21
 
4
 
27
 
Natural gas swaps, futures, forwards and physical
 
 
contracts
(11)
 
89
 
437
 
515
(9)
 
110
 
441
 
542
Other derivatives:
 
FX forwards
-
 
 
34
-
 
 
34
 
Equity derivatives
 
 
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
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
 
on the pending transaction, refer to note 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
49
As at
December 31, 2023
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
 
Commodity swaps and forwards
$
 
7
$
 
6
$
-
 
$
 
13
 
FX forwards
-
 
 
3
-
 
 
3
 
7
 
9
-
 
 
16
HFT derivatives:
 
Power swaps and physical contracts
(5)
 
23
-
 
 
18
 
Natural gas swaps, futures, forwards, physical
 
 
contracts and related transportation
 
42
 
108
 
34
 
184
 
37
 
131
 
34
 
202
Other derivatives:
 
FX forwards
-
 
 
18
-
 
 
18
 
Equity derivatives
 
4
-
 
-
 
 
4
 
4
 
18
-
 
 
22
Total assets
 
48
 
158
 
34
 
240
Liabilities
Regulatory deferral:
 
Commodity swaps and forwards
 
43
 
30
-
 
 
73
 
FX forwards
-
 
 
3
-
 
 
3
 
43
 
33
-
 
 
76
HFT derivatives:
 
Power swaps and physical contracts
-
 
 
24
-
 
 
24
 
Natural gas swaps, futures, forwards and physical
 
 
contracts
 
13
 
19
 
365
 
397
 
13
 
43
 
365
 
421
Other derivatives:
 
FX forwards
-
 
 
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
 
for the year ended December 31, 2024
was as follows:
HFT Derivatives
millions of dollars
Power
Natural gas
 
Total
Assets
Balance, beginning of period
$
-
 
$
 
34
$
 
34
Total
 
realized and unrealized gains (losses) included in non-regulated operating
revenues
 
5
(7)
(2)
Balance, December 31, 2024
 
$
 
5
$
27
$
 
32
Liabilities
Balance, beginning of period
$
-
 
$
 
365
$
 
365
Total
 
realized and unrealized gains (losses) included in non-regulated operating
revenues
 
4
 
72
 
76
Balance, December 31, 2024
 
$
 
4
$
437
$
 
441
Significant unobservable inputs used in the FV measurement
 
of Emera’s natural gas and power
derivatives include third-party sourced pricing for instruments based
 
on illiquid markets. Significant
increases (decreases) in any of these inputs in isolation would result
 
in a significantly lower (higher) FV
measurement. Other unobservable inputs used include internally
 
developed correlation factors and basis
differentials; own credit risk; and discount rates.
 
Internally developed correlations and basis differentials
are reviewed on a quarterly basis based on statistical analysis
 
of the spot markets in the various illiquid
term markets.
 
Discount rates may include a risk premium for those
 
long-term forward contracts with
illiquid future price points to incorporate the inherent uncertainty
 
of these points. Any risk premiums for
long-term contracts are evaluated by observing similar
 
industry practices and in discussion with industry
peers.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50
The Company uses a modelled pricing valuation technique for
 
determining the FV of Level 3 derivative
instruments. The following table outlines quantitative information
 
about the significant unobservable
inputs used in the FV measurements categorized within Level
 
3 of the FV hierarchy:
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
 
relative FV of the instruments.
Long-term debt is a financial liability not measured at
 
FV on the Consolidated Balance Sheets. The
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
 
billion USD denominated Hybrid Notes as a hedge of the
 
foreign
currency exposure of its ne
t investment
 
in USD denominated operations. The Company’s Hybrid Notes
are contingently convertible into preferred shares in the
 
event of bankruptcy or other related events. A
redemption option on or after June 15, 2026 is available
 
and at the control of the Company.
 
The Hybrid
Notes are classified as Level 2 financial assets. As at
 
December 31, 2024, the FV of the Hybrid Notes
was $
1.2
 
billion (2023 – $
1.2
 
billion). An after-tax foreign currency loss of $
139
 
million was recorded in
AOCI for the year ended December 31, 2024 (2023
 
– $
38
 
million after-tax gain).
18. RELATED PARTY
 
TRANSACTIONS
In the ordinary course of business, Emera provides energy
 
and other services and enters into
transactions with its subsidiaries, associates and other
 
related companies on terms similar to those
offered to non-related parties. Intercompany balances
 
and intercompany transactions have been
eliminated on consolidation, except for the net profit on
 
certain transactions between non-regulated and
regulated entities in accordance with accounting standards
 
for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
Significant transactions between Emera and its associated companies
 
are as follows:
●
 
Transactions between NSPI and NSPML
 
related to the Maritime Link assessment are reported
 
in the
Consolidated Statements of Income. NSPI’s expense
 
is reported in Regulated fuel for generation and
purchased power, totalling
 
a recovery of $
324
 
million for the year ended December 31, 2024 (2023
 
–
$
163
 
million expense). NSPML is accounted for as an
 
equity investment, and therefore corresponding
earnings related to this revenue are reflected in Income
 
from equity investments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
51
●
Natural gas transportation capacity purchases from M&NP
 
are reported in the Consolidated
Statements of Income. Purchases from M&NP reported
 
net in Operating revenues, Non-regulated,
totalled $
11
 
million for the year ended December 31, 2024 (2023
– $
14
 
million).
There were no significant receivables or payables between
 
Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December
 
31, 2024 and at December 31, 2023.
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
 
receivables and other current assets
$
 
1,811
$
 
1,817
(1) Capitalized transportation capacity represents the
 
value of transportation/storage received by EES
 
on asset management
agreements at the inception of the contracts. The
 
asset is amortized over the term of each contract.
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
 
Current
Other current liabilities
3
 
3
 
Long-term
Other long-term liabilities
54
 
55
Total
 
lease liabilities
$
57
$
 
58
The Company recorded lease expense of $
123
 
million for the year ended December 31, 2024 (2023
 
–
$
127
 
million), of which $
112
 
million (2023 – $
119
 
million) related to variable costs for power generation
facility finance leases, recorded in “Regulated fuel for
 
generation and purchased power” in the
Consolidated Statements of Income.
 
Future minimum lease payments under non-cancellable operating
 
leases for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Minimum lease payments
$
 
5
$
 
3
$
 
3
$
 
3
$
 
3
$
 
115
$
 
132
Less imputed interest
(75)
Total
$
 
57
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52
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:
 
Operating cash flows for operating leases (millions of dollars)
$
 
10
$
 
8
Right-of-use assets obtained in exchange for lease obligations:
 
Operating leases (millions of dollars)
$
-
 
$
 
1
Weighted average remaining lease term (years)
 
44
 
44
Weighted average discount rate-
 
operating leases
3.96%
3.93%
Lessor
The Company’s net investment in direct finance
 
and sales-type leases primarily relates to Brunswick
Pipeline, Seacoast, compressed natural gas (“CNG”)
 
stations, a renewable natural gas (“RNG”) facility
and heat pumps.
The Company manages its risk associated with the residual
 
value of the Brunswick Pipeline lease
through proper routine maintenance of the asset.
Customers have the option to purchase CNG station assets
 
by paying a make-whole payment at the date
of the purchase based on a targeted internal rate of return
 
or may take possession of the CNG station
asset at the end of the lease term for no cost. Customers
 
have the option to purchase heat pumps at the
end of the lease term for a nominal fee.
Commencing in October 2023, the Company leased a RNG
 
facility to a biogas producer that is classified
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
 
million USD.
 
Direct finance and sales-type lease unearned income is recognized
 
in income over the life of the lease
using a constant rate of interest equal to the internal
 
rate of return on the lease and is recorded as
“Operating revenues – regulated gas” and “Other income,
 
net” on the Consolidated Statements of
Income.
The total net investment in direct finance and sales-type
 
leases consist of the following:
 
As at
December 31
December 31
millions of dollars
 
2024
2023
Total
 
minimum lease payment 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 and sales type leases – long-term
$
610
$
621
As at December 31, 2024, future minimum lease payments
 
to be received for each of the next five years
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
53
21. PROPERTY,
 
PLANT AND EQUIPMENT
PP&E consisted of the following regulated and non-regulated
 
assets:
 
As at
December 31
December 31
millions of dollars
 
Estimated useful life
2024 (1)
2023
Generation
5
 
to
131
$
 
14,297
$
 
13,500
Transmission
10
 
to
80
 
3,106
 
2,835
Distribution
10
 
to
65
 
8,512
 
7,417
Gas transmission and distribution
15
 
to
75
 
4,658
 
5,536
General plant and other
 
(2)
2
 
to
60
 
3,078
 
2,985
Total
 
cost
 
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
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's assets and liabilities
were classified as held for sale and excluded from
 
the table above.
 
For further details on the pending transaction, refer
 
to note 4.
(2) SeaCoast owns a
50
% undivided ownership interest in a jointly
 
owned
26
-mile pipeline lateral located in Florida, which went
 
into
service in 2020. At December 31, 2024, SeaCoast’s
 
share of plant in service was $
27
 
million USD (2023 – $
27
 
million USD), and
accumulated depreciation of $
3
 
million USD (2023 – $
2
 
million USD). SeaCoast’s undivided ownership interest
 
is financed with its
funds and all operations are accounted for as
 
if such participating interest were a wholly
 
owned facility. SeaCoast’s share of direct
expenses of the jointly owned pipeline is included
 
in "OM&G" in the Consolidated Statements
 
of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
54
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
 
the funded status for plans were as follows:
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
 
are primarily due to changes in the discount
 
rate, higher than expected indexation,
and compensation-related assumption changes.
 
Plans with PBO/APBO
in Excess of Plan Assets:
The aggregate financial position for pension plans where
 
the PBO or APBO (for post-retirement benefit
plans) exceeded the plan assets for the years ended December
 
31 were as follows:
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)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets:
The ABO for the DB pension plans was $
2,255
 
million as at December 31, 2024 (2023 – $
2,172
 
million).
The aggregate financial position for those plans with an ABO
 
in excess of the plan assets for the years
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
 
consisted of the following:
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)
-
 
(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
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
 
on the pending transaction, refer to note 4.
Amounts Recognized in AOCI and Regulatory Assets:
Unamortized gains and losses and past service costs
 
arising on post-retirement benefits are recorded in
AOCI or regulatory assets. The following table summarizes
 
the change in AOCI and regulatory assets:
Regulatory assets
Actuarial
 
(gains) losses
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)
$
-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
56
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:
 
Actuarial losses (gains)
 
3
(2)
 
1
(3)
 
Past service gains
-
 
(2)
-
 
-
 
 
Regulatory assets
 
9
(2)
 
6
(2)
Settlement, curtailments
-
 
 
1
 
2
-
 
Total
$
(3)
$
 
8
$
(11)
$
 
9
The expected return on plan assets is determined based on
 
the market-related value of plan assets of
$
2,571
 
million as at January 1, 2024 (2023 – $
2,577
 
million), adjusted for interest on certain cash flows
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
 
regarding the investment philosophy,
 
the level of risk
which the Company is prepared to accept with respect
 
to the investment of the Pension Funds, and the
basis for measuring the performance of the assets. Central to
 
the policy is the target asset allocation by
major asset categories. The objective of the target asset allocation
 
is to diversify risk and to achieve asset
returns that meet or exceed the plan’s actuarial
 
assumptions. The diversification of assets reduces the
inherent risk in financial markets by requiring that assets
 
be spread out amongst various asset classes.
Further, within each asset class,
 
a diversification is undertaken through the investment
 
in a broad range
of investment and non-investment grade securities. Emera’s
 
target asset allocation is as follows:
Asset Class
Target
 
Range at Market
Canadian Pension Plans:
Short-term securities
0%
to
10%
Fixed income
34%
to
49%
Equities:
 
Canadian
5%
to
15%
 
Non-Canadian
37%
to
61%
Non-Canadian Pension Plans:
Cash and cash equivalents
0%
to
10%
Fixed income
29%
to
49%
Equities
48%
to
68%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
57
Pension plan assets are overseen by the respective
 
management pension committees in the sponsoring
companies. All pension investments are in accordance with policies
 
approved by the respective Board of
Directors of each sponsoring company.
 
The following tables set out the classification of the methodology
 
used by the Company to FV its
investments (for more information on the FV hierarchy
 
and measurement, refer to note 17):
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:
 
Canadian equity
-
109
-
109
4
%
 
United States equity
 
-
312
-
312
12
%
 
Other equity
-
140
-
140
5
%
Fixed income securities:
 
Government
-
-
132
132
5
%
 
Corporate
-
-
92
92
4
%
 
Other
-
-
22
22
1
%
Mutual funds
-
13
-
13
1
%
Open-ended investments
measured at NAV
 
(1)
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:
 
Canadian equity
-
96
-
96
4
%
 
United States equity
 
-
141
-
141
6
%
 
Other equity
-
112
-
112
5
%
Fixed income securities:
 
Government
-
 
-
 
172
172
8
%
 
Corporate
-
 
-
 
90
90
4
%
 
Other
-
4
5
9
-
%
Mutual funds
-
50
-
50
2
%
Other
-
6
(1)
5
-
%
Open-ended investments
measured at NAV
 
(1)
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
 
mutual funds, collective investment trusts,
or pooled funds. NAV’s are calculated at least monthly and the funds honour
 
subscription and redemption activity regularly.
(2) The common collective trusts are private funds
 
valued at NAV.
 
The NAVs are calculated based on bid prices of the underlying
securities. Since the prices are not published to external
 
sources, NAV is used as a practical expedient. Certain funds invest
primarily in equity securities of domestic and
 
foreign issuers while others invest in long duration
 
U.S. investment grade fixed
income assets and seeks to increase return through
 
active management of interest rate and
 
credit risks. The funds honour
subscription and redemption activity regularly.
Non-Pension Benefit Plans:
There are no assets set aside to pay for most of the Company’s
 
non-pension benefit plans. As is common
practice, post-retirement health benefits are paid from
 
general accounts as required. The exception to this
is the NMGC Retiree Medical Plan, which is fully funded.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
58
Investments in Emera:
As at December 31, 2024 and 2023, assets related to the
 
pension funds and post-retirement benefit plans
did not hold any material investments in Emera or its subsidiaries
 
securities. However,
 
as a significant
portion of assets for the benefit plan are held in pooled
 
assets, there may be indirect investments in these
securities.
Cash Flows:
The following table shows expected cash flows for DB 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:
The following table shows the assumptions that have been
 
used in accounting for DB pension and other
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
 
- initial (next year)
-
6.53
%
-
6.04
%
 
- ultimate
 
-
3.77
%
-
3.76
%
 
- year ultimate reached
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
 
- initial (current year)
-
6.04
%
-
5.40
%
 
- ultimate
 
-
3.76
%
-
3.77
%
 
- year ultimate reached
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
 
bonds, with maturities matching the
estimated cash flows from the pension plan.
DC Pension Plan:
Emera also provides a DC pension plan for certain employees.
 
The Company’s contribution for the year
ended December 31, 2024 was $
51
 
million (2023 – $
45
 
million).
 
 
 
 
 
 
 
 
 
 
 
 
59
23. GOODWILL
The change in goodwill for the year ended December 31
 
was due to the following:
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
 
and liabilities were classified as held for
 
sale. For further details on the pending
transaction, refer to note 4.
Goodwill is subject to an annual assessment for impairment
 
at the reporting unit level. The goodwill on
Emera’s Consolidated Balance Sheets at December
 
31, 2024, related to TECO Energy,
 
Inc. (reporting
units with goodwill are TEC, PGS, and NMGC).
 
On August 5, 2024, Emera announced an agreement to sell
 
NMGC. As the expected transaction
proceeds on the pending sale will be less than the NMGC carrying
 
amount, the Company performed a
quantitative goodwill impairment assessment for the NMGC
 
reporting unit. It was determined that the
NMGC carrying amount exceeded the FV of the expected transaction
 
proceeds, and as a result, a non-
cash goodwill impairment charge of $
210
 
million, pre-tax, was recorded in Q3 2024, reducing the
 
NMGC
reporting unit goodwill balance to $
303
 
million as at December 31, 2024. This non-cash charge
 
is
included in “Impairment charges” on the Consolidated
 
Statements of Income.
In 2024, a qualitative assessment was performed for TEC
 
given the significant excess of FV over carrying
amounts calculated during the last quantitative test in
 
Q4 2023. Management concluded it was more likely
than not that the FV of this reporting unit exceeded
 
its carrying amount, including goodwill. As such, no
quantitative testing was required. Given the length of time
 
passed since the last quantitative impairment
test for the PGS reporting unit, Emera elected to bypass
 
a qualitative assessment and performed a
quantitative impairment assessment in Q4 2024 using a combination
 
of the income and market approach.
This assessment estimated that the FV of the PGS reporting
 
unit exceeded its carrying amount, including
goodwill, and as a result, no impairment charges were
 
recognized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
60
24. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial
 
paper issuances, advances on revolving and non-
revolving credit facilities and short-term notes. Short-term
 
debt and the related weighted-average interest
rates as at December 31 consisted of the following:
millions of 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
 
to sell NMGC. As at December 31, 2024,
 
NMGC's liabilities were classified
as held for sale. For further details on the pending
 
transaction, refer to note 4.
The Company’s total short-term unsecured revolving
 
and non-revolving credit facilities, outstanding
borrowings and available capacity as at December 31 were
 
as follows:
 
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
 
advances under available facilities
 
1,404
 
1,436
Available capacity under existing agreements
$
 
898
$
 
1,337
The weighted average interest rate on outstanding short-term
 
debt at December 31, 2024 was
5.05
 
per
cent (2023 –
5.95
 
per cent).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
61
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On April 1, 2024, TEC amended its $
800
 
million USD unsecured committed revolving credit facility
 
to
extend the maturity date from
December 17, 2026
 
to
December 1, 2028
. There were no other changes in
commercial terms from the prior agreement.
Other
On June 24, 2024, Emera repaid its $
400
 
million unsecured non-revolving term facility set to mature in
August 2024.
On June 17, 2024, Emera repaid $
200
 
million on the December 2024 unsecured non-revolving
 
term
facility, decreasing
 
the facility from $
400
 
million to $
200
 
million. In December 2024, Emera repaid the
$
200
 
million upon maturity.
On April 1, 2024, TECO Finance amended its $
400
 
million USD unsecured committed revolving credit
facility to extend the maturity date from
December 17, 2026
 
to
December 1, 2028
. There were no other
changes in commercial terms from the prior agreement.
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
62
26. LONG-TERM DEBT
Bonds, notes and debentures are at fixed interest rates
 
and are unsecured unless noted below.
 
Included
are certain bankers’ acceptances and commercial paper
 
where the Company has the intention and the
unencumbered ability to refinance the obligations for a period
 
greater than one year.
Long-term debt as at December 31 consisted of the following:
Weighted average interest
rate
(1)
millions of dollars
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
 
(3)
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
 
(4)
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
 
(6)
(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
 
credit facility which matures in 2029.
 
(3) Notes are issued and payable in either USD
 
or BBD.
 
(4) In 2024, the Company recognized $
110
 
million in interest expense (2023 – $
109
 
million) related to its fixed to floating
subordinated notes.
(5) On August 5, 2024, Emera announced an
 
agreement to sell NMGC. As at December
 
31, 2024, NMGC's liabilities were
classified as held for sale.
 
For further details on the pending transaction,
 
refer to note 4.
(6) Excludes NMGC amounts which are classified
 
as current liabilities associated with assets held
 
for sale.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
63
The Company’s total long-term revolving credit facilities,
 
outstanding borrowings and available capacity as
at December 31 were as follows:
millions of dollars
Maturity
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
 
made by way of overdraft on accounts up to
 
$
50
 
million.
Debt Covenants
Emera and its subsidiaries have debt covenants associated
 
with their credit facilities. Covenants are
tested regularly and the Company is in compliance with
 
covenant requirements. Emera’s significant
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
 
to 1
0.55
 
: 1
Recent Significant Financing Activity by Segment
Florida Electric Utility
On July 12, 2024, TEC repaid a $
300
 
million USD note upon maturity.
 
This note was repaid with
proceeds from commercial paper.
On January 30, 2024, TEC issued $
500
 
million USD of senior unsecured bonds that bear interest
 
at
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
 
credit facility to extend the maturity date
from
July 15, 2024
 
to
June 24, 2025
 
and reduce the facility from $
400
 
million to $
300
 
million. On
December 16, 2024, NSPI repaid the $
300
 
million unsecured non-revolving credit facility.
On June 24, 2024, NSPI amended its unsecured committed
 
revolving credit facility to extend the maturity
date from
December 16, 2027
 
to
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
 
facility to finance the Battery Energy Storage
Project. NSPI can request funds under the facility quarterly
 
for amounts related to incurred project costs
up to the total commitment of the lessor of $
120
 
million and
45.06
 
per cent of the total eligible project
costs over the term of the agreement. The facility will be
 
available until
6
 
months after completion of the
project, not to exceed
May 21, 2027
, and matures
20
 
years following the end of the period. As at
December 31, 2024, NSPI had utilized $
19
 
million from the facility,
 
which bears interest at
2.51
 
per cent.
 
 
 
 
 
 
 
 
 
 
 
 
 
64
Gas Utilities and Infrastructure
On December 10, 2024, Brunswick Pipeline amended
 
its non-revolving loan agreement. The maturity
date was extended to December 2028 and now includes
 
annual principal repayments.
On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid
 
its $
150
 
million USD fixed rate notes upon
maturity.
Other Electric Utilities
On May 2, 2024, BLPC amended its $
92
 
million Barbadian dollar ($
46
 
million USD) loan facility to extend
the maturity date from
February 19, 2025
 
to
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
 
revolving credit facility increasing the facility
from $
900
 
million to $
1,300
 
million. Emera also extended the maturity date from
June 24, 2027
 
to
June
24, 2029
. There were no other material changes in commercial terms
 
from the prior agreement.
On June 15, 2024, Emera Finance repaid its $
300
 
million USD senior notes upon maturity.
On June 18, 2024, EUSHI Finance, Inc., completed an issuance
 
of $
500
 
million USD fixed-to-fixed reset
 
rate junior subordinated notes. The notes initially bear
 
interest at a rate of
7.625
 
per cent, and will reset
 
on December 15, 2029, and every
five years
 
thereafter, to a rate per annum
 
equal to the five-year U.S.
 
treasury rate plus
3.136
 
per cent. The notes mature on
December 15, 2054
. EUSHI Finance, Inc., at its
 
option, may redeem the notes, in whole or in part,
90 days
 
prior to the first interest reset date, and any
 
semi-annual interest payment date thereafter,
 
at a redemption price equal to the principal amount.
On February 16, 2024, Emera amended its $
400
 
million unsecured non-revolving facility to extend the
maturity date from
February 19, 2024
 
to
February 19, 2025
. There were no other changes in commercial
terms from the prior agreement. On July 19, 2024, Emera reduced
 
the amount of the facility from $
400
million to $
200
 
million. On February 20, 2025, Emera extended the agreement
 
for an additional year to
February 2026 with no other changes in terms. This facility
 
was classified as long-term debt at December
31, 2024.
Long-Term Debt Maturities
As at December 31, 2024, long-term debt maturities, including
 
capital lease obligations, for each of the
next five years and in aggregate thereafter are as follows:
millions of dollars
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
65
27. ASSET RETIREMENT OBLIGATIONS
AROs mostly relate to reclamation of land at the thermal, hydro
 
and combustion turbine sites; and the
disposal of polychlorinated biphenyls in transmission and distribution
 
equipment and a pipeline site.
Certain hydro, transmission and distribution assets may have additional
 
AROs that cannot be measured
as these assets are expected to be used for an indefinite
 
period and, as a result, a reasonable estimate of
the FV of any related ARO cannot be made.
 
The change in ARO for the years ended December 31
 
is as follows:
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)
(1)
-
 
Liabilities settled
(2)
(8)
Balance, December 31
$
 
217
$
 
192
(1) As at December 31, 2024, NMGC's assets
 
and liabilities were classified as held for
 
sale. For further details on the pending
transaction, refer to note 4.
28. COMMITMENTS AND CONTINGENCIES
 
A.
Commitments
As at December 31, 2024, contractual commitments (excluding
 
pensions and other post-retirement
obligations, long-term debt and asset retirement obligations) for
 
each of the next five years and in
aggregate thereafter consisted of the following:
millions of dollars
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
 
those related to NMGC. On completion of
 
the sale of
NMGC, all remaining future contractual obligations will
 
be transferred to the buyer. For further details on the pending
 
transaction, refer
to note 4.
(1) Annual requirement to purchase electricity production
 
from IPPs or other utilities over varying contract lengths.
(2) Includes $
86
 
million related to NMGC (2025: $
30
 
million, 2026: $
24
 
million, 2027: $
16
 
million, 2028: $
12
 
million, 2029: $
4
 
million).
(3) Purchasing commitments for transportation of
 
fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$
135
 
million related to a gas transportation contract between
 
PGS and SeaCoast through 2040.
(4) Includes $
177
 
million related to NMGC (2025: $
109
 
million, 2026: $
52
 
million, 2027: $
13
 
million, 2028: $
3
 
million)
NSPI has a contractual obligation to pay NSPML for use of the
 
Maritime Link over approximately
38 years
from its January 15, 2018 in-service date. In November
 
2024, the UARB approved the collection of up to
$
197
 
million from NSPI for the recovery of Maritime Link
 
costs in 2025. The timing and amounts payable
to NSPML for the remainder of the
38
-year commitment period are subject to UARB
 
approval.
Emera has committed to obtain certain transmission rights
 
in New Brunswick during summer periods
(April through October, inclusive)
 
for NLH's use, if requested, effective August 15,
 
2021 and continuing for
50
 
years. As transmission rights are contracted, the obligations
 
are included within “Other” in the above
table.
66
B.
Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had
 
been a potentially responsible party (“PRP”) for certain superfund
 
sites through its
Tampa
 
Electric and former PGS divisions, as well as for certain
 
former manufactured gas plant sites
through its PGS division. As a result of the separation of the PGS
 
division into a separate legal entity,
Peoples Gas System, Inc. is also now a PRP for those sites (in
 
addition to third party PRPs for certain
sites).
 
While the aggregate joint and several liability associated with
 
these sites has not changed as a
result of the PGS legal separation, the sites continue to present
 
the potential for significant response
costs. As at December 31, 2024, the aggregate financial
 
liability of the Florida utilities is estimated to be
$
17
 
million ($
12
 
million USD), primarily at PGS. This estimate assumes
 
that other involved PRPs are
credit-worthy entities. This amount has been accrued and
 
is primarily reflected in the long-term liability
section under “Other long-term liabilities” on the Consolidated
 
Balance Sheets. The environmental
remediation costs associated with these sites are expected
 
to be paid over many years.
 
The estimated amounts represent only the portion of the cleanup
 
costs attributable to the Florida utilities.
The estimates to perform the work are based on the Florida
 
utilities’ experience with similar work,
adjusted for site-specific conditions and agreements with
 
the respective governmental agencies. The
estimates are made in current dollars, are not discounted
 
and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those
 
PRPs are believed to be currently credit-
worthy and are likely to continue to be credit-worthy for
 
the duration of the remediation work. However,
 
in
those instances that they are not, the Florida utilities could be
 
liable for more than their actual percentage
of the remediation costs. Other factors that could impact
 
these estimates include additional testing and
investigation which could expand the scope of the cleanup activities,
 
additional liability that might arise
from the cleanup activities themselves or changes in
 
laws or regulations that could require additional
remediation. Under current regulations, these costs are recoverable
 
through customer rates established
in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may,
 
from time to time, be involved in other legal proceedings,
 
claims and
litigation that arise in the ordinary course of business
 
which the Company believes would not reasonably
be expected to have a material adverse effect on the
 
financial condition of the Company.
C.
Principal Financial Risks and Uncertainties
Emera believes the following principal financial risks could have
 
a material adverse effect on Emera or its
subsidiaries, or their business operations, liquidity or access
 
to or cost of capital, financial position,
prospects, and/or results of operations (herein considered a “Material
 
Adverse Effect”). Risks associated
with derivative instruments and FV measurements are
 
discussed in note 16 and note 17.
 
Sound risk management is an essential discipline for running
 
the business efficiently and pursuing the
Company’s strategy successfully.
 
Emera has an enterprise-wide risk management process,
 
overseen by
its Enterprise Risk Management Committee (“ERMC”)
 
and monitored by the Board of Directors, to ensure
risks are appropriately identified, assessed, monitored
 
and subject to appropriate controls. The Board of
Directors has a Risk and Sustainability Committee (‘RSC”)
 
to assist in carrying out its risk and
sustainability oversight responsibilities. The RSC’s
 
mandate includes oversight of the Company’s
Enterprise Risk Management framework, including the
 
identification, assessment, monitoring and
management of enterprise risks.
 
67
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain
 
investments are subject to complex legislative
and regulatory frameworks that cover material aspects
 
of their businesses. These frameworks influence
key factors such as rates and cost structures, revenue requirements,
 
allowed ROEs, capital structures,
rate base and capital investments, and the recovery
 
of purchased electricity and fuel costs and other
costs. Regulators also review the prudency of costs and make
 
other decisions that can impact customer
rates and the reliability of service. Emera’s cost
 
-of-service utilities must obtain regulatory approvals for
material aspects of their businesses, including changing
 
or adding rates and/or riders. Such approvals
often require public hearing proceedings involving numerous
 
stakeholders, and there is no assurance in
the outcomes or impact of any regulatory process or decision.
If Emera is unable to recover in a timely manner a material
 
amount of costs or a return on invested capital
through regulatory mechanisms or otherwise, is disallowed
 
the recovery of certain costs, is subject to
regulatory penalties, is not permitted to make certain capital
 
investments, or is not permitted to invest in or
divest certain utility assets, it could result in a Material Adverse
 
Effect, including valuation impairments.
Regulatory lag, the time between the incurrence of costs
 
and the granting of the rates to recover those
costs by regulators, may also result in a Material Adverse
 
Effect.
Aspects of the acquisition, ownership, operations, siting, planning,
 
construction, and decommissioning of
electric generation, storage, transmission and distribution facilities
 
and natural gas transportation and
distribution systems are also subject to regulatory processes
 
and approvals of regulators, government
departments and agencies, and other third parties. The failure
 
to obtain, maintain, and renew such
approvals or significant changes in the terms and conditions
 
thereof could have a Material Adverse Effect.
 
The regulatory framework, process and regulatory decisions
 
may also be adversely affected by changes
in government, shifts in government or public policy,
 
legislative changes, regulatory decisions, geopolitical
changes, changes in the economic environment, or other
 
factors. Government interference in the
regulatory process or regulatory decisions can undermine regulatory
 
stability, predictability,
 
and
independence. Any such changes could have a Material
 
Adverse Effect.
 
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes.
 
Emera operates internationally,
with a significant amount of the Company’s net
 
income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the
 
CAD and, particularly,
 
the USD, which could
positively or adversely affect results.
 
Emera manages currency risks through matching US denominated
 
debt to finance its US operations and
may use foreign currency derivative instruments to hedge specific
 
transactions and earnings exposure.
The Company may enter FX forward and swap contracts
 
to limit exposure on certain foreign currency
transactions such as fuel purchases, revenue streams
 
and capital expenditures, and on net income
earned outside of Canada. The regulatory framework for
 
the Company’s rate-regulated subsidiaries
permits the recovery of prudently incurred costs, including
 
FX.
The Company does not utilize derivative financial instruments
 
for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries.
 
Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income
 
as they are reported in AOCI.
68
Liquidity and Capital Markets
 
Risk
Liquidity risk relates to Emera’s ability to ensure sufficient
 
funds are available to meet its financial
obligations. Emera’s access to capital and cost of
 
borrowing is subject to several risk factors, including
financial market conditions, market disruptions and ratings assigned
 
by various market analysts, including
credit rating agencies. Disruptions in capital markets could
 
prevent Emera from issuing new securities or
cause the Company to issue securities with less than preferred
 
terms and conditions. Emera’s growth
plan requires significant capital investments in PP&E and the
 
risk associated with changes in interest
rates could have an adverse effect on the cost
 
of financing. The Company’s future access
 
to capital and
cost of borrowing may be impacted by various market disruptions
 
.
 
The inability to access cost-effective
capital could have a material impact on Emera’s
 
ability to fund its growth plan.
 
Emera is subject to financial risk associated with changes
 
in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit
 
ratings, including the Company’s business,
 
its
regulatory framework and legislative environment, political
 
interference in the regulatory process, the
ability to recover costs and earn returns, diversification,
 
leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency
 
and severity of hurricanes and other
severe weather events. A decrease in a credit rating could
 
result in higher interest rates in future
financings, increased borrowing costs under certain existing
 
credit facilities, limit access to the
commercial paper market, or limit the availability of adequate
 
credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the Company
 
were reduced below investment grade,
the full value of the net liability of these positions could
 
be required to be posted as collateral.
 
The Company has exposure to its own common share
 
price through the issuance of various forms of
stock-based compensation, which affect earnings
 
through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce
 
the earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions
 
in North America and in other geographic
regions in which Emera operates. Like most utilities, economic
 
factors such as consumer income,
employment and housing affect demand for electricity
 
and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic
 
conditions and inflation may impact the ability of
customers to afford rate increases arising from
 
increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could have
 
a Material Adverse Effect. This may also result in
higher credit and counterparty risk, adverse shifts in government
 
policy and legislation, and/or increased
risk to full and timely recovery of costs and regulatory
 
assets.
Interest Rate Risk:
Emera utilizes a combination of fixed and floating rate
 
debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk.
 
For Emera’s regulated subsidiaries, the cost of
 
debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE
 
will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing
 
interest rates and rise in times of
increasing interest rates, albeit not directly and generally with
 
a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect
 
the economic viability of project development
and acquisition initiatives.
Interest rates could also be impacted by changes in credit
 
ratings. For more information, refer to “Liquidity
and Capital Markets
 
Risk”.
 
As with most other utilities and other similar yield-returning
 
investments, Emera’s share price may be
affected by changes in interest rates and could underperform
 
the market in an environment of rising
interest rates.
69
Inflation Risk:
The Company may be exposed to changes in inflation that
 
may result in increased operating and
maintenance costs, capital investment, and fuel costs
 
compared to the revenues provided by customer
rates.
Commodity Price Risk
The Company’s utility fuel supply and purchase
 
of other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price risk
 
through its portfolio of commodity contracts
and arrangements.
Regulated Utilities:
The Company’s utility fuel supply is exposed to
 
broader global market conditions, which may include
impacts on delivery reliability and price, despite contracted terms.
 
Supply and demand dynamics in fuel
markets can be affected by a wide range of factors
 
which are difficult to predict and may change rapidly,
including but not limited to, currency fluctuations, changes
 
in global economic conditions, natural
disasters, transportation or production disruptions, and
 
geo-political risks, such as political instability,
conflicts, changes to international trade agreements, tariffs,
 
trade sanctions or embargos.
 
Prolonged and substantial increases in fuel prices could result
 
in decreased rate affordability,
 
increased
risk of recovery of costs or regulatory assets, and/or negative
 
impacts on customer consumption patterns
and sales, any of which could result in a Material Adverse
 
Effect.
Emera Energy Marketing and Trading:
The majority of Emera Energy’s portfolio of electricity
 
and gas marketing and trading contracts and, in
particular, its natural gas asset
 
management arrangements, are contracted on a back
 
-to-back basis,
avoiding any material long or short commodity positions.
 
However, the portfolio is
 
subject to commodity
price risk, particularly with respect to basis point differentials
 
between relevant markets in the event of an
operational issue, imposition of tariffs or counterparty
 
default. Changes in commodity prices can also
result in increased collateral requirements associated with
 
physical contracts and financial hedges,
resulting in higher liquidity requirements and increased costs
 
to the business.
Income Tax Risk
The computation of the Company’s provision for
 
income taxes is impacted by changes in tax legislation in
Canada, the US and the Caribbean and any such changes
 
could have a Material Adverse Effect. The
value of Emera’s existing deferred income tax
 
assets and liabilities are determined by existing tax laws
and could be negatively impacted by changes in laws.
 
D.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third
 
parties outstanding. The following significant
guarantees and letters of credit were not included within
 
the Consolidated Balance Sheets as at
December 31, 2024
:
TECO Holdings, Inc. (“TECO Holdings”) has a guarantee
 
in connection with SeaCoast’s performance
 
of
obligations under a gas transportation precedent agreement.
 
The guarantee is for a maximum potential
amount of $
45
 
million USD if SeaCoast fails to pay or perform under the
 
contract. The guarantee expires
five years after the gas transportation precedent agreement
 
termination date, which was terminated on
January 1, 2022. The counterparty has the right to require
 
TECO Holdings to provide replacement credit
support either in the form of a substitute guarantee from
 
an affiliate with an investment grade credit
 
rating
or a letter of credit or cash deposit of $
27
 
million USD.
70
TECO Holdings has a guarantee in connection with SeaCoast’s
 
performance obligations under a firm
service agreement, which expires December 31, 2055,
 
subject to two extension terms at the option of the
counterparty with a final expiration date of December 31, 2071.
 
The guarantee is for a maximum potential
amount of $
13
 
million USD if SeaCoast fails to pay or perform under the
 
firm service agreement. The
counterparty has the right to require TECO Holdings to provide
 
replacement credit support in the form of
either a substitute guarantee from an affiliate
 
with an investment grade credit rating or a letter of credit
 
or
cash deposit of $
13
 
million USD.
Emera has a guarantee of $
66
 
million USD relating to outstanding notes of ECI. This
 
guarantee will
automatically terminate on the date upon which the obligations
 
have been repaid in full.
NSPI has guarantees on behalf of its subsidiary,
 
NS Power Energy Marketing Incorporated, in the amount
of $
104
 
million USD (2023 – $
104
 
million USD) with terms of varying lengths.
The Company has standby letters of credit and surety
 
bonds in the amount of $
105
 
million USD
(December 31, 2023 – $
103
 
million USD) to third parties that have extended credit to
 
Emera and its
subsidiaries. These letters of credit and surety bonds typically
 
have a one-year term and are renewed
annually as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure
 
obligations under a supplementary
retirement plan. The expiry date of this letter of credit was
 
extended to June 2025. The amount committed
as at December 31, 2024 was $
58
 
million (December 31, 2023 – $
56
 
million).
Emera has provided an indemnity to a counterparty in
 
relation to certain future tax amounts that could
arise from specific future changes in Canadian federal
 
law, subject to certain conditions
 
and limitations.
No such changes in law have been proposed at this time.
 
A reasonable estimate of the potential amount
of future payments that could result from future claims
 
under this indemnity cannot be calculated, but the
risk of having to make any significant payments under
 
this indemnity is considered to be remote.
Collaborative Arrangements
For the years ended December 31, 2024 and 2023, the
 
Company has identified the following material
collaborative arrangements:
Through NSPI, the Company is a participant in three
 
wind energy projects in Nova Scotia. The
percentage ownership of the wind project assets is based on
 
the relative value of each party’s project
assets by the total project assets. NSPI has power
 
purchase arrangements to purchase the entire net
output of the projects and, therefore, NSPI’s portion
 
of the revenues are recorded net within regulated fuel
for generation and purchased power.
 
NSPI’s portion of operating expenses is recorded
 
in “OM&G” on the
Consolidated Statements of Income. In 2024, NSPI recognized
 
$
12
 
million net expense (2023 – $
8
million) in “Regulated fuel for generation and purchased
 
power” and $
3
 
million (2023 – $
3
 
million) in
“OM&G” on the Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
71
29. CUMULATIVE PREFERRED STOCK
Authorized:
Unlimited number of First Preferred shares, issuable in
 
series.
Unlimited number of Second Preferred shares, issuable in
 
series.
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)
 
Series A
2.182
0.5456
1.84
August 15, 2025
25.00
 
Series B
 
Series C
6.434
1.6085
2.65
August 15, 2028
25.00
 
Series D
 
Series F
(5)(6)
4.202
1.0505
2.63
February 15, 2025
25.00
 
Series G
Minimum rate reset
(3)(4)
 
Series B
2.393
Floating
1.84
August 15, 2025
25.00
 
Series A
 
Series H
6.324
1.5810
4.90
August 15, 2028
25.00
 
Series I
 
Series J
4.250
1.0625
4.25
May 15, 2026
25.00
 
Series K
Perpetual fixed rate
 
Series E
(7)
4.500
1.1250
 
25.00
 
 
Series L
(8)
4.600
1.1500
November 15, 2026
26.00
 
(1) Holders are entitled to receive fixed or
 
floating cumulative cash dividends when declared
 
by the Board of Directors of the Corporation.
(2) On or after the specified redemption dates,
 
the Corporation has the option to redeem
 
for cash the outstanding First Preferred Shares,
 
in
whole or in part, at the specified per share redemption
 
value plus all accrued and unpaid dividends up
 
to but excluding the dates fixed for
redemption.
(3) On the redemption and/or conversion option
 
date the reset annual dividend per share
 
will be determined by multiplying $
25.00
 
per share
by the annual fixed or floating dividend rate,
 
which for Series A, C, F and H is the sum
 
of the five-year Government of Canada
Bond Yield on the applicable reset date, plus the applicable
 
reset dividend yield (Series H annual
 
reset rate must be a minimum of
4.90
 
per
cent) and for Series B equals the Government
 
of Treasury Bill Rate on the applicable reset date,
 
plus
1.84
 
per cent.
(4) On each conversion option date, the holders
 
have the option, subject to certain conditions,
 
to convert any or all of their Shares into an
equal number of Cumulative Redeemable
 
First Preferred Shares of a specified
 
series. The Company has the right to redeem
 
the outstanding Preferred Shares, Series
 
D, Series G and Series I shares without
 
the consent of the holder every five years
 
thereafter for
cash, in whole or in part at a price of
 
$
25.00
 
per share plus all accrued and unpaid dividends
 
up to but excluding the date fixed for redemption
and $
25.50
 
per share plus all accrued and unpaid dividends
 
up to but excluding the date fixed for redemption
 
in the case
of redemptions on any other date after August
 
15, 2028, February 15, 2025 and August
 
15, 2028, respectively. The reset dividend yield for
Series I equals the Government of Treasury Bill Rate on
 
the applicable reset date, plus
2.54
 
per cent.
(5) On January 8, 2025, Emera announced
 
that it would not redeem the outstanding Preferred
 
Shares, Series F on February 15, 2025.
 
During
the conversion period between January 15,
 
2025 and January 31,2025, subject to
 
certain conditions, the holders of Series
 
F shares had the
right, at their option, to convert all or
 
any of their Series F shares, on a one-for-one
 
basis into Cumulative Floating Rate
 
First Preferred Shares,
Series G on February 15, 2025. On February
 
6, 2025, Emera announced after having taken
 
into account all conversion notices received
 
from
holders, no Series F were converted
 
into Series G shares.
(6) On January 16, 2025, Emera announced
 
that the annual fixed dividend per share
 
for Series F shares will be reset from $
1.0505
 
to $
1.4372
for the five-year period from and including
 
February 15, 2025.
(7) First Preferred Shares, Series E are redeemable
 
at $
25.00
 
per share.
(8) First Preferred Shares, Series L are redeemable
 
at $
26.00
 
on or after November 15, 2026 to
 
November 15, 2027, decreasing $
0.25
 
each
year until November 15, 2030 and $
25.00
 
per share thereafter.
 
 
 
 
 
 
 
 
 
 
 
72
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.
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
 
non-voting cumulative redeemable variable perpetual
 
preferred shares.
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
 
Cumulative Variable
 
Perpetual Preferred Stock:
The preferred shares are redeemable by GBPC after June 17, 2021
, at $
1,000
 
Bahamian per share plus
accrued and unpaid dividends and are entitled to a
6.0 per cent per annum fixed cumulative preferential
dividend to be paid semi-annually
.
 
The Preferred Shares rank behind GBPC’s current
 
and future secured and unsecured debt and ahead of
all of GBPC’s current and future common stock.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73
31. SUPPLEMENTARY
 
INFORMATION TO CONSOLIDATED
 
STATEMENTS
 
OF
CASH FLOWS
For the
 
Year ended December 31
millions of dollars
2024
2023
Changes in non-cash working capital:
 
Inventory
$
 
38
$
(31)
 
Receivables and other current assets
(1)
(154)
 
653
 
Accounts payable
 
536
(538)
 
Other current liabilities
(2)
 
32
(179)
Total
 
non-cash working capital
 
$
 
452
$
(95)
(1) The year ended December 31, 2023, includes $
162
 
million related to the January 2023 NMGC gas
 
hedges. Offsetting change in
regulatory liabilities is included in operating cash
 
flow before working capital resulting in no
 
impact to net cash provided by operating
activities.
(2) The year ended December 31, 2023, includes ($
166
) million related to the decreased accrual for
 
the Nova Scotia Cap-
and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included
 
in operating cash flow before
working capital resulting in no impact to net
 
cash provided by operating activities.
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
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.
 
The
maximum aggregate number of Emera common shares
 
reserved for issuance under this plan is
7
 
million
common shares. As at December 31, 2024, Emera was
 
in compliance with this requirement.
Compensation cost for shares issued under the ECSPP for the
 
year ended December 31, 2024 was $
4
million (2023 – $
3
 
million) and was included in “OM&G” on the Consolidated
 
Statements of Income.
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
74
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,
 
unless a stock option has expired, vested options may
 
be
exercised within the
27 months
 
following the option holder’s date of retirement,
six months
 
following a
termination without just cause or death, and within
sixty days
 
following the date of termination for just
cause or resignation. Commencing with the 2022 stock
 
option grant, vested options may be exercised
during the full term of the option following the option holders
 
date of retirement,
six months
 
following a
termination without just cause or death, and within
sixty days
 
following the date of termination for just
cause or resignation. If stock options are not exercised
 
within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate
 
the compensation expense related to
its stock-based compensation and recognizes the expense
 
over the vesting period on a straight-line
basis.
The following table shows the weighted average FV per
 
stock option along with the assumptions
incorporated into the valuation models for options granted, for
 
the year-ended December 31:
2024
2023
Weighted average FV per option
$
4.66
$
6.32
Expected term
(1)
5
 
years
5
 
years
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
 
calculated based on historical exercise behaviour
 
and represents the period of time
that the options are expected to be outstanding.
(2) Based on the Bank of Canada five-year government
 
bond yields.
(3) Incorporates current dividend rates and historical
 
dividend increase patterns.
(4) Estimated using the five-year historical volatility.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75
The following table summarizes stock option information for
 
2024:
Total
 
Options
Non-Vested Options
(1)
Number of
Options
 
Weighted
average exercise
price per share
Number of
Options
Weighted
average grant
date fair-value
Outstanding as at December 31, 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
 
million of unrecognized compensation related to
 
stock options not yet vested which is
expected to be recognized over a weighted
 
average period of approximately
3
 
years (2023 – $
5
 
million,
3
 
years).
(2) As at December 31, 2024, the weighted
 
average remaining term of vested options was
4
 
years with an aggregate intrinsic value of
$
11
 
million (2023 –
5
 
years, $
8
 
million).
(3) As at December 31, 2024, the FV of options
 
that vested in the year was $
2
 
million (2023 – $
2
 
million).
Compensation cost recognized for stock options for the year
 
ended December 31, 2024 was $
2
 
million
(2023 – $
2
 
million), which was included in “OM&G” on the Consolidated
 
Statements of Income.
 
As at December 31, 2024, cash received from option exercises
 
was $
3
 
million (2023 – $
6
 
million). The
total intrinsic value of options exercised for the year ended
 
December 31, 2024 was $
1
 
million (2023 – $
2
million). The range of exercise prices for the options outstanding
 
as at December 31, 2024 was $
39.93
 
to
$
60.03
 
(2023 – $
32.35
 
to $
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.
 
 
 
 
 
 
 
 
 
 
 
 
76
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
 
DSUs for the year ended December 31, 2024
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
 
DSU’s for the year ended December 31, 2024
was $
13
 
million (2023 – $
2
 
million cost recovery). Tax
 
benefits related to this compensation cost for share
units realized for the year ended December 31, 2024
 
were $
4
 
million (2023 – $
1
 
million tax expense). The
aggregate intrinsic value of the outstanding shares for the year
 
ended December 31, 2024 for employees
was $
43
 
million (2023 – $
36
 
million). The aggregate intrinsic value of the outstanding
 
shares for the year
ended December 31, 2024 for directors was $
45
 
million (2023 – $
37
 
million). Cash payments made
during the year ended December 31, 2024 associated with
 
the DSU plan were $
2
 
million (2023 – $
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
77
A summary of the activity related to employee PSUs for
 
the year ended December 31, 2024 is presented
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
 
year ended December 31, 2024 was $
18
 
million
(2023 – $
11
 
million). Tax
 
benefits related to this compensation cost for share
 
units realized for the year
ended December 31, 2024 were $
5
 
million (2023 – $
3
 
million). Cash payments made during the year
ended December 31, 2024 associated with the PSU plan were
 
$
14
 
million (2023 – $
19
 
million).
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
 
the year ended December 31, 2024 is presented
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
 
year ended December 31, 2024 was $
15
 
million
(2023 – $
10
 
million). Tax
 
benefits related to this compensation cost for share
 
units realized for the year
ended December 31, 2024 were $
4
 
million (2023 – $
3
 
million). Cash payments made during the year
ended December 31, 2024 associated with the RSU plan were
 
$
10
 
million (2023– $
10
 
million).
33. VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which
 
it was determined that Emera is not the
primary beneficiary since it does not have the controlling
 
financial interest of NSPML. When the critical
milestones were achieved, NLH was deemed the primary
 
beneficiary of the asset for financial reporting
purposes as it has
 
authority over the majority of the direct activities that
 
are expected to most significantly
impact the economic performance of the Maritime Link. Thus,
 
Emera began recording the Maritime Link
as an equity investment.
 
 
 
78
BLPC has established a SIF,
 
primarily for the purpose of building a fund to cover risk
 
against damage and
consequential loss to certain generating, transmission
 
and distribution systems. ECI holds a variable
interest in the SIF for which it was determined that ECI
 
was the primary beneficiary and, accordingly,
 
the
SIF must be consolidated by ECI. In its determination that
 
ECI controls the SIF,
 
management considered
that, in substance, the activities of the SIF are being conducted
 
on behalf of ECI’s subsidiary BLPC and
BLPC, alone, obtains the benefits from the SIF’s
 
operations. Additionally,
 
because ECI, through BLPC,
has rights to all the benefits of the SIF,
 
it is also exposed to the risks related to the activities
 
of the SIF.
Any withdrawal of SIF fund assets by the Company would
 
be subject to existing regulations. Emera’s
consolidated VIE in the SIF is recorded as “Other long-term
 
assets”, “Restricted cash” and “Regulatory
liabilities” on the Consolidated Balance Sheets. Amounts
 
included in restricted cash represent the cash
portion of funds required to be set aside for the BLPC
 
SIF.
The Company has identified certain long-term purchase power
 
agreements that meet the definition of
variable interests as the Company has to purchase all
 
or a majority of the electricity generation at a fixed
price. However, it was determined
 
that the Company was not the primary beneficiary
 
since it lacked the
power to direct the activities of the entity,
 
including the ability to operate the generating facilities
 
and make
management decisions.
The following table provides information about Emera’s
 
portion of material unconsolidated VIEs:
As at
December 31, 2024
December 31, 2023
Maximum
Maximum
millions of dollars
Total
assets
exposure to
loss
Total
assets
 
exposure to
loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
$
 
475
$
 
6
$
 
489
$
 
6
34. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s
 
evaluation of events occurring subsequent to
the balance sheet date through February 21, 2025, the date
 
the financial statements were issued.
 

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our Firm under the caption “Experts” in the Annual Information Form and to the use in this Annual Report on Form 40-F of our report dated February 21, 2025, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2024 and 2023, and the consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, included in this Annual Report on Form 40-F.

 

   /s/ Ernst & Young LLP

Halifax, Canada

  

Chartered Professional Accountants

February 21, 2025

  

 

Exhibit 99.5

CERTIFICATION

I, Scott C. Balfour, certify that:

 

1.

I have reviewed this annual report on Form 40-F of Emera Incorporated;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

  a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.

The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

  a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

 

  b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

 

Date: February 21, 2025

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

Exhibit 99.6

CERTIFICATION

I, Gregory W. Blunden, certify that:

 

1.

I have reviewed this annual report on Form 40-F of Emera Incorporated;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

  a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.

The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

  a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

 

  b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

 

Date: February 21, 2025

/s/ Gregory W. Blunden

Gregory W. Blunden

Chief Financial Officer

 

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2024 (the “Report”), as filed with the U.S. Securities and Exchange Commission,

I, Scott C. Balfour, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (i)

the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

 

  (ii)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Date: February 21, 2025

/s/ Scott C. Balfour
Scott C. Balfour
President & Chief Executive Officer

 

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2024 (the “Report”), as filed with the U.S. Securities and Exchange Commission,

I, Gregory W. Blunden, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (i)

the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

 

  (ii)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Date: February 21, 2025
/s/ Gregory W. Blunden
Gregory W. Blunden
Chief Financial Officer