10-K 1 ottr-20231231.htm 10-K ottr-20231231
0001466593falseFY2023http://fasb.org/us-gaap/2023#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2023#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesNoncurrentP3Yhttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrent00014665932023-01-012023-12-3100014665932023-06-30iso4217:USD00014665932024-01-31xbrli:shares00014665932023-12-3100014665932022-12-31iso4217:USDxbrli:shares0001466593ottr:ElectricMember2023-01-012023-12-310001466593ottr:ElectricMember2022-01-012022-12-310001466593ottr:ElectricMember2021-01-012021-12-310001466593ottr:ProductSalesMember2023-01-012023-12-310001466593ottr:ProductSalesMember2022-01-012022-12-310001466593ottr:ProductSalesMember2021-01-012021-12-3100014665932022-01-012022-12-3100014665932021-01-012021-12-310001466593us-gaap:CommonStockMember2020-12-310001466593us-gaap:AdditionalPaidInCapitalMember2020-12-310001466593us-gaap:RetainedEarningsMember2020-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-3100014665932020-12-310001466593us-gaap:CommonStockMember2021-01-012021-12-310001466593us-gaap:AdditionalPaidInCapitalMember2021-01-012021-12-310001466593us-gaap:RetainedEarningsMember2021-01-012021-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-01-012021-12-310001466593us-gaap:CommonStockMember2021-12-310001466593us-gaap:AdditionalPaidInCapitalMember2021-12-310001466593us-gaap:RetainedEarningsMember2021-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-12-3100014665932021-12-310001466593us-gaap:AdditionalPaidInCapitalMember2022-01-012022-12-310001466593us-gaap:CommonStockMember2022-01-012022-12-310001466593us-gaap:RetainedEarningsMember2022-01-012022-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2022-01-012022-12-310001466593us-gaap:CommonStockMember2022-12-310001466593us-gaap:AdditionalPaidInCapitalMember2022-12-310001466593us-gaap:RetainedEarningsMember2022-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2022-12-310001466593us-gaap:AdditionalPaidInCapitalMember2023-01-012023-12-310001466593us-gaap:CommonStockMember2023-01-012023-12-310001466593us-gaap:RetainedEarningsMember2023-01-012023-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2023-01-012023-12-310001466593us-gaap:CommonStockMember2023-12-310001466593us-gaap:AdditionalPaidInCapitalMember2023-12-310001466593us-gaap:RetainedEarningsMember2023-12-310001466593us-gaap:AccumulatedOtherComprehensiveIncomeMember2023-12-31ottr:segment0001466593ottr:ElectricPlantMember2023-01-012023-12-310001466593ottr:ElectricPlantMember2022-01-012022-12-310001466593ottr:ElectricPlantMember2021-01-012021-12-310001466593ottr:ElectricPlantMemberus-gaap:EquipmentMembersrt:MinimumMember2023-01-012023-12-310001466593ottr:ElectricPlantMemberus-gaap:EquipmentMembersrt:MaximumMember2023-01-012023-12-310001466593us-gaap:EquipmentMemberottr:NonelectricPlantMembersrt:MinimumMember2023-12-310001466593us-gaap:EquipmentMemberottr:NonelectricPlantMembersrt:MaximumMember2023-12-310001466593ottr:BuildingAndLeaseholdImprovementsMemberottr:NonelectricPlantMembersrt:MinimumMember2023-12-310001466593ottr:BuildingAndLeaseholdImprovementsMemberottr:NonelectricPlantMembersrt:MaximumMember2023-12-31ottr:plantottr:lineottr:reportingUnit0001466593srt:MinimumMember2023-12-310001466593srt:MaximumMember2023-12-31ottr:plan0001466593us-gaap:RelatedPartyMemberottr:ContributionObligationMember2023-12-31ottr:foundation0001466593us-gaap:RelatedPartyMemberottr:ContributionObligationMember2021-12-310001466593us-gaap:RelatedPartyMemberottr:ContributionObligationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:ContributionObligationMember2023-01-012023-12-310001466593us-gaap:RelatedPartyMemberottr:ContributionObligationMember2022-01-012022-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2022-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2021-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2023-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2023-01-012023-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2022-01-012022-12-310001466593ottr:ContributionObligationPaidMemberus-gaap:RelatedPartyMember2021-01-012021-12-310001466593ottr:LigniteSalesAgreementMemberottr:CoyoteCreekMiningCompanyLLCCCMCMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:LigniteSalesAgreementMemberottr:CoyoteCreekMiningCompanyLLCCCMCMemberottr:OtterTailPowerCompanyMember2023-01-012023-12-31xbrli:pure0001466593us-gaap:OperatingSegmentsMemberottr:ElectricMember2023-01-012023-12-310001466593us-gaap:OperatingSegmentsMemberottr:ElectricMember2022-01-012022-12-310001466593us-gaap:OperatingSegmentsMemberottr:ElectricMember2021-01-012021-12-310001466593us-gaap:OperatingSegmentsMemberottr:ManufacturingMember2023-01-012023-12-310001466593us-gaap:OperatingSegmentsMemberottr:ManufacturingMember2022-01-012022-12-310001466593us-gaap:OperatingSegmentsMemberottr:ManufacturingMember2021-01-012021-12-310001466593ottr:PlasticsMemberus-gaap:OperatingSegmentsMember2023-01-012023-12-310001466593ottr:PlasticsMemberus-gaap:OperatingSegmentsMember2022-01-012022-12-310001466593ottr:PlasticsMemberus-gaap:OperatingSegmentsMember2021-01-012021-12-310001466593us-gaap:CorporateNonSegmentMember2023-01-012023-12-310001466593us-gaap:CorporateNonSegmentMember2022-01-012022-12-310001466593us-gaap:CorporateNonSegmentMember2021-01-012021-12-310001466593us-gaap:OperatingSegmentsMemberottr:ElectricMember2023-12-310001466593us-gaap:OperatingSegmentsMemberottr:ElectricMember2022-12-310001466593us-gaap:OperatingSegmentsMemberottr:ManufacturingMember2023-12-310001466593us-gaap:OperatingSegmentsMemberottr:ManufacturingMember2022-12-310001466593ottr:PlasticsMemberus-gaap:OperatingSegmentsMember2023-12-310001466593ottr:PlasticsMemberus-gaap:OperatingSegmentsMember2022-12-310001466593us-gaap:CorporateNonSegmentMember2023-12-310001466593us-gaap:CorporateNonSegmentMember2022-12-310001466593ottr:RetailResidentialMemberottr:ElectricMember2023-01-012023-12-310001466593ottr:RetailResidentialMemberottr:ElectricMember2022-01-012022-12-310001466593ottr:RetailResidentialMemberottr:ElectricMember2021-01-012021-12-310001466593ottr:RetailCommercialAndIndustrialMemberottr:ElectricMember2023-01-012023-12-310001466593ottr:RetailCommercialAndIndustrialMemberottr:ElectricMember2022-01-012022-12-310001466593ottr:RetailCommercialAndIndustrialMemberottr:ElectricMember2021-01-012021-12-310001466593ottr:RetailOtherMemberottr:ElectricMember2023-01-012023-12-310001466593ottr:RetailOtherMemberottr:ElectricMember2022-01-012022-12-310001466593ottr:RetailOtherMemberottr:ElectricMember2021-01-012021-12-310001466593ottr:ElectronicProductRetailMemberottr:ElectricMember2023-01-012023-12-310001466593ottr:ElectronicProductRetailMemberottr:ElectricMember2022-01-012022-12-310001466593ottr:ElectronicProductRetailMemberottr:ElectricMember2021-01-012021-12-310001466593ottr:ElectricMemberus-gaap:ElectricTransmissionMember2023-01-012023-12-310001466593ottr:ElectricMemberus-gaap:ElectricTransmissionMember2022-01-012022-12-310001466593ottr:ElectricMemberus-gaap:ElectricTransmissionMember2021-01-012021-12-310001466593ottr:WholesaleMemberottr:ElectricMember2023-01-012023-12-310001466593ottr:WholesaleMemberottr:ElectricMember2022-01-012022-12-310001466593ottr:WholesaleMemberottr:ElectricMember2021-01-012021-12-310001466593ottr:ElectricMemberottr:ElectricProductOtherMember2023-01-012023-12-310001466593ottr:ElectricMemberottr:ElectricProductOtherMember2022-01-012022-12-310001466593ottr:ElectricMemberottr:ElectricProductOtherMember2021-01-012021-12-310001466593ottr:ElectricMember2023-01-012023-12-310001466593ottr:ElectricMember2022-01-012022-12-310001466593ottr:ElectricMember2021-01-012021-12-310001466593ottr:ManufacturingMemberottr:MetalPartsAndToolingMember2023-01-012023-12-310001466593ottr:ManufacturingMemberottr:MetalPartsAndToolingMember2022-01-012022-12-310001466593ottr:ManufacturingMemberottr:MetalPartsAndToolingMember2021-01-012021-12-310001466593ottr:ManufacturingMemberottr:PlasticProductsMember2023-01-012023-12-310001466593ottr:ManufacturingMemberottr:PlasticProductsMember2022-01-012022-12-310001466593ottr:ManufacturingMemberottr:PlasticProductsMember2021-01-012021-12-310001466593ottr:ManufacturingMemberottr:ScrapMetalMember2023-01-012023-12-310001466593ottr:ManufacturingMemberottr:ScrapMetalMember2022-01-012022-12-310001466593ottr:ManufacturingMemberottr:ScrapMetalMember2021-01-012021-12-310001466593ottr:ManufacturingMember2023-01-012023-12-310001466593ottr:ManufacturingMember2022-01-012022-12-310001466593ottr:ManufacturingMember2021-01-012021-12-310001466593ottr:PlasticsMember2023-01-012023-12-310001466593ottr:PlasticsMember2022-01-012022-12-310001466593ottr:PlasticsMember2021-01-012021-12-310001466593ottr:PensionAndOtherPostretirementBenefitPlansMember2023-12-310001466593ottr:PensionAndOtherPostretirementBenefitPlansMember2022-12-310001466593ottr:AlternativeRevenueProgramRidersMember2023-12-310001466593ottr:AlternativeRevenueProgramRidersMember2022-12-310001466593ottr:AssetRetirementObligationsMember2023-12-310001466593ottr:AssetRetirementObligationsMember2022-12-310001466593ottr:DeferredIncomeTaxesMember2023-12-310001466593ottr:DeferredIncomeTaxesMember2022-12-310001466593ottr:FuelClauseAdjustmentsMember2023-12-310001466593ottr:FuelClauseAdjustmentsMember2022-12-310001466593ottr:RegulatoryAssetDerivativeInstrumentsMember2023-12-310001466593ottr:RegulatoryAssetDerivativeInstrumentsMember2022-12-310001466593ottr:OtherRegulatoryAssetsMember2023-12-310001466593ottr:OtherRegulatoryAssetsMember2022-12-310001466593ottr:DeferredIncomeTaxesMember2023-12-310001466593ottr:DeferredIncomeTaxesMember2022-12-310001466593ottr:PlantRemovalObligationsMember2023-12-310001466593ottr:PlantRemovalObligationsMember2022-12-310001466593ottr:FuelClauseAdjustmentMember2023-12-310001466593ottr:FuelClauseAdjustmentMember2022-12-310001466593ottr:AlternativeRevenueProgramRidersMember2023-12-310001466593ottr:AlternativeRevenueProgramRidersMember2022-12-310001466593ottr:NorthDakotaPTCRefundsMember2023-12-310001466593ottr:NorthDakotaPTCRefundsMember2022-12-310001466593ottr:PensionAndOtherPostretirementBenefitPlansMember2023-12-310001466593ottr:PensionAndOtherPostretirementBenefitPlansMember2022-12-310001466593ottr:OtherRegulatoryLiabilitiesMember2023-12-310001466593ottr:OtherRegulatoryLiabilitiesMember2022-12-310001466593ottr:NDPSCMemberottr:NorthDakotaRateCaseMember2023-11-022023-11-020001466593us-gaap:ElectricGenerationEquipmentMemberottr:ElectricPlantMember2023-12-310001466593us-gaap:ElectricGenerationEquipmentMemberottr:ElectricPlantMember2022-12-310001466593ottr:ElectricPlantMemberottr:TransmissionPlantMember2023-12-310001466593ottr:ElectricPlantMemberottr:TransmissionPlantMember2022-12-310001466593ottr:ElectricPlantMemberottr:DistributionPlantMember2023-12-310001466593ottr:ElectricPlantMemberottr:DistributionPlantMember2022-12-310001466593ottr:ElectricPlantMemberottr:GeneralPlantMember2023-12-310001466593ottr:ElectricPlantMemberottr:GeneralPlantMember2022-12-310001466593ottr:ElectricPlantMemberottr:ElectricPlantInServiceMember2023-12-310001466593ottr:ElectricPlantMemberottr:ElectricPlantInServiceMember2022-12-310001466593ottr:ElectricPlantMemberus-gaap:ConstructionInProgressMember2023-12-310001466593ottr:ElectricPlantMemberus-gaap:ConstructionInProgressMember2022-12-310001466593ottr:ElectricPlantMember2023-12-310001466593ottr:ElectricPlantMember2022-12-310001466593us-gaap:EquipmentMemberottr:NonelectricPlantMember2023-12-310001466593us-gaap:EquipmentMemberottr:NonelectricPlantMember2022-12-310001466593ottr:BuildingsAndLeaseholdImprovementsMemberottr:NonelectricPlantMember2023-12-310001466593ottr:BuildingsAndLeaseholdImprovementsMemberottr:NonelectricPlantMember2022-12-310001466593ottr:NonelectricPlantMemberus-gaap:LandMember2023-12-310001466593ottr:NonelectricPlantMemberus-gaap:LandMember2022-12-310001466593ottr:NonelectricPlantMemberottr:NonelectricOperationsPlantMember2023-12-310001466593ottr:NonelectricPlantMemberottr:NonelectricOperationsPlantMember2022-12-310001466593us-gaap:ConstructionInProgressMemberottr:NonelectricPlantMember2023-12-310001466593us-gaap:ConstructionInProgressMemberottr:NonelectricPlantMember2022-12-310001466593ottr:NonelectricPlantMember2023-12-310001466593ottr:NonelectricPlantMember2022-12-310001466593ottr:BigStonePlantMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:BigStonePlantMember2023-12-310001466593ottr:CoyoteStationMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:CoyoteStationMember2023-12-310001466593ottr:OtterTailPowerCompanyMemberottr:BigStoneSouthEllendaleMultiValueProjectMember2023-12-310001466593ottr:BigStoneSouthEllendaleMultiValueProjectMember2023-12-310001466593ottr:FargoProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:FargoProjectMember2023-12-310001466593ottr:BigStoneSouthBrookingsMultiValueProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:BigStoneSouthBrookingsMultiValueProjectMember2023-12-310001466593ottr:BrookingsProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:BrookingsProjectMember2023-12-310001466593ottr:BemidjiProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:BemidjiProjectMember2023-12-310001466593ottr:JamestownProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:JamestownProjectMember2023-12-310001466593ottr:BigStoneSouthAlexandriaMultiValueProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:BigStoneSouthAlexandriaMultiValueProjectMember2023-12-310001466593ottr:AlexandriaProjectMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:AlexandriaProjectMember2023-12-310001466593ottr:BigStonePlantMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:BigStonePlantMember2022-12-310001466593ottr:CoyoteStationMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:CoyoteStationMember2022-12-310001466593ottr:OtterTailPowerCompanyMemberottr:BigStoneSouthEllendaleMultiValueProjectMember2022-12-310001466593ottr:BigStoneSouthEllendaleMultiValueProjectMember2022-12-310001466593ottr:FargoProjectMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:FargoProjectMember2022-12-310001466593ottr:BigStoneSouthBrookingsMultiValueProjectMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:BigStoneSouthBrookingsMultiValueProjectMember2022-12-310001466593ottr:BrookingsProjectMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:BrookingsProjectMember2022-12-310001466593ottr:BemidjiProjectMemberottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:BemidjiProjectMember2022-12-310001466593ottr:ManufacturingMember2023-12-310001466593ottr:ManufacturingMember2022-12-310001466593ottr:PlasticsMember2023-12-310001466593ottr:PlasticsMember2022-12-310001466593us-gaap:CustomerRelationshipsMember2023-12-310001466593us-gaap:OtherIntangibleAssetsMember2023-12-310001466593us-gaap:CustomerRelationshipsMember2022-12-310001466593us-gaap:OtherIntangibleAssetsMember2022-12-310001466593srt:ParentCompanyMember2023-12-310001466593ottr:OtterTailPowerCompanyMember2023-12-310001466593srt:ParentCompanyMember2022-12-310001466593ottr:OtterTailPowerCompanyMember2022-12-310001466593ottr:OtterTailCorporationCreditAgreementMember2023-12-310001466593ottr:OtterTailCorporationCreditAgreementMember2022-12-310001466593ottr:OTPCreditAgreementMember2023-12-310001466593ottr:OTPCreditAgreementMember2022-12-310001466593ottr:OTPCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2023-12-310001466593ottr:OtterTailCorporationCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2023-12-310001466593ottr:OtterTailCorporationCreditAgreementMemberus-gaap:LetterOfCreditMember2023-12-310001466593ottr:OTPCreditAgreementMemberus-gaap:LetterOfCreditMember2023-12-310001466593ottr:BenchmarkRateMembersrt:MinimumMember2023-01-012023-12-310001466593ottr:BenchmarkRateMembersrt:MaximumMember2023-01-012023-12-310001466593ottr:The355GuaranteedSeniorNotesDueDecember152026Member2023-12-310001466593ottr:The355GuaranteedSeniorNotesDueDecember152026Member2022-12-310001466593ottr:SeniorUnsecuredNotes637SeriesCDueAugust202027Member2023-12-310001466593ottr:SeniorUnsecuredNotes637SeriesCDueAugust202027Member2022-12-310001466593ottr:SeniorUnsecuredNotes468SeriesADueFebruary272029Member2023-12-310001466593ottr:SeniorUnsecuredNotes468SeriesADueFebruary272029Member2022-12-310001466593ottr:SeniorUnsecuredNotes307SeriesADueOctober102029Member2023-12-310001466593ottr:SeniorUnsecuredNotes307SeriesADueOctober102029Member2022-12-310001466593ottr:SeniorUnsecuredNotes307SeriesADueFebruary252030Member2023-12-310001466593ottr:SeniorUnsecuredNotes307SeriesADueFebruary252030Member2022-12-310001466593ottr:SeniorUnsecuredNotes322SeriesBDueAugust202030Member2023-12-310001466593ottr:SeniorUnsecuredNotes322SeriesBDueAugust202030Member2022-12-310001466593ottr:SeniorUnsecuredNotes274SeriesADueNovember292031Member2023-12-310001466593ottr:SeniorUnsecuredNotes274SeriesADueNovember292031Member2022-12-310001466593ottr:SeniorUnsecuredNotes647SeriesDDueAugust202037Member2023-12-310001466593ottr:SeniorUnsecuredNotes647SeriesDDueAugust202037Member2022-12-310001466593ottr:SeniorUnsecuredNotes352SeriesBDueOctober102039Member2023-12-310001466593ottr:SeniorUnsecuredNotes352SeriesBDueOctober102039Member2022-12-310001466593ottr:SeniorUnsecuredNotes362SeriesCDueFebruary252040Member2023-12-310001466593ottr:SeniorUnsecuredNotes362SeriesCDueFebruary252040Member2022-12-310001466593ottr:SeniorUnsecuredNotes547SeriesBDueFebruary272044Member2023-12-310001466593ottr:SeniorUnsecuredNotes547SeriesBDueFebruary272044Member2022-12-310001466593ottr:SeniorUnsecuredNotes407SeriesADueFebruary72048Member2023-12-310001466593ottr:SeniorUnsecuredNotes407SeriesADueFebruary72048Member2022-12-310001466593ottr:SeniorUnsecuredNotes382SeriesCDueOctober102049Member2023-12-310001466593ottr:SeniorUnsecuredNotes382SeriesCDueOctober102049Member2022-12-310001466593ottr:SeniorUnsecuredNotes392SeriesDDueFebruary252050Member2023-12-310001466593ottr:SeniorUnsecuredNotes392SeriesDDueFebruary252050Member2022-12-310001466593ottr:SeniorUnsecuredNotes369SeriesBDueNovember292051Member2023-12-310001466593ottr:SeniorUnsecuredNotes369SeriesBDueNovember292051Member2022-12-310001466593ottr:SeniorUnsecuredNotes377SeriesADueMay202052Member2023-12-310001466593ottr:SeniorUnsecuredNotes377SeriesADueMay202052Member2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2023-01-012023-12-31ottr:year0001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2023-01-012023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanReturnEnhancementMembersrt:MinimumMemberottr:PermittedRange35To60PercentMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanReturnEnhancementMembersrt:MaximumMemberottr:PermittedRange35To60PercentMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanReturnEnhancementMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanReturnEnhancementMember2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:PermittedRange40To80PercentMemberottr:DefinedBenefitPlanRiskManagementMembersrt:MinimumMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:PermittedRange40To80PercentMemberottr:DefinedBenefitPlanRiskManagementMembersrt:MaximumMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanRiskManagementMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanRiskManagementMember2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanAlternativesMembersrt:MinimumMemberottr:PermittedRange0To20PercentMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanAlternativesMembersrt:MaximumMemberottr:PermittedRange0To20PercentMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanAlternativesMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:DefinedBenefitPlanAlternativesMember2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2022-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:DefinedBenefitPlanEquitySecuritiesMember2023-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueInputsLevel3Member2023-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2023-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMember2023-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel1Member2023-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel3Member2023-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2023-12-310001466593us-gaap:FixedIncomeFundsMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberottr:DefinedBenefitPlanHybridFundsMember2023-12-310001466593us-gaap:FairValueInputsLevel2Memberottr:DefinedBenefitPlanHybridFundsMember2023-12-310001466593us-gaap:FairValueInputsLevel3Memberottr:DefinedBenefitPlanHybridFundsMember2023-12-310001466593us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberottr:DefinedBenefitPlanHybridFundsMember2023-12-310001466593ottr:DefinedBenefitPlanHybridFundsMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:USTreasuryAndGovernmentMember2023-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueInputsLevel3Member2023-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2023-12-310001466593us-gaap:USTreasuryAndGovernmentMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMember2023-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueInputsLevel3Member2023-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2023-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMember2023-12-310001466593us-gaap:FairValueInputsLevel1Member2023-12-310001466593us-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:FairValueInputsLevel3Member2023-12-310001466593us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:DefinedBenefitPlanEquitySecuritiesMember2022-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueInputsLevel3Member2022-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-12-310001466593us-gaap:DefinedBenefitPlanEquitySecuritiesMember2022-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel1Member2022-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueInputsLevel3Member2022-12-310001466593us-gaap:FixedIncomeFundsMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-12-310001466593us-gaap:FixedIncomeFundsMember2022-12-310001466593us-gaap:FairValueInputsLevel1Memberottr:DefinedBenefitPlanHybridFundsMember2022-12-310001466593us-gaap:FairValueInputsLevel2Memberottr:DefinedBenefitPlanHybridFundsMember2022-12-310001466593us-gaap:FairValueInputsLevel3Memberottr:DefinedBenefitPlanHybridFundsMember2022-12-310001466593us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberottr:DefinedBenefitPlanHybridFundsMember2022-12-310001466593ottr:DefinedBenefitPlanHybridFundsMember2022-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:USTreasuryAndGovernmentMember2022-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueInputsLevel3Member2022-12-310001466593us-gaap:USTreasuryAndGovernmentMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-12-310001466593us-gaap:USTreasuryAndGovernmentMember2022-12-310001466593us-gaap:FairValueInputsLevel1Memberottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMember2022-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueInputsLevel3Member2022-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-12-310001466593ottr:DefinedBenefitPlanOtherSEIEnergyDebtCollectiveFundMember2022-12-310001466593us-gaap:FairValueInputsLevel1Member2022-12-310001466593us-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:FairValueInputsLevel3Member2022-12-310001466593us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2021-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2022-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2021-12-310001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-12-310001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2022-01-012022-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2023-01-012023-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2022-01-012022-12-310001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-01-012022-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2023-12-310001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsToAge39Member2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsToAge39Member2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge40To49Member2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge40To49Member2022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge50AndOlderMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge50AndOlderMember2022-12-310001466593ottr:ParticipantsAge40To49NonUnionEmployeeMember2023-12-310001466593ottr:ParticipantsAge50AndOlderNonUnionEmployeeMember2023-12-310001466593us-gaap:PensionPlansDefinedBenefitMember2021-01-012021-12-310001466593ottr:ExecutiveSurvivorAndSupplementalRetirementPlanMember2021-01-012021-12-310001466593us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-01-012021-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsToAge39Member2023-01-012023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsToAge39Member2022-01-012022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsToAge39Member2021-01-012021-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge40To49Member2023-01-012023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge40To49Member2022-01-012022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge40To49Member2021-01-012021-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge50AndOlderMember2023-01-012023-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge50AndOlderMember2022-01-012022-12-310001466593us-gaap:PensionPlansDefinedBenefitMemberottr:ParticipantsAge50AndOlderMember2021-01-012021-12-310001466593us-gaap:StateAndLocalJurisdictionMember2023-12-310001466593ottr:TaxYears2024To2029Memberus-gaap:StateAndLocalJurisdictionMember2023-12-310001466593ottr:TaxYears2030To2037Memberus-gaap:StateAndLocalJurisdictionMember2023-12-310001466593us-gaap:StateAndLocalJurisdictionMemberottr:TaxYears2038To2043Member2023-12-310001466593ottr:ConstructionProgramsMemberottr:OtterTailPowerCompanyMember2023-01-012023-12-310001466593ottr:OTPLandEasementsMemberottr:OtterTailPowerCompanyMember2023-01-012023-12-310001466593ottr:ConstructionProgramAndOtherCommitmentsMembersrt:SubsidiariesMember2023-12-310001466593ottr:OtterTailPowerCompanyMemberottr:CapacityAndEnergyRequirementsMember2023-12-310001466593ottr:CoalPurchaseCommitmentsMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:FederalEnergyRegulatoryCommissionMemberottr:OtterTailPowerCompanyMember2023-12-310001466593us-gaap:CumulativePreferredStockMember2023-12-310001466593ottr:CumulativePreferenceSharesMember2023-12-310001466593us-gaap:CumulativePreferredStockMember2022-12-310001466593ottr:SecondShelfRegistrationMember2021-05-032021-05-030001466593ottr:SecondShelfRegistrationMember2023-01-012023-12-310001466593ottr:SecondShelfRegistrationMember2023-12-310001466593srt:MinimumMemberottr:OtterTailPowerCompanyMemberottr:MinnesotaPublicUtilitiesCommissionMember2023-01-012023-12-310001466593srt:MaximumMemberottr:OtterTailPowerCompanyMemberottr:MinnesotaPublicUtilitiesCommissionMember2023-01-012023-12-310001466593srt:MaximumMemberottr:OtterTailPowerCompanyMember2023-12-310001466593ottr:OtterTailPowerCompanyMember2023-01-012023-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2020-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2020-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2021-01-012021-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2021-01-012021-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2021-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2021-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2022-01-012022-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2022-01-012022-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2022-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2022-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2023-01-012023-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2023-01-012023-12-310001466593us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2023-12-310001466593us-gaap:AccumulatedNetUnrealizedInvestmentGainLossMember2023-12-310001466593ottr:The1999EmployeeStockPurchasePlanMember2023-12-310001466593ottr:The1999EmployeeStockPurchasePlanMember2023-01-012023-12-310001466593ottr:The1999EmployeeStockPurchasePlanMembersrt:MinimumMember2023-01-012023-12-310001466593ottr:The1999EmployeeStockPurchasePlanMembersrt:MaximumMember2023-01-012023-12-310001466593ottr:The1999EmployeeStockPurchasePlanMember2022-01-012022-12-310001466593ottr:The1999EmployeeStockPurchasePlanMember2021-01-012021-12-310001466593ottr:The2023StockIncentivePlanMember2023-04-300001466593ottr:The2023StockIncentivePlanMember2023-04-012023-04-300001466593ottr:The2023StockIncentivePlanMember2023-12-310001466593ottr:The2023StockIncentivePlanMember2023-01-012023-12-310001466593ottr:The2023StockIncentivePlanMember2022-01-012022-12-310001466593ottr:The2023StockIncentivePlanMember2021-01-012021-12-310001466593srt:MinimumMemberus-gaap:RestrictedStockMember2023-01-012023-12-310001466593srt:MaximumMemberus-gaap:RestrictedStockMember2023-01-012023-12-310001466593us-gaap:RestrictedStockMember2023-01-012023-12-310001466593us-gaap:RestrictedStockMember2022-12-310001466593us-gaap:RestrictedStockMember2023-12-310001466593us-gaap:RestrictedStockMember2022-01-012022-12-310001466593us-gaap:RestrictedStockMember2021-01-012021-12-310001466593us-gaap:PerformanceSharesMember2023-01-012023-12-310001466593us-gaap:PerformanceSharesMembersrt:MinimumMember2023-01-012023-12-310001466593us-gaap:PerformanceSharesMembersrt:MaximumMember2023-01-012023-12-310001466593us-gaap:PerformanceSharesMember2023-12-31ottr:measure0001466593us-gaap:PerformanceSharesMember2022-01-012022-12-310001466593us-gaap:PerformanceSharesMember2021-01-012021-12-310001466593us-gaap:PerformanceSharesMember2022-12-310001466593us-gaap:EmployeeStockOptionMember2023-01-012023-12-310001466593us-gaap:EmployeeStockOptionMember2022-01-012022-12-310001466593us-gaap:EmployeeStockOptionMember2021-01-012021-12-31utr:MWh0001466593us-gaap:SwapMember2023-01-012023-12-310001466593us-gaap:SwapMember2022-01-012022-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Member2023-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CorporateDebtSecuritiesMember2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:CorporateDebtSecuritiesMemberus-gaap:FairValueInputsLevel2Member2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Memberus-gaap:CorporateDebtSecuritiesMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberottr:GovernmentDebtSecuritiesMember2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Memberottr:GovernmentDebtSecuritiesMember2023-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Memberottr:GovernmentDebtSecuritiesMember2023-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Member2022-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CorporateDebtSecuritiesMember2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:CorporateDebtSecuritiesMemberus-gaap:FairValueInputsLevel2Member2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Memberus-gaap:CorporateDebtSecuritiesMember2022-12-310001466593us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberottr:GovernmentDebtSecuritiesMember2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Memberottr:GovernmentDebtSecuritiesMember2022-12-310001466593us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel3Memberottr:GovernmentDebtSecuritiesMember2022-12-310001466593us-gaap:CarryingReportedAmountFairValueDisclosureMember2023-12-310001466593us-gaap:EstimateOfFairValueFairValueDisclosureMember2023-12-310001466593us-gaap:CarryingReportedAmountFairValueDisclosureMember2022-12-310001466593us-gaap:EstimateOfFairValueFairValueDisclosureMember2022-12-310001466593srt:ParentCompanyMemberus-gaap:RelatedPartyMember2023-12-310001466593srt:ParentCompanyMemberus-gaap:RelatedPartyMember2022-12-310001466593srt:ParentCompanyMemberus-gaap:RelatedPartyMember2023-01-012023-12-310001466593srt:ParentCompanyMemberus-gaap:RelatedPartyMember2022-01-012022-12-310001466593srt:ParentCompanyMemberus-gaap:RelatedPartyMember2021-01-012021-12-310001466593srt:ParentCompanyMember2023-01-012023-12-310001466593srt:ParentCompanyMember2022-01-012022-12-310001466593srt:ParentCompanyMember2021-01-012021-12-310001466593us-gaap:NonrelatedPartyMembersrt:ParentCompanyMember2023-01-012023-12-310001466593us-gaap:NonrelatedPartyMembersrt:ParentCompanyMember2022-01-012022-12-310001466593us-gaap:NonrelatedPartyMembersrt:ParentCompanyMember2021-01-012021-12-310001466593srt:ParentCompanyMember2021-12-310001466593srt:ParentCompanyMember2020-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailPowerCompanyMemberottr:OtterTailCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:NorthernPipeProductsIncMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:VinyltechCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:BTDManufacturingIncMemberottr:OtterTailCorporationMember2023-12-310001466593ottr:TOPlasticsIncMemberus-gaap:RelatedPartyMemberottr:OtterTailCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:VaristarCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailAssuranceLimitedMemberottr:OtterTailCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMember2023-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailPowerCompanyMemberottr:OtterTailCorporationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:NorthernPipeProductsIncMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:VinyltechCorporationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:BTDManufacturingIncMemberottr:OtterTailCorporationMember2022-12-310001466593ottr:TOPlasticsIncMemberus-gaap:RelatedPartyMemberottr:OtterTailCorporationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMemberottr:VaristarCorporationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailAssuranceLimitedMemberottr:OtterTailCorporationMember2022-12-310001466593us-gaap:RelatedPartyMemberottr:OtterTailCorporationMember2022-12-310001466593us-gaap:AllowanceForCreditLossMember2022-12-310001466593us-gaap:AllowanceForCreditLossMember2023-01-012023-12-310001466593us-gaap:AllowanceForCreditLossMember2023-12-310001466593us-gaap:AllowanceForCreditLossMember2021-12-310001466593us-gaap:AllowanceForCreditLossMember2022-01-012022-12-310001466593us-gaap:AllowanceForCreditLossMember2020-12-310001466593us-gaap:AllowanceForCreditLossMember2021-01-012021-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2022-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2023-01-012023-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2023-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2021-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2022-01-012022-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2020-12-310001466593us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember2021-01-012021-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2023 or
    Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number 0-53713 
OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter) 
Minnesota
(State or other jurisdiction of incorporation or organization)
27-0383995
(I.R.S. Employer Identification No.)
215 South Cascade Street, Box 496, Fergus Falls, Minnesota
(Address of principal executive offices)
56538-0496
(Zip Code)
Registrant's telephone number, including area code: 866-410-8780
Securities registered pursuant to Section 12(b) of the Act: 
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Shares, par value $5.00 per shareOTTRThe Nasdaq Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act: None 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes     No  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes     No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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 pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes       No   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): 
 
Large Accelerated Filer
Accelerated Filer
 
Non-Accelerated Filer
Smaller Reporting Company
Emerging Growth Company
 
If an emerging growth company, 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.   
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).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes    No  
As of June 30, 2023, the aggregate market value of common stock held by non-affiliates was $3,646,181,401
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 41,710,521 Common Shares ($5 par value) as of January 31, 2024
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's definitive Proxy Statement for its 2024 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.


TABLE OF CONTENTS
 DescriptionPage
 
  
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 1C.
ITEM 2.
ITEM 3.
ITEM 3A.
Information About Our Executive Officers (as of February 14, 2024) 
ITEM 4.
  
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8. 
 
 
 
 
 
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 9C.
  
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
  
ITEM 15.
ITEM 16.
 

1

DEFINITIONS
The following abbreviations or acronyms are used in the text.
AFUDCAllowance for Funds Used During Constructionkwhkilowatt-hour
AME
Available Maximum Energy
LSALignite Sales Agreement
AROAsset Retirement ObligationMDTMetering and Distribution Technology
ARPAlternative Revenue ProgramMISOMidcontinent Independent System Operator
ASC
Accounting Standards Codification
MW
Megawatt
BTDBTD Manufacturing, Inc.
MPUC
Minnesota Public Utilities Commission
CCMCCoyote Creek Mining Company, L.L.C.NAVNet Asset Value
CCSCarbon Capture and SequestrationNDDEQNorth Dakota Department of Environmental Quality
CDDCooling Degree DayNDPSCNorth Dakota Public Service Commission
CISCritical Security ControlsNERCNorth American Electric Reliability Corporation
CO2
Carbon dioxideNorthern PipeNorthern Pipe Products, Inc.
COSO
Committee of Sponsoring Organizations of the Treadway Commission
OTCOtter Tail Corporation
ECO
Energy Conservation and Optimization Rider
OTPOtter Tail Power Company
EEIEdison Electric InstituteParis AgreementUnited Nations Framework Convention on Climate Change
EEPEnergy Efficiency PlanPFASPolyfluoroalkyl substances
EGUElectric Generating UnitPIRPhase-in Rider
EPAEnvironmental Protection AgencyPSLRAPrivate Securities Litigation Reform Act of 1995
ERISAEmployee Retirement Income Security Act of 1974PTCsProduction tax credits
ESSRPExecutive Survivor and Supplemental Retirement PlanPVCPolyvinyl chloride
EUICElectric Utility Infrastructure Costs RiderRHRRegional Haze Rule
FASBFinancial Accounting Standards BoardROEReturn on equity
FCAFuel Clause AdjustmentREC
Renewable Energy Certificate
FERCFederal Energy Regulatory CommissionRRRRenewable Resource Rider
FOB
Free on Board
SDPUCSouth Dakota Public Utilities Commission
GCRGeneration Cost Recovery RiderSECSecurities and Exchange Commission
GHGGreenhouse GasSIP
State implementation plan
HDDHeating Degree DaySOFRSecured Overnight Financing Rate
ICSPInformation and Cybersecurity ProgramT.O. PlasticsT.O. Plastics, Inc.
IRPIntegrated Resource PlanTCRTransmission Cost Recovery Rider
ITCsInvestment Tax Credits
TSR
Total Shareholder Return
kVkiloVoltVIEVariable Interest Entity
kWkiloWattVinyltechVinyltech Corporation
2


WHERE TO FIND MORE INFORMATION
We make available free of charge at our website (www.ottertail.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy and information statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). These reports are also available on the SEC's website (www.sec.gov). Information on our and the SEC's websites is not deemed to be incorporated by reference into this report on Form 10-K.
FORWARD-LOOKING INFORMATION
This report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the PSLRA). When used in this Form 10-K and in future filings by the Company with the SEC, in the Company’s press releases and in oral statements, words such as “anticipate,” “believe,” "can,"“could,” “estimate,” “expect,” "future," "goal," “intend,” "likely," “may,” “outlook,” “plan,” “possible,” “potential,” "predict," "probable," "projected ," “should,” "target," “will,” “would” or similar expressions are intended to identify forward-looking statements within the meaning of the PSLRA. Such statements are based on current expectations and assumptions and entail various risks and uncertainties that could cause actual results to differ materially from those expressed in such forward-looking statements. Such risks and uncertainties include the various factors set forth in Item 1A. Risk Factors of this report on Form 10-K and in our other SEC filings.
3

PART I
ITEM 1.BUSINESS
Otter Tail Corporation (OTC) has interests in diversified operations that include an electric utility and manufacturing and plastic pipe businesses with corporate offices located in Fergus Falls, Minnesota and Fargo, North Dakota.
We classify our five operating companies into three reportable segments consistent with our business strategy and management structure. The following table depicts our three segments and the subsidiary entities included within each segment:
ELECTRIC SEGMENTMANUFACTURING SEGMENTPLASTICS SEGMENT
Otter Tail Power Company (OTP)BTD Manufacturing, Inc. (BTD)Northern Pipe Products, Inc. (Northern Pipe)
T.O. Plastics, Inc. (T.O. Plastics)Vinyltech Corporation (Vinyltech)
Electric includes the generation, purchase, transmission, distribution and sale of electric energy in western Minnesota, eastern North Dakota and northeastern South Dakota. Otter Tail Power (OTP), our largest operating subsidiary and primary business since 1907, serves more than 133,000 customers in more than 400 communities across a predominantly rural and agricultural service territory.
Manufacturing consists of businesses engaged in the following manufacturing activities: contract machining; metal parts stamping; fabrication and painting; and production of plastic thermoformed horticultural containers, life science and industrial packaging, material handling components and extruded raw material stock. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the western half of the United States and Canada.
Throughout the remainder of this report, we use the terms "Company", "us", "our", or "we" to refer to OTC and its subsidiaries collectively. We will also refer to our Electric, Manufacturing and Plastics segments and our individual subsidiaries as indicated above.
INVESTMENT AND GROWTH STRATEGY
We maintain a moderate risk profile by investing in rate base growth opportunities in our Electric segment and organic growth opportunities in our Manufacturing and Plastics segments (collectively, our manufacturing platform). This strategy and risk profile are designed to provide a more predictable and growing earnings stream, support quality credit ratings, and provide for dividend payments.
Our long-term focus remains on executing our strategy to grow our business and achieving operational, commercial and talent excellence to strengthen our position in the markets we serve. Our long-term financial objectives include achieving a compounded annual growth rate in earnings per share in the range of 5 - 7%, with a long-term earnings mix of approximately 65% from our Electric segment and 35% from our manufacturing platform. We also are targeting an annual increase in our dividend to be in the range of 5 - 7%. We expect our earnings growth and cash flow generation to be driven by rate base investments in our Electric segment and from existing capacities and planned investments within our Manufacturing and Plastics segments.
Over the past three years, we delivered earnings growth well in excess of our 5 - 7% target due to unique industry conditions within the PVC pipe industry, which led to extraordinary revenue, earnings and cash flow growth in our Plastics Segment. We expect these industry conditions to gradually normalize over the course of 2024 and into 2025. As they do, we expect earnings and cash flow generation within our Plastics segment to moderate from current levels. Once these industry conditions have normalized, we expect to achieve our long-term financial objectives as outlined above.
We will continue to review our business portfolio to identify additional opportunities to improve our risk profile, enhance our credit metrics and generate additional sources of cash to support the organic growth opportunities in our Electric, Manufacturing, and Plastics segments. We will also evaluate opportunities to allocate capital to potential acquisitions. We are a committed long-term owner and do not acquire companies in pursuit of short-term gains. However, we will divest of businesses which no longer fit into our strategy and risk profile over the long term.
We maintain a set of criteria used in evaluating the strategic fit of our operating businesses. The operating company should:
Maintain a minimum level of net earnings and a return on invested capital in excess of the Company’s weighted-average cost of capital,
Have a strategic differentiation from competitors and a sustainable cost advantage,
Operate within a stable and growing industry and be able to quickly adapt to changing economic cycles, and
Have a strong management team committed to operational and commercial excellence.

4

Our actual mix of earnings for the years ended December 31, 2023, 2022 and 2021 was as follows:
4441
HUMAN CAPITAL
Our employees are a critical resource and an integral part of our success. We strive to provide an environment of opportunity and accountability where people are valued and empowered to do their best work. We are focused on the health and safety of our employees and creating a culture of inclusion, excellence and learning, and our executive annual incentive plan reflects those commitments. We monitor various metrics and objectives associated with i) employee safety, ii) workforce stability, iii) management and workforce demographics, including gender, racial and ethnic diversity, iv) leadership development and succession planning and v) productivity. We have established the following in furtherance of these efforts:
Safety - Safety is one of our core values. In managing our business, we focus on the safety of our employees and have implemented safety programs and management practices to promote a culture of safety. Safety is also a metric used and evaluated in determining annual incentive compensation. We continually monitor the Occupational Safety and Health Administration Total Recordable Incident Rate (number of work-related injuries per 100 employees for a one-year period) and Lost Time Incident Rate (number of employees who lost time due to work-related injuries per 100 employees for a one-year period). New cases are reported and evaluated for corrective action during monthly safety meetings attended by safety professionals at all locations. Our 2023 Total Recordable Incident Rate was 1.70, compared to 2.08 in 2022 and our Lost Time Incident Rate was 0.53 in 2023, compared to 0.49 in 2022.
Employee and Leadership Development, Succession Planning and Training Programs - We invest in training and professional development for various levels of employees, management and leaders throughout the Company to ensure all have the necessary training and skills to perform their work well, and to build enterprise-wide understanding of our culture, strategy and processes. Annual succession planning, individual development planning, mentoring, and supervisory and leadership development programs all play a role in ensuring a capable leadership team now and in the future. Our skill progression and technical training programs help to retain a stable and skilled workforce.
Workforce Stability - Recruiting, retaining and developing employees is an important factor in our continued success and growth. We regularly evaluate our recruiting programs, employee retention and turnover rates.
Employee Engagement - To enhance the effectiveness of our workforce and to help our companies continue to be places where our employees choose to work and thrive, we have undertaken a multi-year series of employee engagement surveys. We use the feedback to help shape the employee programs of our organization.
Human Rights - We are committed to the protection of our employee’s freedom of expression and freedom of organization and assembly.
Diversity, Equity, and Inclusion - We expect, and are committed to, diversity, equity and inclusion as part of who we are, what we value, and how we achieve individual, business and community success. We hold every employee accountable for their behavior in maintaining a workplace free of discrimination and harassment. We have implemented education initiatives for all employees, aimed at inclusive leadership and a respectful workplace, focused on identities and culture, unconscious bias, the power of diverse teams and culturally sensitive conversations. We have implemented initiatives to improve upon our demographic profile, including revised hiring processes and a commitment to diverse slates of interview candidates.
Code of Business Ethics - We require employees to complete training on several topics associated with our code of business ethics to reinforce our commitment to compliance with laws, regulations and values that guide who we are and how we do business.
5

As of December 31, 2023, we employed 2,655 full-time employees as shown in the table below:
Segment/OrganizationEmployees
Electric Segment
OTP (1)
790 
Manufacturing Segment
BTD1,458 
T.O. Plastics192 
Segment Total1,650 
Plastics Segment
Northern Pipe98 
Vinyltech80 
Segment Total178 
Corporate37 
Total2,655 
(1) Includes all full-time employees of Otter Tail Power Company, including employees working at jointly owned facilities. Labor costs associated with employees working at jointly owned facilities are allocated to each of the co-owners based on their ownership interest.
At December 31, 2023, 378 employees of OTP were represented by local unions of the International Brotherhood of Electrical Workers under two separate collective bargaining agreements expiring on August 31, 2026 and October 31, 2026. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good. None of the employees of our other operating companies are represented by local unions.
The demographics of our workforce, including our Board of Directors, as of December 31, 2023 was as follows:
% Female% Racially and Ethnically Diverse
Board of Directors
36 %%
CEO Direct Reports33 %— %
Management21 %%
Non-Management Employees15 %15 %
ELECTRIC
Contribution to Operating Revenues: 39% (2023), 38% (2022), 40% (2021)
OTP, headquartered in Fergus Falls, Minnesota, is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve its more than 133,000 residential, commercial and industrial customers in a service area encompassing approximately 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota.
CUSTOMERS
Our service territory is predominantly rural and agricultural and includes over 400 communities, most of which have populations of less than 10,000. While our customer base includes relatively few large customers, sales to commercial and industrial customers are significant, with two customers accounting for 21% of segment operating revenues for the year ended December 31, 2023 and 16% for the year ended December 31, 2022.
The following charts summarize our retail electric revenues by state and by customer segment for the years ended December 31, 2023 and 2022:
922923
6

In addition to retail revenue, our Electric segment also generates operating revenues from the transmission of electricity for others over the transmission assets we wholly or jointly own with other transmission service providers, and from the sale of electricity we generate and sell into the wholesale electricity market.
COMPETITIVE CONDITIONS
Retail electric sales are made to customers in assigned service territories. As a result, most retail customers do not have the ability to choose their electric supplier. Competition is present in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and co-generators. Electricity also competes with other forms of energy.
Competition also arises from customers supplying their own power through distributed generation, which is the generation of electricity on-site or close to where it is needed in small facilities designed to meet local needs. Distributed energy resources can include combined heat and power, solar photovoltaic, wind, battery storage, thermal storage and demand-response technologies.
The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy and advances in technology. Irrespective of the competitive environment, we are focused on providing value to our customers and ensuring our retail rates remain among the lowest in the region and in the nation.
The following table presents our average retail rate per kilowatt-hour (kwh) by customer class and in total for the years ended December 31, 2023 and 2022:
Revenue per kwh20232022
Residential10.82 ¢10.99 ¢
Commercial & Industrial7.02 ¢7.54 ¢
Total Retail7.90 ¢8.41 ¢
Wholesale electricity markets are competitive under the Federal Energy Regulatory Commission (FERC) open access transmission tariffs, which require utilities to provide nondiscriminatory access to all wholesale users. In addition, the FERC has established a competitive process for the construction and operation of certain new electric transmission facilities under federal regulation. Certain states have laws which provide the incumbent transmission owner the right of first refusal to construct and own new transmission facilities.
OTP has franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves. Franchise rights generally require periodic renewal. No franchises are required to serve unincorporated communities in any of the three states OTP serves.
GENERATION AND PURCHASED POWER
OTP primarily relies on company-owned generation, supplemented by power purchase agreements, to supply the energy to meet our customer needs. Wholesale market purchases and sales of electricity are used as necessary to balance supply and demand. Our mix of owned generation and wholesale market energy purchases to meet customer demand are impacted by wholesale energy prices and the relative cost of each energy source.
7

As of December 31, 2023, OTP’s wholly or jointly owned plants and facilities, as well as in place power purchase agreements, and their dependable kilowatt (kW) capacity were:
 Capacity /
Purchased Power
in kW
Owned Generation:
Baseload Plants 
Big Stone Plant(1)
256,900 
Coyote Station(2)
148,400 
Total Baseload Plants405,300 
Combustion Turbine and Small Diesel Units
Astoria Station249,700 
All Other102,800 
Total Combustion Turbine and Small Diesel Units352,500 
Owned Wind Facilities (rated at nameplate)
Merricourt
150,000 
Ashtabula III
62,400 
Luverne
49,500 
Ashtabula
48,000 
Langdon
40,500 
Total Owned Wind Facilities350,400 
Hoot Lake Solar
49,900 
Hydroelectric Facilities2,600 
Total Owned Generation Capacity1,160,700 
 Power Purchase Agreements:
Purchased Wind Power (rated at nameplate and greater than 2,000 kW)
Edgeley21,000 
Langdon19,500 
Total Purchased Wind40,500 
Total Generating Capacity1,201,200 
(1) Reflects OTP's 53.9% ownership percentage of jointly owned facility.
(2) Reflects OTP's 35.0% ownership percentage of jointly owned facility.
The following charts summarize the percentage of our generating capacity by source, including owned and jointly owned facilities and through power purchase arrangements, as of December 31, 2023 and 2022:
45854586    
Under Midcontinent Independent System Operator (MISO) requirements, OTP is required to provide sufficient capacity through wholly or jointly owned generating capacity or power purchase agreements to meet its monthly weather-normalized forecast demand, plus a reserve obligation. MISO operates under a seasonal resource adequacy construct in which generation resources are accredited and planning reserve margin requirements are implemented on a seasonal basis. Current planning reserve margin requirements range between 7.4% and 25.5%, depending on the season.
8

The following charts summarize the percentage of retail kwh sold by source during the years ended December 31, 2023 and 2022:
60116012                    
Capacity Additions
As part of our investment plan to meet our future energy needs, the following projects have been recently undertaken, completed, or acquired:
Ashtabula III Wind Farm is a 62-megawatt (MW) wind farm located in eastern North Dakota. The facility was purchased for approximately $50 million in January 2023. Prior to the purchase of the wind farm assets, we were purchasing the wind-generated electricity from the wind farm pursuant to a power purchase agreement.
Hoot Lake Solar is a 49-MW solar farm constructed on and around our Hoot Lake Plant property in Fergus Falls, Minnesota, with a total cost of approximately $60 million. The facility was placed into commercial operation in August 2023.
Wind Energy Facility Upgrades consisting of the replacement and upgrade of hubs, gearboxes, blades, generators and other components of our Ashtabula, Ashtabula III, Langdon and Luverne wind facilities at a total cost of approximately $230 million. Once complete, we expect the increased energy production from these facilities will be equivalent to an additional 40-MW of generation. We anticipate the repowering of our Langdon facility will be completed in 2024 and the remaining facilities to be completed in 2025. Once complete, the energy production from each of these facilities is eligible for production tax credits (PTCs) over a ten-year period. We expect these projects will lower customer costs through a combination of fuel savings and the tax credit benefits afforded to our customers.
ENERGY TRANSITION
OTP is committed to transitioning to a lower-carbon and increasingly clean energy future, while maintaining affordable and reliable electricity to serve our customers. We have developed the following goals in furtherance of our efforts to support the energy transition:
Own or purchase energy generation that is 55% renewable by 2030.
Reduce carbon emissions from owned generation resources 50% by 2030 from 2005 levels.
Reduce carbon emissions from owned generation resources 97% by 2050 from 2005 levels.
We have based these goals on our December 2023 supplemental Integrated Resource Plan (IRP) filing in Minnesota. While modified from our previously published goals, they reflect current market conditions, including the impact of higher natural gas prices, and higher than originally forecasted dispatch levels of our co-owned, coal-fired power plants.
We have undertaken numerous initiatives to reduce our carbon footprint and mitigate greenhouse gas (GHG) emissions in the process of generating electricity for our customers. Our recent initiatives include retiring the 140-MW coal-fired Hoot Lake Plant, adding the 150-MW Merricourt Wind Energy Center and the 49-MW Hoot Lake Solar facility to our resource mix and sponsoring energy conservation programs. We anticipate our Minnesota retail sales will be 80% carbon free by 2030, in compliance with Minnesota clean energy requirements.
From 2005 through 2023, we have reduced our carbon dioxide (CO2) emissions approximately 39% and increased the amount of renewable generation resources we own or purchase through power purchase agreements by approximately 420-MW. We currently own or contract energy generation that is 37% renewable.

9

The following chart depicts our energy resource mix, which is the electricity we used to serve our customers in 2005 and 2023, and the projected mix in 2030 and 2050. The amounts include energy generated from owned resources, procured through power purchase agreements and energy purchased in the wholesale market:
9150
RESOURCE MATERIALS
Coal is the principal fuel burned at our jointly owned Big Stone and Coyote Station generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Big Stone Plant burns western subbituminous coal transported by rail. We source coal for our coal-fired power plants through requirements contracts which do not include minimum purchase requirements but do require all coal necessary for the operation of the respective plant to be purchased from the counterparty. Our coal supply contracts for our Big Stone Plant and Coyote Station have expiration dates in 2024 and 2040, respectively.
The supply agreement between the Coyote Station owners, including OTP, and the coal supplier includes provisions requiring the Coyote Station owners to purchase the membership interests and pay off or assume loan and lease obligations of the coal supplier, as well as complete mine closing and post-mining reclamation, in the event of certain early termination events and at the expiration of the coal supply agreement in 2040. See below and Note 1 to our consolidated financial statements included in this report on Form 10-K for additional information.
Coal is transported to Big Stone Plant by rail and is provided under a common carrier rate which includes a mileage-based fuel surcharge.
We purchase natural gas for use at our combustion turbine facilities based on anticipated short-term resource needs. We procure natural gas from multiple vendors at spot prices in a liquid market primarily under firm delivery contracts.
TRANSMISSION AND DISTRIBUTION
Our transmission and distribution assets deliver energy from energy generation sources to our customers. In addition, we earn revenue from the transmission of electricity over our wholly or jointly owned transmission assets for others under approved rate tariffs. As of December 31, 2023, we were the sole or joint owner of approximately 14,000 miles of transmission and distribution lines.
Midcontinent Independent System Operator
MISO is an independent, non-profit organization that operates the transmission facilities owned by other entities, including OTP, within its regional jurisdiction and administers energy and generation capacity markets. MISO has operational control of our transmission facilities above 100 kilovolts (kV). MISO seeks to optimize the efficiency of the interconnected system, provide solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions.
Transmission Additions
In 2022, MISO approved several projects within the first tranche of its long-range transmission plan, which includes two new 345 kV transmission projects. OTP will have a varying level of ownership interest in these projects, which will be completed over several years and are at various stages of planning and development:
Jamestown-Ellendale includes the construction of a new 345 kV transmission line in southeastern North Dakota spanning approximately 95 miles from Jamestown, North Dakota to Ellendale, North Dakota. This project is in the initial stages of planning and development. This jointly owned project is expected to be completed in 2028 and our capital investment is estimated to be approximately $230 million.
Big Stone South-Alexandria-Big Oaks includes the construction of a new 345 kV transmission line in eastern South Dakota and western Minnesota and the addition of a second circuit to an existing 345 kV line in central Minnesota. The new transmission line will span approximately 100 miles between Big Stone, South Dakota and Alexandria, Minnesota. A second circuit will be added to the existing transmission line spanning from Alexandria, Minnesota to Big Oaks, Minnesota. This project is in the initial stages of planning and development. This jointly owned project is expected to be completed in 2031 and our capital investment is estimated to be approximately $190 million.
SEASONALITY
Electricity demand is affected by seasonal weather differences, with peak demand occurring in the summer and winter months. As a result, our Electric segment operating results regularly fluctuate on a seasonal basis. In addition, fluctuations in electricity demand within the same season but
10

between years can impact our operating results. We monitor the level of heating and cooling degree days in a period to assess the impact of weather-related effects on our operating results between periods.
PUBLIC UTILITY REGULATION
OTP is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for, among other matters, the interstate transmission of electricity. OTP operates under approved retail electric tariff rates in all three states it serves. Tariff rates are designed to recover plant investments, a return on those investments, and operating costs. In addition to determining rate tariffs, state regulatory commissions also authorize return on equity (ROE), capital structure, and depreciation rates of our plant investments. Decisions by our regulators significantly impact our operating results, financial position, and cash flows.
Below is a summary of the regulatory agencies with jurisdiction of electric rates over OTP covered by each regulatory agency:
Regulatory
AgencyAreas of Regulation
Minnesota Public Utilities Commission
(MPUC)
Retail rates, issuance of securities, depreciation rates, capital structure, public utility services, construction of major facilities, establishment of exclusive assigned service areas, contracts with subsidiaries and other affiliated interests and other matters.
Selection or designation of sites for new generating plants (50,000 kW or more) and routes for transmission lines (100 kV or more).
Review and approval of fifteen-year Integrated Resource Plan.
North Dakota Public Service Commission
(NDPSC)
Retail rates, certain issuances of securities, construction of major utility facilities and other matters.
Approval of site and routes for new electric generating facilities (>500 kW for wind generating facilities; >50,000 kW for non-wind generating facilities) and high voltage transmission lines (>115 kV).
Review of fifteen-year Integrated Resource Plan.
South Dakota Public Utilities Commission
(SDPUC)
Retail rates, public utility services, construction of major facilities, establishment of assigned service areas and other matters.
Approval of sites and routes for new electric generating facilities (100,000 kW or more) and most transmission lines (115 kV or more).
Federal Energy Regulatory Commission
(FERC)
Wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, hydroelectric licensing and accounting policies and practices.
Compliance with North American Electric Reliability Corporation (NERC) reliability standards, including standards on cybersecurity and protection of critical infrastructure.
In addition to base rates, which are established through periodic rate case proceedings within each state jurisdiction, there are other mechanisms for recovery of our capital investments and operating expenses between rate cases. The following table summarizes these recovery mechanisms:
Recovery MechanismJurisdiction(s)Additional Information
Fuel Clause Adjustment (FCA)MN, ND, SD
Provides for periodic billing adjustments for changes in prudently incurred costs of fuel and purchased power. In North and South Dakota, fuel and purchased power costs are generally adjusted on a monthly basis. In Minnesota, fuel and purchased power costs are estimated on an annual basis and the accumulated difference between actual and estimated cost per kwh is refunded or recovered, subject to regulatory approval, in subsequent periods.
Transmission Cost Recovery Rider (TCR)MN, ND, SDProvides for the recovery of costs outside of a general rate case for investments in new or modified electric transmission assets and certain MISO transmission service and related costs.
Renewable Resource Rider (RRR)MN, NDProvides for the recovery of costs outside of a general rate case for investments in certain new renewable energy projects.
Energy Conservation and Optimization Rider (ECO)
MN
Under Minnesota law, OTP is required to save 1.75% of its gross retail energy revenues through the energy conservation and optimization program. Recovery of these costs outside of a general rate case occurs through the ECO rider.
Electric Utility Infrastructure Costs Rider (EUIC)MNProvides for the recovery of costs for investments made to replace or modify existing infrastructure if the replacement or modification conserves energy or uses energy more efficiently.
Metering and Distribution Technology Cost Recovery Rider (MDT)
NDProvides for the recovery of costs for advanced metering infrastructure, outage management systems and demand response projects.
Generation Cost Recovery Rider (GCR)NDProvides for the recovery of costs outside of a general rate case for investments in new generation facilities.
Energy Efficiency Plan (EEP)SDProvides for the recovery of costs from energy efficiency investments.
Phase-In Rider (PIR)SDProvides for the recovery of costs outside of a general rate case for investments in new generation facilities and advanced grid infrastructure.
11

Resource Planning
Under Minnesota law, utilities are required to submit for approval by the Minnesota Public Utilities Commission (MPUC) a 15-year advance Integrated Resource Plan (IRP). An IRP is a set of resource options a utility could use to meet the service needs of its customers over the forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding IRPs are considered to be prima facie evidence, subject to rebuttal, in future rate reviews and other proceedings.
In 2021, the North Dakota Legislative Assembly enacted a provision requiring investor-owned electric utilities to submit an IRP to the North Dakota Public Service Commission (NDPSC) and granted the NDPSC the authority to adopt rules and regulations for the preparation and submission of IRPs. The NDPSC's rules and regulations were finalized and became effective on January 1, 2023. Under the finalized regulation, utilities are required to submit a 15-year advance IRP every three years.
Capital Structure Petition
Minnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing the MPUC reviews and approves OTP's capital structure. Once approved, OTP may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved petition. OTP’s current capital structure approved by the MPUC on August 29, 2023, allows for an equity-to-total-capitalization ratio between 48.3% and 59.1%, with total capitalization not to exceed $1.958 billion.
Renewable Energy Standard
Minnesota has a renewable energy standard requiring utilities to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 25% by 2025 and 55% by 2035. Qualifying renewable sources are classified as wind, hydropower, hydrogen, and certain biomass generation. We met the current renewable sources requirements with a combination of owned renewable generation and purchases from renewable generation sources. Minnesota law also requires 1.5% of total Minnesota retail electric sales by public utilities to be supplied by solar energy. For a public utility with between 50,000 and 200,000 retail electric customers, such as OTP, at least 10% of the 1.5% requirement must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less. We met the current solar requirement with a combination of owned solar generation and solar renewable energy certificate (REC) purchases. We plan to comply with the requirements of this standard in the future through a combination of our existing and projected renewable generation fleet and the purchase of RECs.
Minnesota Clean Energy Bill
In February 2023, Minnesota enacted the Clean Energy Bill, which requires electric utilities to generate or procure sufficient electricity from carbon-free resources, to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040. Carbon-free resources include wind, solar, hydropower, and nuclear generation. To provide flexibility, the law allows electric utilities to use RECs to offset carbon emissions and for the MPUC to consider whether a regulated utility's requirement to meet established standards should be delayed due to affordability or reliability impacts. We expect to meet these requirements based on our existing and projected renewable generation fleet and the purchase of RECs.
ENVIRONMENTAL REGULATION
OTP is subject to stringent federal and state environmental standards and regulations regarding, among other things, air, water and solid waste pollution. OTP's facilities have been designed, constructed and, as necessary, updated to operate in compliance with applicable environmental regulations. However, new or amended laws and regulations or changes in interpretations of current laws and regulations may require additional pollution control equipment or emission reduction measures, and there can be no assurance that our facilities will remain economic to operate. Prudent expenditures incurred to comply with environmental regulations are eligible to be recovered in rates authorized by regulators in jurisdictions in which we operate; however, there can be no assurance that future costs will be authorized for recovery. Alternatively, additional pollution control equipment or other emission reduction measures may prove to be uneconomic, potentially leading to the exiting of a facility earlier than originally planned. As it relates to our jointly owned facilities, we may determine it is necessary to transfer, sell or otherwise divest of our ownership, or the ownership group may determine the early closure or repurposing of a facility is necessary.
Financial Impacts
For the five-year period ended December 31, 2023, OTP invested approximately $6.6 million in environmental control facilities, including $1.4 million in 2023. Our construction budget for the next five years includes approximately $7.5 million of capital investments in environmental control equipment. The timing and amount of our expenditures may change as the regulatory environment changes.
Emerging Regulation
The Environmental Protection Agency (EPA) adopted the Regional Haze Rule (RHR) in 1999 as an effort to improve visibility in national parks and wilderness areas. The RHR requires states, in coordination with the EPA and other governmental agencies, to develop and implement state implementation plans (SIPs) that work towards achieving natural visibility conditions by the year 2064; to set goals to ensure reasonable progress is being made; and periodically evaluate whether those goals and progress are on track or whether additional emission reductions are appropriate. The second RHR implementation period covers the years 2018-2028.
Coyote Station is subject to assessment in the second implementation period under the North Dakota SIP for the RHR. The North Dakota Department of Environmental Quality (NDDEQ) submitted its proposed RHR SIP to the EPA for approval in August 2022. In its plan, the NDDEQ concluded it is not reasonable to require additional emission controls during this planning period. The EPA submitted comments during the development of the SIP requesting NDDEQ to reassess its determination for Coyote Station. See Note 13 to our consolidated financial statements for additional information. At this time we are unable to predict the ultimate impact, however, there could be a cost of compliance which could have a material impact on our operating results, financial condition and liquidity.
12

In April 2023, the EPA released a proposal to tighten aspects of the Mercury and Air Toxics Standards, including the reduction of emissions limits for filterable particulate matter, and requiring the use of continuous emissions monitoring systems to demonstrate compliance. Until the EPA takes final action on this rulemaking, we are unable to predict the ultimate impact, however, there could be a cost of compliance which could have a material impact on our operating results, financial condition and liquidity.
Climate Change and Greenhouse Gas Regulation
Global climate change presents a significant energy and environmental policy challenge. Combustion of fossil fuels for the generation of electricity is a considerable source of CO2 emissions, which is the primary GHG emitted by our utility operations. The federal government and many states are pursuing climate policies to regulate GHG emissions as part of a broad-based effort to limit global warming.
In February 2021, the U.S. rejoined the United Nations Framework Convention on Climate Change (the Paris Agreement), which is a legally binding international treaty on climate change adopted by over 190 countries. The goal of the Paris Agreement is to limit the global temperature increase to well below 2° Celsius compared to pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5° Celsius. The Biden Administration set goals of reducing GHG emissions by 50% to 52% from 2005 levels in 2030 and reaching 100% carbon pollution-free electricity by 2035 as part of the U.S. plan to achieve the goals under the Paris Agreement.
In February 2023, Minnesota enacted the Clean Energy Bill, which requires electric utilities to generate or procure sufficient electricity from carbon-free resources to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040.
The implementation of climate change programs, such as the Paris Agreement, the Minnesota Clean Energy Bill, and other federal or state regulations targeting GHG emissions may have a significant impact on our utility business. Specific regulatory measures to address climate change continue to evolve.
In May 2023, the EPA proposed new regulations under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based electric generating units (EGU). The proposal provides requirements for different types of fossil fuel-based EGUs with various compliance dates.
For existing coal-fired steam generating units that were in operation before January 8, 2014 and that plan to operate past December 31, 2039, the proposal would (subject to certain exceptions) set emissions standards that reflect the use of carbon capture and sequestration (CCS) with 90% capture of CO2 emissions beginning in 2030.
For existing coal-fired steam generating units that are scheduled to be retired between January 1, 2032 and December 31, 2039, the proposed rule would, in general, set emissions standards that reflect the use of co-firing 40% natural gas with coal beginning in 2030.
For existing coal-fired steam generating units that will either (a) retire by January 1, 2032, or (b) retire between 2032 and December 21, 2034 and will operate at a 20% annual capacity factor limit in the meantime, the proposed rule would simply require routine maintenance and no increase in emission rate.
The proposal also includes emission standards for existing large (greater than 300 mega-watt), frequently used (those that operate at a capacity factor over 50%) natural gas combustion turbines, including which emission standard would reflect the use of CCS by 2035 or co-firing with low-GHG hydrogen at incremental portions in 2032 (30% of volume) and 2038 (96% of volume). Under the proposed rule, each state must submit a plan to the EPA to implement standards that are at least as stringent as the EPA’s emission guidelines, unless states demonstrate that due to remaining useful life and other factors, a facility cannot reasonably achieve the standards. The EPA is proposing to require states to submit their plans within 24 months of the effective date of the final regulation. This proposed rule has the potential to impact the emissions controls needed at OTP’s coal-fired power plants, which could have an impact on our operating results, financial condition and liquidity.
While the future financial impact of any current, proposed, or pending litigation or regulation of GHG or other emissions is unknown at this time, any capital or operating costs incurred for additional pollution control equipment or emission reduction measures could materially adversely impact our future operating results, financial position, and liquidity unless such costs could be recovered through related rates and/or future market prices for energy.
MANUFACTURING
Contribution to Operating Revenues: 30% (2023), 27% (2022), 28% (2021)
Manufacturing consists of businesses engaged in the following activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components and extruded raw material stock. The following is a brief description of each of these businesses:
BTD Manufacturing, Inc. (BTD), with facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia, provides metal fabrication services for custom machine parts and metal components through metal stamping, tool and die, machining, tube bending, welding and assembly.
T.O. Plastics, Inc. (T.O. Plastics), with facilities in Otsego and Clearwater, Minnesota, manufactures thermoformed plastics products, including its own line of horticulture containers and custom packaging products for the medical and industrial product markets.
CUSTOMERS
Our metal fabrication business primarily serves Midwestern and Southeastern U.S. manufacturers in the recreational vehicle, lawn and garden, agricultural, construction, and industrial and energy equipment end markets. Our plastic products business serves primarily U.S. customers in the
13

horticulture, medical and life sciences, industrial, recreational and electronics industries. The principal method of production distribution is by direct shipment to our customers through direct customer pick-up or common carrier ground transportation.
No single customer or product of our Manufacturing segment businesses accounted for 10% or more of our consolidated operating revenues in 2023. However, two customers combined to account for 30% of segment operating revenues for the year ended December 31, 2023 and 40% for the year ended December 31, 2022.
COMPETITIVE CONDITIONS
We compete in a highly fragmented market with competition from both domestic and international entities. Our competitors vary in size, ranging from small companies focused on certain end markets or geographical area, to large companies with broad manufacturing capabilities and geographical reach. Competition can be geographically regionalized as customers procure products locally to manage cost and minimize logistical complexities. Certain competitors may have broader product lines, more manufacturing capacity, and greater distribution capabilities than we do.
We believe the principal competitive factors in our Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line. We intend to continue to compete based on high quality products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings. 
RESOURCE MATERIALS
We use raw materials in the products we manufacture, including, among others, steel, aluminum, and polystyrene and other plastics resins. Managing price volatility and ensuring raw material availability are important aspects of our business. We attempt to pass increases in the costs of these raw materials through to our customers. Increases in the costs of raw materials that cannot be passed on to customers could have a negative effect on profit margins. Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our Manufacturing segment as it reduces their ability to mitigate the costs associated with excess material.
ENVIRONMENTAL REGULATION
Our manufacturing businesses are subject to environmental, health and safety laws and regulations, including those governing discharges to air and water, the management and disposal of hazardous substances, the cleanup of contaminated sites and health and safety matters.
PLASTICS
Contribution to Operating Revenues: 31% (2023), 35% (2022), 32% (2021)
Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The following is a brief description of these businesses:
Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North Dakota, manufactures and sells PVC pipe for municipal water, rural water, wastewater, storm drainage systems and other uses in the northern, midwestern, south-central and western regions of the United States as well as central and western Canada.
Vinyltech Corporation (Vinyltech), located in Phoenix, Arizona, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the western, northwest and south-central regions of the United States.
PVC pipe is manufactured through an extrusion process, during which PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe. The newly extruded pipe is pulled through a series of water-cooling tanks, marked to identify the type of pipe and cut to finished lengths.
CUSTOMERS
PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for our PVC pipe products consist primarily of wholesalers and distributors, and the principal method for distribution of our products is by common carrier ground transportation. No single customer of the PVC pipe companies accounted for 10% or more of our consolidated operating revenues in 2023. However, two customers, both of which are distributors of PVC pipe, combined to account for 36% of segment operating revenues for the year ended December 31, 2023 and 46% for the year ended December 31, 2022.
COMPETITIVE CONDITIONS
The plastic pipe industry is fragmented and competitive due to the number of producers, the small number of raw material suppliers and the fungible nature of the product. Due to shipping costs, competition is usually regional instead of national in scope. The principal factors of competition are price, customer service and product performance. We compete not only against other plastic pipe manufacturers, but also ductile iron, high-density polyethylene, steel and concrete pipe producers. Pricing pressure will continue to affect our operating margins in the future.
We will continue to compete based on our high-quality products, cost-effective production techniques and close customer relations and support, including our responsiveness and reliability.
14

RESOURCE MATERIALS
PVC resins are acquired in bulk and shipped to our facilities by rail. There are four vendors from which we can source our PVC resin requirements. In 2023 we sourced all of our PVC resin from three vendors. Our contractual arrangements to acquire resin generally include estimated annual order quantities with no required minimum purchases, and include variable pricing based on market prices for resin. The supply of PVC resin may also be limited primarily due to manufacturing capacity and the limited availability of raw material components. Most U.S. resin production plants are located in the Gulf Coast region. These plants are subject to the risk of damage and production shutdowns because of exposure to hurricanes or other extreme weather events that occur in this part of the United States. The loss of a key vendor, or any interruption or delay in the supply of PVC resin could disrupt the ability of our Plastics segment businesses to manufacture products, cause customers to cancel orders or result in increased expenses for obtaining PVC resin from alternative sources, if such sources were available. We believe we have good relationships with our key raw material vendors.
Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical with significant fluctuations in prices and gross margins.
In addition to PVC resin, we use certain other materials, such as stabilizers, gaskets and lumber, in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers, and supply chain constraints or disruptions related to these materials could disrupt our ability to manufacture or ship products and could result in increased costs.
SEASONALITY
Demand for our PVC pipe products can be impacted by seasonal weather differences, with generally lower sales volumes realized in the first quarter of the year when cold temperatures and frozen ground across the northern portion of our footprint can delay or prevent construction activity and consequently delay or prevent customer orders of PVC pipe.
ENVIRONMENTAL REGULATION
Our plastics businesses are subject to environmental, health and safety laws and regulations, including those governing discharges to air and water, the management and disposal of hazardous substances, the cleanup of contaminated sites and health and safety matters.
15

ITEM 1A.RISK FACTORS
RISK FACTORS AND CAUTIONARY STATEMENTS
Our businesses are subject to various risks and uncertainties. Any of the risks described below or elsewhere in this report on Form 10-K or in our other SEC filings could materially adversely affect our business, operating results, financial condition and liquidity. Additional risks and uncertainties we are not presently aware of or that we currently consider immaterial may also affect our business, operating results, financial condition and liquidity.
OPERATIONAL RISKS
Our strategy includes large capital investments, which are subject to risks.
Our business strategy includes major capital investments at our operating companies. These capital projects are planned years in advance of their in-service dates and are subject to various risks including: adverse changes in regulatory treatment or public policy; changes in commodity pricing or construction costs; delivery of critical materials; obtaining necessary permits and licenses; and other adverse conditions. Capital investments in our Electric segment require regulatory approval and are subject to the risks of not being granted timely approval or allowed to be fully recovered. In addition, our ability to construct and own utility assets may be impacted by regulatory requirements to competitively bid such investments, which could impact the amount and timing of our capital investments. A lack of direct ownership, or the inability to complete capital projects on budget and in a timely manner could impact our ability to achieve our strategic financial goals and could adversely impact our operating results and financial condition.
Weather impacts, including seasonal fluctuations, could adversely affect our operating results.
Our Electric segment business is seasonal and weather patterns have had an impact on our financial performance in the past and may again in the future. Demand for electricity is normally greater in the winter and summer months. Unusually mild summers and winters could have an adverse effect on our financial condition and results of operations. Our Plastics segment businesses can be affected by seasonal weather prohibiting or delaying construction projects at any time of the year in any geography, but specifically times of the year when frozen ground and cold temperatures in many parts of the country can delay construction projects, all of which can result in reduced customer demand and could have an adverse effect on our financial condition, operating results and liquidity.
We are subject to physical and transition risks associated with climate change and extreme weather events.
Longer term shifts in climate patterns may impact our customers' demand for electricity, interrupt our business operations and damage our facilities; reduce the availability of natural resources, such as water; and cause disruptions in our supply chains.
Climate change may increase the frequency and severity of extreme weather events, such as prolonged periods of extreme cold or heat, and natural disasters, such as severe snow and ice storms, tornadoes, flooding and wildfires. These acute events could result in the interruption of our business operations and damage to our facilities. An extreme weather event within our utility service area could directly affect our capital assets, causing disruption in service to customers, and result in reduced operating revenues and repair or replacement costs, due to downed wires and poles or damage to other operating equipment.
In the past, severe weather events in the Gulf Coast region of the U.S. have disrupted the supply of PVC resin, the primary material input of our Plastics segment businesses. As most U.S. PVC resin production plants are located in the Gulf Coast region, an area prone to seasonal hurricane activity and other extreme weather events, our access to PVC resin may be impacted by the volume and magnitude of hurricane and storm activity in this region, which could impact our Plastics segment businesses.
Increased risk of natural disasters, such as wildfires, could have financial consequences, including limiting our ability to secure sufficient insurance coverage, or lead to increased insurance cost. While we carry liability insurance, given an extreme event, if we were found to be liable for damages, amounts that exceed our coverage limit could negatively impact our financial condition, operating results and liquidity.
These risks may also negatively impact our credit ratings, which may limit our access to capital markets and increase our borrowing costs. In addition, to the extent investors view climate change, fossil fuel combustion and GHG emissions as a financial risk, our stock price or our ability to access capital markets on favorable terms and conditions could be adversely impacted.
We may experience transition risks in moving towards low carbon generation and manufacturing. For example, we may face challenges with the adoption of new technologies, meeting changing customer expectations and committing to voluntary GHG emissions reduction goals, as well as complying with evolving local, state or federal regulatory requirements intended to reduce GHG emissions.
The loss of, or significant reduction in revenue from, any of our key customers could have an adverse effect on our operating results.
While no single customer provided more than 10% of our consolidated operating revenues, each of our segments have customers which accounted for over 10% of the segment’s operating revenues. In 2023, two customers accounted for 21% of Electric segment revenues, two customers combined to account for 30% of Manufacturing segment operating revenues and two customers combined to account for 36% of Plastics segment operating revenues. The loss of any one of these customers or a significant decline in sales to these customers, would have a significant negative impact on the segment's financial condition and operating results, and could have a significant negative impact on the Company’s consolidated financial condition, operating results and liquidity.
We are subject to counterparty credit risk.
We extend credit to our customers in the ordinary course of business in each of our operating segments. Our customers' ability to pay depends on a variety of factors including macroeconomic conditions, local economic conditions including unemployment rates, and industry conditions in which our customers operate. Increased customer delinquencies and bad debts could adversely impact our operating results and liquidity.
16

Our operations are subject to environmental, health and safety laws and regulations. 
We are subject to numerous federal, state, and local environmental, health and safety laws and regulations governing, among other things, discharges to air and water, natural resources, hazardous waste and toxic substances, the cleanup of contaminated sites, and health and safety matters. Our failure to comply with applicable laws and regulations could result in civil or criminal fines or penalties, enforcement actions, and regulatory or judicial orders enjoining or curtailing operations or requiring corrective measures, which could materially and adversely affect our business. Compliance with these laws and regulations is a significant factor in our business. We have incurred and expect to continue to incur capital expenditures and operating costs to comply with applicable current and future laws and regulations.
Our businesses continue to be subject to additional and changing environmental, health and safety laws and regulations, and we could incur additional costs complying with requirements that are promulgated in the future. New laws or regulations or changes to existing laws and regulations in the future may result in disruptions to our business, changes in customer preferences, or changes in customer demand, which could adversely impact our financial condition, operating results and liquidity.
Recently, various federal and state agencies have heightened their scrutiny of per- and polyfluoroalkyl substances (PFAS), which are manufactured chemicals used in a variety of consumer and industrial products. Regulators have recently proposed additional chemicals be designated as hazardous substances, including a proposal to designate perfluorooctanesulfonic acid and perfluorooctanoic acid, two of the most common PFAS chemicals, as hazardous substances, which could have wide-ranging impacts on companies across various industries, including ours. We are investigating whether PFAS compounds are used in our manufacturing or operating processes that occur in our various businesses. At this time, we cannot predict the outcome or the severity of the impact, if any, of future laws or regulations enacted to address PFAS.
A cyber incident, security breach or system failure could adversely affect our business and operating results.
The operation of our business is dependent on the secure functioning of our computer hardware and software systems, as well as that of third-party service providers and vendors we use to electronically process certain of our business transactions. Information systems, both ours and those of third parties, are vulnerable to security breaches by computer hackers and cyber terrorists, and the negligent or intentional breach of established controls and procedures, or mismanagement of confidential information by employees. Cyber-attacks or other security breaches may also be perpetrated through the use of artificial intelligence, which could introduce additional complexity to such an attack or breach. While we employ a defense-in-depth strategy and regularly conduct cybersecurity assessments, we cannot be certain our information security systems and protocols and those of our vendors and other third parties are sufficient to withstand a cyber-attack or other security breach.
A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage, and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For example, we may be subject to liability under various federal, state and international disclosure laws and data protection laws. These laws are subject to change and expansion and may require additional operational changes and costs to comply. 
The misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant monetary damages, regulatory enforcement actions and breach notification and mitigation expenses, such as credit monitoring, and result in reputational damage affecting relations with shareholders, customers, regulators and others. In addition to property and casualty insurance, which may cover restoration of data, certain physical damage or third-party injuries, we have cybersecurity insurance related to a breach event. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any available insurance.
The inability to attract and retain a qualified workforce could have an adverse effect on our operations.
The success of our business is heavily dependent on the leadership of our executive officers and key employees for implementation of our strategy. In addition, all of our businesses rely on a qualified workforce, including technical employees who possess certain specialized knowledge and skills. The inability to attract and retain a skilled and stable workforce at necessary staffing levels, whether due to decreases in hiring rates, increases in employee retirements, increases in terminations, or any combination thereof, may negatively affect our ability to service our customers, manufacture products or successfully manage our business and achieve our objectives.
Our acquisition or divestiture strategies are subject to risk and could adversely impact our financial position and operating results.
As part of our business strategy, we continually assess our mix of businesses and potential strategic acquisitions or divestitures. This investment strategy is subject to various risks, including the ability to identify appropriate acquisition candidates, or successfully negotiate and finance any acquisitions. In addition, difficulties in integrating the operations, services, products and personnel of the acquired business, and the potential loss of key employees, customers and suppliers of the acquired business could adversely impact our financial condition and operating results.
FINANCIAL RISKS
We are subject to capital market and interest rate risks.
We rely on access to debt and equity capital markets as a source of liquidity to fund our investment initiatives, including rate base growth investments in our Electric segment and opportunities for investment, including acquisitions, in our Manufacturing and Plastics segments. Capital markets are impacted by global and domestic economic conditions, monetary policy, commodity prices, geopolitical events and other factors. If we are unable to access capital on acceptable terms and at reasonable costs, our ability to implement our business plans may be adversely affected. In addition, higher market interest rates on outstanding variable-rate, short-term indebtedness could also impact our operating results. In 2023, rising market interest rates caused the applicable rate of interest on our short-term indebtedness to increase significantly. However, the impact to our operating results was not significant due to our low level of outstanding borrowings on our short-term indebtedness. Our operating results could be
17

impacted if we significantly increase our short-term borrowings or issue new long-term debt, and interest rates remain elevated or continue to increase.
A decrease in our credit ratings could increase our borrowing costs and result in additional contractual costs.
We rely on our investment grade credit ratings to provide acceptable costs for accessing the capital markets. A downgrade of our credit ratings could result in higher borrowing costs thereby negatively impacting our operating results and limiting our ability to access capital markets, which may negatively impact our ability to implement our business plans. In addition, OTP is a party to contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below certain levels.
Our pension and other postretirement benefit plans are subject to investment and interest rate risks.
The financial obligations and related costs of our pension and other postretirement benefit plans are affected by numerous factors. Assumptions related to future costs, investment returns, actuarial estimates and interest rates have a significant effect on our funding obligations and the cost recognized related to these plans. If our pension plan assets do not achieve our estimated long-term rate of return or if our other estimates prove to be inaccurate, our operating results, financial condition and liquidity may be adversely impacted. In addition, our funding requirements could be impacted by changes to the Pension Protection Act.
We rely on our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and pay dividends to our shareholders. 
Otter Tail Corporation is a holding company with no significant operations of its own. The primary source of funds for payment of our financial obligations and dividends to our shareholders is from cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the earnings, cash flows, capital requirements and general financial positions of our subsidiary companies. In addition, OTP is subject to federal and state regulations which may restrict its ability to pay dividends. Finally, we are also reliant on our subsidiary companies to maintain compliance with financial covenants under our various short- and long-term debt agreements. Our debt agreements include restrictions on the payment of cash dividends upon an event of default. 
Changes in tax laws could materially affect our financial condition and operating results.
Our provision for income taxes and tax obligations are impacted by various tax laws and regulations, including the availability of various tax credits, IRS tax policies such as tax normalization and, at times, the ability to carryforward net operating losses and tax credits. Changes in tax laws, regulations and interpretations could have an adverse effect on our financial condition and operating results. Tax law changes that reduce or eliminate production or investment tax credits (ITCs), or the ability to transfer or sell these credits, may impact the economics of constructing certain electric generation resources, which may impact our planned investments, and could adversely affect our financial condition and operating results.
ELECTRIC SEGMENT RISKS
General economic and industry conditions impact our business.
Several factors, many of which are beyond our control, may contribute to reduced demand for energy from our customers or increase the cost of providing energy to our customers. These risks include economic growth or decline in our service areas, demographic changes in our customer base and changes in customer demand or load growth due to, among other items, proliferation of distributed generation, energy efficiency initiatives and technological advancements. In addition, customer demand could be impacted by increased competition in our service territories or the loss of a service territory or franchise. Other risks include increased transmission or interconnection costs, generation curtailment and changes in the manner in which wholesale power is purchased and sold. A decrease in revenues or an increase in expenses related to our electric operations could negatively impact our financial condition, operating results and liquidity.
Our utility business is significantly impacted by government legislation and regulation.
OTP is subject to federal and state legislation and comprehensive regulation by federal and state regulatory agencies, including the public utility commissions in each of the three states in which OTP operates, and by the FERC. State utility commissions regulate, among other matters, the establishment of assigned service areas, the siting and construction of major facilities, the capital structure of the utility business, and the allowed rates to charge customers for providing energy and utility service. Each state utility commission operates independent of one another; therefore, OTP is subject to and must adhere to the decisions of each independent state commission. The FERC regulates, among other matters, wholesale energy transactions, hydroelectric licensing, transmission and sale of electric energy in interstate commerce, and the interconnection of electric facilities.
Our financial condition, operating results and liquidity are significantly impacted by, and dependent upon, our ability to recover the costs associated with providing utility service and earn a return on our utility capital investments. There is no assurance that each state utility commission will judge our utility costs to have been prudently incurred or that rates will produce full recovery of such costs. In addition, changes in the federal or state regulatory framework could impair our ability to recover utility costs historically collected from our customers. Diverging public policy priorities across the jurisdictions we serve, and a lack of inter-jurisdictional consensus, may impact our ability to recover the cost of, and return on, our capital investments and our operating costs; it may impact our future capital investment opportunities; and may result in inefficiencies which could negatively impact our financial position, operating results and liquidity.
In addition to the recovery of our utility costs, our profitability is impacted by our authorized ROE, which can be impacted by macroeconomic factors such as interest rates. There can be no assurance that each state utility commission or the FERC will authorize a rate of return which allows us to achieve our financial goals. An adverse decision by one or more regulatory authorities or any prolonged delay in rendering a decision in a rate or other proceeding could adversely impact our financial condition, operating results and liquidity.
18

Inflationary cost pressures have increased the cost of constructing our utility assets and operating our utility business. There can be no assurance that our state regulatory commissions will authorize recovery of rising costs. Regulatory commissions may also limit future capital investments or the rate of return allowed on such investments in response to inflationary cost pressures and customer bill impacts. Such limitations could negatively impact our financial position, operating results and liquidity.
Our generating facilities are subject to risks that could result in early closure or the sale of our ownership interest.
Changes in operational or economic factors, environmental regulation or risks of litigation could result in the early closure or the sale of our interest in a generating facility. In the event of an early closure, a significant asset impairment charge could be required, and we would be obligated to pay for our share of the costs of closure of the generating facility, including costs associated with decommissioning, remediation, reclamation and restoration of the property, and any costs of terminating contracts associated with the generating facility, such as coal supply arrangements. In the event of a sale of our interest in a generating facility, we may not be able to negotiate the sale on favorable terms, which could result in the recognition of a loss on the sale and other potential liabilities. There can be no assurance that we would be authorized by any of our state utility commissions to recover any costs or losses associated with the early closure of or sale of our interest in a generating facility.
The loss of a major generating facility would require OTP to identify and obtain approval for other sources of generation for its customers, if available, and potentially expose us to higher purchased power costs. In addition, OTP may not be able to obtain timely regulatory approval for new generation resources to replace closed or sold facilities.
Our IRP, as revised in two supplemental filings in 2023, outlined our plan to withdraw from our 35% ownership interest in Coyote Station, a jointly owned coal-fired generation plant, in the event we are required to make a major, non-routine capital investment in the plant. In the event we were to withdraw from our ownership, we will seek to recover all costs related to the withdrawal from Coyote Station; however, there is a risk we may not be granted recovery of such costs. A full or partial denial of recovery of the costs of withdrawal could significantly impact our operating results, financial condition and liquidity.
Joint ownership of coal-fired generation facilities could impact our ability to manage changing regulations and economic conditions.
We own our coal-fired generation facilities jointly with other co-owners with varying ownership interests in such facilities. Our ability to make determinations on our IRP in order to best navigate changing environmental regulations and economic conditions may be impacted by our rights and obligations under the co-ownership agreements and related agreements, and our ability to reconcile a divergence in the interests of OTP and the co-owners of these generation facilities. Such a divergence could impair our ability to effectively manage these changing conditions to meet our strategic objectives and could adversely impact our financial condition, operating results and liquidity.
Federal and state environmental regulation could require us to incur substantial capital expenditures, increased operating costs or make it no longer economically viable to operate some of our facilities.
We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements may require us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.
Coyote Station, one of OTP's jointly owned coal-fired power plants, is subject to assessment under the second implementation period of RHR as part of the state of North Dakota's RHR SIP. We cannot predict with certainty the impact the SIP may have on our business until the plan has been approved or otherwise acted on by the EPA, including its potential implementation of an alternative federal implementation plan. However, significant emission control investments could be required. Alternatively, investments in emission control equipment may prove to be uneconomic and result in the early closure or the sale of, or withdrawal from, our interest in Coyote Station.
Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. The multiple jurisdictions that govern our electric utility business may not agree as to the appropriate resource mix, which may lead to costs incurred to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our financial condition, operating results and liquidity, making the operation of some of our facilities no longer economically viable.
Legislation, regulation, litigation or other actions related to climate change and greenhouse gas emissions could materially impact us.
Current and future federal, state, regional and international regulations to address global climate change and reduce GHG emissions, including measures such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions, or cap-and-trade regimes, could require us to incur significant costs which could negatively impact our financial condition, operating results and liquidity if such costs cannot be recovered through rates granted by rate-making authorities or through increased market prices for electricity.
In 2021, the Biden Administration introduced new targets aimed at reducing economy-wide net GHG emissions by 50% to 52% from 2005 levels by 2030. In addition, the Administration set a goal to reach 100% carbon pollution-free electricity by 2035. As a part of achieving these targets, the EPA proposed new regulations in May 2023 under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based EGUs. As detailed above, this proposal would require states to implement stringent emissions standards for most coal-fired steam generating units and certain larger natural gas combustion plants. Until the EPA takes final action on this rulemaking, we are unable to evaluate the precise impacts; however, the proposed rule has the potential to impact the emissions controls needed at OTP’s coal-fired power plants, which could have an impact on our operating results, financial condition and liquidity. The EPA may implement additional new regulations targeting power plants to
19

support its aforementioned economy-wide GHG reduction goals, which could impose substantial costs on and impact the operations of our utility business, which may materially impact our financial condition, operating results and liquidity.
In addition to complying with legislation and regulation, we could be subject to litigation related to climate change. In recent years, there has been an increase in litigation against electric utilities and fossil fuel producers. If OTP were subjected to such litigation, the costs of such litigation could be significant and an adverse outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages which could affect our financial condition, operating results and liquidity if the costs are not recoverable in rates or covered by insurance.
Violations of extensive legal and regulatory compliance requirements could have a negative impact on our business and results of operations.
We are subject to an extensive legal and regulatory framework imposed under federal and state laws and regulatory agencies, including the FERC and the North American Electric Reliability Corporation (NERC). We could be subject to potential financial penalties for compliance violations. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. If a serious reliability incident were to occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance. We attempt to mitigate the risk of regulatory penalties through formal training. However, there is no guarantee our compliance program will be sufficient to ensure against violations.
In addition, energy policy initiatives at the state or federal level could increase incentives for distributed generation, or authorize municipal utility formation or acquisition of service territory, or local initiatives could introduce generation or distribution requirements that could change the current integrated utility model.
These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary approvals for our existing operations and that our business is conducted in accordance with applicable laws and regulatory requirements; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our financial condition, operating results and liquidity.
Our transmission and generation facilities could be vulnerable to cyber and physical attack.
OTP owns electric transmission and generation facilities subject to mandatory and enforceable standards advanced by the NERC. These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack.
In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system.
OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and remains abreast of best practices within the business and the utility industry to protect its computers and computer-controlled systems from outside attack. We rely on industry-accepted security measures and technology to securely maintain confidential and proprietary information necessary for the operation of our systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls and disaster recovery plans designed to protect and preserve the confidentiality, integrity and availability of data and systems. We also take prudent and reasonable steps to protect the physical security of our generation and transmission facilities. However, all these measures and technology may not adequately prevent security breaches, ransomware attacks or other cyber-attacks, or enable us to recover effectively from such a breach or attack. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches or physical attack of our generation or transmission facilities could adversely affect our business and our financial condition, operating results and liquidity.
Our generation, transmission, and distribution facilities are subject to operational risks which include circumstances that could result in injuries, loss of life, property damage, and fires.
The operation of our generation, transmission, and distribution facilities involves many risks including equipment failures, accidents and workforce safety matters, environmental damage, property damage, operator error, and the occurrence of catastrophic events such as fires, explosions and floods. Diminished availability or performance of those facilities could result in facility shutdowns, reduced customer satisfaction, reputational harm, and regulatory inquiries and fines.
Accidents, fires, explosions, catastrophic failures, general system damage or dysfunction, intentional acts of destruction, and other unplanned events related to our infrastructure would increase repair costs and may expose us to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by our transmission, distribution, or generation infrastructure, or that allegedly result from our contractors’ operating or maintenance practices, could also expose us to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. We maintain insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover our ultimate liability. We may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms. If the amount of insurance is insufficient or otherwise unavailable, and if we are unable to fully recover in rates the costs of uninsured losses, our financial condition, operating results and liquidity could be materially affected.
20

We are subject to risks associated with the procurement and transportation of fuel to our coal and natural gas powered generation facilities.
We rely on a limited number of suppliers to provide coal and a limited number of service providers to transport coal and natural gas to our facilities. A counterparty's failure to perform their obligations may arise due to liquidity challenges or insolvency, operational deficiencies or other circumstances such as severe weather or natural disasters, which could impact our ability to provide service to our customers or require us to seek alternative sources for these products and services, if available. A prolonged failure to perform by one or more of our current suppliers or service providers could lead to increased costs or other consequences which could negatively impact our financial condition, operating results and liquidity.
We are subject to risks associated with energy markets.
Our electric business is subject to the risks associated with energy markets, including market supply and changing energy prices. If we are faced with shortages in market supply, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs, or suffer increased liabilities for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs could negatively affect our financial condition, operating results and liquidity.
MANUFACTURING SEGMENT RISKS
The price and availability of raw materials could adversely impact our operating results.
The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture including, among others, steel, aluminum, and polystyrene and other plastics resins. The price and availability of the raw materials used in our manufacturing processes are based on global supply and demand conditions, which can create volatile pricing and supply disruptions as conditions change. Federal trade policies, including imposed tariffs, can also impact prices for these raw materials. If we are unable to pass cost increases through to our customers or are unable to procure adequate or timely raw material inputs for use in our manufacturing processes, our financial condition, operating results and liquidity could be negatively impacted.
Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes used by our manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our manufacturing companies as it reduces their ability to mitigate the cost associated with excess material.
Competition from domestic and foreign manufacturers could affect the revenues and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to intense competition from domestic and foreign manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development personnel and facilities, and other capabilities. Our ability to compete on product performance, competitive pricing, technological innovation and customer service is critical to our ongoing success. If we are unable to compete in these and potentially other areas, our business and financial condition, operating results and liquidity could be adversely impacted.
Economic conditions in the end markets in which our customers operate could have an adverse impact on our operating results and liquidity.
Our manufacturing businesses derive a large amount of their revenues from customers in the following industry sectors: recreational vehicle/powersports, lawn and garden, construction, agriculture, energy and horticulture. Factors affecting any of these industries in general could adversely affect our operating results as growth in our operating revenues is largely dependent on the growth of our customers’ businesses in their respective industries. These factors include:
seasonality of demand for our customers’ products which may cause our manufacturing capacity to be underutilized for periods of time;
our customers’ failure to successfully market their products, gain or retain widespread commercial acceptance of their products or compete effectively in their industries;
loss of market share for our customers’ products which may lead our customers to reduce or discontinue purchasing our products and components and to reduce prices, thereby exerting pricing pressure on us;
economic conditions in the markets in which our customers operate, the United States in particular, including recessionary periods such as a global economic downturn;
our customers’ decisions to bring the production of components in-house that have traditionally been outsourced to us; and
product design changes or manufacturing process changes that may reduce or eliminate demand for the components we supply.
We expect future sales will continue to depend on the success of our customers. If economic conditions or demand for our customers’ products deteriorates, we may experience a material adverse effect on our financial condition, operating results and liquidity.
Our business may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise.
The markets for our manufacturing businesses are characterized by changing technology and evolving process development. The continued success of our businesses will depend on our ability to:
maintain technological leadership in our industry;
implement new and expand on current robotics, automation and tooling technologies; and
anticipate or respond to changes in manufacturing processes in a cost-effective and timely manner.
We may be unable to develop the capabilities required by our customers in the future. The emergence of new technologies, industry standards or customer requirements may render our equipment, inventory or processes obsolete or noncompetitive. We may be required to acquire new technologies and equipment to remain competitive. The acquisition and implementation of new technologies and equipment may require us to incur significant expense and capital investment, which could reduce our margins and affect our operating results. When we establish or acquire new facilities, we may not be able to maintain or develop our manufacturing, engineering and technological expertise due to a lack of trained
21

personnel, ineffective training of new staff or technical difficulties with machinery. Failure to anticipate and adapt to customers’ changing technological needs and requirements and to maintain manufacturing, engineering and technological expertise may have material adverse effects on our financial condition, operating results and liquidity.
PLASTICS SEGMENT RISKS
External factors beyond our control could cause fluctuations in demand for our PVC pipe products and changes in our prices and margins, which could adversely impact our operating results.
Our PVC pipe products, sold through distributors and wholesalers, are primarily used in municipal and rural water projects, wastewater projects, storm drainage systems and reclamation systems. External factors beyond our control can cause volatility in demand for our products and sales prices impacting our operating margins. These factors can magnify the impact of economic cycles on our business and results of operations. Examples of external factors include:
general economic conditions including housing and construction markets which can be cyclical;
increases in interest rates;
severe weather and natural disasters;
governmental regulation in the United States; and
funding shortages for municipal water and wastewater projects.
Extraordinary industry supply and demand dynamics beginning in 2021 and continuing through 2023 led to a rapid and significant increase in sales prices for PVC pipe and led to a significant expansion in our operating margins. As industry conditions normalize, sales prices for PVC pipe are expected to moderate from current levels resulting in decreased operating margins prospectively. The pace and magnitude of the decline in product pricing could materially impact our operating results.
Changes in PVC resin prices could negatively affect our plastics business.
The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices were rising or stable, margins and sales volumes were higher and when resin prices were falling, sales volumes and margins were lower. Changes in PVC resin prices can negatively affect PVC pipe prices, profit margins on PVC pipe sales and the value of our finished goods inventory.
Our plastics operations are highly dependent on a limited number of vendors and a limited supply of PVC resin and other materials.
We rely on a limited number of vendors to supply the PVC resin used in our plastics businesses. In 2023, we sourced all of our PVC resin needs from three vendors. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. Most U.S. resin production plants are located in the Gulf Coast region. This could increase the risk of a shortage of resin in the event of a hurricane, other extreme weather events and other natural disasters in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources were available.
Although PVC resin is the most significant raw material input in our PVC pipe manufacturing process, we also use certain other materials, such as stabilizers, gaskets, lumber, banding and others in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers and any significant supply chain constraints or disruptions related to these materials could also disrupt our ability to manufacture or ship products and could result in increased costs.
We compete against many other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.
The plastic pipe industry is fragmented and competitive due to the number of producers and the fungible nature of the product. We compete not only against other plastic pipe manufacturers, but also against ductile iron, steel and concrete pipe manufacturers. Due to shipping costs, competition is usually regional instead of national in scope and the principal areas of competition are a combination of price, service, warranty and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics businesses.
GENERAL RISK FACTORS
Economic conditions could negatively impact our businesses.
Our businesses are affected by local, national and worldwide economic conditions, including the impact of inflation, tightening of credit in financial markets, economic recessions or other changes in economic conditions. Our businesses may be adversely affected by decreases in the general level of economic activity, such as decreases in business and consumer spending. A decline in the level of economic activity and uncertainty regarding energy and commodity prices could adversely affect our results of operations and our future growth. Inflationary pressures may lead to rising material and commodity costs and increased labor costs. Our operating results and liquidity would be adversely impacted if we were unable to recover these increased costs from our customers. Tightening of credit in financial markets could adversely affect the ability of customers to finance purchases of our goods and services, resulting in decreased orders, cancelled or deferred orders, slower payment cycles, and increased bad debt and customer bankruptcies.
If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.
We expect much of our growth in the next few years will come from major capital investments at existing companies. To achieve the organic growth we expect, we must have access to the capital markets, be successful with capital expansion programs related to organic growth, develop new products and services, expand our markets and increase efficiencies in our businesses. Competitive and economic factors could adversely
22

affect our ability to do this. If we are unable to achieve and sustain consistent organic growth, we will be less likely to meet our earnings growth targets, which may adversely affect the market price of our common shares.
The effects of a major public health crisis, such as an epidemic or pandemic, and measures taken to reduce and slow the spread of the disease could adversely impact our business.
A future widespread outbreak of an infectious disease, which affects a large percentage of the population regionally, nationally, or globally could impact our business operations, including our employees, customers, construction contractors, suppliers and vendors, and could impact our operating results, financial condition and liquidity.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 1C.CYBERSECURITY
CYBERSECURITY RISK
The operation of our businesses is dependent on the secure functioning of our computer infrastructure and digital information systems. Furthermore, all our businesses require us to collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. We also use third-party service providers to electronically process certain of our business transactions and perform certain cyber-related functions, such as system monitoring and critical infrastructure protection and maintenance. The confidentiality, integrity, and availability of information systems, both ours and those of our third-party service providers, are vulnerable to security breaches by computer hackers and cyber terrorists and the negligent or intentional breach of established controls and procedures or mismanagement of confidential information by employees. We may also be impacted by attacks and data security breaches of financial institutions, merchants or other business partners. As part of our utility operations, we own electric generation, transmission and distribution facilities that are part of an interconnected regional grid, the operation of which is dependent on information technology systems. Parties who wish to disrupt the U.S. bulk power system or our utility operations could view our computer systems, software or networks as attractive targets for cyber-attack. Although we have not historically experienced material cyber incidents, we and other utilities are subject to cyber-attacks of increasing frequency and sophistication, and any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches, could adversely affect our business and our financial condition, operating results and liquidity.
RISK MANAGEMENT AND STRATEGY
Our cybersecurity policies and practices, which are based on the Center for Information Security (CIS) Critical Security Controls, are governed by our information and cybersecurity governance program. The CIS Critical Security Controls are a set of 18 cybersecurity-related controls which aid companies in designing an effective control environment and are viewed as best practices by organizations worldwide. A significant number of our cybersecurity policies and practices associated with our electric utility operations are also subject to regulation by multiple governmental and other agencies.
Our information and cybersecurity governance program is the foundation of our cybersecurity risk management strategy. The program includes policies which authorize and guide the development of procedures, standards, and guidelines for personnel activities, incident prevention and reporting, and compliance monitoring. Cybersecurity policies, procedures and controls are reviewed and approved by our Information and Cybersecurity Program (ICSP) group annually, with amendments made as deemed necessary for any updates for regulatory compliance and best practices, legal privacy protection and information protection, or to reflect current technology or new methods for ensuring secure business procedures.
We perform a corporate risk assessment annually, which includes specific consideration and assessment of cybersecurity risk. As part of our risk assessment process, we incorporate results from procedures performed by third-party consultants. We utilize third-party consultants to complete risk quantification analysis and perform penetration and vulnerability testing and monitoring, as well as overall cybersecurity control testing. Potential risks associated with the use of third-party service providers are monitored and managed through an established service provider management policy. Service providers must meet certain security requirements such as security incident or data breach notification and response protocols, data encryption requirements, and data disposal commitments.
In managing cybersecurity risk, we employ a defense-in-depth strategy and regularly monitor our cyber environment for potential new threats. Our strategy includes employee training and awareness on cybersecurity risks and related best practices, required password complexity, the use of multi-factor authentication, information security protocols, anti-virus and anti-ransomware software, a patch management program, the execution of tabletop exercises on a periodic basis, established policies and protocols for cyber incident response planning and reporting, and ongoing internal cybersecurity testing.
GOVERNANCE
At the management level, our cyber program is managed by our ICSP group. The ICSP group consists of Information Technology (IT) managers, IT security subject matter experts, and internal audit personnel and is led by our Vice President of IT who has more than 25 years of experience in IT, enterprise security, and cyber risk management, a Bachelor's degree of Science, CIS, Information Technology and Master's of Business, Information Systems, and holds Certified Information Systems Security Professional, Certified Information Security Manager, and Certified Data Privacy Solution Engineer designations. The ICSP group is in charge of developing, maintaining, and measuring compliance with the information and cybersecurity governance program, as well as monitoring cyber incidents and implementing mitigation measures as part of an evolving, dynamic external environment. Our approach to cybersecurity incident reporting and response planning is governed by our incident response plans established for
23

each of our business units. The plans outline the processes related to detecting, assessing, investigating, mitigating, and remediating cyber incidents, as well the communication and reporting plan and the required personnel to be included in the process and communications.
Our cybersecurity risk management is integrated into our overall risk management system through our internal business risk management process. Our business risk management group works closely with our ICSP group to regularly assess and identify possible material risks from cybersecurity threats, including, but not limited to, financial, operations, reputational and regulatory impact to the Company, as well as impacts on our employees and customers. Their risk assessment results are reported to the Executive Risk Committee on a quarterly basis. The Executive Risk Committee, which is comprised of our executive officers, meets quarterly to identify and assess short-, medium- and long-term risks, and to ensure adequate mitigation strategies are implemented. During these meetings, the Executive Risk Committee reviews significant and emerging risks, including cybersecurity risks, and assesses the Company’s plans to mitigate or otherwise manage and monitor those risks.
Our Board of Directors provides oversight of our cybersecurity program through quarterly and annual risk review and cybersecurity reporting. On a quarterly basis, cybersecurity risk and mitigation strategies are reviewed as part of our business risk management group's reporting to the Board of Directors, which includes the reporting of significant business risks, including cybersecurity mitigation strategies employed to manage these risks, and a review of any emerging risks. Annually, our Vice President of IT provides an overview of our cybersecurity program to the Board of Directors, including a review of key strategies, emerging risks and a summary of key performance indicators. In addition, annually the Board of Directors reviews the results of our penetration and vulnerability testing.
ITEM 2.PROPERTIES
The following provides a summary of our properties which are material to our operations, by segment, as of December 31, 2023.
ELECTRIC SEGMENT
The following reflects our wholly or jointly owned material electric generation facilities as of December 31, 2023:
DescriptionLocationYear
Placed in Service
Fuel TypeCapacity - kW
(Nameplate Rating)
Big Stone Plant(1)
Big Stone City, SD1975Subbituminous Coal223,146 
Coyote Station(2)
Beulah, ND1981Lignite Coal144,900 
Jamestown Combustion Turbines
Jamestown, ND1975Fuel Oil48,108 
Lake Preston Combustion TurbineLake Preston, SD1978Fuel Oil24,100 
Solway Combustion TurbineSolway, MN2003Natural Gas/Fuel Oil44,500 
Astoria StationAstoria, SD2021Natural Gas245,000 
Langdon Wind Energy Center
Cavalier County, ND2007Wind40,500 
Ashtabula Wind Energy Center
Barnes County, ND2008Wind48,000 
Luverne Wind Energy Center
Griggs and Steele Counties, ND2009Wind 49,500 
Merricourt Wind Energy Center
McIntosh and Dickey Counties, ND
2020Wind150,000 
Ashtabula III Wind Energy Center
Barnes County, ND
2023(3)
Wind
62,400 
Hoot Lake Solar
Otter Tail County, MN
2023
Solar
49,900 
(1) OTP holds a 53.9% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage.
(2) OTP holds a 35.0% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage.
(3) Originally placed in service in 2010 and owned by an unrelated third party. OTP acquired this facility in 2023.
In addition to our generation facilities, we wholly or jointly own transmission and distribution lines as of December 31, 2023 as follows:
Miles
Transmission
345 kV(3)
891 
230 kV(4)
496 
115 kV961 
Less than 115 kV4,005 
Distribution
Less than 115 kV7,998 
(3) As of December 31, 2023, OTP held a 14.2% ownership interest of 242 miles, a 4.8% ownership interest of 250 miles, and a 50.0% ownership interest of 234 miles of the 345 kV transmission lines, with the remaining miles being wholly owned.
(4) As of December 31, 2023, OTP held a 14.8% ownership interest of 70 miles of the 230 kV transmission lines, with the remaining miles being wholly owned.
24

MANUFACTURING AND PLASTICS SEGMENTS
The following reflects the material properties of our Manufacturing and Plastic segments as of December 31, 2023:
Segment/LocationOwned/LeasedFacility Type/UseApproximate
Square Feet
Manufacturing Segment
Washington, ILLeasedOffice/Manufacturing/Warehouse217,508 
Detroit Lakes, MNOwnedOffice/Manufacturing/Warehouse353,812 
Lakeville, MNLeasedOffice/Manufacturing/Warehouse413,000 
Dawsonville, GAOwnedOffice/Manufacturing/Warehouse172,000 
Buford, GALeasedWarehouse71,357 
Clearwater, MNOwnedOffice/Manufacturing/Warehouse203,840 
Otsego, MNLeasedManufacturing/Warehouse86,400 
Plastics Segment
Fargo, NDOwnedOffice/Manufacturing/Warehouse122,441 
Phoenix, AZOwnedOffice/Manufacturing/Warehouse87,336 
We are currently undertaking an expansion project at our Georgia location which will add approximately 162,000 square feet of manufacturing and warehouse space, and will replace the warehouse facility that is currently being leased. We anticipate the project will be completed in 2025. We are also undertaking an expansion project at our Arizona location which will add approximately 65,000 square feet of manufacturing, warehouse, and office space. We anticipate the project will be completed in 2024.
We believe the facilities described above, along with the planned expansions, are adequate for our present business.
ITEM 3.LEGAL PROCEEDINGS
We are the subject of various legal and regulatory proceedings in the ordinary course of our business. See Note 13, Commitments and Contingencies, to the consolidated financial statements, and Management's Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Matters, which information is incorporated herein by reference, for discussion of certain legal, environmental and other regulatory proceedings to which we are a party.
ITEM 3A.INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined by rules of the SEC. Each of the executive officers has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly owned subsidiary, Otter Tail Power Company.
Name and AgeDate Elected to OfficeCurrent Position
Charles S. MacFarlane (59)
04/13/15President and Chief Executive Officer
Todd R. Wahlund (53)
01/01/24
Vice President, Chief Financial Officer
Timothy J. Rogelstad (57)
04/14/14Senior Vice President, Electric Platform
John S. Abbott (65)
02/11/15Senior Vice President, Manufacturing Platform
Jennifer O. Smestad (53)
01/01/18Vice President, General Counsel and Corporate Secretary
Chuck MacFarlane has served as the Company’s President and Chief Executive Officer and as a member of the Company’s Board of Directors since April 13, 2015.
Todd Wahlund was appointed to succeed Kevin Moug, Chief Financial Officer and Senior Vice President, subsequent to Mr. Moug's retirement on December 31, 2023. Mr. Wahlund has served as Chief Financial Officer and Vice President since January 1, 2024, and previously served as Chief Financial Officer and Vice President, Finance for OTP from May 1, 2018 to December 31, 2023.
Timothy Rogelstad has served as President of OTP and Senior Vice President, Electric Platform of the Company since April 14, 2014.
John Abbott has served as Senior Vice President, Manufacturing Platform, since February 11, 2015.
Jennifer Smestad has served as Vice President, General Counsel and Corporate Secretary of the Company, since January 1, 2018. Ms. Smestad has also served as General Counsel for OTP since March 1, 2013.
The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the board of directors at any time during the term. There are no family relationships between any of the executive officers or directors.
25

ITEM 4.MINE SAFETY DISCLOSURES
Not Applicable.
26

PART II
ITEM 5.MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the Nasdaq Global Select Market under the Nasdaq symbol “OTTR”. As of December 31, 2023, there were 10,650 holders of record of our common stock.
We do not have a publicly announced stock repurchase program and we did not repurchase any equity securities during the quarter ended December 31, 2023. 
PERFORMANCE GRAPH COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
This graph compares the cumulative total shareholder return on our common shares for the last five years with the cumulative return of the Nasdaq Stock Market Index and the Edison Electric Institute (EEI) Index over the same period (assuming the investment of $100 in each vehicle on December 31, 2018, and reinvestment of all dividends).
704
201820192020202120222023
OTTR$100.00 $105.64 $90.88 $156.27 $133.22 $197.24 
EEI$100.00 $125.79 $124.33 $145.61 $147.29 $134.47 
Nasdaq$100.00 $131.17 $159.07 $200.26 $160.75 $203.23 
ITEM 6.[RESERVED]
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and the related notes appearing under Item 8 of this Form 10-K.
OVERVIEW
Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our Electric business is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve our customers in western Minnesota, eastern North Dakota and northeastern South Dakota. Our Manufacturing segment provides metal fabrication for custom machine parts and metal components, and manufactures extruded and thermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater and water reclamation projects.
Our strategy includes investing in rate base growth opportunities in our Electric segment and capitalizing on organic growth opportunities in our Manufacturing and Plastics segments. Investments in our Electric segment are expected to produce increased earnings and cash flows, lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund our dividend. Our Electric segment is complemented by our Manufacturing and Plastics segment businesses, which we expect to contribute to earnings growth by capitalizing
27

on market expansion opportunities and increasing utilization of existing capacities, along with planned investments to create additional capacity and increased efficiencies. Collectively, our mix of businesses is expected to contribute to the achievement of our long-term targeted annual growth in earnings per share of 5 - 7%.
2023 FINANCIAL RESULTS
In 2023, our diversified business model generated record financial results, producing net income of $294.2 million, or $7.00 per diluted share, an increase of 4% from $284.2 million, or $6.78 per diluted share, in 2022. Our financial results for the year were driven by earnings growth in our Electric and Manufacturing segments, as well as lower corporate costs, as we benefited from returns on our short-term investments funded by the significant cash flows our businesses have generated over the last three years. Our Plastics segment again produced extraordinary financial results as we continued to capitalize on favorable industry dynamics; however, earnings in this segment did decline modestly from the record level achieved in 2022. In 2023, we paid an annual dividend of $1.75 per share, or $73.1 million, completing our 85th consecutive year of dividend payments to our shareholders.
Our Electric segment produced earnings growth of 6% in 2023, from $80.0 million in 2022 to $84.4 million in 2023, primarily due to increased rider revenue, increased commercial and industrial sales, and lower pension and other postretirement benefit costs, partially offset by increased operating and maintenance expenses and the impact of unfavorable weather.
Our Manufacturing segment produced earnings growth of 2% in 2023, from $21.0 million in 2022 to $21.5 million in 2023, primarily due to increased sales volumes at our metal fabrication business driven by strong end market demand across several markets we serve, and incremental volumes from additional work with existing customers. Increased sales volumes at our metal fabrication business were partially offset by increased labor and overhead costs, as well as decreased horticulture product sales volumes at our plastic thermoforming business.
Our Plastics segment earnings declined 4%, from $195.4 million in 2022 to $187.7 million in 2023. We experienced an unprecedented level of earnings in 2022, resulting from extraordinary industry supply and demand dynamics. Industry dynamics have begun to moderate, but at a modest pace, as further described below. Our Plastics segment businesses continued to capitalize on these industry conditions in 2023, producing earnings significantly in excess of pre-2021 levels.
Our earnings mix in 2023 was 29% from our Electric segment and 71% from the combination of our Manufacturing and Plastics segments excluding unallocated corporate costs. Electric segment earnings as a percentage of our total earnings were less than our long-term target of 65% due to the unique market conditions occurring in the plastics industry.
PVC PIPE SUPPLY AND DEMAND CONDITIONS
Extraordinary supply and demand conditions in the PVC industry beginning in 2021 have led to a significant expansion in operating margins and elevated earnings in our Plastics segment over the past three years. Periodic disruptions in the supply of resin, the primary material input used in the manufacturing of PVC pipe, coupled with robust demand for resin, led to a significant increase in the cost of resin beginning in 2021. Low industry volumes of PVC pipe and robust end market demand for the product led to a rapid and significant increase in sales prices for PVC pipe, significantly outpacing the increase in resin input costs, leading to increased operating margins within our Plastics segment.
Demand for PVC pipe began to soften in the second half of 2022, as distributors and contractors reduced purchase volumes in response to uncertain and competitive market conditions. Softening demand continued through the first half of 2023, but sales volumes in the second half of the year exceeded those in the previous year. Resin prices have declined from the previous year and although sales prices for PVC pipe have also declined, they have declined at a slower pace than resin prices, continuing to produce expanded operating margins from those experienced in 2022.
The unique market dynamics impacting our Plastics segment resulted in a significant increase in earnings in the last three years compared to historical levels. We expect these market conditions to gradually normalize over the course of 2024 and into 2025. The marketplace dynamics impacting our Plastics segments are fluid and subject to change and may impact our operating results prospectively.
FINANCIAL AND OTHER METRICS
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. Normal weather conditions are defined as the 20-year average of actual historical weather conditions. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
OTP generally bases its forecasted kwh sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast, and on period-to-period results.
Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, rate base consists of the value of property used by the utility in providing service. Rate base can also include cash, working capital, materials and supplies, construction work in progress, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and, in some cases, accumulated deferred ITCs. We present actual and forecasted levels of utility rate base to provide an indication of expected investments on which we expect to earn future returns.
28

RESULTS OF OPERATIONS
For a comparison of fiscal year 2022 to 2021, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our report on Form 10-K for the fiscal year ended December 31, 2022, filed with the SEC on February 15, 2023.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment, but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated statements of income.
CONSOLIDATED RESULTS
The following table summarizes our consolidated results of operations for the years ended December 31, 2023 and 2022:
(in thousands)20232022$ change% change
Operating Revenues$1,349,166 $1,460,209 $(111,043)(7.6)%
Operating Expenses971,247 1,069,770 (98,523)(9.2)
Operating Income377,919 390,439 (12,520)(3.2)
Interest Expense
(37,677)(36,016)(1,661)4.6 
Nonservice Components of Postretirement Benefits
10,597 1,075 9,522 n/m
Other Income12,650 2,037 10,613 n/m
Income Before Income Taxes363,489 357,535 5,954 1.7 
Income Tax Expense69,298 73,351 (4,053)(5.5)
Net Income$294,191 $284,184 $10,007 3.5 %
Operating Revenues decreased $111.0 million on a consolidated basis in 2023. Electric segment operating revenues decreased 4% primarily due to decreased fuel recovery and wholesale revenues and the impact of unfavorable weather, partially offset by increased rider revenues and increased commercial and industrial sales. Manufacturing segment operating revenues increased 1% primarily due to higher sales volumes in our metal fabrication business. Plastics segment operating revenues decreased 18% due to a combination of decreased sales volumes and sales prices. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses decreased $98.5 million in 2023. Electric segment operating expenses decreased primarily due to decreased purchased power costs resulting from lower market energy prices and lower fuel costs due to decreased natural gas prices. Operating expenses in our Manufacturing segment increased primarily due to increased sales volumes in our metal fabrication business and an increase in certain variable compensation costs. Operating expenses in our Plastics segment decreased primarily due to lower sales volumes and decreased PVC resin costs. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Expense increased $1.7 million in 2023 due to an increase in our average short-term borrowings, primarily used to fund capital investments in our Electric segment, and increased interest rates on our short-term borrowings.
Nonservice Components of Postretirement Benefits improved by $9.5 million in 2023, having a positive impact on net income, primarily due to a change in actuarial assumptions used to measure our pension benefit and postretirement benefit obligations, including an increase in the discount rate applied and an increase in the expected return on assets assumption.
Other Income increased $10.6 million in 2023 primarily due to an increase in investment income earned on our short-term cash equivalent investments and investment gains from our corporate-owned life insurance policies compared to investment losses in the previous year.
Income Tax Expense decreased $4.1 million in 2023 primarily due to an increase in PTCs produced by our wind and solar generation assets. Our effective tax rate was 19.1% in 2023 and 20.5% in 2022. See Note 12 to our consolidated financial statements included in this report on Form 10-K for additional information regarding factors impacting our effective tax rate.
29

ELECTRIC SEGMENT RESULTS
The following table summarizes the operating results of our Electric segment for the years ended December 31, 2023 and 2022:
(in thousands)20232022$ change% change
Retail Sales Revenue$455,840 $470,300 $(14,460)(3.1)%
Transmission Services Revenues52,555 52,213 342 0.7 
Wholesale Revenues12,459 18,539 (6,080)(32.8)
Other Electric Revenues7,505 8,647 (1,142)(13.2)
Total Operating Revenue528,359 549,699 (21,340)(3.9)
Production Fuel60,339 65,110 (4,771)(7.3)
Purchased Power78,292 100,281 (21,989)(21.9)
Operating and Maintenance Expenses191,263 181,378 9,885 5.4 
Depreciation and Amortization75,330 72,050 3,280 4.6 
Property Taxes16,614 17,742 (1,128)(6.4)
Operating Income$106,521 $113,138 $(6,617)(5.8)%
Electric kwh Sales (in thousands)
  
Retail kwh Sales5,772,215 5,592,368 179,847 3.2 %
Wholesale kwh Sales351,729 267,184 84,545 31.6 
Heating Degree Days6,259 7,122 (863)(12.1)
Cooling Degree Days590 531 59 11.1 
Our Electric segment operating results are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table presents heating and cooling degree days as a percent of normal for the years ended December 31, 2023 and 2022:
 20232022
Heating Degree Days98.4 %112.5 %
Cooling Degree Days127.2 %113.5 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail sales under actual weather conditions and expected retail sales under normal weather conditions for the years ended December 31, 2023 and 2022, and between years:
 2023 vs Normal2023 vs 20222022 vs Normal
Effect on Diluted Earnings Per Share$0.02 $(0.09)$0.11 
Retail Revenues decreased $14.5 million primarily due to the following:
A $26.2 million decrease in fuel recovery revenues, primarily due to lower purchased power and fuel costs arising from decreased market energy costs and natural gas prices, as described below.
A $5.2 million decrease in revenues from the unfavorable impact of weather compared to last year.
Our Minnesota rate case, which was finalized in 2022, included a determination of the final interim rate refund and resulted in an additional $4.1 million of retail revenue last year.
The decreases in retail revenues described above were partially offset by the following:
•    A $10.5 million increase in retail revenues from increased sales volumes from commercial and industrial customers, including the impact of a new commercial customer load in North Dakota added during 2022.
•    A $9.6 million increase in rider revenues, including recovery of our investment in the Ashtabula III wind farm, which we acquired in January 2023, and the recovery of our investment in Hoot Lake Solar, which was completed during the year, as well as operating costs associated with these facilities.
Wholesale Revenues decreased $6.1 million primarily due to a 49% decrease in wholesale electric prices driven by decreased fuel costs.
Production Fuel costs decreased $4.8 million due to a 17% decrease in fuel cost per kwh resulting from decreases in natural gas prices, partially offset by an increase in kwhs generated from our natural gas-burning plants.
Purchased Power costs to serve retail customers decreased $22.0 million due to a 14% decrease in the price of purchased power per kwh, primarily due to decreased market energy costs, as well as decreased purchase volumes due to the acquisition of the Ashtabula III wind farm and completion of our Hoot Lake Solar project in the current year. Prior to the acquisition of Ashtabula III, OTP purchased the wind generated electricity from the facility under the terms of a power purchase agreement.
30

Operating and Maintenance Expense increased $9.9 million primarily due to:
A $3.9 million increase in labor and benefit costs partially due to increased health insurance costs, wage increases, and increased headcount.
A $2.2 million increase in vegetative maintenance costs.
A $1.9 million increase in insurance expense due in part to the addition of Ashtabula III and Hoot Lake Solar to our generation fleet during the year.
A $1.3 million increase in maintenance related to the addition and operation of Ashtabula III.
These expense increases were partially offset by, among other items, decreased outage-related costs and travel costs compared to the previous year.
Depreciation and Amortization expense increased $3.3 million primarily due to the acquisition of Ashtabula III and continued investment in distribution facilities during the year.
MANUFACTURING SEGMENT RESULTS
The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2023 and 2022:
(in thousands)20232022$ change% change
Operating Revenues$402,781 $397,983 $4,798 1.2 %
Cost of Products Sold (excluding depreciation)
310,601 315,375 (4,774)(1.5)
Selling, General, and Administrative Expenses
44,545 37,341 7,204 19.3 
Depreciation and Amortization18,495 16,202 2,293 14.2 
Operating Income$29,140 $29,065 $75 0.3 %
Operating Revenues increased $4.8 million primarily due to the combination of the following:
At BTD, operating revenues increased $12.5 million primarily due to a combination of higher sales volumes and increased pricing. Sales volumes increased 12% compared to the previous year due to strong end market demand in several segments, including the construction, industrial, and agricultural segments, and incremental volumes from additional work with existing customers. Sales price increases were implemented during the year in response to labor and non-steel material cost inflation. Sales price increases and sales volume growth were partially offset by decreased steel prices, resulting in an 11% decrease in material costs, which are passed through to customers.
At T.O. Plastics, operating revenues decreased $7.7 million primarily due to lower sales volumes. Sales volumes decreased 19% primarily due to decreased sales of horticulture products, as order and delivery lead times for these products have normalized after volatility experienced in the previous year, and customers reduced their inventory levels and are beginning to return to normal seasonal buying patterns.
Cost of Products Sold decreased $4.8 million primarily due to the combination of the following:
Cost of products sold at BTD increased $0.8 million primarily due to higher sales volumes, as discussed above. Cost of products sold also increased due to lower productivity and inflationary cost pressures which resulted in higher non-steel material, labor and overhead costs. The increase in labor costs and lower level of productivity was partially attributable to increased shift incentives and overtime wages combined with increased staffing levels to meet higher production volumes and the time required for new employees to achieve peak productivity. The impacts of higher sales volumes and increased labor and overhead costs were largely offset by decreased material costs, as discussed above.
Cost of products sold at T.O. Plastics decreased $5.6 million primarily due to lower sales volumes of horticulture products, as discussed above.
Selling, General, and Administrative Expenses increased $7.2 million primarily due to increased employee compensation from an increase in headcount, inflationary cost pressure and variable compensation driven by current year financial performance.
Depreciation and Amortization increased $2.3 million due to capital expenditures during the year, which included investments in facility improvements and purchases of equipment.
PLASTICS SEGMENT RESULTS
The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2023 and 2022:
(in thousands)20232022$ change% change
Operating Revenues$418,026 $512,527 $(94,501)(18.4)%
Cost of Products Sold (excluding depreciation)
143,521 227,569 (84,048)(36.9)
Selling, General, and Administrative Expenses
16,076 16,175 (99)(0.6)
Depreciation and Amortization4,027 4,205 (178)(4.2)
Operating Income$254,402 $264,578 $(10,176)(3.8)%
31

Operating Revenues decreased $94.5 million primarily due to a 14% decrease in sales volumes. Sales volume decreases were attributable to softer end market demand coupled with distributor inventory management, as these customers reduced their inventory levels during the first half of the year after previously building higher inventory levels in response to market uncertainty and supply chain challenges. Operating revenue decreases were also the result of a 5% decrease in sales prices, as prices in 2023 decreased from record highs in 2022.
Cost of Products Sold decreased $84.0 million due to a 26% decrease in the cost per pound of PVC pipe sold, primarily due to lower resin costs, as well as the 14% decrease in sales volumes discussed above.
CORPORATE
The following table summarizes Corporate results of operations for the years ended December 31, 2023 and 2022:
(in thousands)20232022$ change% change
Selling, General, and Administrative Expenses
$12,042 $16,202 $(4,160)(25.7)%
Depreciation and Amortization102 140 (38)(27.1)
Operating Loss$12,144 $16,342 $(4,198)(25.7)%
Selling, General, and Administrative Expenses decreased $4.2 million primarily due to lower health care costs related to our self-funded health insurance program in 2023 compared to higher claim costs in 2022.
REGULATORY MATTERS
The following provides a summary of OTP's current and recent rate case filings, rate rider filings, and other regulatory filings that have or are expected to have a material impact on our operating results, financial position, or cash flows.
RATE CASES
The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:
RevenueAllowed
ImplementationRequirementReturn onReturnEquity
JurisdictionDate(in millions)Rate Baseon EquityRatio
Minnesota07/01/22$209.0 7.18 %9.48 %52.50 %
North Dakota02/01/19153.1 7.64 9.77 52.50 
South Dakota(1)
08/01/1935.5 7.09 8.75 52.92 
(1) Includes an earnings sharing mechanism to share with South Dakota customers any weather-normalized earnings above the authorized ROE of 8.75%. The mechanism requires 50% of any weather-normalized revenue creating annual earnings in excess of the authorized ROE up to a maximum of 9.50% be returned to customers and 100% returns of revenue creating annual earnings above 9.50%.
North Dakota Rate Case: On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of return on equity of 10.6% on an equity ratio of 53.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost and investment recovery, with recovery moving from riders into base rates. The filing also includes a proposal to implement a sales adjustment mechanism to address potential significant load additions or losses. The filing included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023, and interim rates went into effect on January 1, 2024. These interim rate revenues, when collected, are subject to potential refund until the finalization of the rate case.
32

RATE RIDERS
The following table includes a summary of substantial pending and recently concluded rate rider proceedings:
RecoveryFilingAmountEffective
MechanismJurisdictionStatusDate(in millions)DateNotes
RRR - 2023
MN
Approved
11/01/22$17.507/01/23Recovery of Hoot Lake Solar costs, Ashtabula III costs, and true up for PTCs from Merricourt.
ECO - 2023
MNApproved04/03/239.710/01/23Recovery of energy conservation improvement costs as well as a demand side management financial incentive.
RRR - 2024
MN
Requested
12/04/238.007/01/24
Recovery of Hoot Lake Solar costs, Ashtabula III costs, wind upgrade project costs at our four owned wind facilities, and true up of PTCs for Merricourt.
RRR - 2023NDApproved12/30/2212.205/01/23Recovery of Merricourt, Ashtabula III and other costs.
RRR - 2022NDApproved01/05/227.804/01/22
Recovery of Merricourt costs, Ashtabula III costs, and deferred taxes and PTCs.
TCR - 2023
NDApproved09/15/227.501/01/23Recovery of transmission project costs.
TCR - 2024ND
Approved
11/02/234.501/01/24Recovery of transmission project costs.
GCR - 2022NDApproved03/01/223.307/01/22Annual update to generation cost recovery rider.
MDT - 2023
NDApproved07/08/223.101/01/23Recovery of advanced metering infrastructure, outage management system and demand response projects.
PIR - 2022SDApproved06/01/223.009/01/22Recovery of Ashtabula III, Merricourt, Astoria Station, Advanced Grid Infrastructure project costs, and impact of load growth credits.
TCR - 2023
SD
Approved
11/01/223.003/01/23Recovery of transmission project costs.
RESOURCE PLANNING
On March 31, 2023, OTP submitted a supplemental resource plan filing to the MPUC, the NDPSC, and the South Dakota Public Utilities Commission (SDPUC). The supplemental filing updated OTP’s original 2022 Integrated Resource Plan (2022 IRP), which was filed on September 1, 2021. In the supplemental filing, OTP outlined its updated plan for meeting all customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates in light of several changes that had occurred since the original filing, including significant winter and spring reserve planning margins adopted by MISO, tax credits made available for renewable energy projects under the Inflation Reduction Act, the enactment of the Clean Energy Bill in Minnesota, and volatility experienced in energy and capacity markets.
On December 15, 2023, OTP submitted a second supplemental resource plan filing to the MPUC outlining an updated plan specifically for meeting Minnesota customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates. Based on feedback received on the preferred plan outlined in the March 31, 2023 supplemental filing and the inability to reach a consensus on certain aspects of the plan, the second supplemental filing includes a proposal to bifurcate OTP's resource planning by jurisdiction.
Under bifurcated resource planning, it is anticipated that OTP would develop two separate resource plans, one plan developed for Minnesota and a second developed for North Dakota and South Dakota. Each plan would be developed incorporating the assumption that all existing generation resources, except Hoot Lake Solar, would continue to be allocated to all jurisdictions using established jurisdictional allocators. Hoot Lake Solar is currently directly allocated to only Minnesota. As new generation resources are needed for each plan, those generation resources would be allocated to the jurisdiction that is needing the resource. To the extent a common generation resource is needed for both plans, that resource would be allocated using established jurisdictional allocators. This method of resource planning would diverge from OTP’s historical practice of planning on an integrated basis for all jurisdictions served.
With the proposal of bifurcated resource planning, the supplemental filing outlines OTP’s preferred plan for Minnesota only. The preferred plan in this supplemental filing includes:
repowering four of our existing wind facilities in 2025;
the addition of approximately 200 megawatts of solar generation in 2025;
the addition of approximately 100 megawatts of wind generation in 2026;
the addition of on-site liquefied natural gas fuel storage at our Astoria Station natural gas plant in 2027;
the designation of Coyote Station, a jointly owned coal-fired generation plant, as an Available Maximum Emergency (AME) Resource beginning in 2029 and annually thereafter;
a withdrawal from our 35 percent ownership interest in Coyote Station in the event we are required to make a major, non-routine capital investment in the plant; and
the addition of approximately 50 megawatts of wind generation in 2032.
The preferred plan requests the MPUC issue an order requiring the Minnesota’s jurisdictionally allocated share of the generation from Coyote Station be designated as an AME Resource beginning March 1, 2029, subject to additional analysis to be performed by OTP. AME Resources are
33

resources called on only in the event of a maximum generation event, such as in the cases of extreme heat, cold, or other extreme events. Designating Coyote Station as an AME Resource would allow us to retain Coyote Station’s capacity, thereby providing an important reliability benefit. This also helps ensure we remain compliant with market monitoring regulations and our contractual obligations to the co-owners of Coyote Station while advancing our compliance with Minnesota's carbon-free standard. The supplemental filing requests Minnesota customer rates continue to include the recovery of an allocated share of OTP’s costs associated with owning the plant, and a return on those costs, as well as the fixed costs of operating the plant. The variable cost of operating the plant, which consists primarily of variable fuel costs, would not be attributed to Minnesota customers, except when the plant is called upon to serve Minnesota customers in emergency situations.
The supplemental IRP filing made December 15, 2023 outlines our proposed resource plan for Minnesota. We anticipate filing future resource plans on a bifurcated basis in North Dakota and South Dakota.
LIQUIDITY
LIQUIDITY OVERVIEW
We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability, because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct business operations and fund our capital expenditure program. Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of December 31, 2023, we were in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).
The following table presents the status of our lines of credit as of December 31, 2023 and 2022:
20232022
(in thousands)Line LimitAmount OutstandingLetters
of Credit
Amount AvailableAmount Available
OTC Credit Agreement
$170,000 $— $— $170,000 $170,000 
OTP Credit Agreement170,000 81,422 9,132 79,446 152,223 
Total$340,000 $81,422 $9,132 $249,446 $322,223 
OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.
As of December 31, 2023, we had $249.4 million of available liquidity under our credit facilities and $230.4 million of available cash and cash equivalents, resulting in total available liquidity of $479.8 million, compared to total available liquidity of $441.2 million as of December 31, 2022.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2023 and 2022:
(in thousands)20232022
Net Cash Provided by Operating Activities$404,499 $389,309 
Net Cash Provided by Operating Activities increased $15.2 million primarily due to an increase in net income, the absence of any pension contribution in 2023 due to the plan's funded status, and the timing of customer collections of forecasted fuel costs, partially offset by increased working capital. Working capital increased primarily due to an increase in receivables in our Plastics segment, due to increased sales volumes in the fourth quarter of the current year, and a decrease in payables due to the timing of capital investment spending in our Electric segment and inventory purchases in our Plastics segment compared to last year.
Unique market dynamics experienced by our Plastics segment businesses in 2023 and 2022 resulted in a significant increase in our overall cash from operations compared to prior periods, and we do not expect cash from operations at these levels to continue in future years.
(in thousands)20232022
Net Cash Used in Investing Activities$289,287 $175,071 
Net Cash Used in Investment Activities increased $114.2 million primarily due to a higher amount of Electric segment capital investment compared to last year, including the purchase of the Ashtabula III wind farm, investments in our Hoot Lake Solar facility and several wind repowering projects, transmission and distribution asset investments, and investments in new technology. Capital expenditures in our Manufacturing and Plastics segments increased $23.1 million as a result of investments in additional equipment and facility expansion projects at our Plastics segment facility in Arizona and our Manufacturing segment facility in Georgia.
34

(in thousands)20232022
Net Cash Used in Financing Activities$3,835 $96,779 
Net Cash Used in Financing Activities decreased $92.9 million primarily due to increased short-term borrowings on our OTP credit facility, which were primarily used to fund capital expenditures in our Electric segment, including the acquisition of the Ashtabula III wind farm. Our financing activities in 2023 included net short-term borrowings of $73.2 million compared to net short-term repayments of $83.0 million in 2022. There was no change in our long-term debt in 2023. In 2022, OTP issued $60.0 million of long-term debt, net of retirements, which was primarily used to fund the repayment of short-term credit facility borrowings and fund capital expenditures. In 2023, we made dividend payments of $73.1 million compared to $68.8 million in 2022.
CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
Our capital expenditure plan includes investments in electric generation facilities, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure plan is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.
The following provides a summary of capital expenditures for the years ended December 31, 2023 and 2022 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2024 through 2028:
(in millions)2022202320242025202620272028Total
Electric Segment:       
Renewables
$118 $93 $33 $113 $129 $486 
Transmission
51 85 111 98 100 445 
Distribution
38 39 36 38 39 190 
Other67 37 30 27 25 186 
Total Electric Segment148 241 274 254 210 276 293 1,307 
Manufacturing and Plastics Segments23 46 79 35 27 25 26 192 
Total Capital Expenditures$171 $287 $353 $289 $237 $301 $319 $1,499 
CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at December 31, 2023 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.
(in millions)TotalLess than
1 Year
1-3
Years
3-5
Years
More than
5 Years
Debt Obligations$908 $81 $80 $42 $705 
Interest on Debt Obligations602 35 70 62 435 
Coal Contracts485 24 49 52 360 
Capacity and Energy Requirements4 — — — 
Postretirement Benefit Obligations66 11 11 39 
Other Purchase Obligations (including land easements)79 59 
Operating Lease Obligations17 — 
Total Contractual Cash Obligations$2,161 $157 $227 $175 $1,602 
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company (CCMC) under the Lignite Sales Agreement (LSA) that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan (ESSRP), but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make any contributions to that plan.
COMMON STOCK DIVIDENDS
We paid dividends to our shareholders totaling $73.1 million, or $1.75 per share, in 2023. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, level of earnings and cash flows from operations, our capital expenditure plan and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC. These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders. See Note 14 to our consolidated financial statements included in this report on Form 10-K for additional information. The decision to declare a dividend is reviewed quarterly by our Board of Directors. On February 5, 2024, our Board of Directors increased the quarterly dividend from $0.4375 to $0.4675 per common share.
35

CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, borrowing capacity under our lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing. Debt financing will be required in the five-year period from 2024 through 2028 to refinance maturing debt and to finance our capital investments within our Electric segment. Our financing plans are subject to change and are impacted by our planned level of capital investments, a decision to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes.
REGISTRATION STATEMENTS
On May 3, 2021, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement expires in May 2024, at which time we anticipate filing a new shelf registration statement. No shares were issued pursuant to the registration statement in 2023.
On May 3, 2021, we filed a second registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends or making optional cash investments. Shares purchased under the plan may be new issue common shares or common shares purchased on the open market. The registration statement expires in May 2024, at which time we plan to file a new registration statement. In 2023, we issued 105,663 shares under the plan. All shares issued under the plan to date have been open market purchases and there have been no new issue shares, resulting in no proceeds received by the Company. As of December 31, 2023, 1,145,330 shares remained available for purchase or issuance under the plan.
SHORT-TERM DEBT
The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. The agreements generally bear interest at the Secured Overnight Financing Rate (SOFR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the issuer. The weighted-average interest rate on all outstanding borrowings as of December 31, 2023 and 2022 was 6.70% and 5.61%.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2023:
(in thousands, except interest rates)OTC Credit AgreementOTP Credit Agreement
Borrowing Limit$170,000 $170,000 
Borrowing Limit if Accordion Exercised1
290,000 250,000 
Amount Restricted Due to Outstanding Letters of Credit at Year-End— 9,132 
Amount Outstanding at Year-End— 81,422 
Average Amount Outstanding During Year— 50,883 
Maximum Amount Outstanding During the Year— 87,788 
Interest Rate at Year-End6.85 %6.70 %
Expiration DateOctober 29, 2027October 29, 2027
1Each facility includes an accordion feature allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
At December 31, 2023, we had $827.0 million of principal outstanding under long-term debt arrangements. Note 9 to our consolidated financial statements included in this report on Form 10-K includes information regarding these instruments. The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2052.
Financial Covenants
Certain of our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2023, we were in compliance with these financial covenants as further described below:
OTC, under its financial covenants, may not permit its ratio of Interest-Bearing Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Indebtedness to exceed 10% of our Total Capitalization. As of December 31, 2023, our Interest-Bearing Debt to Total Capitalization was 0.39 to 1.00, our Interest and Dividend Coverage Ratio was 10.85 to 1.00 and we had no Priority Indebtedness outstanding.
OTP, under its financial covenants, may not permit its ratio of Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Debt to exceed 20% of its Total Capitalization. As of December 31, 2023, OTP's Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, its Interest and Dividend Coverage Ratio was 3.54 to 1.00 and it had no Priority Indebtedness outstanding.
None of our debt agreements include any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
36

Credit Ratings
The credit ratings of OTC and OTP as of December 31, 2023 are summarized below:
Otter Tail CorporationOtter Tail Power Company
Moody'sFitchS&PMoody'sFitchS&P
Corporate Credit/Long-Term Issuer Default RatingBaa2
BBB
BBBA3
BBB+
BBB+
Senior Unsecured Debtn/a
BBB
n/an/a
A-
n/a
OutlookStableStableStableStableStableStable
CRITICAL ACCOUNTING ESTIMATES
Preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and the Company’s discussion and analysis of its financial condition and operating results requires management to make assumptions, estimates and judgments that affect the reported amounts. While we believe the estimates, assumptions, and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of our Board of Directors. The following critical accounting policies affect the most significant judgments and estimates used in the preparation of our consolidated financial statements.
REGULATORY ACCOUNTING
Our utility business is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which requires the recognition of regulatory assets and regulatory liabilities for amounts that otherwise would impact the statement of income or comprehensive income when it is probable that such amounts will be collected from customers or credited to customers through the rate-making process. This guidance also provides recognition criteria for adjustments to rates outside of a general rate case proceeding which are provided to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. Regulatory assets generally represent costs that have been incurred but have been deferred because future recovery from customers, as established through the rate-making process, is probable. Regulatory liabilities generally represent amounts to be refunded to customers or amounts currently collected from customers for future costs.
We assess the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Our probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which we operate and the impact these incurred costs may have on our customers. Changes in our assessments regarding the likelihood of recovery or settlement of our regulatory assets and liabilities may have a material impact on our operating results and financial position. Further, if we determine that all or a portion of our utility business no longer meets the criteria for continued application of regulatory accounting, or our regulators disallow recovery of a previously incurred cost or eliminate a regulatory liability, we would be required to remove the associated regulatory assets and liabilities from our consolidated balance sheets and recognize those amounts in the consolidated statement of income as an expense or income item, or in the consolidated statement of comprehensive income as a loss or gain item, in the period in which this accounting treatment is no longer applicable.
As of December 31, 2023 and 2022, we had regulatory assets of $111.8 million and $119.7 million and regulatory liabilities of $302.0 million and $261.8 million. If future recovery of amounts recorded as regulatory assets was no longer probable we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.
PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS
Pension and postretirement benefit liabilities and expenses are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates. See Note 10 to our consolidated financial statements included in this report on Form 10-K for additional information on our pension and postretirement benefit plans and related assumptions.
These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 30 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Likewise, compensation decreases and healthcare cost decreases or an increase in the discount rate applied from one year to the next can significantly decrease our benefit expenses in the year of the change. Also, a change in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well above or below assumed rates of return or a change in the anticipated life expectancy of plan participants could result in significant increases or decreases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.
37

We estimate the discount rate through the use of a hypothetical bond portfolio method, which incorporates yields on a collection of high credit quality bonds that produce cash flows similar to our anticipated future benefit payments.
We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels.
Pension plan assets are invested in a portfolio according to our return, liquidity and diversification objectives to provide a source of funding for plan obligations and manage contributions to the plan. The principal process for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.
At December 31, 2023, we set the discount rate used to measure our pension plan obligations at 5.57% and at 5.53% to measure postretirement healthcare obligations, a six and one basis point increase, respectively, from the estimates used at December 31, 2022. Our estimates used to determine benefit cost for 2023 included a discount rate of 5.51% for pension benefits and 5.52% for postretirement healthcare costs, a 248 and 251 basis point increase, respectively, from 2022 estimates. The 5.52% discount rate for postretirement healthcare costs was adjusted to 6.06% effective September 30, 2023, in connection with a remeasurement of our plan liability due to an amendment to the plan. The adjustment to 6.06% was a 305 basis point increase from the 2022 estimate. In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2023, a 70 basis point increase from our 2022 estimate.
The following table summarizes the impact on 2023 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:
(in thousands)