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as $ 14.0 million, $ 13.4 million, | text | 13.4 | monetaryItemType | text: <entity> 13.4 </entity> <entity type> monetaryItemType </entity type> <context> as $ 14.0 million, $ 13.4 million, </context> | us-gaap:DefinedContributionPlanCostRecognized |
and $ 12.2 million, respectively. | text | 12.2 | monetaryItemType | text: <entity> 12.2 </entity> <entity type> monetaryItemType </entity type> <context> and $ 12.2 million, respectively. </context> | us-gaap:DefinedContributionPlanCostRecognized |
The accumulated benefit obligation for all defined benefit pension plans was $ 360.7 million and | text | 360.7 | monetaryItemType | text: <entity> 360.7 </entity> <entity type> monetaryItemType </entity type> <context> The accumulated benefit obligation for all defined benefit pension plans was $ 360.7 million and </context> | us-gaap:DefinedBenefitPlanAccumulatedBenefitObligation |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 281.1 | monetaryItemType | text: <entity> 281.1 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsPlanAssets |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 278.4 | monetaryItemType | text: <entity> 278.4 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsAccumulatedBenefitObligation |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 224.0 | monetaryItemType | text: <entity> 224.0 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsProjectedBenefitObligation |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 262.7 | monetaryItemType | text: <entity> 262.7 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsPlanAssets |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 251.0 | monetaryItemType | text: <entity> 251.0 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsAccumulatedBenefitObligation |
were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re | text | 210.4 | monetaryItemType | text: <entity> 210.4 </entity> <entity type> monetaryItemType </entity type> <context> were $ 281.1 million, $ 278.4 million, and $ 224.0 million, respectively, as of December 31, 2023 and $ 262.7 million, $ 251.0 million, and $ 210.4 million, re </context> | us-gaap:DefinedBenefitPlanPensionPlanWithProjectedBenefitObligationInExcessOfPlanAssetsProjectedBenefitObligation |
The accumulated benefit obligation and fair value of plan assets for other postretirement benefit plans with an accumulated benefit obligation in excess of plan assets were $ 21.3 million and $ 0.0 million , respectively, as of December 31, 2023 and were | text | 21.3 | monetaryItemType | text: <entity> 21.3 </entity> <entity type> monetaryItemType </entity type> <context> The accumulated benefit obligation and fair value of plan assets for other postretirement benefit plans with an accumulated benefit obligation in excess of plan assets were $ 21.3 million and $ 0.0 million , respectively, as of December 31, 2023 and were </context> | us-gaap:DefinedBenefitPlanPensionPlansWithAccumulatedBenefitObligationsInExcessOfPlanAssetsAggregateAccumulatedBenefitObligation |
The accumulated benefit obligation and fair value of plan assets for other postretirement benefit plans with an accumulated benefit obligation in excess of plan assets were $ 21.3 million and $ 0.0 million , respectively, as of December 31, 2023 and were | text | 0.0 million | monetaryItemType | text: <entity> 0.0 million </entity> <entity type> monetaryItemType </entity type> <context> The accumulated benefit obligation and fair value of plan assets for other postretirement benefit plans with an accumulated benefit obligation in excess of plan assets were $ 21.3 million and $ 0.0 million , respectively, as of December 31, 2023 and were </context> | us-gaap:DefinedBenefitPlanPensionPlansWithAccumulatedBenefitObligationsInExcessOfPlanAssetsAggregateFairValueOfPlanAssets |
$ 19.9 million and $ 0.0 million , | text | 19.9 | monetaryItemType | text: <entity> 19.9 </entity> <entity type> monetaryItemType </entity type> <context> $ 19.9 million and $ 0.0 million , </context> | us-gaap:DefinedBenefitPlanPensionPlansWithAccumulatedBenefitObligationsInExcessOfPlanAssetsAggregateAccumulatedBenefitObligation |
$ 19.9 million and $ 0.0 million , | text | 0.0 million | monetaryItemType | text: <entity> 0.0 million </entity> <entity type> monetaryItemType </entity type> <context> $ 19.9 million and $ 0.0 million , </context> | us-gaap:DefinedBenefitPlanPensionPlansWithAccumulatedBenefitObligationsInExcessOfPlanAssetsAggregateFairValueOfPlanAssets |
We recorded settlement losses totaling $ 1.2 million during 2022. The settlement losses were the result of lump-sum payments to participants that exceeded the sum of the pension plan's respective annual service cost and interest cost amounts. | text | 1.2 | monetaryItemType | text: <entity> 1.2 </entity> <entity type> monetaryItemType </entity type> <context> We recorded settlement losses totaling $ 1.2 million during 2022. The settlement losses were the result of lump-sum payments to participants that exceeded the sum of the pension plan's respective annual service cost and interest cost amounts. </context> | us-gaap:DefinedBenefitPlanRecognizedNetGainLossDueToSettlements1 |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 45 | percentItemType | text: <entity> 45 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 60 | percentItemType | text: <entity> 60 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 40 | percentItemType | text: <entity> 40 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 55 | percentItemType | text: <entity> 55 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 80 | percentItemType | text: <entity> 80 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 90 | percentItemType | text: <entity> 90 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 10 | percentItemType | text: <entity> 10 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. | text | 20 | percentItemType | text: <entity> 20 </entity> <entity type> percentItemType </entity type> <context> Absent regulatory or statutory limitations, the target asset allocation for the investment of the assets for our ongoing pension plans is 45 - 60 % in asset protection investments and 40 - 55 % in asset growth investments and for our pension plans where the majority of the participants are in payment or terminated vested status is 80 - 90 % in asset protection investments and 10 - 20 % in asset growth investments. Asset growth investments include a diversified mix of U.S. and international equity, primarily invested through investment funds. Asset protection investments include government securities and investment grade corporate bonds, primarily invested through investment funds and group insurance contracts. We develop our expected long-term rate of return assumptions based on the historical rates of returns for securities and instruments of the type in which our plans invest. </context> | us-gaap:DefinedBenefitPlanPlanAssetsTargetAllocationPercentage |
We anticipate contributing $ 12.3 million and $ 1.5 million to our pension and other postretirement plans, respectively, during 2024. | text | 12.3 | monetaryItemType | text: <entity> 12.3 </entity> <entity type> monetaryItemType </entity type> <context> We anticipate contributing $ 12.3 million and $ 1.5 million to our pension and other postretirement plans, respectively, during 2024. </context> | us-gaap:DefinedBenefitPlanExpectedFutureEmployerContributionsNextFiscalYear |
We anticipate contributing $ 12.3 million and $ 1.5 million to our pension and other postretirement plans, respectively, during 2024. | text | 1.5 | monetaryItemType | text: <entity> 1.5 </entity> <entity type> monetaryItemType </entity type> <context> We anticipate contributing $ 12.3 million and $ 1.5 million to our pension and other postretirement plans, respectively, during 2024. </context> | us-gaap:DefinedBenefitPlanExpectedFutureEmployerContributionsNextFiscalYear |
In addition, we reclassified $ 0.1 million of accumulated foreign currency translation gains associated with the sale of the Hite JV. | text | 0.1 | monetaryItemType | text: <entity> 0.1 </entity> <entity type> monetaryItemType </entity type> <context> In addition, we reclassified $ 0.1 million of accumulated foreign currency translation gains associated with the sale of the Hite JV. </context> | us-gaap:OtherComprehensiveIncomeForeignCurrencyTransactionAndTranslationGainLossBeforeReclassificationAndTax |
At December 31, 2023, the total unrecognized compensation cost related to all nonvested awards was $ 31.5 million. That cost is expected to be recognized over a weighted-average period of 2.0 years. Historically, we have issued treasury shares, if available, to satisfy award c | text | 31.5 | monetaryItemType | text: <entity> 31.5 </entity> <entity type> monetaryItemType </entity type> <context> At December 31, 2023, the total unrecognized compensation cost related to all nonvested awards was $ 31.5 million. That cost is expected to be recognized over a weighted-average period of 2.0 years. Historically, we have issued treasury shares, if available, to satisfy award c </context> | us-gaap:EmployeeServiceShareBasedCompensationNonvestedAwardsTotalCompensationCostNotYetRecognized |
We sell our products to many customers in several markets across multiple geographic areas. The ten largest customers, of which seven are distributors, constitute in aggregate approximately 44 %, 45 %, and 44 % of revenues in 2023, 2022, and 2021, respectively. | text | 44 | percentItemType | text: <entity> 44 </entity> <entity type> percentItemType </entity type> <context> We sell our products to many customers in several markets across multiple geographic areas. The ten largest customers, of which seven are distributors, constitute in aggregate approximately 44 %, 45 %, and 44 % of revenues in 2023, 2022, and 2021, respectively. </context> | us-gaap:ConcentrationRiskPercentage1 |
We sell our products to many customers in several markets across multiple geographic areas. The ten largest customers, of which seven are distributors, constitute in aggregate approximately 44 %, 45 %, and 44 % of revenues in 2023, 2022, and 2021, respectively. | text | 45 | percentItemType | text: <entity> 45 </entity> <entity type> percentItemType </entity type> <context> We sell our products to many customers in several markets across multiple geographic areas. The ten largest customers, of which seven are distributors, constitute in aggregate approximately 44 %, 45 %, and 44 % of revenues in 2023, 2022, and 2021, respectively. </context> | us-gaap:ConcentrationRiskPercentage1 |
At December 31, 2023, we were committed to purchase approximately 2.7 million pounds of copper at an aggregate fixed cost of $ 10.5 million. At December 31, 2023, this fixed cost was $ 0.1 million greater than the market cost that would be incurred on a spot purchase of the same amount of copper. The aggregate market cost was based on the current market price of copper obtained from the New York Mercantile Exchange. | text | 10.5 | monetaryItemType | text: <entity> 10.5 </entity> <entity type> monetaryItemType </entity type> <context> At December 31, 2023, we were committed to purchase approximately 2.7 million pounds of copper at an aggregate fixed cost of $ 10.5 million. At December 31, 2023, this fixed cost was $ 0.1 million greater than the market cost that would be incurred on a spot purchase of the same amount of copper. The aggregate market cost was based on the current market price of copper obtained from the New York Mercantile Exchange. </context> | us-gaap:RecordedUnconditionalPurchaseObligation |
Approximately 27 % of our labor force is covered by collective bargaining agreements at various locations around the world, and we expect to renegotiate these agreements during 2024. | text | 27 | percentItemType | text: <entity> 27 </entity> <entity type> percentItemType </entity type> <context> Approximately 27 % of our labor force is covered by collective bargaining agreements at various locations around the world, and we expect to renegotiate these agreements during 2024. </context> | us-gaap:ConcentrationRiskPercentage1 |
At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. | text | 10.6 | monetaryItemType | text: <entity> 10.6 </entity> <entity type> monetaryItemType </entity type> <context> At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. </context> | us-gaap:LossContingencyEstimateOfPossibleLoss |
At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. | text | 4.7 | monetaryItemType | text: <entity> 4.7 </entity> <entity type> monetaryItemType </entity type> <context> At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. </context> | us-gaap:LossContingencyEstimateOfPossibleLoss |
At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. | text | 4.6 | monetaryItemType | text: <entity> 4.6 </entity> <entity type> monetaryItemType </entity type> <context> At December 31, 2023, we were party to unused standby letters of credit, surety bonds, and bank guarantees totaling $ 10.6 million, $ 4.7 million, and $ 4.6 million, respectively. These commitments are generally issued to secure obligations we have for a variety of commercial reasons, such as workers compensation self-insurance programs in several states and the importation and exportation of product. </context> | us-gaap:LossContingencyEstimateOfPossibleLoss |
We present two reportable segments: Regulated Operations and ALLETE Clean Energy. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment. | text | two | integerItemType | text: <entity> two </entity> <entity type> integerItemType </entity type> <context> We present two reportable segments: Regulated Operations and ALLETE Clean Energy. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment. </context> | us-gaap:NumberOfReportableSegments |
Our investment in Nobles 2 represents a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20 -year PPA with Minnesota Power. | text | 49 | percentItemType | text: <entity> 49 </entity> <entity type> percentItemType </entity type> <context> Our investment in Nobles 2 represents a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20 -year PPA with Minnesota Power. </context> | us-gaap:EquityMethodInvestmentOwnershipPercentage |
BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2024, Square Butte supplied 50 percent ( 227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 9. Commitments, Guarantees and Contingencies.) | text | 50 | percentItemType | text: <entity> 50 </entity> <entity type> percentItemType </entity type> <context> BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2024, Square Butte supplied 50 percent ( 227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 9. Commitments, Guarantees and Contingencies.) </context> | us-gaap:LongTermContractForPurchaseOfElectricPowerShareOfPlantOutputBeingPurchased |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 13.3 | monetaryItemType | text: <entity> 13.3 </entity> <entity type> monetaryItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:AccountsReceivableGross |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 11.2 | monetaryItemType | text: <entity> 11.2 </entity> <entity type> monetaryItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:AccountsReceivableGross |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 33 | percentItemType | text: <entity> 33 </entity> <entity type> percentItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:ConcentrationRiskPercentage1 |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 27 | percentItemType | text: <entity> 27 </entity> <entity type> percentItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:ConcentrationRiskPercentage1 |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 32 | percentItemType | text: <entity> 32 </entity> <entity type> percentItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:ConcentrationRiskPercentage1 |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 21 | percentItemType | text: <entity> 21 </entity> <entity type> percentItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:ConcentrationRiskPercentage1 |
We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). | text | 26 | percentItemType | text: <entity> 26 </entity> <entity type> percentItemType </entity type> <context> We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022). </context> | us-gaap:ConcentrationRiskPercentage1 |
Prepayments and Other on the Consolidated Balance Sheet included $ 32.4 million of costs in excess of billings at New Energy as of December 31, 2024 ($ 21.5 million as of December 31, 2023). | text | 32.4 | monetaryItemType | text: <entity> 32.4 </entity> <entity type> monetaryItemType </entity type> <context> Prepayments and Other on the Consolidated Balance Sheet included $ 32.4 million of costs in excess of billings at New Energy as of December 31, 2024 ($ 21.5 million as of December 31, 2023). </context> | us-gaap:OtherAssetsCurrent |
Prepayments and Other on the Consolidated Balance Sheet included $ 32.4 million of costs in excess of billings at New Energy as of December 31, 2024 ($ 21.5 million as of December 31, 2023). | text | 21.5 | monetaryItemType | text: <entity> 21.5 </entity> <entity type> monetaryItemType </entity type> <context> Prepayments and Other on the Consolidated Balance Sheet included $ 32.4 million of costs in excess of billings at New Energy as of December 31, 2024 ($ 21.5 million as of December 31, 2023). </context> | us-gaap:OtherAssetsCurrent |
(a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $ 42.3 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 37.2 million as of December 31, 2023). | text | 42.3 | monetaryItemType | text: <entity> 42.3 </entity> <entity type> monetaryItemType </entity type> <context> (a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $ 42.3 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 37.2 million as of December 31, 2023). </context> | us-gaap:OtherReceivables |
(a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $ 42.3 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 37.2 million as of December 31, 2023). | text | 37.2 | monetaryItemType | text: <entity> 37.2 </entity> <entity type> monetaryItemType </entity type> <context> (a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $ 42.3 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 37.2 million as of December 31, 2023). </context> | us-gaap:OtherReceivables |
The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the drag line at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $ 3 million and is included in our calculation of the right-of-use asset and lease liability recorded. None of our other leases contain residual value guarantees. We have one finance lease for heavy equipment which includes a purchase option we are reasonably certain to exercise when the lease terminates. | text | 3 | monetaryItemType | text: <entity> 3 </entity> <entity type> monetaryItemType </entity type> <context> The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the drag line at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $ 3 million and is included in our calculation of the right-of-use asset and lease liability recorded. None of our other leases contain residual value guarantees. We have one finance lease for heavy equipment which includes a purchase option we are reasonably certain to exercise when the lease terminates. </context> | us-gaap:ResidualValueOfLeasedAsset |
includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 56 percent of total regulated utility kWh sales for the year ended December 31, 2024. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2024. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2028 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $ 60 million per annum through 2028 and approximately $ 10 million in 2029, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts. | text | 60 | monetaryItemType | text: <entity> 60 </entity> <entity type> monetaryItemType </entity type> <context> includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 56 percent of total regulated utility kWh sales for the year ended December 31, 2024. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2024. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2028 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $ 60 million per annum through 2028 and approximately $ 10 million in 2029, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts. </context> | us-gaap:RevenueRemainingPerformanceObligation |
includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 56 percent of total regulated utility kWh sales for the year ended December 31, 2024. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2024. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2028 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $ 60 million per annum through 2028 and approximately $ 10 million in 2029, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts. | text | 10 | monetaryItemType | text: <entity> 10 </entity> <entity type> monetaryItemType </entity type> <context> includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 56 percent of total regulated utility kWh sales for the year ended December 31, 2024. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2024. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2028 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $ 60 million per annum through 2028 and approximately $ 10 million in 2029, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts. </context> | us-gaap:RevenueRemainingPerformanceObligation |
We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). | text | 15.9 | monetaryItemType | text: <entity> 15.9 </entity> <entity type> monetaryItemType </entity type> <context> We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). </context> | us-gaap:ContractWithCustomerAssetNetNoncurrent |
We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). | text | 18.5 | monetaryItemType | text: <entity> 18.5 </entity> <entity type> monetaryItemType </entity type> <context> We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). </context> | us-gaap:ContractWithCustomerAssetNetNoncurrent |
We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). | text | 2.4 | monetaryItemType | text: <entity> 2.4 </entity> <entity type> monetaryItemType </entity type> <context> We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $ 2.4 million of non-cash amortization for the year ended December 31, 2024 ($ 2.4 million for the year ended December 31, 2023). </context> | us-gaap:CapitalizedContractCostAmortization |
Interest and Investment Income for the year ended December 31, 2023, reflects $ 5.1 million of interest income related to interest awarded as part of an arbitration ruling involving a subsidiary of ALLETE Clean Energy. (See Note 9. Commitments, Guarantees and Contingencies.) | text | 5.1 | monetaryItemType | text: <entity> 5.1 </entity> <entity type> monetaryItemType </entity type> <context> Interest and Investment Income for the year ended December 31, 2023, reflects $ 5.1 million of interest income related to interest awarded as part of an arbitration ruling involving a subsidiary of ALLETE Clean Energy. (See Note 9. Commitments, Guarantees and Contingencies.) </context> | us-gaap:OtherNonoperatingIncomeExpense |
Minnesota Power owns 80 percent of the 585 MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining 20 percent, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income. | text | 80 | percentItemType | text: <entity> 80 </entity> <entity type> percentItemType </entity type> <context> Minnesota Power owns 80 percent of the 585 MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining 20 percent, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary, is developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting upon completion of the facility pursuant to a capacity dedication agreement. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $ 700 million, of which South Shore Energy will be responsible for approximately 20 percent. South Shore Energy’s portion of NTEC project costs incurred through December 31, 2024, is approximately $ 10 million. | text | 20 | percentItemType | text: <entity> 20 </entity> <entity type> percentItemType </entity type> <context> South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary, is developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting upon completion of the facility pursuant to a capacity dedication agreement. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $ 700 million, of which South Shore Energy will be responsible for approximately 20 percent. South Shore Energy’s portion of NTEC project costs incurred through December 31, 2024, is approximately $ 10 million. </context> | us-gaap:LongTermContractForPurchaseOfElectricPowerShareOfPlantOutputBeingPurchased |
.) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). | text | 20.0 | monetaryItemType | text: <entity> 20.0 </entity> <entity type> monetaryItemType </entity type> <context> .) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). </context> | us-gaap:RegulatedOperatingRevenueOther |
.) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). | text | 57.0 | monetaryItemType | text: <entity> 57.0 </entity> <entity type> monetaryItemType </entity type> <context> .) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). </context> | us-gaap:RegulatedOperatingRevenueOther |
.) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). | text | 38.8 | monetaryItemType | text: <entity> 38.8 </entity> <entity type> monetaryItemType </entity type> <context> .) Revenue from cost recovery riders was $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022). </context> | us-gaap:RegulatedOperatingRevenueOther |
Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See | text | 9.25 | percentItemType | text: <entity> 9.25 </entity> <entity type> percentItemType </entity type> <context> Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See | text | 53.81 | percentItemType | text: <entity> 53.81 </entity> <entity type> percentItemType </entity type> <context> Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See | text | 9.65 | percentItemType | text: <entity> 9.65 </entity> <entity type> percentItemType </entity type> <context> Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See | text | 52.50 | percentItemType | text: <entity> 52.50 </entity> <entity type> percentItemType </entity type> <context> Minnesota Power’s retail base rates through 2022 were based on a 2018 MPUC retail rate order that allowed for a 9.25 percent return on common equity and a 53.81 percent equity ratio. Interim rates were implemented in Minnesota Power’s 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power’s 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
.) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity 9.78 percent and an equity ratio of 53.00 percent. | text | 9.78 | percentItemType | text: <entity> 9.78 </entity> <entity type> percentItemType </entity type> <context> .) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity 9.78 percent and an equity ratio of 53.00 percent. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
.) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity 9.78 percent and an equity ratio of 53.00 percent. | text | 53.00 | percentItemType | text: <entity> 53.00 </entity> <entity type> percentItemType </entity type> <context> .) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity 9.78 percent and an equity ratio of 53.00 percent. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. | text | 12.00 | percentItemType | text: <entity> 12.00 </entity> <entity type> percentItemType </entity type> <context> On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreasePercentage |
On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. | text | 10.30 | percentItemType | text: <entity> 10.30 </entity> <entity type> percentItemType </entity type> <context> On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. | text | 53.00 | percentItemType | text: <entity> 53.00 </entity> <entity type> percentItemType </entity type> <context> On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. | text | 89 | monetaryItemType | text: <entity> 89 </entity> <entity type> monetaryItemType </entity type> <context> On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. | text | 64 | monetaryItemType | text: <entity> 64 </entity> <entity type> monetaryItemType </entity type> <context> On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. | text | 33.97 | monetaryItemType | text: <entity> 33.97 </entity> <entity type> monetaryItemType </entity type> <context> On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. | text | 9.78 | percentItemType | text: <entity> 9.78 </entity> <entity type> percentItemType </entity type> <context> On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. | text | 53.00 | percentItemType | text: <entity> 53.00 </entity> <entity type> percentItemType </entity type> <context> On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. | text | 23.0 | monetaryItemType | text: <entity> 23.0 </entity> <entity type> monetaryItemType </entity type> <context> On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power’s refund calculation. </context> | us-gaap:RegulatoryLiabilities |
. In an order dated February 28, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC’s order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023. | text | 9.65 | percentItemType | text: <entity> 9.65 </entity> <entity type> percentItemType </entity type> <context> . In an order dated February 28, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC’s order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
. In an order dated February 28, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC’s order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023. | text | 52.50 | percentItemType | text: <entity> 52.50 </entity> <entity type> percentItemType </entity type> <context> . In an order dated February 28, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC’s order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
In an order dated September 29, 2023, the MPUC approved Minnesota Power’s final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power’s interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $ 39 million pre-tax as of September 30, 2023 (approximately $ 18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023. | text | 39 | monetaryItemType | text: <entity> 39 </entity> <entity type> monetaryItemType </entity type> <context> In an order dated September 29, 2023, the MPUC approved Minnesota Power’s final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power’s interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $ 39 million pre-tax as of September 30, 2023 (approximately $ 18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023. </context> | us-gaap:CustomerRefundLiabilityCurrent |
In an order dated September 29, 2023, the MPUC approved Minnesota Power’s final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power’s interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $ 39 million pre-tax as of September 30, 2023 (approximately $ 18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023. | text | 18 | monetaryItemType | text: <entity> 18 </entity> <entity type> monetaryItemType </entity type> <context> In an order dated September 29, 2023, the MPUC approved Minnesota Power’s final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power’s interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $ 39 million pre-tax as of September 30, 2023 (approximately $ 18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023. </context> | us-gaap:CustomerRefundLiabilityCurrent |
Minnesota Power incurred higher fuel and purchased power costs in 2022 than those factored in its fuel adjustment forecast filed in May 2021 for 2022, which resulted in the recognition of an approximately $ 13 million regulatory asset as of December 31, 2022. The MPUC approved recovery of the regulatory asset in an order dated July 31, 2023; recovery of the regulatory asset began in the third quarter of 2023 and ended in mid-2024. | text | 13 | monetaryItemType | text: <entity> 13 </entity> <entity type> monetaryItemType </entity type> <context> Minnesota Power incurred higher fuel and purchased power costs in 2022 than those factored in its fuel adjustment forecast filed in May 2021 for 2022, which resulted in the recognition of an approximately $ 13 million regulatory asset as of December 31, 2022. The MPUC approved recovery of the regulatory asset in an order dated July 31, 2023; recovery of the regulatory asset began in the third quarter of 2023 and ended in mid-2024. </context> | us-gaap:RegulatoryAssetsNoncurrent |
Minnesota Power incurred lower fuel and purchased power costs in 2023 than those factored in its fuel adjustment forecast filed in May 2022 for 2023, which resulted in the recognition of a $ 15.5 million regulatory liability as of December 31, 2023. Minnesota Power requested to refund the regulatory liability over 12 months beginning in the third quarter of 2024 as part of its annual true-up filing submitted to the MPUC on March 1, 2024. In an order dated July 1, 2024, the MPUC approved the filing, and authorized Minnesota Power to refund the regulatory liability over 12 months beginning on September 1, 2024. | text | 15.5 | monetaryItemType | text: <entity> 15.5 </entity> <entity type> monetaryItemType </entity type> <context> Minnesota Power incurred lower fuel and purchased power costs in 2023 than those factored in its fuel adjustment forecast filed in May 2022 for 2023, which resulted in the recognition of a $ 15.5 million regulatory liability as of December 31, 2023. Minnesota Power requested to refund the regulatory liability over 12 months beginning in the third quarter of 2024 as part of its annual true-up filing submitted to the MPUC on March 1, 2024. In an order dated July 1, 2024, the MPUC approved the filing, and authorized Minnesota Power to refund the regulatory liability over 12 months beginning on September 1, 2024. </context> | us-gaap:RegulatoryLiabilityNoncurrent |
Minnesota Power incurred higher fuel and purchased power costs in 2024 than those factored in its fuel adjustment forecast filed in May 2023 for 2024, which resulted in the recognition of a $ 4.5 million regulatory asset as of December 31, 2024. Minnesota Power expects to request recovery of the regulatory asset as part of its annual true-up filing with the MPUC in March 2025. | text | 4.5 | monetaryItemType | text: <entity> 4.5 </entity> <entity type> monetaryItemType </entity type> <context> Minnesota Power incurred higher fuel and purchased power costs in 2024 than those factored in its fuel adjustment forecast filed in May 2023 for 2024, which resulted in the recognition of a $ 4.5 million regulatory asset as of December 31, 2024. Minnesota Power expects to request recovery of the regulatory asset as part of its annual true-up filing with the MPUC in March 2025. </context> | us-gaap:RegulatoryLiabilityNoncurrent |
On December 30, 2024, Minnesota Power submitted a petition with the MPUC seeking deferral accounting treatment for investigative costs and the increase in depreciation expense resulting from compliance costs that will be incurred related to the new Coal Combustion Rule (CCR) Legacy Rule, which was published in the Federal Register on May 8, 2024. (See Note 9. Commitments, Guarantees and Contingencies.) Compliance with the CCR Legacy Rule is expected to result in a significant increase to our MPUC-approved decommissioning costs for Boswell and Laskin. If the MPUC approves our request for deferral accounting treatment, these costs would be deferred for recovery to our next rate case or other regulatory proceeding. In 2024, we recorded depreciation expense related to this rule, of which $ 4.2 million pre-tax would be moved to a deferred tracking account for MPUC review through a future rate case or other proceeding if the MPUC approves our request for deferral accounting treatment. We are unable to predict the outcome of this proceeding. | text | 4.2 | monetaryItemType | text: <entity> 4.2 </entity> <entity type> monetaryItemType </entity type> <context> On December 30, 2024, Minnesota Power submitted a petition with the MPUC seeking deferral accounting treatment for investigative costs and the increase in depreciation expense resulting from compliance costs that will be incurred related to the new Coal Combustion Rule (CCR) Legacy Rule, which was published in the Federal Register on May 8, 2024. (See Note 9. Commitments, Guarantees and Contingencies.) Compliance with the CCR Legacy Rule is expected to result in a significant increase to our MPUC-approved decommissioning costs for Boswell and Laskin. If the MPUC approves our request for deferral accounting treatment, these costs would be deferred for recovery to our next rate case or other regulatory proceeding. In 2024, we recorded depreciation expense related to this rule, of which $ 4.2 million pre-tax would be moved to a deferred tracking account for MPUC review through a future rate case or other proceeding if the MPUC approves our request for deferral accounting treatment. We are unable to predict the outcome of this proceeding. </context> | us-gaap:Depreciation |
SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See | text | 10.40 | percentItemType | text: <entity> 10.40 </entity> <entity type> percentItemType </entity type> <context> SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See | text | 10.00 | percentItemType | text: <entity> 10.00 </entity> <entity type> percentItemType </entity type> <context> SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P’s 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
.) The resolution of SWL&P’s 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See | text | 9.80 | percentItemType | text: <entity> 9.80 </entity> <entity type> percentItemType </entity type> <context> .) The resolution of SWL&P’s 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
.) The resolution of SWL&P’s 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> .) The resolution of SWL&P’s 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 10.00 | percentItemType | text: <entity> 10.00 </entity> <entity type> percentItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 5.90 | percentItemType | text: <entity> 5.90 </entity> <entity type> percentItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreasePercentage |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 7.3 | monetaryItemType | text: <entity> 7.3 </entity> <entity type> monetaryItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 5.5 | monetaryItemType | text: <entity> 5.5 </entity> <entity type> monetaryItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 9.80 | percentItemType | text: <entity> 9.80 </entity> <entity type> percentItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. | text | 3.3 | monetaryItemType | text: <entity> 3.3 </entity> <entity type> monetaryItemType </entity type> <context> In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. | text | 10.00 | percentItemType | text: <entity> 10.00 </entity> <entity type> percentItemType </entity type> <context> In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. | text | 55.00 | percentItemType | text: <entity> 55.00 </entity> <entity type> percentItemType </entity type> <context> In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2023. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on ECOs each year. On April 1, 2024, Minnesota Power submitted its 2023 ECO annual filing, formerly known as the conservation improvement program, detailing Minnesota Power’s ECO plan results and proposed financial incentive, which was approved by the MPUC on November 8, 2024. As a result, Minnesota Power recognized revenue of $ 2.2 million in 2024 for the approved financial incentive ($ 2.2 million in 2023 and $ 1.9 million in 2022). The financial incentives are recognized in the period in which the MPUC approves the filing. | text | 2.2 | monetaryItemType | text: <entity> 2.2 </entity> <entity type> monetaryItemType </entity type> <context> Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on ECOs each year. On April 1, 2024, Minnesota Power submitted its 2023 ECO annual filing, formerly known as the conservation improvement program, detailing Minnesota Power’s ECO plan results and proposed financial incentive, which was approved by the MPUC on November 8, 2024. As a result, Minnesota Power recognized revenue of $ 2.2 million in 2024 for the approved financial incentive ($ 2.2 million in 2023 and $ 1.9 million in 2022). The financial incentives are recognized in the period in which the MPUC approves the filing. </context> | us-gaap:RegulatedOperatingRevenueOther |
Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on ECOs each year. On April 1, 2024, Minnesota Power submitted its 2023 ECO annual filing, formerly known as the conservation improvement program, detailing Minnesota Power’s ECO plan results and proposed financial incentive, which was approved by the MPUC on November 8, 2024. As a result, Minnesota Power recognized revenue of $ 2.2 million in 2024 for the approved financial incentive ($ 2.2 million in 2023 and $ 1.9 million in 2022). The financial incentives are recognized in the period in which the MPUC approves the filing. | text | 1.9 | monetaryItemType | text: <entity> 1.9 </entity> <entity type> monetaryItemType </entity type> <context> Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on ECOs each year. On April 1, 2024, Minnesota Power submitted its 2023 ECO annual filing, formerly known as the conservation improvement program, detailing Minnesota Power’s ECO plan results and proposed financial incentive, which was approved by the MPUC on November 8, 2024. As a result, Minnesota Power recognized revenue of $ 2.2 million in 2024 for the approved financial incentive ($ 2.2 million in 2023 and $ 1.9 million in 2022). The financial incentives are recognized in the period in which the MPUC approves the filing. </context> | us-gaap:RegulatedOperatingRevenueOther |
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