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In November 2024, the Virginia SCC issued a final order approving an annual base rate increase of $ 10 million, effective January 2025, based on a 9.75 % ROE. | text | 9.75 | percentItemType | text: <entity> 9.75 </entity> <entity type> percentItemType </entity type> <context> In November 2024, the Virginia SCC issued a final order approving an annual base rate increase of $ 10 million, effective January 2025, based on a 9.75 % ROE. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 251 | monetaryItemType | text: <entity> 251 </entity> <entity type> monetaryItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 10.8 | percentItemType | text: <entity> 10.8 </entity> <entity type> percentItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 52 | percentItemType | text: <entity> 52 </entity> <entity type> percentItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedDebtCapitalStructurePercentage |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 48 | percentItemType | text: <entity> 48 </entity> <entity type> percentItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 94 | monetaryItemType | text: <entity> 94 </entity> <entity type> monetaryItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. | text | 21 | monetaryItemType | text: <entity> 21 </entity> <entity type> monetaryItemType </entity type> <context> In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $ 32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLC and AROs. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition. | text | 32 | monetaryItemType | text: <entity> 32 </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $ 32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLC and AROs. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. | text | 57 | monetaryItemType | text: <entity> 57 </entity> <entity type> monetaryItemType </entity type> <context> In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. | text | 10.6 | percentItemType | text: <entity> 10.6 </entity> <entity type> percentItemType </entity type> <context> In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. | text | 55 | percentItemType | text: <entity> 55 </entity> <entity type> percentItemType </entity type> <context> In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedDebtCapitalStructurePercentage |
In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. | text | 45 | percentItemType | text: <entity> 45 </entity> <entity type> percentItemType </entity type> <context> In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedEquityCapitalStructurePercentage |
In August 2023, I&M filed a request with the IURC for a $ 116 million annual increase in Indiana base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a proposed capital structure of 48.8 % debt and 51.2 % common equity. I&M proposed that the annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes, but is not limited to, a $ 41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $ 15 million increase related to storm expenses. I&M’s Indiana base case filing requested recovery of certain historical period regulatory asset balances and proposed deferral accounting for certain future investments and tax-related issues, including CAMT expense and PTCs related to the Cook Plant. | text | 10.5 | percentItemType | text: <entity> 10.5 </entity> <entity type> percentItemType </entity type> <context> In August 2023, I&M filed a request with the IURC for a $ 116 million annual increase in Indiana base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a proposed capital structure of 48.8 % debt and 51.2 % common equity. I&M proposed that the annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes, but is not limited to, a $ 41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $ 15 million increase related to storm expenses. I&M’s Indiana base case filing requested recovery of certain historical period regulatory asset balances and proposed deferral accounting for certain future investments and tax-related issues, including CAMT expense and PTCs related to the Cook Plant. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In May 2024, the IURC issued an order approving the settlement agreement with minor modifications. In January 2025, in accordance with the IURC’s order on I&M’s 2023 Indiana base case filing, I&M submitted a filing with the IURC reflecting December 31, 2024 balances of electric plant in service in comparison to I&M’s 2024 forecasted test year, resulting in a $ 15 million annual increase in I&M Indiana base rates effective January 2025. | text | 15 | monetaryItemType | text: <entity> 15 </entity> <entity type> monetaryItemType </entity type> <context> In May 2024, the IURC issued an order approving the settlement agreement with minor modifications. In January 2025, in accordance with the IURC’s order on I&M’s 2023 Indiana base case filing, I&M submitted a filing with the IURC reflecting December 31, 2024 balances of electric plant in service in comparison to I&M’s 2024 forecasted test year, resulting in a $ 15 million annual increase in I&M Indiana base rates effective January 2025. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
In September 2023, I&M filed a request with the MPSC for a $ 34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a capital structure of 49.4 % debt and 50.6 % common equity. The proposed annual increase includes an $ 11 million annual increase in depreciation expense driven by increased capital investment. I&M’s Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax-related issues, including CAMT expense and PTCs related to the Cook Plant. | text | 10.5 | percentItemType | text: <entity> 10.5 </entity> <entity type> percentItemType </entity type> <context> In September 2023, I&M filed a request with the MPSC for a $ 34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a capital structure of 49.4 % debt and 50.6 % common equity. The proposed annual increase includes an $ 11 million annual increase in depreciation expense driven by increased capital investment. I&M’s Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax-related issues, including CAMT expense and PTCs related to the Cook Plant. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. | text | 17 | monetaryItemType | text: <entity> 17 </entity> <entity type> monetaryItemType </entity type> <context> In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. | text | 9.86 | percentItemType | text: <entity> 9.86 </entity> <entity type> percentItemType </entity type> <context> In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. | text | 52 | percentItemType | text: <entity> 52 </entity> <entity type> percentItemType </entity type> <context> In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. </context> | us-gaap:PublicUtilitiesApprovedDebtCapitalStructurePercentage |
In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. | text | 48 | percentItemType | text: <entity> 48 </entity> <entity type> percentItemType </entity type> <context> In July 2024, the MPSC issued a final order approving an annual base rate increase of $ 17 million based on a 9.86 % ROE and a capital structure of 52 % debt and 48 % common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
In June 2023, KPCo filed a request with the KPSC for a $ 94 million net annual increase in base rates based upon a proposed 9.9 % ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $ 471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50 % interest in Mitchell Plant, which will be addressed in the future. As of December 31, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $ 547 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | text | 9.9 | percentItemType | text: <entity> 9.9 </entity> <entity type> percentItemType </entity type> <context> In June 2023, KPCo filed a request with the KPSC for a $ 94 million net annual increase in base rates based upon a proposed 9.9 % ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $ 471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50 % interest in Mitchell Plant, which will be addressed in the future. As of December 31, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $ 547 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In June 2023, KPCo filed a request with the KPSC for a $ 94 million net annual increase in base rates based upon a proposed 9.9 % ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $ 471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50 % interest in Mitchell Plant, which will be addressed in the future. As of December 31, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $ 547 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | text | 547 | monetaryItemType | text: <entity> 547 </entity> <entity type> monetaryItemType </entity type> <context> In June 2023, KPCo filed a request with the KPSC for a $ 94 million net annual increase in base rates based upon a proposed 9.9 % ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $ 471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50 % interest in Mitchell Plant, which will be addressed in the future. As of December 31, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $ 547 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:PropertyPlantAndEquipmentNet |
In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $ 60 million based upon a 9.75 % ROE effective with billing cycles mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $ 14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order, the $ 14 million base rate revenue requirement reduction. In January 2025, the Commonwealth of Kentucky Franklin Circuit Court issued an order agreeing with KPCo’s appeal and remanded this issue back to the KPSC with instructions to enter an order, within 30 days, which includes setting rates to allow KPCo to recover the $ 14 million of annual PJM transmission costs effective upon KPCo's January 2024 implementation of updated base rates. | text | 9.75 | percentItemType | text: <entity> 9.75 </entity> <entity type> percentItemType </entity type> <context> In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $ 60 million based upon a 9.75 % ROE effective with billing cycles mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $ 14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order, the $ 14 million base rate revenue requirement reduction. In January 2025, the Commonwealth of Kentucky Franklin Circuit Court issued an order agreeing with KPCo’s appeal and remanded this issue back to the KPSC with instructions to enter an order, within 30 days, which includes setting rates to allow KPCo to recover the $ 14 million of annual PJM transmission costs effective upon KPCo's January 2024 implementation of updated base rates. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65 % on capital costs for certain riders. In June 2023, intervenors filed testimony opposing OPCo’s plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7 % and continuation of a number of riders including the DIR subject to revenue caps. In April 2024, the PUCO issued an order approving the settlement agreement. In May 2024, intervenors filed an application for rehearing with the PUCO on the approved settlement agreement and the PUCO denied the intervenors’ application for rehearing in June 2024. | text | 9.7 | percentItemType | text: <entity> 9.7 </entity> <entity type> percentItemType </entity type> <context> In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65 % on capital costs for certain riders. In June 2023, intervenors filed testimony opposing OPCo’s plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7 % and continuation of a number of riders including the DIR subject to revenue caps. In April 2024, the PUCO issued an order approving the settlement agreement. In May 2024, intervenors filed an application for rehearing with the PUCO on the approved settlement agreement and the PUCO denied the intervenors’ application for rehearing in June 2024. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In January 2024, PSO filed a request with the OCC for a $ 218 million annual base rate increase based upon a 10.8 % ROE with a capital structure of 48.9 % debt and 51.1 % common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040. | text | 10.8 | percentItemType | text: <entity> 10.8 </entity> <entity type> percentItemType </entity type> <context> In January 2024, PSO filed a request with the OCC for a $ 218 million annual base rate increase based upon a 10.8 % ROE with a capital structure of 48.9 % debt and 51.1 % common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $ 69 million based upon a 10 % ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $ 50 million based upon a 9.6 % ROE, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $ 2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. | text | 9.6 | percentItemType | text: <entity> 9.6 </entity> <entity type> percentItemType </entity type> <context> In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $ 69 million based upon a 10 % ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $ 50 million based upon a 9.6 % ROE, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $ 2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In October 2020, SWEPCo filed a request with the PUCT for a $ 105 million annual increase in Texas base rates based upon a proposed 10.35 % ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $ 90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $ 100 million which would result in an $ 85 million net annual base rate increase after moving the proposed riders to rate base. | text | 10.35 | percentItemType | text: <entity> 10.35 </entity> <entity type> percentItemType </entity type> <context> In October 2020, SWEPCo filed a request with the PUCT for a $ 105 million annual increase in Texas base rates based upon a proposed 10.35 % ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $ 90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $ 100 million which would result in an $ 85 million net annual base rate increase after moving the proposed riders to rate base. </context> | us-gaap:PublicUtilitiesRequestedReturnOnEquityPercentage |
In January 2022, the PUCT issued a final order approving an annual revenue increase of $ 39 million based upon a 9.25 % ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $ 5 million of the proposed increase related to vegetation management, (c) $ 2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $ 12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. | text | 9.25 | percentItemType | text: <entity> 9.25 </entity> <entity type> percentItemType </entity type> <context> In January 2022, the PUCT issued a final order approving an annual revenue increase of $ 39 million based upon a 9.25 % ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $ 5 million of the proposed increase related to vegetation management, (c) $ 2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $ 12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. | text | 337 | monetaryItemType | text: <entity> 337 </entity> <entity type> monetaryItemType </entity type> <context> In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. </context> | us-gaap:SecuredDebt |
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. | text | 180 | monetaryItemType | text: <entity> 180 </entity> <entity type> monetaryItemType </entity type> <context> In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. </context> | us-gaap:SecuredDebt |
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. | text | 150 | monetaryItemType | text: <entity> 150 </entity> <entity type> monetaryItemType </entity type> <context> In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. </context> | us-gaap:SecuredDebt |
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. | text | 7 | monetaryItemType | text: <entity> 7 </entity> <entity type> monetaryItemType </entity type> <context> In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement. In December 2024, SWEPCo issued $ 337 million of securitization bonds. The securitization bonds included $ 180 million for storm costs related to Hurricanes Laura and Delta and $ 150 million related to a storm reserve. In June 2023, SWEPCo incurred approximately $ 44 million in storm costs impacting the Louisiana jurisdiction. As authorized by the LPSC, the June 2023 storm costs were applied against the $ 150 million storm reserve. Any costs applied against the remaining storm reserve are subject to audit and prudency reviews. SWEPCo is required to accrue carrying charges on the remaining storm reserve liability. The securitization bonds also included $ 7 million related to estimated financing costs and carrying charges. </context> | us-gaap:DeferredFinanceCostsGross |
In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 12 million in 2021. See “2020 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. | text | 12 | monetaryItemType | text: <entity> 12 </entity> <entity type> monetaryItemType </entity type> <context> In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 12 million in 2021. See “2020 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. </context> | us-gaap:OtherAssetImpairmentCharges |
In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 12 million in 2021. See “2020 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. | text | 2 | monetaryItemType | text: <entity> 2 </entity> <entity type> monetaryItemType </entity type> <context> In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 12 million in 2021. See “2020 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $ 2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. </context> | us-gaap:OtherAssetImpairmentCharges |
In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $ 14 million in the first quarter of 2024. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $ 14 million in the first quarter of 2024. </context> | us-gaap:OtherAssetImpairmentCharges |
In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of December 31, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $ 69 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition. | text | 69 | monetaryItemType | text: <entity> 69 </entity> <entity type> monetaryItemType </entity type> <context> In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of December 31, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $ 69 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition. </context> | us-gaap:NetRegulatoryAssets |
In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $ 20 million of fuel costs in 2021 and defer approximately $ 35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $ 55 million, including denial of recovery of the $ 35 million deferral, with refunds to customers over five years . In February 2024, an ALJ issued a final recommendation which included a proposed $ 55 million refund to customers and the denial of recovery of the $ 35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $ 11 million. The remaining $ 24 million regulatory asset balance will be recovered over three years with interest. | text | 24 | monetaryItemType | text: <entity> 24 </entity> <entity type> monetaryItemType </entity type> <context> In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $ 20 million of fuel costs in 2021 and defer approximately $ 35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $ 55 million, including denial of recovery of the $ 35 million deferral, with refunds to customers over five years . In February 2024, an ALJ issued a final recommendation which included a proposed $ 55 million refund to customers and the denial of recovery of the $ 35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $ 11 million. The remaining $ 24 million regulatory asset balance will be recovered over three years with interest. </context> | us-gaap:RegulatoryAssets |
In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. | text | 4 | monetaryItemType | text: <entity> 4 </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. </context> | us-gaap:LineOfCreditFacilityMaximumBorrowingCapacity |
In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. | text | 5 | monetaryItemType | text: <entity> 5 </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. </context> | us-gaap:LineOfCreditFacilityMaximumBorrowingCapacity |
In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. | text | 1 | monetaryItemType | text: <entity> 1 </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. </context> | us-gaap:LineOfCreditFacilityMaximumBorrowingCapacity |
In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. | text | 1.2 | monetaryItemType | text: <entity> 1.2 </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. </context> | us-gaap:LineOfCreditFacilityMaximumBorrowingCapacity |
In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. | text | no | monetaryItemType | text: <entity> no </entity> <entity type> monetaryItemType </entity type> <context> In March 2024, AEP increased its $ 4 billion revolving credit facility to $ 5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $ 1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $ 1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2024, no letters of credit were issued under the revolving credit facility. </context> | us-gaap:LineOfCreditFacilityMaximumBorrowingCapacity |
An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $ 450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2024 were as follows: | text | 450 | monetaryItemType | text: <entity> 450 </entity> <entity type> monetaryItemType </entity type> <context> An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $ 450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2024 were as follows: </context> | us-gaap:DebtInstrumentFaceAmount |
In April 2024, AEP reached an agreement with the four shareholders to fully and finally resolve the Derivative Actions and the Litigation Demand, and all claims asserted or that could have been asserted by any AEP shareholder based on the facts alleged, in the manner and upon the terms and conditions set forth in the settlement documents (the Settlement). In July 2024, the U.S. District Court preliminarily approved the Settlement. The Settlement includes a payment of $ 450 thousand for attorneys’ fees | text | 450 | monetaryItemType | text: <entity> 450 </entity> <entity type> monetaryItemType </entity type> <context> In April 2024, AEP reached an agreement with the four shareholders to fully and finally resolve the Derivative Actions and the Litigation Demand, and all claims asserted or that could have been asserted by any AEP shareholder based on the facts alleged, in the manner and upon the terms and conditions set forth in the settlement documents (the Settlement). In July 2024, the U.S. District Court preliminarily approved the Settlement. The Settlement includes a payment of $ 450 thousand for attorneys’ fees </context> | us-gaap:LitigationSettlementAmountAwardedToOtherParty |
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. In January 2025, AEP and the SEC reached a settlement concluding and resolving the SEC’s investigation concerning AEP’s relationship with and statements about Empowering Ohio’s Economy, a 501(c)(4) organization and AEP’s related internal accounting and disclosure controls. Under the terms of the administrative order, in which AEP neither admits nor denies the SEC’s findings, AEP agreed to pay a civil penalty of $ 19 million and to cease and desist from committing or causing any violations and any future violations of the specified provisions of the federal securities laws. AEP recorded an accrual for the full amount of the penalty in the third quarter of 2024. The $ 19 million penalty is included in Other Operation expenses on AEP’s statements of income and in Other Current Liabilities on AEP’s balance sheet. | text | 19 | monetaryItemType | text: <entity> 19 </entity> <entity type> monetaryItemType </entity type> <context> In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. In January 2025, AEP and the SEC reached a settlement concluding and resolving the SEC’s investigation concerning AEP’s relationship with and statements about Empowering Ohio’s Economy, a 501(c)(4) organization and AEP’s related internal accounting and disclosure controls. Under the terms of the administrative order, in which AEP neither admits nor denies the SEC’s findings, AEP agreed to pay a civil penalty of $ 19 million and to cease and desist from committing or causing any violations and any future violations of the specified provisions of the federal securities laws. AEP recorded an accrual for the full amount of the penalty in the third quarter of 2024. The $ 19 million penalty is included in Other Operation expenses on AEP’s statements of income and in Other Current Liabilities on AEP’s balance sheet. </context> | us-gaap:LossContingencyLossInPeriod |
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. | text | three | integerItemType | text: <entity> three </entity> <entity type> integerItemType </entity type> <context> In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. </context> | us-gaap:NumberOfRealEstateProperties |
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. | text | 45.5 | percentItemType | text: <entity> 45.5 </entity> <entity type> percentItemType </entity type> <context> In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. </context> | us-gaap:BusinessAcquisitionPercentageOfVotingInterestsAcquired |
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. | text | 54.5 | percentItemType | text: <entity> 54.5 </entity> <entity type> percentItemType </entity type> <context> In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. </context> | us-gaap:BusinessAcquisitionPercentageOfVotingInterestsAcquired |
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. | text | 2 | monetaryItemType | text: <entity> 2 </entity> <entity type> monetaryItemType </entity type> <context> In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively. In total, the three wind facilities cost approximately $ 2 billion and consist of Traverse ( 998 MW), Maverick ( 287 MW) and Sundance ( 199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. </context> | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse, the final NCWF project, during its development and construction for $ 1.2 billion. Traverse was placed in-service in March 2022. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the assets in proportion to their undivided ownership interests. PSO and SWEPCo apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects. | text | 1.2 | monetaryItemType | text: <entity> 1.2 </entity> <entity type> monetaryItemType </entity type> <context> In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse, the final NCWF project, during its development and construction for $ 1.2 billion. Traverse was placed in-service in March 2022. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the assets in proportion to their undivided ownership interests. PSO and SWEPCo apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects. </context> | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $ 146 million. In accordance with the guidance for “Business Combinations,” AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material at the time of acquisition. | text | 146 | monetaryItemType | text: <entity> 146 </entity> <entity type> monetaryItemType </entity type> <context> In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $ 146 million. In accordance with the guidance for “Business Combinations,” AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material at the time of acquisition. </context> | us-gaap:BusinessCombinationConsiderationTransferred1 |
In April 2023, AEP initiated a sales process for its ownership in AEP OnSite Partners. AEP OnSite Partners targeted opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. In September 2024, AEP completed the sale and received cash proceeds of approximately $ 318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt. | text | 318 | monetaryItemType | text: <entity> 318 </entity> <entity type> monetaryItemType </entity type> <context> In April 2023, AEP initiated a sales process for its ownership in AEP OnSite Partners. AEP OnSite Partners targeted opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. In September 2024, AEP completed the sale and received cash proceeds of approximately $ 318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt. </context> | us-gaap:ProceedsFromDivestitureOfBusinesses |
In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $ 107 million, net of taxes and transaction costs. The transaction did not have a material impact on net income or financial condition. | text | 107 | monetaryItemType | text: <entity> 107 </entity> <entity type> monetaryItemType </entity type> <context> In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $ 107 million, net of taxes and transaction costs. The transaction did not have a material impact on net income or financial condition. </context> | us-gaap:ProceedsFromDivestitureOfBusinesses |
As a result of delays in the anticipated timing of the closing of the transaction and other factors, AEP recorded a $ 363 million pretax loss on the expected sale of the Kentucky Operations for the year ended December 31, 2022. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. Upon termination of the sale and reverting to a held and used model, in the first quarter of 2023, AEP reversed $ 28 million of expected transaction costs included in the $ 363 million pretax loss and was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value which resulted in a $ 335 million reduction recorded in Property, Plant and Equipment. The reduced investment in KPCo’s assets is being amortized over the 30-year average useful life of the KPCo assets. | text | 363 | monetaryItemType | text: <entity> 363 </entity> <entity type> monetaryItemType </entity type> <context> As a result of delays in the anticipated timing of the closing of the transaction and other factors, AEP recorded a $ 363 million pretax loss on the expected sale of the Kentucky Operations for the year ended December 31, 2022. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. Upon termination of the sale and reverting to a held and used model, in the first quarter of 2023, AEP reversed $ 28 million of expected transaction costs included in the $ 363 million pretax loss and was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value which resulted in a $ 335 million reduction recorded in Property, Plant and Equipment. The reduced investment in KPCo’s assets is being amortized over the 30-year average useful life of the KPCo assets. </context> | us-gaap:OtherAssetImpairmentCharges |
In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $ 1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $ 93 million ($ 73 million after-tax) for the year ended December 31, 2023 related to the sale. | text | 1.2 | monetaryItemType | text: <entity> 1.2 </entity> <entity type> monetaryItemType </entity type> <context> In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $ 1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $ 93 million ($ 73 million after-tax) for the year ended December 31, 2023 related to the sale. </context> | us-gaap:ProceedsFromDivestitureOfBusinesses |
In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $ 1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $ 93 million ($ 73 million after-tax) for the year ended December 31, 2023 related to the sale. | text | 93 | monetaryItemType | text: <entity> 93 </entity> <entity type> monetaryItemType </entity type> <context> In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $ 1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $ 93 million ($ 73 million after-tax) for the year ended December 31, 2023 related to the sale. </context> | us-gaap:GainLossOnSaleOfBusiness |
In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $ 120 million of proceeds. The sale resulted in a pretax gain of $ 116 million in the second quarter of 2022. | text | 120 | monetaryItemType | text: <entity> 120 </entity> <entity type> monetaryItemType </entity type> <context> In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $ 120 million of proceeds. The sale resulted in a pretax gain of $ 116 million in the second quarter of 2022. </context> | us-gaap:ProceedsFromSaleOfPropertyPlantAndEquipment |
In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $ 120 million of proceeds. The sale resulted in a pretax gain of $ 116 million in the second quarter of 2022. | text | 116 | monetaryItemType | text: <entity> 116 </entity> <entity type> monetaryItemType </entity type> <context> In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $ 120 million of proceeds. The sale resulted in a pretax gain of $ 116 million in the second quarter of 2022. </context> | us-gaap:GainLossOnSaleOfOtherAssets |
In December 2023, SWEPCo recorded a pretax, non-cash disallowance of $ 86 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowance of recovery of AFUDC on Turk Plant in the 2012 Texas Base Rate case. See the “2012 Texas Base Rate Case” section of Note 4 for additional information. | text | 86 | monetaryItemType | text: <entity> 86 </entity> <entity type> monetaryItemType </entity type> <context> In December 2023, SWEPCo recorded a pretax, non-cash disallowance of $ 86 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowance of recovery of AFUDC on Turk Plant in the 2012 Texas Base Rate case. See the “2012 Texas Base Rate Case” section of Note 4 for additional information. </context> | us-gaap:OtherAssetImpairmentCharges |
In December 2023, as a result of sale negotiations AEP determined a decline in the fair value of AEP’s investment in NMRD was other than temporary. In accordance with the accounting guidance for “Investment - Equity Method and Joint Ventures”, in the fourth quarter of 2023 AEP recorded a pretax other than temporary impairment charge of $ 19 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. The carrying value of the investment in NMRD was not material to AEP as of December 31, 2023. | text | 19 | monetaryItemType | text: <entity> 19 </entity> <entity type> monetaryItemType </entity type> <context> In December 2023, as a result of sale negotiations AEP determined a decline in the fair value of AEP’s investment in NMRD was other than temporary. In accordance with the accounting guidance for “Investment - Equity Method and Joint Ventures”, in the fourth quarter of 2023 AEP recorded a pretax other than temporary impairment charge of $ 19 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. The carrying value of the investment in NMRD was not material to AEP as of December 31, 2023. </context> | us-gaap:EquityMethodInvestmentOtherThanTemporaryImpairment |
In 2019, AEP acquired a 50 % ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs. | text | 50 | percentItemType | text: <entity> 50 </entity> <entity type> percentItemType </entity type> <context> In 2019, AEP acquired a 50 % ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs. </context> | us-gaap:EquityMethodInvestmentOwnershipPercentage |
Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of Flat Ridge 2’s deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $ 186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. In the third quarter of 2022, AEP recorded an additional $ 2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate third-party for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements. | text | 186 | monetaryItemType | text: <entity> 186 </entity> <entity type> monetaryItemType </entity type> <context> Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of Flat Ridge 2’s deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $ 186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. In the third quarter of 2022, AEP recorded an additional $ 2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate third-party for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements. </context> | us-gaap:EquityMethodInvestmentOtherThanTemporaryImpairment |
Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of Flat Ridge 2’s deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $ 186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. In the third quarter of 2022, AEP recorded an additional $ 2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate third-party for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements. | text | 2 | monetaryItemType | text: <entity> 2 </entity> <entity type> monetaryItemType </entity type> <context> Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of Flat Ridge 2’s deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $ 186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. In the third quarter of 2022, AEP recorded an additional $ 2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate third-party for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements. </context> | us-gaap:EquityMethodInvestmentOtherThanTemporaryImpairment |
In January 2022, the PUCT issued a final order which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $ 12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging denial of a reasonable return or carrying costs on the Dolet Hills Power Station among other items. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. See “2020 Texas Base Rate Case” section of Note 4 for additional information. | text | 12 | monetaryItemType | text: <entity> 12 </entity> <entity type> monetaryItemType </entity type> <context> In January 2022, the PUCT issued a final order which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $ 12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging denial of a reasonable return or carrying costs on the Dolet Hills Power Station among other items. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. See “2020 Texas Base Rate Case” section of Note 4 for additional information. </context> | us-gaap:OtherAssetImpairmentCharges |
No contributions were made to the qualified pension plan for the years ended December 31, 2024 and 2023, respectively. Contributions to the non-qualified pension plans were $ 14 million and $ 8 million for the years ended December 31, 2024 and 2023, respectively. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> No contributions were made to the qualified pension plan for the years ended December 31, 2024 and 2023, respectively. Contributions to the non-qualified pension plans were $ 14 million and $ 8 million for the years ended December 31, 2024 and 2023, respectively. </context> | us-gaap:DefinedBenefitPlanContributionsByEmployer |
No contributions were made to the qualified pension plan for the years ended December 31, 2024 and 2023, respectively. Contributions to the non-qualified pension plans were $ 14 million and $ 8 million for the years ended December 31, 2024 and 2023, respectively. | text | 8 | monetaryItemType | text: <entity> 8 </entity> <entity type> monetaryItemType </entity type> <context> No contributions were made to the qualified pension plan for the years ended December 31, 2024 and 2023, respectively. Contributions to the non-qualified pension plans were $ 14 million and $ 8 million for the years ended December 31, 2024 and 2023, respectively. </context> | us-gaap:DefinedBenefitPlanContributionsByEmployer |
AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. | text | 379 | monetaryItemType | text: <entity> 379 </entity> <entity type> monetaryItemType </entity type> <context> AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. </context> | us-gaap:MultiemployerPlanEmployerContributionCost |
AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. | text | 396 | monetaryItemType | text: <entity> 396 </entity> <entity type> monetaryItemType </entity type> <context> AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. </context> | us-gaap:MultiemployerPlanEmployerContributionCost |
AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. | text | 329 | monetaryItemType | text: <entity> 329 </entity> <entity type> monetaryItemType </entity type> <context> AEP affiliates contributed $ 379 thousand, $ 396 thousand and $ 329 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2024, 2023 and 2022, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2022 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2023. The plan’s 2022 Form 5500 was filed in the second quarter of 2024. </context> | us-gaap:MultiemployerPlanEmployerContributionCost |
AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. | text | seven | integerItemType | text: <entity> seven </entity> <entity type> integerItemType </entity type> <context> AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. </context> | us-gaap:NumberOfOperatingSegments |
who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one reportable segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. | text | one | integerItemType | text: <entity> one </entity> <entity type> integerItemType </entity type> <context> who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one reportable segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. </context> | us-gaap:NumberOfReportableSegments |
According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 87 million and $ 46 million as of December 31, 2024 and 2023, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2024 and 2023. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2024 and 2023. | text | 87 | monetaryItemType | text: <entity> 87 </entity> <entity type> monetaryItemType </entity type> <context> According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 87 million and $ 46 million as of December 31, 2024 and 2023, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2024 and 2023. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2024 and 2023. </context> | us-gaap:SecuritiesReceivedAsCollateral |
According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 87 million and $ 46 million as of December 31, 2024 and 2023, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2024 and 2023. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2024 and 2023. | text | 46 | monetaryItemType | text: <entity> 46 </entity> <entity type> monetaryItemType </entity type> <context> According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 87 million and $ 46 million as of December 31, 2024 and 2023, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2024 and 2023. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2024 and 2023. </context> | us-gaap:SecuritiesReceivedAsCollateral |
Amounts include $( 22 ) million and $( 30 ) million as of December 31, 2024 and 2023, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. | text | 22 | monetaryItemType | text: <entity> 22 </entity> <entity type> monetaryItemType </entity type> <context> Amounts include $( 22 ) million and $( 30 ) million as of December 31, 2024 and 2023, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. </context> | us-gaap:HedgedLiabilityDiscontinuedFairValueHedgeCumulativeIncreaseDecrease |
Amounts include $( 22 ) million and $( 30 ) million as of December 31, 2024 and 2023, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. | text | 30 | monetaryItemType | text: <entity> 30 </entity> <entity type> monetaryItemType </entity type> <context> Amounts include $( 22 ) million and $( 30 ) million as of December 31, 2024 and 2023, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. </context> | us-gaap:HedgedLiabilityDiscontinuedFairValueHedgeCumulativeIncreaseDecrease |
As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: | text | 110.3 | monetaryItemType | text: <entity> 110.3 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: </context> | us-gaap:OperatingLossCarryforwards |
As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: | text | 2.7 | monetaryItemType | text: <entity> 2.7 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: </context> | us-gaap:OperatingLossCarryforwards |
As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: | text | 27.8 | monetaryItemType | text: <entity> 27.8 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: </context> | us-gaap:OperatingLossCarryforwards |
As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: | text | 36.1 | monetaryItemType | text: <entity> 36.1 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2024, AEP, OPCo, PSO, and SWEPCo have pretax state NOLC as indicated in the table below. Net of tax, the NOLCs for AEP and subsidiaries amount to $ 110.3 million of future tax benefit. Additionally, the amounts presented below for OPCo, PSO, and SWEPCo amount to $ 2.7 million, $ 27.8 million, and $ 36.1 million, respectively.: </context> | us-gaap:OperatingLossCarryforwards |
, $ 13 million, and $ 23 million, respectively. | text | 13 | monetaryItemType | text: <entity> 13 </entity> <entity type> monetaryItemType </entity type> <context> , $ 13 million, and $ 23 million, respectively. </context> | us-gaap:UnrecognizedTaxBenefitsThatWouldImpactEffectiveTaxRate |
, $ 13 million, and $ 23 million, respectively. | text | 23 | monetaryItemType | text: <entity> 23 </entity> <entity type> monetaryItemType </entity type> <context> , $ 13 million, and $ 23 million, respectively. </context> | us-gaap:UnrecognizedTaxBenefitsThatWouldImpactEffectiveTaxRate |
These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. Settlement accounting was triggered for the qualified pension plan in November 2024 under the accounting guidance for “Compensation - Retirement Benefits”. A settlement charge of $ 90 million was recorded. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 8 - Benefit Plans for additional information associated with the plan. | text | 90 | monetaryItemType | text: <entity> 90 </entity> <entity type> monetaryItemType </entity type> <context> These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. Settlement accounting was triggered for the qualified pension plan in November 2024 under the accounting guidance for “Compensation - Retirement Benefits”. A settlement charge of $ 90 million was recorded. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 8 - Benefit Plans for additional information associated with the plan. </context> | us-gaap:PostemploymentBenefitsPeriodExpense |
In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. | text | 4437136 | sharesItemType | text: <entity> 4437136 </entity> <entity type> sharesItemType </entity type> <context> In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. </context> | us-gaap:StockIssuedDuringPeriodSharesNewIssues |
In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. | text | 397 | monetaryItemType | text: <entity> 397 </entity> <entity type> monetaryItemType </entity type> <context> In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. </context> | us-gaap:ProceedsFromIssuanceOfCommonStock |
In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. | text | 1.3 | sharesItemType | text: <entity> 1.3 </entity> <entity type> sharesItemType </entity type> <context> In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. For the year ended 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $ 397 million under the ATM program. As of December 31, 2024, approximately $ 1.3 billion of equity is available for issuance under the ATM program. </context> | us-gaap:CommonStockCapitalSharesReservedForFutureIssuance |
In January and February 2025, I&M retired $ 9 million and $ 4 million, respectively, of Notes Payable related to DCC Fuel. | text | 9 | monetaryItemType | text: <entity> 9 </entity> <entity type> monetaryItemType </entity type> <context> In January and February 2025, I&M retired $ 9 million and $ 4 million, respectively, of Notes Payable related to DCC Fuel. </context> | us-gaap:RepaymentsOfDebt |
In January and February 2025, I&M retired $ 9 million and $ 4 million, respectively, of Notes Payable related to DCC Fuel. | text | 4 | monetaryItemType | text: <entity> 4 </entity> <entity type> monetaryItemType </entity type> <context> In January and February 2025, I&M retired $ 9 million and $ 4 million, respectively, of Notes Payable related to DCC Fuel. </context> | us-gaap:RepaymentsOfDebt |
In January 2025, Transource Energy issued $ 2 million of variable rate Other Long-term Debt due in 2025. | text | 2 | monetaryItemType | text: <entity> 2 </entity> <entity type> monetaryItemType </entity type> <context> In January 2025, Transource Energy issued $ 2 million of variable rate Other Long-term Debt due in 2025. </context> | us-gaap:DebtInstrumentFaceAmount |
In January 2025, KPCo entered into a $ 150 million term loan due in February 2026. | text | 150 | monetaryItemType | text: <entity> 150 </entity> <entity type> monetaryItemType </entity type> <context> In January 2025, KPCo entered into a $ 150 million term loan due in February 2026. </context> | us-gaap:DebtInstrumentFaceAmount |
In February 2025, APCo retired $ 14 million of Securitization Bonds. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> In February 2025, APCo retired $ 14 million of Securitization Bonds. </context> | us-gaap:RepaymentsOfDebt |
In February 2025, AEP Texas retired $ 12 million of Securitization Bonds. | text | 12 | monetaryItemType | text: <entity> 12 </entity> <entity type> monetaryItemType </entity type> <context> In February 2025, AEP Texas retired $ 12 million of Securitization Bonds. </context> | us-gaap:RepaymentsOfDebt |
Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. | text | 8.6 | monetaryItemType | text: <entity> 8.6 </entity> <entity type> monetaryItemType </entity type> <context> Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. </context> | us-gaap:RetainedEarningsUnappropriated |
Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. | text | 1.9 | monetaryItemType | text: <entity> 1.9 </entity> <entity type> monetaryItemType </entity type> <context> Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. </context> | us-gaap:PaymentsOfDividendsCommonStock |
Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. | text | 1.8 | monetaryItemType | text: <entity> 1.8 </entity> <entity type> monetaryItemType </entity type> <context> Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. </context> | us-gaap:PaymentsOfDividendsCommonStock |
Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. | text | 1.6 | monetaryItemType | text: <entity> 1.6 </entity> <entity type> monetaryItemType </entity type> <context> Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2024, AEP had $ 8.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.9 billion, $ 1.8 billion and $ 1.6 billion of dividends to common shareholders for the years ended December 31, 2024, 2023 and 2022, respectively. </context> | us-gaap:PaymentsOfDividendsCommonStock |
Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: | text | 5.39 | percentItemType | text: <entity> 5.39 </entity> <entity type> percentItemType </entity type> <context> Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: </context> | us-gaap:DebtInstrumentInterestRateDuringPeriod |
Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: | text | 900 | monetaryItemType | text: <entity> 900 </entity> <entity type> monetaryItemType </entity type> <context> Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: </context> | us-gaap:TransfersAccountedForAsSecuredBorrowingsAssociatedLiabilitiesCarryingAmount |
Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: | text | 2.9 | monetaryItemType | text: <entity> 2.9 </entity> <entity type> monetaryItemType </entity type> <context> Securitized Debt for Receivables, for the year ended 2024, had a weighted-average interest rate of 5.39 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2024, had a weighted-average yield of 5.39 % and a maximum amount outstanding of $ 2.9 billion. AEP’s outstanding short-term debt was as follows: </context> | us-gaap:ShorttermDebtMaximumAmountOutstandingDuringPeriod |
AEP’s long-term incentive plan available for eligible employees and directors, the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), was replaced prospectively for new grants by the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) effective in April 2024. The 2024 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2024, 9,806,016 shares remained available for issuance under the 2024 LTIP. No new awards may be granted under the 2015 LTIP. To the extent the issuance of a share is subject to an outstanding award under the 2015 LTIP, the issuance of that share will take place under the 2015 LTIP. Awards granted under the 2024 LTIP may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. All types of shares issued under the 2024 LTIP including stock options, stock appreciation rights, restricted stock units and performance shares reduce the shares remaining available for grants at a rate of 1 to 1. Cash settled awards do not reduce the number of shares remaining available under the 2024 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. | text | 10 | sharesItemType | text: <entity> 10 </entity> <entity type> sharesItemType </entity type> <context> AEP’s long-term incentive plan available for eligible employees and directors, the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), was replaced prospectively for new grants by the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) effective in April 2024. The 2024 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2024, 9,806,016 shares remained available for issuance under the 2024 LTIP. No new awards may be granted under the 2015 LTIP. To the extent the issuance of a share is subject to an outstanding award under the 2015 LTIP, the issuance of that share will take place under the 2015 LTIP. Awards granted under the 2024 LTIP may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. All types of shares issued under the 2024 LTIP including stock options, stock appreciation rights, restricted stock units and performance shares reduce the shares remaining available for grants at a rate of 1 to 1. Cash settled awards do not reduce the number of shares remaining available under the 2024 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. </context> | us-gaap:ShareBasedCompensationArrangementByShareBasedPaymentAwardNumberOfSharesAvailableForGrant |
AEP’s long-term incentive plan available for eligible employees and directors, the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), was replaced prospectively for new grants by the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) effective in April 2024. The 2024 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2024, 9,806,016 shares remained available for issuance under the 2024 LTIP. No new awards may be granted under the 2015 LTIP. To the extent the issuance of a share is subject to an outstanding award under the 2015 LTIP, the issuance of that share will take place under the 2015 LTIP. Awards granted under the 2024 LTIP may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. All types of shares issued under the 2024 LTIP including stock options, stock appreciation rights, restricted stock units and performance shares reduce the shares remaining available for grants at a rate of 1 to 1. Cash settled awards do not reduce the number of shares remaining available under the 2024 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. | text | 9806016 | sharesItemType | text: <entity> 9806016 </entity> <entity type> sharesItemType </entity type> <context> AEP’s long-term incentive plan available for eligible employees and directors, the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), was replaced prospectively for new grants by the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) effective in April 2024. The 2024 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2024, 9,806,016 shares remained available for issuance under the 2024 LTIP. No new awards may be granted under the 2015 LTIP. To the extent the issuance of a share is subject to an outstanding award under the 2015 LTIP, the issuance of that share will take place under the 2015 LTIP. Awards granted under the 2024 LTIP may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. All types of shares issued under the 2024 LTIP including stock options, stock appreciation rights, restricted stock units and performance shares reduce the shares remaining available for grants at a rate of 1 to 1. Cash settled awards do not reduce the number of shares remaining available under the 2024 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans. </context> | us-gaap:CommonStockCapitalSharesReservedForFutureIssuance |
The total aggregate intrinsic value of nonvested RSUs as of December 31, 2024 was $ 44 million and the weighted-average remaining contractual life was 1.5 years. | text | 44 | monetaryItemType | text: <entity> 44 </entity> <entity type> monetaryItemType </entity type> <context> The total aggregate intrinsic value of nonvested RSUs as of December 31, 2024 was $ 44 million and the weighted-average remaining contractual life was 1.5 years. </context> | us-gaap:SharebasedCompensationArrangementBySharebasedPaymentAwardEquityInstrumentsOtherThanOptionsAggregateIntrinsicValueNonvested |
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