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Sanofi was notified that, in August 2007, GenRx Proprietary Limited ("GenRx") obtained regulatory approval of an application for clopidogrel bisulfate 75mg tablets in Australia. GenRx, formerly a subsidiary of Apotex Inc., subsequently changed its name to Apotex ("GenRx-Apotex"). In August 2007, GenRx-Apotex filed an application in the Federal Court of Australia seeking revocation of Sanofi's Australian Patent No. 597784 (Case No. NSD 1639 of 2007). Sanofi filed counterclaims of infringement and sought an injunction. On September 21, 2007, the Federal Court of Australia granted Sanofi's injunction. A subsidiary of BMS was subsequently added as a party to the proceedings. In February 2008, a second company, Spirit Pharmaceuticals Pty. Ltd., also filed a revocation suit against the same patent. This case was consolidated with the GenRx-Apotex case. On August 12, 2008, the Federal Court of Australia held that claims of Patent No. 597784 covering clopidogrel bisulfate, hydrochloride, hydrobromide, and taurocholate salts were valid. The Federal Court also held that the process claims, pharmaceutical composition claims, and claim directed to clopidogrel and its pharmaceutically acceptable salts were invalid. BMS and Sanofi filed notices of appeal in the Full Court of the Federal Court of Australia ("Full Court") appealing the holding of invalidity of the claim covering clopidogrel and its pharmaceutically acceptable salts, process claims, and pharmaceutical composition claims. GenRx-Apotex appealed. On September 29, 2009, the Full Court held all of the claims of Patent No. 597784 invalid. In March 2010, the High Court of Australia denied a request by BMS and Sanofi to hear an appeal of the Full Court decision. The case was remanded to the Federal Court for further proceedings related to damages sought by GenRx-Apotex. BMS and GenRx-Apotex settled, and the GenRx-Apotex case was dismissed. The Australian government intervened in this matter seeking maximum damages up to 449 million AUD ($ 307 million), plus interest, which would be split between BMS and Sanofi, for alleged losses experienced for paying a higher price for branded | text | 307 | monetaryItemType | text: <entity> 307 </entity> <entity type> monetaryItemType </entity type> <context> Sanofi was notified that, in August 2007, GenRx Proprietary Limited ("GenRx") obtained regulatory approval of an application for clopidogrel bisulfate 75mg tablets in Australia. GenRx, formerly a subsidiary of Apotex Inc., subsequently changed its name to Apotex ("GenRx-Apotex"). In August 2007, GenRx-Apotex filed an application in the Federal Court of Australia seeking revocation of Sanofi's Australian Patent No. 597784 (Case No. NSD 1639 of 2007). Sanofi filed counterclaims of infringement and sought an injunction. On September 21, 2007, the Federal Court of Australia granted Sanofi's injunction. A subsidiary of BMS was subsequently added as a party to the proceedings. In February 2008, a second company, Spirit Pharmaceuticals Pty. Ltd., also filed a revocation suit against the same patent. This case was consolidated with the GenRx-Apotex case. On August 12, 2008, the Federal Court of Australia held that claims of Patent No. 597784 covering clopidogrel bisulfate, hydrochloride, hydrobromide, and taurocholate salts were valid. The Federal Court also held that the process claims, pharmaceutical composition claims, and claim directed to clopidogrel and its pharmaceutically acceptable salts were invalid. BMS and Sanofi filed notices of appeal in the Full Court of the Federal Court of Australia ("Full Court") appealing the holding of invalidity of the claim covering clopidogrel and its pharmaceutically acceptable salts, process claims, and pharmaceutical composition claims. GenRx-Apotex appealed. On September 29, 2009, the Full Court held all of the claims of Patent No. 597784 invalid. In March 2010, the High Court of Australia denied a request by BMS and Sanofi to hear an appeal of the Full Court decision. The case was remanded to the Federal Court for further proceedings related to damages sought by GenRx-Apotex. BMS and GenRx-Apotex settled, and the GenRx-Apotex case was dismissed. The Australian government intervened in this matter seeking maximum damages up to 449 million AUD ($ 307 million), plus interest, which would be split between BMS and Sanofi, for alleged losses experienced for paying a higher price for branded </context> | us-gaap:LossContingencyDamagesPaidValue |
BMS has received Notice Letters from Xspray Pharma AB ("Xspray"), Nanocopoeia, LLC ("Nanocopoeia"), Handa Oncology, LLC ("Handa") and Zydus Pharmaceuticals ("Zydus"), each notifying BMS that it has filed applications containing paragraph IV certifications seeking approval of a dasatinib product in the U.S. and challenging two FDA Orange Book-listed monohydrate form patents expiring in 2025 and 2026. In February 2022, BMS filed a patent infringement action against Xspray in the U.S. District Court for the District of New Jersey. In May 2022, BMS filed a patent infringement action against Nanocopoeia in the U.S. District Court for the District of Minnesota. In November 2022, BMS filed a patent infringement action against Handa in the U.S. District Court for the Northern District of California. On March 24, 2023, the Minnesota court denied a motion that Nanocopoeia had filed seeking a judgment based on the pleadings. On June 16, 2023, BMS entered into a confidential settlement agreement with Handa, settling all outstanding claims in the litigation. On September 13, 2023, BMS entered into a confidential settlement agreement with XSpray, settling all outstanding claims in the litigation. On October 10, 2023, BMS entered into a confidential settlement agreement with Nanocopoeia, settling all outstanding claims in the litigation. In October 2023, BMS filed a patent infringement action against Zydus in the U.S. District Court for the District of New Jersey. | text | two | integerItemType | text: <entity> two </entity> <entity type> integerItemType </entity type> <context> BMS has received Notice Letters from Xspray Pharma AB ("Xspray"), Nanocopoeia, LLC ("Nanocopoeia"), Handa Oncology, LLC ("Handa") and Zydus Pharmaceuticals ("Zydus"), each notifying BMS that it has filed applications containing paragraph IV certifications seeking approval of a dasatinib product in the U.S. and challenging two FDA Orange Book-listed monohydrate form patents expiring in 2025 and 2026. In February 2022, BMS filed a patent infringement action against Xspray in the U.S. District Court for the District of New Jersey. In May 2022, BMS filed a patent infringement action against Nanocopoeia in the U.S. District Court for the District of Minnesota. In November 2022, BMS filed a patent infringement action against Handa in the U.S. District Court for the Northern District of California. On March 24, 2023, the Minnesota court denied a motion that Nanocopoeia had filed seeking a judgment based on the pleadings. On June 16, 2023, BMS entered into a confidential settlement agreement with Handa, settling all outstanding claims in the litigation. On September 13, 2023, BMS entered into a confidential settlement agreement with XSpray, settling all outstanding claims in the litigation. On October 10, 2023, BMS entered into a confidential settlement agreement with Nanocopoeia, settling all outstanding claims in the litigation. In October 2023, BMS filed a patent infringement action against Zydus in the U.S. District Court for the District of New Jersey. </context> | us-gaap:LossContingencyPatentsAllegedlyInfringedNumber |
*. In February 2021, a Hawaii state court judge issued a decision against Sanofi and BMS, imposing penalties in the total amount of $ 834 million, with $ 417 million attributed to BMS. Sanofi and BMS appealed the decision. On March 15, 2023, the Hawaii Supreme Court issued its decision, reversing in part and affirming in part the trial court decision, vacating the penalty award and remanding the case for a new trial and penalty determination. A new bench trial concluded on October 16, 2023, and a decision is pending. | text | 834 | monetaryItemType | text: <entity> 834 </entity> <entity type> monetaryItemType </entity type> <context> *. In February 2021, a Hawaii state court judge issued a decision against Sanofi and BMS, imposing penalties in the total amount of $ 834 million, with $ 417 million attributed to BMS. Sanofi and BMS appealed the decision. On March 15, 2023, the Hawaii Supreme Court issued its decision, reversing in part and affirming in part the trial court decision, vacating the penalty award and remanding the case for a new trial and penalty determination. A new bench trial concluded on October 16, 2023, and a decision is pending. </context> | us-gaap:LossContingencyDamagesSoughtValue |
*. In February 2021, a Hawaii state court judge issued a decision against Sanofi and BMS, imposing penalties in the total amount of $ 834 million, with $ 417 million attributed to BMS. Sanofi and BMS appealed the decision. On March 15, 2023, the Hawaii Supreme Court issued its decision, reversing in part and affirming in part the trial court decision, vacating the penalty award and remanding the case for a new trial and penalty determination. A new bench trial concluded on October 16, 2023, and a decision is pending. | text | 417 | monetaryItemType | text: <entity> 417 </entity> <entity type> monetaryItemType </entity type> <context> *. In February 2021, a Hawaii state court judge issued a decision against Sanofi and BMS, imposing penalties in the total amount of $ 834 million, with $ 417 million attributed to BMS. Sanofi and BMS appealed the decision. On March 15, 2023, the Hawaii Supreme Court issued its decision, reversing in part and affirming in part the trial court decision, vacating the penalty award and remanding the case for a new trial and penalty determination. A new bench trial concluded on October 16, 2023, and a decision is pending. </context> | us-gaap:LossContingencyDamagesSoughtValue |
caused them to engage in compulsive gambling and other impulse control disorders. Cases were filed in state and federal courts in the United States. Pursuant to a previously disclosed master settlement agreement and settlement related court orders, the vast majority of the cases in the United States. were resolved or dismissed. Eleven inactive cases remain pending in state courts in New Jersey. There are also eleven cases pending in Canada ( four class actions and seven individual injury claims), two of which are active (the certified class actions in Quebec and Ontario). | text | eleven | integerItemType | text: <entity> eleven </entity> <entity type> integerItemType </entity type> <context> caused them to engage in compulsive gambling and other impulse control disorders. Cases were filed in state and federal courts in the United States. Pursuant to a previously disclosed master settlement agreement and settlement related court orders, the vast majority of the cases in the United States. were resolved or dismissed. Eleven inactive cases remain pending in state courts in New Jersey. There are also eleven cases pending in Canada ( four class actions and seven individual injury claims), two of which are active (the certified class actions in Quebec and Ontario). </context> | us-gaap:LossContingencyPendingClaimsNumber |
) before a contractual milestone date, thereby allegedly avoiding a $ 6.4 billion potential obligation to holders of the contingent value rights governed by the CVR Agreement and by allegedly failing to permit inspection of records in response to a request by the alleged successor trustee. The plaintiff seeks damages in an amount to be determined at trial and other relief, including interest and attorneys' fees. BMS disputes the allegations. BMS filed a motion to dismiss the alleged successor trustee's complaint for failure to state a claim upon which relief can be granted, which was denied on June 24, 2022. On February 2, 2024, BMS filed a motion to dismiss the complaint for lack of subject matter jurisdiction. | text | 6.4 | monetaryItemType | text: <entity> 6.4 </entity> <entity type> monetaryItemType </entity type> <context> ) before a contractual milestone date, thereby allegedly avoiding a $ 6.4 billion potential obligation to holders of the contingent value rights governed by the CVR Agreement and by allegedly failing to permit inspection of records in response to a request by the alleged successor trustee. The plaintiff seeks damages in an amount to be determined at trial and other relief, including interest and attorneys' fees. BMS disputes the allegations. BMS filed a motion to dismiss the alleged successor trustee's complaint for failure to state a claim upon which relief can be granted, which was denied on June 24, 2022. On February 2, 2024, BMS filed a motion to dismiss the complaint for lack of subject matter jurisdiction. </context> | us-gaap:ContractualObligation |
In September 2023, certain health plan entities filed an action on behalf of a putative class of end-payor plaintiffs against Celgene, BMS, and certain generic pharmaceutical manufacturers in the U.S. District Court for the Southern District of New York. The class complaint asserts claims under federal antitrust law and state antitrust, consumer protection, and unjust enrichment laws based on allegations that Celgene and BMS engaged in anticompetitive conduct related to pomalidomide in the U.S., including by allegedly engaging in fraud before the USPTO in the acquisition of patents related to the use of pomalidomide, by filing alleged sham patent litigations against generic pharmaceutical companies seeking to market generic pomalidomide, and by entering into allegedly unlawful patent litigation settlements with certain generic pharmaceutical companies seeking to market generic pomalidomide. In December 2023, the plaintiffs filed an amended complaint that added one individual Pomalyst patient as a plaintiff, removed the generic manufacturer defendants, and added two individuals as defendants. No trial date has been scheduled. | text | one | integerItemType | text: <entity> one </entity> <entity type> integerItemType </entity type> <context> In September 2023, certain health plan entities filed an action on behalf of a putative class of end-payor plaintiffs against Celgene, BMS, and certain generic pharmaceutical manufacturers in the U.S. District Court for the Southern District of New York. The class complaint asserts claims under federal antitrust law and state antitrust, consumer protection, and unjust enrichment laws based on allegations that Celgene and BMS engaged in anticompetitive conduct related to pomalidomide in the U.S., including by allegedly engaging in fraud before the USPTO in the acquisition of patents related to the use of pomalidomide, by filing alleged sham patent litigations against generic pharmaceutical companies seeking to market generic pomalidomide, and by entering into allegedly unlawful patent litigation settlements with certain generic pharmaceutical companies seeking to market generic pomalidomide. In December 2023, the plaintiffs filed an amended complaint that added one individual Pomalyst patient as a plaintiff, removed the generic manufacturer defendants, and added two individuals as defendants. No trial date has been scheduled. </context> | us-gaap:LossContingencyNumberOfPlaintiffs |
In September 2023, certain health plan entities filed an action on behalf of a putative class of end-payor plaintiffs against Celgene, BMS, and certain generic pharmaceutical manufacturers in the U.S. District Court for the Southern District of New York. The class complaint asserts claims under federal antitrust law and state antitrust, consumer protection, and unjust enrichment laws based on allegations that Celgene and BMS engaged in anticompetitive conduct related to pomalidomide in the U.S., including by allegedly engaging in fraud before the USPTO in the acquisition of patents related to the use of pomalidomide, by filing alleged sham patent litigations against generic pharmaceutical companies seeking to market generic pomalidomide, and by entering into allegedly unlawful patent litigation settlements with certain generic pharmaceutical companies seeking to market generic pomalidomide. In December 2023, the plaintiffs filed an amended complaint that added one individual Pomalyst patient as a plaintiff, removed the generic manufacturer defendants, and added two individuals as defendants. No trial date has been scheduled. | text | two | integerItemType | text: <entity> two </entity> <entity type> integerItemType </entity type> <context> In September 2023, certain health plan entities filed an action on behalf of a putative class of end-payor plaintiffs against Celgene, BMS, and certain generic pharmaceutical manufacturers in the U.S. District Court for the Southern District of New York. The class complaint asserts claims under federal antitrust law and state antitrust, consumer protection, and unjust enrichment laws based on allegations that Celgene and BMS engaged in anticompetitive conduct related to pomalidomide in the U.S., including by allegedly engaging in fraud before the USPTO in the acquisition of patents related to the use of pomalidomide, by filing alleged sham patent litigations against generic pharmaceutical companies seeking to market generic pomalidomide, and by entering into allegedly unlawful patent litigation settlements with certain generic pharmaceutical companies seeking to market generic pomalidomide. In December 2023, the plaintiffs filed an amended complaint that added one individual Pomalyst patient as a plaintiff, removed the generic manufacturer defendants, and added two individuals as defendants. No trial date has been scheduled. </context> | us-gaap:LossContingencyNumberOfDefendants |
With respect to CERCLA and other remediation matters for which BMS is responsible under various state, federal and international laws, BMS typically estimates potential costs based on information obtained from the U.S. Environmental Protection Agency, or counterpart state or foreign agency and/or studies prepared by independent consultants, including the total estimated costs for the site and the expected cost-sharing, if any, with other "potentially responsible parties," and BMS accrues liabilities when they are probable and reasonably estimable. BMS estimated its share of future costs for these sites to be $ 80 million as of December 31, 2023, which represents the sum of best estimates or, where no best estimate can reasonably be made, estimates of the minimal probable amount among a range of such costs (without taking into account any potential recoveries from other parties). The amount includes the estimated costs for any additional probable loss associated with the previously disclosed North Brunswick Township High School Remediation Site. | text | 80 | monetaryItemType | text: <entity> 80 </entity> <entity type> monetaryItemType </entity type> <context> With respect to CERCLA and other remediation matters for which BMS is responsible under various state, federal and international laws, BMS typically estimates potential costs based on information obtained from the U.S. Environmental Protection Agency, or counterpart state or foreign agency and/or studies prepared by independent consultants, including the total estimated costs for the site and the expected cost-sharing, if any, with other "potentially responsible parties," and BMS accrues liabilities when they are probable and reasonably estimable. BMS estimated its share of future costs for these sites to be $ 80 million as of December 31, 2023, which represents the sum of best estimates or, where no best estimate can reasonably be made, estimates of the minimal probable amount among a range of such costs (without taking into account any potential recoveries from other parties). The amount includes the estimated costs for any additional probable loss associated with the previously disclosed North Brunswick Township High School Remediation Site. </context> | us-gaap:AccruedLiabilitiesCurrentAndNoncurrent |
As of December 31, 2023 and 2022, Exelon owned 100 % of PECO, BGE, and PHI and more than 99 % of ComEd. PHI owns 100 % of Pepco, DPL, and ACE. As of December 31, 2021, Exelon owned 100 % of Generation. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation, including Generation and its subsidiaries, meets the | text | 100 | percentItemType | text: <entity> 100 </entity> <entity type> percentItemType </entity type> <context> As of December 31, 2023 and 2022, Exelon owned 100 % of PECO, BGE, and PHI and more than 99 % of ComEd. PHI owns 100 % of Pepco, DPL, and ACE. As of December 31, 2021, Exelon owned 100 % of Generation. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation, including Generation and its subsidiaries, meets the </context> | us-gaap:SubsidiaryOrEquityMethodInvesteeCumulativePercentageOwnershipAfterAllTransactions |
On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that was tax-free to Exelon and its shareholders for U.S. federal income tax purposes. | text | 326663937 | sharesItemType | text: <entity> 326663937 </entity> <entity type> sharesItemType </entity type> <context> On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that was tax-free to Exelon and its shareholders for U.S. federal income tax purposes. </context> | us-gaap:CommonStockSharesIssued |
Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. | text | 1.15 | monetaryItemType | text: <entity> 1.15 </entity> <entity type> monetaryItemType </entity type> <context> Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. </context> | us-gaap:ShortTermBankLoansAndNotesPayable |
Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. | text | 300 | monetaryItemType | text: <entity> 300 </entity> <entity type> monetaryItemType </entity type> <context> Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. </context> | us-gaap:DebtInstrumentFaceAmount |
Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. | text | 250 | monetaryItemType | text: <entity> 250 </entity> <entity type> monetaryItemType </entity type> <context> Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information. </context> | us-gaap:DebtInstrumentFaceAmount |
Exelon received cash from Generation of $ 258 million to settle the intercompany loan on January 31, 2022. See Note 16 — Debt and Credit Agreements for additional information. | text | 258 | monetaryItemType | text: <entity> 258 </entity> <entity type> monetaryItemType </entity type> <context> Exelon received cash from Generation of $ 258 million to settle the intercompany loan on January 31, 2022. See Note 16 — Debt and Credit Agreements for additional information. </context> | us-gaap:ProceedsFromSaleAndCollectionOfNotesReceivable |
Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. | text | 151 | monetaryItemType | text: <entity> 151 </entity> <entity type> monetaryItemType </entity type> <context> Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. </context> | us-gaap:DiscontinuedOperationIntraEntityAmountsDiscontinuedOperationAfterDisposalExpense |
Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. </context> | us-gaap:DiscontinuedOperationIntraEntityAmountsDiscontinuedOperationAfterDisposalExpense |
Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. | text | 266 | monetaryItemType | text: <entity> 266 </entity> <entity type> monetaryItemType </entity type> <context> Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. </context> | us-gaap:DiscontinuedOperationIntraEntityAmountsDiscontinuedOperationAfterDisposalExpense |
Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. | text | 43 | monetaryItemType | text: <entity> 43 </entity> <entity type> monetaryItemType </entity type> <context> Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively. </context> | us-gaap:DiscontinuedOperationIntraEntityAmountsDiscontinuedOperationAfterDisposalExpense |
There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of December 31, 2023 and 2022. Constellation had net assets of $ 11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information. | text | 11573 | monetaryItemType | text: <entity> 11573 </entity> <entity type> monetaryItemType </entity type> <context> There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of December 31, 2023 and 2022. Constellation had net assets of $ 11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information. </context> | us-gaap:AssetsNet |
ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. | text | 144 | monetaryItemType | text: <entity> 144 </entity> <entity type> monetaryItemType </entity type> <context> ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. | text | 5.94 | percentItemType | text: <entity> 5.94 </entity> <entity type> percentItemType </entity type> <context> ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. | text | 7.85 | percentItemType | text: <entity> 7.85 </entity> <entity type> percentItemType </entity type> <context> ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. | text | 5.91 | percentItemType | text: <entity> 5.91 </entity> <entity type> percentItemType </entity type> <context> ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. | text | 7.78 | percentItemType | text: <entity> 7.78 </entity> <entity type> percentItemType </entity type> <context> ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 451 | monetaryItemType | text: <entity> 451 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 6 | monetaryItemType | text: <entity> 6 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 30 | monetaryItemType | text: <entity> 30 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 8.905 | percentItemType | text: <entity> 8.905 </entity> <entity type> percentItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. | text | 50 | percentItemType | text: <entity> 50 </entity> <entity type> percentItemType </entity type> <context> Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset. </context> | us-gaap:PublicUtilitiesApprovedDebtCapitalStructurePercentage |
On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48 %, inclusive of an allowed ROE of 8.91 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points. | text | 6.48 | percentItemType | text: <entity> 6.48 </entity> <entity type> percentItemType </entity type> <context> On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48 %, inclusive of an allowed ROE of 8.91 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48 %, inclusive of an allowed ROE of 8.91 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points. | text | 8.91 | percentItemType | text: <entity> 8.91 </entity> <entity type> percentItemType </entity type> <context> On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48 %, inclusive of an allowed ROE of 8.91 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 59 | monetaryItemType | text: <entity> 59 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 39 | monetaryItemType | text: <entity> 39 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 42 | monetaryItemType | text: <entity> 42 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 53 | monetaryItemType | text: <entity> 53 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 11 | monetaryItemType | text: <entity> 11 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 10 | monetaryItemType | text: <entity> 10 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 25 | percentItemType | text: <entity> 25 </entity> <entity type> percentItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreasePercentage |
Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i | text | 50 | percentItemType | text: <entity> 50 </entity> <entity type> percentItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreasePercentage |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 41 | monetaryItemType | text: <entity> 41 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 113 | monetaryItemType | text: <entity> 113 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 25 | monetaryItemType | text: <entity> 25 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 126 | monetaryItemType | text: <entity> 126 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 62 | monetaryItemType | text: <entity> 62 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 13 | monetaryItemType | text: <entity> 13 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 7 | monetaryItemType | text: <entity> 7 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 39 | monetaryItemType | text: <entity> 39 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. | text | 15 | monetaryItemType | text: <entity> 15 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. | text | 21 | monetaryItemType | text: <entity> 21 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. | text | 16 | monetaryItemType | text: <entity> 16 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. | text | 15 | monetaryItemType | text: <entity> 15 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. | text | 25 | percentItemType | text: <entity> 25 </entity> <entity type> percentItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreasePercentage |
Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively. | text | 17 | monetaryItemType | text: <entity> 17 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively. | text | 6 | monetaryItemType | text: <entity> 6 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively. | text | 36 | monetaryItemType | text: <entity> 36 </entity> <entity type> monetaryItemType </entity type> <context> Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively. | text | 9 | monetaryItemType | text: <entity> 9 </entity> <entity type> monetaryItemType </entity type> <context> Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $ 117 million, $ 37 million, and $ 37 million in 2024, 2025 and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals. | text | 117 | monetaryItemType | text: <entity> 117 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $ 117 million, $ 37 million, and $ 37 million in 2024, 2025 and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $ 117 million, $ 37 million, and $ 37 million in 2024, 2025 and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals. | text | 37 | monetaryItemType | text: <entity> 37 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $ 117 million, $ 37 million, and $ 37 million in 2024, 2025 and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. | text | 69 | monetaryItemType | text: <entity> 69 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmendedAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. | text | 54 | monetaryItemType | text: <entity> 54 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmendedAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. | text | 51 | monetaryItemType | text: <entity> 51 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmendedAmount |
Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. | text | 14 | monetaryItemType | text: <entity> 14 </entity> <entity type> monetaryItemType </entity type> <context> Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmendedAmount |
The increase in BGE's transmission revenue requirement includes a $ 3 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. | text | 3 | monetaryItemType | text: <entity> 3 </entity> <entity type> monetaryItemType </entity type> <context> The increase in BGE's transmission revenue requirement includes a $ 3 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmendedAmount |
Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $ 1.472 billion to $ 1.545 billion. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $ 1.487 billion. | text | 1.487 | monetaryItemType | text: <entity> 1.487 </entity> <entity type> monetaryItemType </entity type> <context> Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $ 1.472 billion to $ 1.545 billion. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $ 1.487 billion. </context> | us-gaap:PublicUtilitiesRequestedRateIncreaseDecreaseAmount |
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset. | text | 501 | monetaryItemType | text: <entity> 501 </entity> <entity type> monetaryItemType </entity type> <context> On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset. | text | 986 | monetaryItemType | text: <entity> 986 </entity> <entity type> monetaryItemType </entity type> <context> On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period. ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of December 31, 2023 is $ 673 million. | text | 673 | monetaryItemType | text: <entity> 673 </entity> <entity type> monetaryItemType </entity type> <context> CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period. ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of December 31, 2023 is $ 673 million. </context> | us-gaap:RegulatoryAssets |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 71 | monetaryItemType | text: <entity> 71 </entity> <entity type> monetaryItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 47 | monetaryItemType | text: <entity> 47 </entity> <entity type> monetaryItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 6.48 | percentItemType | text: <entity> 6.48 </entity> <entity type> percentItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 8.91 | percentItemType | text: <entity> 8.91 </entity> <entity type> percentItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 7.47 | percentItemType | text: <entity> 7.47 </entity> <entity type> percentItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedEquityCapitalStructurePercentage |
ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. | text | 10.89 | percentItemType | text: <entity> 10.89 </entity> <entity type> percentItemType </entity type> <context> ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. </context> | us-gaap:PublicUtilitiesApprovedReturnOnEquityPercentage |
As of December 31, 2023, the $ 49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $ 88 million and $ 66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows. | text | 88 | monetaryItemType | text: <entity> 88 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2023, the $ 49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $ 88 million and $ 66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows. </context> | us-gaap:GainLossOnContractTermination |
As of December 31, 2023, the $ 49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $ 88 million and $ 66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows. | text | 66 | monetaryItemType | text: <entity> 66 </entity> <entity type> monetaryItemType </entity type> <context> As of December 31, 2023, the $ 49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $ 88 million and $ 66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows. </context> | us-gaap:GainLossOnContractTermination |
On February 28, 2018, ACE filed with the NJBPU the Registrants' IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $ 338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement. | text | 96 | monetaryItemType | text: <entity> 96 </entity> <entity type> monetaryItemType </entity type> <context> On February 28, 2018, ACE filed with the NJBPU the Registrants' IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $ 338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
October 31, 2022, ACE filed with the NJBPU a second IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $ 379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program. | text | 93 | monetaryItemType | text: <entity> 93 </entity> <entity type> monetaryItemType </entity type> <context> October 31, 2022, ACE filed with the NJBPU a second IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $ 379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program. </context> | us-gaap:PublicUtilitiesApprovedRateIncreaseDecreaseAmount |
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income. | text | six | integerItemType | text: <entity> six </entity> <entity type> integerItemType </entity type> <context> Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income. </context> | us-gaap:NumberOfReportableSegments |
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income. | text | three | integerItemType | text: <entity> three </entity> <entity type> integerItemType </entity type> <context> Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income. </context> | us-gaap:NumberOfReportableSegments |
PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. | text | 42.55 | percentItemType | text: <entity> 42.55 </entity> <entity type> percentItemType </entity type> <context> PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. | text | 1 | percentItemType | text: <entity> 1 </entity> <entity type> percentItemType </entity type> <context> PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. | text | 13.9 | percentItemType | text: <entity> 13.9 </entity> <entity type> percentItemType </entity type> <context> PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. | text | 7.45 | percentItemType | text: <entity> 7.45 </entity> <entity type> percentItemType </entity type> <context> PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. | text | 21.78 | percentItemType | text: <entity> 21.78 </entity> <entity type> percentItemType </entity type> <context> PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation. </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
Certain facilities are fully owned by Exelon through its 100 % ownership in PECO, DPL, and ACE. These facilities are operated by Exelon Registrants. PECO's, DPL's, and ACE's material undivided ownership interests in Exelon owned facilities as of December 31, 2023 and 2022 were as follows: | text | 100 | percentItemType | text: <entity> 100 </entity> <entity type> percentItemType </entity type> <context> Certain facilities are fully owned by Exelon through its 100 % ownership in PECO, DPL, and ACE. These facilities are operated by Exelon Registrants. PECO's, DPL's, and ACE's material undivided ownership interests in Exelon owned facilities as of December 31, 2023 and 2022 were as follows: </context> | us-gaap:JointlyOwnedUtilityPlantProportionateOwnershipShare |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. | text | 2.6 | monetaryItemType | text: <entity> 2.6 </entity> <entity type> monetaryItemType </entity type> <context> Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. </context> | us-gaap:Goodwill |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. | text | 4.0 | monetaryItemType | text: <entity> 4.0 </entity> <entity type> monetaryItemType </entity type> <context> Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. </context> | us-gaap:Goodwill |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. | text | 2.1 | monetaryItemType | text: <entity> 2.1 </entity> <entity type> monetaryItemType </entity type> <context> Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. </context> | us-gaap:Goodwill |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. | text | 1.4 | monetaryItemType | text: <entity> 1.4 </entity> <entity type> monetaryItemType </entity type> <context> Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. </context> | us-gaap:Goodwill |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. | text | 0.5 | monetaryItemType | text: <entity> 0.5 </entity> <entity type> monetaryItemType </entity type> <context> Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $ 2.1 billion, $ 1.4 billion, and $ 0.5 billion, respectively. </context> | us-gaap:Goodwill |
For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 54 million. | text | 54 | monetaryItemType | text: <entity> 54 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 54 million. </context> | us-gaap:IncomeTaxReconciliationStateAndLocalIncomeTaxes |
For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to transmission and distribution rate case settlements. | text | 38 | monetaryItemType | text: <entity> 38 </entity> <entity type> monetaryItemType </entity type> <context> For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to transmission and distribution rate case settlements. </context> | us-gaap:IncreaseDecreaseInIncomeTaxes |
For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. | text | 67 | monetaryItemType | text: <entity> 67 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. </context> | us-gaap:IncomeTaxReconciliationChangeInEnactedTaxRate |
For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. | text | 40 | monetaryItemType | text: <entity> 40 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. </context> | us-gaap:ValuationAllowanceDeferredTaxAssetChangeInAmount |
For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. | text | 43 | monetaryItemType | text: <entity> 43 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. </context> | us-gaap:IncomeTaxReconciliationStateAndLocalIncomeTaxes |
For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. | text | 11 | monetaryItemType | text: <entity> 11 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. </context> | us-gaap:IncomeTaxReconciliationOtherAdjustments |
For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. | text | 38 | monetaryItemType | text: <entity> 38 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. </context> | us-gaap:IncreaseDecreaseInIncomeTaxes |
For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of $ 15 million as a result of the separation. | text | 15 | monetaryItemType | text: <entity> 15 </entity> <entity type> monetaryItemType </entity type> <context> For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of $ 15 million as a result of the separation. </context> | us-gaap:IncomeTaxCreditsAndAdjustments |
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