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Regulatory Matters | 3 Months Ended
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Mar. 31, 2021
Regulated Operations [Abstract] |
REGULATORY MATTERS | REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility. MARYLAND PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE's approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers program costs through an annually reconciled surcharge, with most costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On September 1, 2020, PE filed its proposed plan for the 2021-2023 EmPOWER Maryland program cycle. The new plan largely continues PE’s existing programs and is estimated to cost approximately $148 million over the three-year period. The MDPSC approved the plan on December 18, 2020. On March 22, 2019, MDPSC issued an order approving PE’s 2018 base rate case filing, which among other things, approved an annual rate increase of $6.2 million, approved three of the four EDIS programs for four years to fund enhanced service reliability programs, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs. On September 22, 2020, PE filed its depreciation study reflecting a slight increase in expense and is seeking the difference to be deferred for future recovery in PE’s next base rate case. On January 29, 2021, the Maryland Office of People's Counsel filed testimony recommending an annual reduction in depreciation expense of $10.8 million, and the staff of the MDPSC filed testimony recommending an annual reduction of $9.6 million. PE's rebuttal testimony was filed on March 2, 2021, and the Public Utility Law Judge conducted a hearing on the matter on April 12, 2021. Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 pandemic. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expense, incurred from the date of the Governor’s order (or earlier if the utility could show that the expenses related to suspension of service terminations). In July 2020, the MDPSC subsequently issued orders allowing Maryland electric and gas utilities to resume residential service terminations for non-payment on November 15, 2020, subject to various restrictions, and clarifying that utilities could resume charging late fees on October 1, 2020. On April 9, 2021, PE provided the MDPSC additional information related to customer arrearages, which will be used, to determine the distribution of at least $30 million of COVID-19 relief that was allocated by the Maryland General Assembly. NEW JERSEY JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the NJ Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. Oral Argument was held on March 10, 2021, which JCP&L participated in. JCP&L is contesting this appeal but is unable to predict the outcome of this matter. On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase. On October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which will become effective for customers on November 1, 2021. Until the rates become effective, and starting on January 1, 2021, JCP&L began to amortize an existing regulatory liability totaling approximately $86 million to offset the base rate increase that otherwise would have occurred in this period. The parties also agreed that the actual net gain from the sale of JCP&L’s interest in the Yards Creek pumped-storage hydro generation facility in New Jersey (210 MWs), as further discussed below, be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs. Lastly, the parties agreed that approximately $95 million of Reliability Plus capital investment for projects through December 31, 2020 is included in rate base effective December 31, 2020, with a final prudence review of only those capital investment projects from July 1, 2020 through December 31, 2020 to occur in January 2021. During the first quarter of 2021, JCP&L submitted its review of storm costs, filed a written report for its Reliability Plus projects placed in service from July 1, 2020 through December 31, 2020, and submitted the vegetation management report, all required under the stipulation of settlement. On March 24, 2021, JCP&L, NJ Rate Counsel and the NJBPU Staff submitted a stipulation of settlement to the NJBPU, which was approved on April 7, 2021, providing that the Reliability Plus projects placed into service from July 1, 2020 through December 31, 2020 were reasonable and prudent. On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility. Subject to terms and conditions of the agreement, the base purchase price is $155 million. As of December 31, 2020, assets held for sale on FirstEnergy’s Consolidated Balance Sheets associated with the transaction consist of property, plant and equipment of $45 million, which is included in the regulated distribution segment. On July 31, 2020, FERC approved the transfer of JCP&L’s interest in the hydroelectric operating license. On October 8, 2020, FERC issued an order authorizing the transfer of JCP&L’s ownership interest in the hydroelectric facilities. On October 28, 2020, the NJBPU approved the sale of Yards Creek. With the receipt of all required regulatory approvals, the transaction was consummated on March 5, 2021 and resulted in a $109 million gain within the regulated distribution segment. As further discussed above, the gain from the transaction was applied against and reduced JCP&L’s existing regulatory asset for previously deferred storm costs and, as a result, was offset by expense in the “Amortization of regulatory assets, net”, line on the Consolidated Statements of Income, resulting in no earnings impact to FirstEnergy or JCP&L. On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposes the deployment of approximately 1.2 million advanced meters over a three-year period beginning on January 1, 2023, at a total cost of approximately $418 million, including the pre-deployment phase. The 3-year deployment is part of the 20-year AMI Program that is expected to cost a total of approximately $732 million and proposes a cost recovery mechanism through a separate AMI tariff rider. On January 13, 2021, a procedural schedule was established, which includes evidentiary hearings the week of May 24, 2021. On February 26, 2021, JCP&L filed a letter requesting a suspension of the procedural schedule to allow for settlement discussions, which was granted on March 5, 2021. On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments over a ten-year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. On September 25, 2020, JCP&L filed its energy efficiency and peak demand reduction program. JCP&L’s program consists of 11 energy efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021 through June 30, 2024. The program also seeks approval of cost recovery totaling approximately $230 million as well as lost revenues associated with the energy savings resulting from the programs. While a procedural order has been established in this matter, on January 20, 2021, JCP&L filed a letter requesting a suspension of the procedural schedule to allow for settlement discussions. The Clean Energy Act contemplates a final order from the NJBPU by May 2, 2021. On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 through September 30, 2021, or until the Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. Through various Executive Orders issued by Governor Murphy, the moratorium period is extended to June 30, 2021. The recent credit rating actions taken on October 28, 2020, by S&P and Fitch triggered a requirement from various NJBPU orders that JCP&L file a mitigation plan, which was filed on November 5, 2020, to demonstrate that JCP&L has sufficient liquidity to meet its BGS obligations. On December 11, 2020, the NJBPU held a public hearing on the mitigation plan. Written comments on JCP&L’s mitigation plan were submitted on January 8, 2021. On September 23, 2020, the NJBPU issued an Order requiring all New Jersey electric distribution companies to file electric vehicle programs. JCP&L filed its electric vehicle program on March 1, 2021, which consists of six sub-programs, including a consumer education and outreach initiative that would begin on January 1, 2022, and continue over a four-year period. The total proposed budget for the electric vehicle program is approximately $50 million, of which $16 million is capital expenditures and $34 million is for operations and maintenance expenses. JCP&L is proposing to recover the electric vehicle program costs via a non-bypassable rate clause applicable to all distribution customer rate classes, which would become effective on January 1, 2022. OHIO The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues were decoupled, through a mechanism that took effect on February 1, 2020 and under which the Ohio Companies billed customers until February 9, 2021, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenue associated with energy efficiency and peak demand reduction programs, which is discussed further below; (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through the DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that the DMR is lawful, and remanded the matter to the PUCO with instructions to remove the DMR from ESP IV. The PUCO entered an order directing the Ohio Companies to cease further collection through the DMR, credit back to customers a refund of the DMR funds collected since July 2, 2019 and remove the DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 for OE and claiming a $42 million refund is due to OE customers. On December 1, 2020, the SCOH reversed the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for OE for calendar year 2017, and remanded the case to the PUCO with instructions to conduct new proceedings which includes the DMR revenues in the analysis, determines the threshold against which the earned return is measured, and makes other necessary determinations. FirstEnergy is unable to predict the outcome of these proceedings but has not deemed a liability probable as of March 31, 2021. On July 23, 2019, Ohio enacted HB 6, which established support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, HB 6 included provisions implementing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered a wind-down of statutorily required energy efficiency programs to commence on September 30, 2020, that the programs terminate on December 31, 2020, with the Ohio Companies' existing portfolio plans extended through 2020 without changes. On February 24, 2021, the PUCO found that statewide energy efficiency mandates had been achieved, and ordered that Ohio electric utilities’ energy efficiency and peak demand reduction cost recovery riders terminate. On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. On March 31, 2021, Governor DeWine signed HB 128, which, among other things, would repeal parts of HB 6, the legislation that established support for nuclear energy supply in Ohio, provided for a decoupling mechanism for Ohio electric utilities, and provided for the ending of current energy efficiency program mandates. HB 128 is effective June 29, 2021. As further discussed below, in connection with a partial settlement with the OAG and other parties, the Ohio Companies filed an application with the PUCO on February 1, 2021, to set the respective decoupling riders (CSR) to zero. On February 2, 2021, the PUCO approved the application. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies will of their own accord not seek to recover lost distribution revenue from residential and commercial customers. FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway as further discussed herein. As a result of the partial settlement, and the decision to not seek lost distribution revenue, FirstEnergy recognized a $108 million pre-tax charge ($84 million after-tax) in the fourth quarter of 2020, and $77 million (pre-tax) of which is associated with forgoing collection of lost distribution revenue. On March 31, 2021, FirstEnergy announced that the Ohio Companies will proactively refund to customers amounts previously collected under decoupling, with interest, which total approximately $27 million. On April 22, 2021, the Ohio Companies filed an application with the PUCO to modify CSR to return such amounts. Furthermore, as FirstEnergy would not have financially benefited from the Clean Air Fund included in HB 6, which is the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to any repeal of that provision of HB 6. On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to flow back to customers. The settlement had broad support, including PUCO staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. In March 2020, the PUCO issued entries directing utilities to review their service disconnection and restoration policies and suspend, for the duration of the COVID-19 pandemic, otherwise applicable requirements that may impose a service continuity hardship or service restoration hardship on customers. The Ohio Companies are utilizing their existing approved cost recovery mechanisms where applicable to address the financial impacts of these directives. On July 31, 2020, the Ohio Companies filed with the PUCO their transition plan and requests for waivers to allow for the safe resumption of normal business operations, including service disconnections for non-payment. On September 23, 2020, the PUCO approved the Ohio Companies’ transition plan, including approval of the resumption of service disconnections for non-payment, which the Ohio Companies began on October 5, 2020. On July 29, 2020, the PUCO consolidated the Ohio Companies’ Applications for determination of the existence of significantly excessive earnings, or SEET, under ESP IV for calendar years 2018 and 2019, which had been previously filed on July 15, 2019, and May 15, 2020, respectively, and set a procedural schedule with evidentiary hearings. On September 4, 2020, the PUCO opened its quadrennial review of ESP IV, consolidated it with the Ohio Companies’ 2018 and 2019 SEET Applications, and set a procedural schedule for the consolidated matters. On October 29, 2020, the PUCO issued an entry extending the deadline for the Ohio Companies to file quadrennial review of ESP IV testimony and supplemental SEET testimony to March 1, 2021, with the evidentiary hearings to commence no sooner than May 3, 2021. On January 12, 2021, the PUCO consolidated these matters with the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017, which the SCOH had remanded to the PUCO. On March 1, 2021, the Ohio Companies filed testimony in the quadrennial review and supplemental testimony in the SEET cases for calendar years 2017 through 2019. The calculations included in the quadrennial review for 2020 through 2024 demonstrate that the prospective effect of ESP IV is not substantially likely to provide the Ohio Companies with significantly excessive earnings during the balance of ESP IV. In addition, the Ohio Companies’ quadrennial review testimony demonstrates that ESP IV continues to be more favorable in the aggregate and during the remaining term of ESP IV as compared to the expected results of a market rate offer. Further, the revised calculations included in the Ohio Companies’ supplemental SEET testimony for calendar years 2017 through 2019 demonstrated that the Ohio Companies did not have significantly excessive earnings, on an individual company basis or on a consolidated basis. However, on March 31, 2021, Governor DeWine signed House Bill 128, which repeals legislation passed in 2019 that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis. HB 128 is effective June 29, 2021. Further, the OCC and another party filed testimony on April 5, 2021, recommending refunds for one or more of the Ohio Companies for calendar years 2017 through 2019. On April 20, 2021, the Ohio Companies filed supplemental testimony in the quadrennial review providing prospective SEET values on an individual company basis, which demonstrate that the Ohio Companies are not projected to have significantly excessive earnings, on an individual company basis, during the balance of ESP IV. On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. The Ohio Companies’ filed a response in opposition to the OCC’s motions on September 23, 2020. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from ratepayers through the DMR were only used for the purposes established in ESP IV. On April 7, 2021, the PUCO set deadlines for selection of an auditor and the filing of the final audit report, by June 2, 2021 and October 29, 2021, respectively. Initial discovery is ongoing. On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by ratepayers. The Ohio Companies filed a response on September 30, 2020, stating that any political and charitable spending in support of HB 6 or the subsequent referendum were not included in rates or charges paid for by its customers. Several parties requested that the PUCO broaden the scope of the review of political and charitable spending. Discovery is ongoing. In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020, with a final audit report to be filed in June 2021. On January 27, 2021, the PUCO selected an auditor, and the auditor’s investigation and discovery are ongoing. On November 24, 2020, the Environmental Law and Policy Center filed motions to vacate the PUCO’s orders in proceedings related to the Ohio Companies’ settlement that provides for the implementation of the first phase of grid modernization plans and for all tax savings associated with the Tax Act to flow back to customers, the Ohio Companies’ energy efficiency portfolio plans for the period from 2013 through 2016, and the Ohio Companies’ application for a two-year extension of the DMR, on the grounds that the former Chairman of the PUCO should have recused himself in these matters. On December 30, 2020, the PUCO denied the motions, and reinstated the requirement under ESP IV that the Ohio Companies file a base distribution rate case by May 31, 2024, the end of ESP IV, which the Ohio Companies had indicated they would not oppose. In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting charges required by HB 6, which the Ohio Companies are further required to remit to other Ohio electric distribution utilities or to the State Treasurer, to provide for refunds in the event HB 6 is repealed. The Ohio Companies contested the motions, which are pending before the PUCO. On December 7, 2020, the Citizens’ Utility Board of Ohio filed a complaint with the PUCO against the Ohio Companies. The complaint alleges that the Ohio Companies’ new charges resulting from HB 6, and any increased rates resulting from proceedings over which the former PUCO Chairman presided, are unjust and unreasonable, and that the Ohio Companies violated Ohio corporate separation laws by failing to operate separately from unregulated affiliates. The complaint requests, among other things, that any rates authorized by HB 6 or authorized by the PUCO in a proceeding over which the former Chairman presided be made refundable; that the Ohio Companies be required to file a new distribution rate case at the earliest possible date; and that the Ohio Companies’ corporate separation plans be modified to introduce institutional controls. The Ohio Companies are contesting the complaint. In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, on March 10, 2021, the PUCO expanded the scope of the audit to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, which were disclosed in FirstEnergy’s Form 10-K for the year ended 2020, filed on February 18, 2021, and determine whether funds collected from ratepayers were used to pay the vendors and if so, whether or not the funds associated with those payments should be returned to ratepayers through Rider DCR or through an alternative proceeding. See Note 9, "Commitments, Guarantees and Contingencies" for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6. PENNSYLVANIA The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 was separately tracked and its treatment will be addressed in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. The Pennsylvania Companies’ Phase IV plans were filed November 30, 2020. A settlement has been reached in this matter, and a joint petition seeking approval of that settlement by the parties was filed on February 16, 2021. On March 25, 2021, the PPUC issued an order approving the settlement without modification. Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. Briefs and Reply Briefs of the parties were filed, and oral argument before the Supreme Court was held on October 21, 2020. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy. The PPUC issued an order on March 13, 2020, forbidding utilities from terminating service for non-payment for the duration of the COVID-19 pandemic. On May 13, 2020, the PPUC issued a Secretarial letter directing utilities to track all prudently incurred incremental costs arising from the COVID-19 pandemic, and to create a regulatory asset for future recovery of incremental uncollectibles incurred as a result of the COVID-19 pandemic and termination moratorium. On October 13, 2020, the PPUC entered an order lifting the service termination moratorium effective November 9, 2020, subject to certain additional notification, payment procedures and exceptions, and permits the Pennsylvania Companies to create a regulatory asset for all incremental expenses associated with their compliance with the order. On March 19, 2021, the PPUC entered an order lifting the moratorium in total effective March 31, 2021, subject to certain additional guidelines regarding the duration of payment arrangements and reporting obligations. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is updated annually. On March 13, 2020, the WVPSC urged all utilities to suspend utility service terminations except where necessary as a matter of safety or where requested by the customer. On May 15, 2020, the WVPSC issued an order to authorize MP and PE to record a deferral of additional, extraordinary costs directly related to complying with the various COVID-19 government shut-down orders and operational precautions, including impacts on uncollectible expense and cash flow related to temporary discontinuance of service terminations for non-payment and any credits to minimum demand charges associated with business customers adversely impacted by shut-downs or temporary closures related to the pandemic. MP and PE resumed disconnection activity for commercial and industrial customers on September 15, 2020, and for residential customers on November 4, 2020. On August 28, 2020, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $55 million beginning January 1, 2021, representing a 4% decrease in rates compared to those in effect on August 28, 2020. The decrease in the ENEC rates is net of recovering approximately $10.5 million in previously deferred, incremental uncollectible and other related costs resulting from the COVID-19 pandemic. The WVPSC approved a unanimous settlement by the parties on December 16, 2020 with rates effective January 1, 2021. Also, on August 28, 2020, MP and PE filed with the WVPSC for recovery of costs associated with modernization and improvement program for their coal-fired boilers. The proposed annual revenue increase for these environmental compliance projects is $5 million beginning January 1, 2021. The WVPSC approved a unanimous settlement by the parties on December 16, 2020 approving the recovery of those costs. On December 30, 2020, MP and PE filed an integrated resource plan with the WVPSC. The plan projects a small capacity deficit but an energy surplus in MP’s and PE’s supply resources when compared with current WV load demand and projects the capacity deficit growing over the next 15 years. The plan does not recommend additional supply-side resources with a possible exception for small utility-scale solar resources and recommends that the capacity deficit be met through the PJM capacity market. MP currently expects to seek approval in 2021 to construct solar generation sources of up to 50 MWs. The WVPSC issued a procedural order on February 26, 2021, allowing informational filing comments to be filed by April 28, 2021. On December 30, 2020, MP and PE filed with the WVPSC a determination of the rate impact of the Tax Act with respect to ADIT. The filing proposes an annual revenue reduction of $2.6 million annually, effective January 1, 2022, with reconciliation and any resulting adjustments incorporated into the annual ENEC proceedings. A hearing is set for August 18, 2021. FERC REGULATORY MATTERS Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions. Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. ATSI Transmission Formula Rate On May 1, 2020, ATSI filed amendments to its formula rate to recover regulatory assets for certain costs that ATSI incurred as a result of its 2011 move from MISO to PJM, certain costs allocated to ATSI by FERC for transmission projects that were constructed by other MISO transmission owners, and certain costs for transmission-related vegetation management programs. Additionally, ATSI proposed certain income tax-related adjustments and certain tariff changes addressing the revenue credit components of the formula rate template. In its filing, ATSI requested recovery of approximately $85 million related to ATSI’s costs to move to PJM, and the MISO transmission project costs that are allocated to ATSI through December 31, 2020; and recovery of future costs associated with the MISO transmission projects. Per prior FERC orders, ATSI included a “cost-benefit study” to support recovery of ATSI’s costs to move to PJM, and the MISO transmission project costs that are allocated to ATSI. Finally, ATSI proposed recovery of approximately $19 million in costs for transmission-related vegetation management programs. Certain intervenors filed protests of the formula rate amendments on May 29, 2020, and ATSI filed a reply on June 15, 2020. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund, suspending the effective date for five months to be effective December 1, 2020, and setting the matter for hearing and settlement proceedings. ATSI is engaged in settlement negotiations with the other parties to this proceeding. FERC Actions on Tax Act On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to: (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. Certain intervenors filed protests of the compliance filings, to which ATSI and MAIT responded. On October 28, 2020, FERC staff requested additional information about ATSI’s proposed rate base adjustment mechanism, and ATSI submitted the requested information on November 25, 2020. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. These compliance filings each remain pending before FERC. MP, WP and PE (as holders of a “stated” transmission rate) are addressing these requirements in the transmission formula rates amendments that were filed on October 29, 2020, and which have been accepted by FERC effective January 1, 2021, subject to refund, pending further hearing and settlement procedures. JCP&L is addressing these requirements as part of its pending transmission formula rate case. JCP&L and the active parties to the pending FERC transmission formula rate case filed an offer of settlement with FERC on February 2, 2021. On April 15, 2021, FERC approved the settlement agreement as filed, with no changes. Transmission ROE Methodology FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On May 21, 2020, FERC issued Opinion No. 569-A that changed FERC’s ROE methodology. Under FERC’s revised methodology, ROE is based on three financial models – discounted cash flow, capital-asset pricing, and risk premium – which are used to calculate a composite zone of reasonableness. FERC noted that utilities could, in utility-specific proceedings, also ask to have the expected earnings methodology included in calculating the utility’s authorized ROE. FERC also noted that, going forward, it will divide that zone into three equal parts, to be used for high risk, normal risk, and low risk utilities. A given utility will be assigned to one of these three parts of the zone of reasonableness, and its ROE will be set at the median or midpoint of the other utilities that are in the applicable third of the zone. FirstEnergy filed a request for rehearing, which FERC denied on July 22, 2020. On November 19, 2020, FERC issued Opinion No. 569-B, which affirmed the Opinion No. 569-A rulings. FirstEnergy initiated, but subsequently withdrew, appeals of these orders. Appeals of Opinion Nos. 569, 569-A and 569-B were filed by other parties, and are pending before the D.C. Circuit. Any changes to FERC’s transmission rate ROE and incentive policies for the Utilities would be applied on a prospective basis. On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments were submitted July 1, 2020, and reply comments were filed on July 16, 2020. FirstEnergy participated through EEI and through a consortium of PJM Transmission Owners. In a supplemental rulemaking proceeding on April 15, 2021, FERC is seeking comments on, among other things, whether to require utilities that have been members of an RTO for three years or more and that have been collecting an “RTO membership” ROE incentive adder to file tariff updates that would terminate collection of the incentive adder. Initial comments are due 30 days after the supplement is published in the Federal Register, and reply comments are due 15 days later. FirstEnergy is a member of PJM and could be affected by the supplemental proposed rule and is currently evaluating the potential impacts this rule would have on certain of its subsidiaries. JCP&L Transmission Formula Rate On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding subsequently were able to reach settlement, and on February 2, 2021, JCP&L filed an offer of settlement, pending FERC approval. On April 15, 2021, FERC approved the settlement agreement as filed, with no changes.

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