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.

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 2021-2023 EmPOWER Maryland program cycles to the extent the MDPSC determines that cost-effective programs and services are available. PE's approved 2021-2023 EmPOWER Maryland plan continues and expands upon prior years' programs for a projected total investment of approximately $148 million over the three-year period. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. 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.

In 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. Following the filing of PE’s depreciation study and subsequent filings by the Maryland Office of the People’s Counsel and the staff of the MDPSC, the public utility law judge issued a proposed order reducing PE’s base rates by $2.1 million. The MDPSC denied PE’s appeal of the proposed order on October 26, 2021, and the proposed order was affirmed.

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 customers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation. 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 and on June 7, 2021, the Superior Court issued an order reversing the NJBPU’s CTA rules and remanded the case back to the NJBPU. Specifically, the Court’s ruling requires 100% of the CTA savings to be credited to customers in lieu of the NJBPU’s current policy requiring 25%. On December 6, 2021, the NJBPU issued proposed amended rules modifying its current CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order. Once the proposed rules are final, they will be applied on a prospective basis in a future base rate case, however, it is not expected to have a material adverse effect on FirstEnergy’s results or financial condition.

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 became effective for customers on November 1, 2021. Between January 1, 2021 and October 31, 2021, JCP&L amortized 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. Included in the NJBPU approved-settlement in JCP&L’s distribution rate case on October 28, 2020, was that JCP&L will be subject to a management audit. The management audit began at the end of May 2021 and is currently ongoing.

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 proposed 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 then proposed 3-year deployment was part of the 20-year AMI Program that was projected to cost approximately $732 million and proposed a cost recovery mechanism through a separate AMI tariff rider. On September 14, 2021, JCP&L submitted a supplemental filing, which reflected increases in the AMI Program’s costs. Under the revised AMI Program, during the first six years of the AMI Program from 2022 through 2027, JCP&L estimates costs of $494 million, consisting of capital expenditures of approximately $390 million, incremental operations and maintenance expenses of approximately $73 million and cost of removal of $31 million. On February 8, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others, that, pending NJBPU approval, would affirm the terms of the revised AMI Program. JCP&L expects a NJBPU order by the end of the first quarter of 2022. The Stipulation also provided that the revised AMI Program-related capital costs, the legacy meter stranded costs, and the operations and maintenance expense will be deferred and placed in regulatory assets, with such amounts sought to be recovered in the JCP&L’s subsequent base rate cases.

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 with a return 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, which consists of 11 energy

efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021, through June 30, 2024. On April 23, 2021, JCP&L filed a Stipulation of Settlement with the NJBPU for approval of recovery of lost revenues resulting from the programs and a three-year plan including total program costs of $203 million, of which $158 million of investment is recovered over a ten-year amortization period with a return as well as operations and maintenance expenses and financing costs of $45 million recovered on an annual basis. On April 27, 2021, the NJBPU issued an Order approving the Stipulation of Settlement.

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 and continuing until the New Jersey 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 the New Jersey Governor, the moratorium period was extended to December 31, 2021. On December 21, 2021, the moratorium on residential disconnections for certain entities providing utility service was extended until March 15, 2022. The moratorium on residential disconnections was not extended for investor-owned electric utilities such as JCP&L, but does require that investor-owned electric public utilities offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service.

Pursuant to an NJBPU order requiring all New Jersey electric distribution companies to file electric vehicle programs, JCP&L filed its program on March 1, 2021. JCP&L’s proposed electric vehicle program consisted 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 became effective on January 1, 2022. On May 26, 2021, a procedural schedule was set to include evidentiary hearings the week of October 18, 2021. On July 16, 2021, the procedural schedule was extended by thirty days as requested by JCP&L to continue settlement discussions. On August 19, 2021, the presiding commissioner issued an order modifying the procedural schedule by extending the procedural schedule by ninety days as requested by JCP&L to continue settlement discussions. On November 12, 2021, JCP&L filed a letter with the presiding commissioner requesting a suspension of the procedural schedule in order to allow the parties to continue settlement discussion. On November 23, 2021, the presiding commissioner entered an order suspending the procedural schedule. JCP&L expects an order from the NJBPU by the end of the first quarter of 2022.

The Ohio Companies operate under PUCO approved base distribution rates that became effective in 2009. 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) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) 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 DMR revenues, but the SCOH reversed the PUCO’s decision to include DMR in ESP IV. Subsequently, the PUCO entered an order directing the Ohio Companies to cease further collection through the DMR and credit back to customers a refund of the DMR funds collected since July 2, 2019. 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 include the DMR revenues in the analysis, determine the threshold against which the earned return is measured, and make other necessary determinations. As further described below, the Ohio Stipulation resolves the Ohio Companies’ 2017 SEET proceeding.

On July 23, 2019, Ohio enacted HB 6, which included provisions supporting nuclear energy, authorizing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates. Under HB 6, the energy efficiency program mandates, as well as Ohio electric utilities’ energy efficiency and peak demand reduction cost recovery riders, ended on December 31, 2020, subject to final reconciliation. Third-parties have challenged the Ohio Companies’ authorization to recover all lost distribution revenue under energy efficiency and peak demand reduction cost recovery riders. The Ohio Stipulation resolves the issues related to lost distribution revenue with no financial impact to the Ohio Companies.

On March 31, 2021, the Ohio Governor signed HB 128, which, among other things, repealed 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 was effective June 30, 2021. As FirstEnergy would not have financially benefited from the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to the repeal of that provision in HB 6.

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 elected to forego recovery of lost distribution revenue. FirstEnergy also committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings then 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. The Ohio Stipulation affirms the Ohio Companies’ commitment to not seek recovery of lost distribution revenue through the end of its ESP IV in May 2024.

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. 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 customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor. The auditor filed the final audit report on January 14, 2022, which made findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identify. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies.

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, and 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 customers. The Ohio Companies initially filed a response stating 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 customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the Rider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive.

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. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report, and a PUCO attorney examiner has issued a procedural schedule setting an evidentiary hearing on May 9, 2022.

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. On December 21, 2021, the Citizens’ Utility Board of Ohio filed a notice of voluntary dismissal of its complaint without prejudice. The PUCO dismissed the complaint without prejudice on January 12, 2022.

On November 1, 2021, the Ohio Companies, together with the OCC, PUCO Staff, and several other signatories, entered into an Ohio Stipulation with the intent of resolving the ongoing energy efficiency rider audits, various SEET, proceedings, including the Ohio Companies’ 2017 SEET proceeding, and the Ohio Companies’ quadrennial ESP review, each of which was pending before the PUCO. Specifically, the Ohio Stipulation provides that the Ohio Companies’ current ESP IV passes the required statutory test for their prospective SEET review as part of the Quadrennial Review of ESP IV, and except for limited circumstances, the signatory parties have agreed not to challenge the Ohio Companies’ SEET return on equity calculation methodology for their 2021-2024 SEET proceedings. The Ohio Stipulation additionally affirms that: (i) the Ohio Companies’ ESP IV shall continue through its previously authorized term of May 31, 2024; and (ii) the Ohio Companies will file their next base rate case in May 2024, and further, no signatory party will seek to adjust the Ohio Companies’ base distribution rates before that time, except in limited circumstances. The Ohio Companies further agreed to refund $96 million to customers in connection with the 2017-2019 SEET cases, and to provide $210 million in future rate reductions for all customers, including $80 million in 2022, $60 million in 2023, $45 million in 2024, and $25 million in 2025. The PUCO approved the 2017-2019 SEET refunds and 2022 rate reductions December 1, 2021, and refunds began in January 2022. As a result of the PUCO approval, FirstEnergy recognized a $96 million pre-tax charge in the fourth quarter of 2021 at the regulated distribution segment within Amortization (deferral) of Regulatory Assets, net, on the Consolidated Statements of Income associated with the refund. The future rate reductions will be recognized as a reduction to regulated distribution segment’s revenue in the Consolidated Statements of Income as they are provided to the Ohio Companies’ customers.

In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO.

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. On November 18, 2021, the PPUC issued orders to each of the Pennsylvania Companies directing they operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which DSPs provide for the competitive procurement of generation supply for customers who do not receive service from an alternative EGS. 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. On December 14, 2021, the Pennsylvania Companies filed proposed DSPs for provision of generation for the June 1, 2023 through May 31, 2027 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS. Under the 2023-2027 DSPs, supply is proposed to be provided through a mix of 12 and 24-month energy contracts, as well as long-term solar PPAs.

In March 2018, the PPUC approved adjusted customer rates of the Pennsylvania Companies to reflect the net impact of the Tax Act. As a result, the Pennsylvania Companies established riders that, beginning July 1, 2018, refunded to customers tax savings attributable to the Tax Act as compared to the amounts established in their most recent base rate proceedings on a current and going forward basis. The amounts recorded as savings for the total period of January 1 through June 30, 2018, were tracked and were to be addressed for treatment in a future proceeding. On May 17, 2021, the Pennsylvania Companies filed petitions with

the PPUC proposing to refund the net savings for the January through June 2018 period to customers beginning January 1, 2022. On November 18, 2021, the PPUC approved the Pennsylvania Companies' proposed refunds, but also revised a previous methodology for calculating the net tax savings, which resulted in additional tax savings attributable to the Tax Act to be refunded to customers and directed the Pennsylvania Companies to file new petitions to propose the timing and methodology to provide these additional refunds to customers. The Pennsylvania Companies recalculated the net impact for 2018 through 2021 under the revised PPUC methodology in comparison to amounts already refunded to customers under the existing riders, which resulted in an additional $61 million in savings, with interest, to be provided to customers. As a result, FirstEnergy recognized a pre-tax charge of $61 million in the fourth quarter of 2021 at the regulated distribution segment within Amortization (deferral) of Regulatory Assets, net, on the Consolidated Statement of Income associated with the additional refund associated with the November 2021 PPUC order and methodology. The Pennsylvania Companies are required to file petitions to propose the timing and methodology of the refund of these amounts by March 3, 2022.

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 and subsequently approved by PPUC without modification on March 25, 2021.

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. On June 25, 2021, the Pennsylvania OCA filed a complaint against Penn’s quarterly DSIC rate, disputing the recoverability of the Companies’ automated distribution management system investment under the DSIC mechanism. On January 26, 2022, the parties filed a joint petition for settlement that resolves all issues in this matter pending PPUC approval.

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. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for ADIT and state taxes. The matter awaits further action by the PPUC. The 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.

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 proposed an annual revenue reduction of $2.6 million, effective January 1, 2022, with reconciliation and any resulting adjustments incorporated into annual ENEC proceedings. On August 12, 2021, a unanimous settlement was reached with all the parties agreeing to a $7.7 million rate reduction beginning January 1, 2022, with a true-up in the ENEC proceeding each year. On November 30, 2021, the WVPSC approved the settlement on all terms, except for the proposed effective date of the rate reduction, which was held in abeyance until further notice.

On November 22, 2021, MP and PE filed with the WVPSC their plan to construct 50 MWs of solar generation at five sites in West Virginia. The plan includes a tariff to offer solar power to West Virginia customers and cost recovery for MP and PE from other customers through a surcharge for any solar investment not fully subscribed by their customers. A hearing has been set for March 16, 2022. The solar generation project is expected to cost approximately $100 million and begin being in-service by the end of 2023 and finalized no later than the end of 2025.

On August 27, 2021, MP and PE filed with the WVPSC a biennial review of the vegetation management surcharge seeking a $16 million annual revenue increase. A settlement among the parties was reached on December 3, 2021 and on December 27, 2021, the WVPSC approved the settlement, which granted a $16 million increase in rates, and continued the vegetation management program and surcharge for another two years. Additionally, the WVPSC order added a provision requiring equipment inspections be performed within a reasonable time after vegetation management occurs on a circuit.

On December 17, 2021, MP and PE filed with the WVPSC for approval of environmental compliance projects at the Ft. Martin and Harrison Power Stations to comply with the EPA’s ELG and operate these plants beyond 2028. The request includes a surcharge to recover the expected $142 million capital investment and $3 million in annual operation and maintenance expense. A ruling from the WVPSC is expected in mid-summer 2022, and if approved, construction would be expected to be completed by the end of 2025. See "Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.

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 RFC. 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.

FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations. One of the audit report findings and related recommendations state that FirstEnergy may have used an inappropriate methodology for allocation of certain costs to regulatory capital accounts under certain FERC regulations and reporting. Based on the finding and related recommendations, FirstEnergy is currently performing an analysis of these costs and how it impacted certain wholesale transmission customer rates. FirstEnergy is unable to predict or estimate the final outcome of this analysis and audit, however, it could result in refunds, with interest, to certain wholesale transmission customers and/or write-offs of previously capitalized costs if they are determined to be nonrecoverable.

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. A portion of these costs would have been charged to the Ohio Companies. Additionally, ATSI proposed certain income tax-related adjustments and certain tariff changes addressing the revenue credit components of the formula rate template. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund and setting the matter for hearing and settlement proceedings. ATSI and the parties to the FERC proceeding subsequently were able to reach settlement, and on October 14, 2021, filed the settlement with FERC. As a result of the filed settlement, FirstEnergy recognized a $21 million pre-tax charge during the third quarter of 2021, which was recognized in Other Operating Expenses on the FirstEnergy Consolidated Statements of Income. This $21 million charge reflects the difference between amounts originally recorded as regulatory assets and amounts which will ultimately be recovered as a result of the pending settlement. From a segment perspective, during the third quarter of 2021, the Regulated Transmission segment recorded a pre-tax charge of $48 million and the Regulated Distribution segment recognized a $27 million reduction to a reserve previously recorded in 2010. In addition, the settlement provides for partial recovery of future incurred costs allocated to ATSI by MISO for the above-referenced transmission projects that were constructed by other MISO transmission owners, which is not expected to have a material impact on FirstEnergy or ATSI. The uncontested settlement is pending before FERC for approval.

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. On November 18, 2021, FERC issued an order that: (i) accepted ATSI proposed tariff amendments to its rate base adjustment mechanism, effective January 27, 2020; (ii) directed ATSI to make a further compliance filing by January 17, 2022; and (iii) set the amount of ATSI’s recorded ADIT balances as of December 31, 2017, for hearing and settlement procedures. ATSI submitted the compliance filing, and is participating in settlement negotiations. On December 3, 2021, FERC issued an order that (i) accepted MAIT’s proposed tariff amendments to its rate base adjustment mechanism, effective January 27, 2020; (ii) directed MAIT to make a further compliance filing by February 1, 2022; and (iii) set the amount of MAIT’s recorded ADIT balances as of December 31, 2017 for hearing and settlement procedures. MAIT submitted the compliance filing, and is participating in settlement negotiations. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. On May 4, 2021, FERC staff requested additional information about PATH’s proposed rate base adjustment mechanism, and PATH submitted the requested information on June 3, 2021. On July 12, 2021, FERC staff requested additional information about TrAIL’s proposed rate base adjustment mechanism. TrAIL filed its response on August 6, 2021. The PATH and TrAIL compliance filings each remain pending before FERC. MP, WP and PE (as holders of a “stated” transmission rate when Order No. 864 issued) 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, MP, WP and PE are engaged in settlement negotiations with other parties to

On May 20, 2021, in a case not involving FirstEnergy, FERC issued Opinion No. 575 in which it reiterated the nationwide ROE methodology set forth in 2020 in Opinion Nos. 569-A and 569-B. Under this methodology, FERC employs three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness. As it has done in other recent ROE cases, FERC rejected the use of the expected earnings methodology in calculating the authorized ROE. A request for clarification or, alternatively, rehearing of Opinion No. 575 was filed on June 21, 2021, and on September 9, 2021, FERC issued an order clarifying aspects of its prior opinion, but affirming the result. On July 15, 2021, FERC issued another order, addressing ROE for a generation company in New England, which applied a standard consistent with Opinion Nos. 569-A and 569-B. FERC’s Opinion Nos. 569-A and 569-B, upon which Opinion No. 575 is based, have been appealed to the D.C. Circuit. FirstEnergy is not participating in the appeal. Any changes to FERC’s transmission rate ROE and incentive policies for transmission rates 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. FirstEnergy submitted comments through EEI and as part of a consortium of PJM Transmission Owners. In a supplemental rulemaking proceeding that was initiated on April 15, 2021, FERC requested 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 on the proposed rule were filed on June 25, 2021, and reply comments were filed on July 26, 2021. The rulemaking remains pending before FERC. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the supplemental proposed rule. FirstEnergy participated in comments that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy transmission incentive ROE, such changes will be applied on a prospective basis.

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 with FERC. On April 15, 2021, FERC approved the settlement agreement as filed, with no changes, effective January 1, 2021.

On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to implement a forward-looking formula transmission rate, to be effective January 1, 2021. In addition, on October 30, 2020, KATCo filed a proposed new tariff to establish a forward-looking formula rate and requested that the new rate become effective January 1, 2021. In its filing, KATCo explained that while it currently owns no transmission assets, it may build new transmission facilities in the Allegheny zone, and that it may seek required state and federal authorizations to acquire transmission assets from PE and WP by January 1, 2022. These transmission rate filings were accepted for filing by FERC on December 31, 2020, effective January 1, 2021, subject to refund, pending further hearing and settlement procedures and were consolidated into a single proceeding. MP, PE and WP, and KATCo are engaged in settlement negotiations with the other parties to the formula rate proceedings. KATCo will be included in the Regulated Transmission reportable segment.