Regulatory Matters	9 Months Ended
Sep. 30, 2019
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 are subject to certain regulations of the VSCC. 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 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 January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019. On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, 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. 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. On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators. 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 Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter. Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for cost recovery established with JCP&L Reliability Plus. On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification. OHIO 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 continues a base distribution rate freeze through May 31, 2024 and continues 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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (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. In addition, ESP IV provided for the Ohio Companies to collect through Rider 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. Revenues from Rider DMR are excluded from the significantly excessive earnings test. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through Rider DMR, credit back to customers a refund of Rider DMR funds collected since July 2, 2019, and remove Rider DMR from ESP IV. The Ohio Companies filed revised tariffs to implement the refund of Rider DMR funds collected since July 2, 2019. On October 1, 2019, the Ohio Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of Rider DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. The Ohio Companies intend to contest this appeal but are unable to predict the outcome of this matter. Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan includes a portfolio of energy efficiency programs targeted to a variety of customer segments. The Ohio Companies anticipate the cost of the plan will be approximately $268 million over the life of the plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plan with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap. On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. On October 23, 2019, the PUCO solicited comments on whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. The Ohio Companies plan to apply to the PUCO for approval of the decoupling mechanism later this year, 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. Opponents to the legislation are petitioning to submit the legislation to a statewide referendum on the November 2020 ballot, and stay its effect unless and until approved by a majority of Ohio voters. On September 4, 2019, a lawsuit was filed with the SCOH, challenging the referendum on the grounds that the provisions supporting nuclear energy are a new tax and taxes cannot be overturned by referendum. On October 7, 2019, petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio challenging various Ohio legal requirements for a referendum, and seeking additional time to gather signatures in support of a referendum. Petitioners did not meet the October 21, 2019 deadline to file the necessary number of petition signatures. On October 23, 2019, legislation went into effect. The U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. In February 2016, the Ohio Companies filed a Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan, a portfolio of distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. Also, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the 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. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has 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. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On August 16, 2019, environmental advocates who were not parties to the settlement filed an application for rehearing challenging the PUCO’s approval of the settlement. On September 11, 2019, the PUCO denied the application for rehearing. The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019. On October 9, 2019, the PUCO approved the recovery of the $95 million of previously excluded Legacy RTEP charges. 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 must also be separately tracked for treatment 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. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW, customer assistance program shopping limitations, and script modifications related to the Pennsylvania Companies’ customer referral programs. 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. Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed. On August 30, 2019, the Pennsylvania Companies filed individual Petitions for approval of proposed 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 September 30, 2019, the Pennsylvania OCA submitted comments on the Pennsylvania Companies’ LTIIPs. A PPUC decision is expected by year-end. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018 and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On July 25, 2019, the PPUC and the Pennsylvania Companies filed separate Applications for Reargument of the Commonwealth Court’s July 11, 2019 Opinion and Order. The Applications were denied by the Commonwealth Court by Orders entered September 4, 2019. On October 7, 2019, the PPUC and the Pennsylvania Companies filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to the Pennsylvania Supreme Court. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. The Pennsylvania Office of Small Business Advocate and the Pennsylvania OCA have opposed Penn’s Petition. On September 20, 2019, Penn filed its direct testimony in support of its Petition. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates 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 August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. A hearing has been set for December 11, 2019 to consider the settlement, and an order is expected in December 2019 for rates effective January 1, 2020. On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. The hearing in this matter has been set for December 11, 2019. 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, AGC, 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 major wholesale purchases remain subject to 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. RTO Realignment On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI’s transmission rate for certain charges that collectively can be described as “exit fees” and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach. FERC Actions on Tax Act On March 15, 2018, FERC issued a NOI seeking information regarding whether and how FERC should 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 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (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. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending. Transmission ROE Methodology In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the NOI comments, and any subsequent rulemaking and other proceedings. 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.

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 are subject to certain regulations of the VSCC. 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 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 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 January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, 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.

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.

On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.

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 Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.

Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for cost recovery established with JCP&L Reliability Plus.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.

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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (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.

In addition, ESP IV provided for the Ohio Companies to collect through Rider 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. Revenues from Rider DMR are excluded from the significantly excessive earnings test. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through Rider DMR, credit back to customers a refund of Rider DMR funds collected since July 2, 2019, and remove Rider DMR from ESP IV. The Ohio Companies filed revised tariffs to implement the refund of Rider DMR funds collected since July 2, 2019. On October 1, 2019, the Ohio Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019.

Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan includes a portfolio of energy efficiency programs targeted to a variety of customer segments. The Ohio Companies anticipate the cost of the plan will be approximately $268 million over the life of the plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plan with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. On October 23, 2019, the PUCO solicited comments on whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. The Ohio Companies plan to apply to the PUCO for approval of the decoupling mechanism later this year, 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. Opponents to the legislation are petitioning to submit the legislation to a statewide referendum on the November 2020 ballot, and stay its effect unless and until approved by a majority of Ohio voters. On September 4, 2019, a lawsuit was filed with the SCOH, challenging the referendum on the grounds that the provisions supporting nuclear energy are a new tax and taxes cannot be overturned by referendum. On October 7, 2019, petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio challenging various Ohio legal requirements for a referendum, and seeking additional time to gather signatures in support of a referendum. Petitioners did not meet the October 21, 2019 deadline to file the necessary number of petition signatures. On October 23, 2019, legislation went into effect. The U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer.

In February 2016, the Ohio Companies filed a Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan, a portfolio of distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. Also, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the 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. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has 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. On July 17, 2019, the PUCO approved the settlement agreement with no material

The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019. On October 9, 2019, the PUCO approved the recovery of the $95 million of previously excluded Legacy RTEP charges.

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 must also be separately tracked for treatment 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. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW, customer assistance program shopping limitations, and script modifications related to the Pennsylvania Companies’ customer referral programs.

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.

Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed. On August 30, 2019, the Pennsylvania Companies filed individual Petitions for approval of proposed 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 September 30, 2019, the Pennsylvania OCA submitted comments on the Pennsylvania Companies’ LTIIPs. A PPUC decision is expected by year-end.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018 and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On July 25, 2019, the PPUC and the Pennsylvania Companies filed separate Applications for Reargument of the Commonwealth Court’s July 11, 2019 Opinion and Order. The Applications were denied by the Commonwealth Court by Orders entered September 4, 2019. On October 7, 2019, the PPUC and the Pennsylvania Companies filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to the Pennsylvania Supreme Court. On August

30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. The Pennsylvania Office of Small Business Advocate and the Pennsylvania OCA have opposed Penn’s Petition. On September 20, 2019, Penn filed its direct testimony in support of its Petition.

On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. A hearing has been set for December 11, 2019 to consider the settlement, and an order is expected in December 2019 for rates effective January 1, 2020.

On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. The hearing in this matter has been set for December 11, 2019.

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, AGC, 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 major wholesale purchases remain subject to 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.

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI’s transmission rate for certain charges that collectively can be described as “exit fees” and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed

settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.

On March 15, 2018, FERC issued a NOI seeking information regarding whether and how FERC should 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 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (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. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.

In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the NOI comments, and any subsequent rulemaking and other proceedings.